Generic Environmental 

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 57

Regarding LaSalle County 

Station, Units 1 and 2

Final Report

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 57

Generic Environmental

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 57 

Regarding LaSalle County 

Station, Units 1 and 2

Final Report

Manuscript Completed: August 2016

Date Published: August 2016

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 57 

iii

COVER SHEET

Responsible Agency: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 

Regulation. There are no cooperating agencies involved in the preparation of this document.

Title: Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 

Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Final Report

(NUREG–1437). LaSalle County Station, Units 1 and 2, is located in LaSalle County, Illinois.

For additional information or copies of this document contact:

Division of License Renewal

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Mail Stop O-11F1

11555 Rockville Pike

Rockville, Maryland 20852

Phone: 1-800-368-5642, extension 6223

Email: william.ford@nrc.gov

ABSTRACT

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

application submitted by Exelon Generation Company, LLC (Exelon), to renew the operating 

licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years.

This SEIS includes the analysis that evaluates the environmental impacts of the proposed 

action and alternatives to the proposed action. Alternatives considered include: (1) new

nuclear power generation, (2) coal-integrated gasification combined-cycle, (3) natural gas 

combined-cycle (NGCC), (4) a combination of NGCC, wind, and solar generation, (5) purchased 

power, and (6) the no-action alternative (i.e., no renewal of the licenses).

The U.S. Nuclear Regulatory Commission (NRC) staff’s recommendation is that the adverse 

environmental impacts of license renewal for LSCS are not so great that preserving the option 

of license renewal for energy-planning decisionmakers would be unreasonable. The NRC staff 

based its recommendation on the following factors:

• the analysis and findings in NUREG–1437, Volumes 1 and 2, Generic Environmental 

Impact Statement for License Renewal of Nuclear Plants;

• the Environmental Report submitted by Exelon;

• consultation with Federal, State, local, and Tribal government agencies;

• the NRC staff’s independent environmental review; and

• consideration of public comments received during the scoping process and received 

on the draft SEIS.

v

TABLE OF CONTENTS

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

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

FIGURES................................................................................................................................. xv

TABLES ................................................................................................................................ xvii

EXECUTIVE SUMMARY ........................................................................................................ xxi

ABBREVIATIONS AND ACRONYMS ..................................................................................xxvii

UNITS OF MEASURE ..........................................................................................................xxxv

1.0 INTRODUCTION......................................................................................................... 1-1

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

1.2 Purpose and Need for 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 Decisions to Be Supported by the SEIS........................................................... 1-6

1.7 Cooperating Agencies...................................................................................... 1-6

1.8 Consultations ................................................................................................... 1-6

1.9 Correspondence .............................................................................................. 1-7

1.10 Status of Compliance....................................................................................... 1-7

1.11 Related Federal and State Activities ................................................................ 1-7

1.12 References ...................................................................................................... 1-8

2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION......................................... 2-1

2.1 Proposed Action .............................................................................................. 2-1

2.1.1 Plant Operations during the License Renewal Term.......................... 2-1

2.1.2 Refurbishment and Other Activities Associated with License 

Renewal ............................................................................................ 2-2

2.1.3 Termination of Nuclear Power Plant Operations and 

Decommissioning after the License Renewal Term ........................... 2-2

2.2 Alternatives...................................................................................................... 2-3

2.2.1 No-Action Alternative......................................................................... 2-3

2.2.2 Replacement Power Alternatives....................................................... 2-4

2.2.2.1 New Nuclear Alternative .................................................... 2-9

2.2.2.2 IGCC Alternative.............................................................. 2-10

2.2.2.3 NGCC Alternative ............................................................ 2-12

2.2.2.4 Combination Alternative (NGCC, Wind, and Solar).......... 2-13

2.2.2.5 Purchased Power Alternative........................................... 2-16

2.3 Alternatives Considered but Dismissed.......................................................... 2-16

2.3.1 Energy Conservation and Energy Efficiency.................................... 2-17
Table of Contents

vi

2.3.2 Solar................................................................................................ 2-17

2.3.3 Wind................................................................................................ 2-18

2.3.3.1 Offshore Wind.................................................................. 2-18

2.3.3.2 Wind Power with Storage ................................................ 2-19

2.3.3.3 Conclusion....................................................................... 2-19

2.3.4 Biomass .......................................................................................... 2-19

2.3.5 Hydroelectric ................................................................................... 2-20

2.3.6 Wave and Ocean Energy................................................................. 2-20

2.3.7 Fuel Cells ........................................................................................ 2-21

2.3.8 Delayed Retirement......................................................................... 2-21

2.3.9 Geothermal...................................................................................... 2-22

2.3.10 Municipal Solid Waste ..................................................................... 2-22

2.3.11 Petroleum........................................................................................ 2-22

2.3.12 Supercritical Pulverized Coal........................................................... 2-23

2.4 Comparison of Alternatives ............................................................................ 2-23

2.5 References .................................................................................................... 2-27

3.0 AFFECTED ENVIRONMENT ...................................................................................... 3-1

3.1 Description of Nuclear Power Plant Facility and Operation .............................. 3-1

3.1.1 External Appearance and Setting ...................................................... 3-1

3.1.2 Nuclear Reactor Systems .................................................................. 3-6

3.1.3 Cooling and Auxiliary Water Systems................................................ 3-6

3.1.4 Radioactive Waste Management Systems ...................................... 3-13

3.1.4.1 Radioactive Liquid Waste Management........................... 3-14

3.1.4.2 Radioactive Gaseous Waste Management ...................... 3-15

3.1.4.3 Radioactive Solid Waste Management ............................ 3-16

3.1.4.4 Radioactive Waste Storage ............................................. 3-17

3.1.4.5 Radiological Environmental Monitoring Program ............. 3-17

3.1.5 Nonradioactive Waste Management Systems ................................. 3-18

3.1.6 Utility and Transportation Infrastructure........................................... 3-19

3.1.6.1 Electricity......................................................................... 3-19

3.1.6.2 Fuel ................................................................................. 3-19

3.1.6.3 Water............................................................................... 3-19

3.1.6.4 Transportation Systems................................................... 3-20

3.1.6.5 Power Transmission Systems.......................................... 3-20

3.1.7 Nuclear Power Plant Operations and Maintenance.......................... 3-21

3.2 Land Use and Visual Resources.................................................................... 3-21

3.2.1 Land Use......................................................................................... 3-21

3.2.1.1 Onsite Land Use.............................................................. 3-21

3.2.1.2 Coastal Zone ................................................................... 3-22

3.2.1.3 Offsite Land Use.............................................................. 3-23

3.2.2 Visual Resources............................................................................. 3-24
Table of Contents

vii

3.3 Meteorology, Air Quality, and Noise............................................................... 3-24

3.3.1 Meteorology and Climatology .......................................................... 3-24

3.3.2 Air Quality........................................................................................ 3-25

3.3.3 Noise............................................................................................... 3-28

3.4 Geologic Environment.................................................................................... 3-29

3.4.1 Physiography and Geology.............................................................. 3-30

3.4.2 Soils ................................................................................................ 3-31

3.4.3 Seismic Setting................................................................................ 3-35

3.5 Water Resources ........................................................................................... 3-36

3.5.1 Surface Water Resources................................................................ 3-36

3.5.1.1 Surface Water Hydrology................................................. 3-36

3.5.1.2 Surface Water Use .......................................................... 3-40

3.5.1.3 Surface Water Quality and Effluents ................................ 3-42

3.5.2 Groundwater Resources.................................................................. 3-47

3.5.2.1 Site Description and Hydrogeology.................................. 3-47

3.5.2.2 Groundwater Use ............................................................ 3-49

3.5.2.3 Groundwater Quality........................................................ 3-52

3.6 Terrestrial Resources..................................................................................... 3-53

3.6.1 LSCS Ecoregion.............................................................................. 3-53

3.6.2 LSCS Site Surveys, Studies, and Reports ....................................... 3-54

3.6.3 LSCS Site........................................................................................ 3-55

3.6.3.1 Vegetation ....................................................................... 3-55

3.6.3.2 Wildlife............................................................................. 3-56

3.6.4 LSCS Wildlife Management Plan..................................................... 3-56

3.6.5 Important Species and Habitats....................................................... 3-57

3.6.5.1 Important Species............................................................ 3-57

3.6.5.2 Important Habitats ........................................................... 3-59

3.6.6 Invasive and Non-Native Species .................................................... 3-60

3.7 Aquatic Resources......................................................................................... 3-60

3.7.1 Illinois River..................................................................................... 3-60

3.7.1.1 Aquatic Communities in the Illinois River ......................... 3-61

3.7.2 LSCS Cooling Pond......................................................................... 3-69

3.7.2.1 Aquatic Community in the Cooling Pond.......................... 3-69

3.7.2.2 Cooling Pond Fish Kill Events.......................................... 3-70

3.7.3 Important Species and Habitats....................................................... 3-71

3.7.3.1 State-Listed Species........................................................ 3-71

3.7.3.2 Important Habitats ........................................................... 3-74

3.7.4 Non-Native and Nuisance Species .................................................. 3-74

3.8 Federally Protected Species and Habitats...................................................... 3-74

3.8.1 Action Area...................................................................................... 3-75

3.8.2 Federally Protected Species and Habitats Considered .................... 3-76
Table of Contents

viii

3.9 Historic and Cultural Resources..................................................................... 3-81

3.9.1 Cultural Background........................................................................ 3-82

3.9.2 Historic and Cultural Resources ...................................................... 3-84

3.10 Socioeconomics............................................................................................. 3-84

3.10.1 Power Plant Employment and Expenditures.................................... 3-84

3.10.2 Regional Economic Characteristics ................................................. 3-85

3.10.2.1 Employment and Income ................................................. 3-85

3.10.2.2 Unemployment ................................................................ 3-88

3.10.3 Demographic Characteristics........................................................... 3-88

3.10.3.1 Transient Population........................................................ 3-90

3.10.3.2 Migrant Farm Workers..................................................... 3-91

3.10.4 Housing and Community Services................................................... 3-92

3.10.4.1 Housing ........................................................................... 3-93

3.10.4.2 Education ........................................................................ 3-93

3.10.4.3 Public Water Supply ........................................................ 3-93

3.10.5 Tax Revenues ................................................................................. 3-95

3.10.6 Local Transportation........................................................................ 3-97

3.11 Human Health................................................................................................ 3-98

3.11.1 Radiological Exposure and Risk ...................................................... 3-98

3.11.2 Chemical Hazards ........................................................................... 3-99

3.11.3 Microbiological Hazards................................................................... 3-99

3.11.3.1 Thermophilic Microorganisms of Concern...................... 3-100

3.11.3.2 Prevalence of Waterborne Diseases Associated with 

Recreational Waters ...................................................... 3-101

3.11.4 Electromagnetic Fields .................................................................. 3-101

3.11.5 Other Hazards ............................................................................... 3-102

3.12 Environmental Justice.................................................................................. 3-103

3.12.1 Minority Population........................................................................ 3-104

3.12.2 Low-Income Population ................................................................. 3-104

3.13 Waste Management and Pollution Prevention.............................................. 3-108

3.13.1 Radioactive Waste......................................................................... 3-108

3.13.2 Nonradioactive Waste ................................................................... 3-108

3.14 References .................................................................................................. 3-108

4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS....................... 4-1

4.1 Introduction...................................................................................................... 4-1

4.2 Land Use and Visual Resources...................................................................... 4-1

4.2.1 Proposed Action ................................................................................ 4-1

4.2.2 No-Action Alternative......................................................................... 4-2

4.2.2.1 Land Use........................................................................... 4-2

4.2.2.2 Visual Resources............................................................... 4-2

4.2.3 New Nuclear Alternative .................................................................... 4-2
Table of Contents

ix

4.2.3.1 Land Use........................................................................... 4-2

4.2.3.2 Visual Resources............................................................... 4-3

4.2.4 IGCC Alternative ............................................................................... 4-3

4.2.4.1 Land Use........................................................................... 4-3

4.2.4.2 Visual Resources............................................................... 4-4

4.2.5 Natural Gas Combined-Cycle Alternative .......................................... 4-4

4.2.5.1 Land Use........................................................................... 4-4

4.2.5.2 Visual Resources............................................................... 4-4

4.2.6 Combination Alternative (NGCC, Wind, Solar)................................... 4-5

4.2.6.1 Land Use........................................................................... 4-5

4.2.6.2 Visual Resources............................................................... 4-5

4.2.7 Purchased Power Alternative ............................................................ 4-6

4.2.7.1 Land Use........................................................................... 4-6

4.2.7.2 Visual Resources............................................................... 4-6

4.3 Air Quality and Noise ....................................................................................... 4-6

4.3.1 Proposed Action ................................................................................ 4-6

4.3.1.1 Air Quality.......................................................................... 4-6

4.3.1.2 Noise ................................................................................. 4-7

4.3.2 No-Action Alternative......................................................................... 4-7

4.3.2.1 Air Quality.......................................................................... 4-7

4.3.2.2 Noise ................................................................................. 4-7

4.3.3 New Nuclear Alternative .................................................................... 4-7

4.3.3.1 Air Quality.......................................................................... 4-7

4.3.3.2 Noise ................................................................................. 4-9

4.3.4 IGCC Alternative ............................................................................. 4-10

4.3.4.1 Air Quality........................................................................ 4-10

4.3.4.2 Noise ............................................................................... 4-13

4.3.5 NGCC Alternative............................................................................ 4-13

4.3.5.1 Air Quality........................................................................ 4-13

4.3.5.2 Noise ............................................................................... 4-15

4.3.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-16

4.3.6.1 Air Quality........................................................................ 4-16

4.3.6.2 Noise ............................................................................... 4-18

4.3.7 Purchased Power Alternative .......................................................... 4-19

4.3.7.1 Air Quality........................................................................ 4-19

4.3.7.2 Noise ............................................................................... 4-19

4.4 Geologic Environment.................................................................................... 4-20

4.4.1 Proposed Action .............................................................................. 4-20

4.4.2 No-Action Alternative....................................................................... 4-20

4.4.3 New Nuclear Alternative .................................................................. 4-20

4.4.4 IGCC Alternative ............................................................................. 4-21
Table of Contents

x

4.4.5 NGCC Alternative............................................................................ 4-21

4.4.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-21

4.4.7 Purchased Power Alternative .......................................................... 4-21

4.5 Water Resources ........................................................................................... 4-21

4.5.1 Proposed Action .............................................................................. 4-21

4.5.1.1 Surface Water Resources................................................ 4-21

4.5.1.2 Groundwater Resources.................................................. 4-23

4.5.2 No-Action Alternative....................................................................... 4-26

4.5.2.1 Surface Water Resources................................................ 4-26

4.5.2.2 Groundwater Resources.................................................. 4-26

4.5.3 New Nuclear Alternative .................................................................. 4-26

4.5.3.1 Surface Water Resources................................................ 4-26

4.5.3.2 Groundwater Resources.................................................. 4-27

4.5.4 IGCC Alternative ............................................................................. 4-27

4.5.4.1 Surface Water Resources................................................ 4-27

4.5.4.2 Groundwater Resources.................................................. 4-28

4.5.5 NGCC Alternative............................................................................ 4-28

4.5.5.1 Surface Water Resources................................................ 4-28

4.5.5.2 Groundwater Resources.................................................. 4-29

4.5.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-29

4.5.6.1 Surface Water Resources................................................ 4-29

4.5.6.2 Groundwater Resources.................................................. 4-30

4.5.7 Purchased Power Alternative .......................................................... 4-30

4.5.7.1 Surface Water Resources................................................ 4-30

4.5.7.2 Groundwater Resources.................................................. 4-30

4.6 Terrestrial Resources..................................................................................... 4-30

4.6.1 Proposed Action .............................................................................. 4-30

4.6.1.1 Generic GEIS Issues ....................................................... 4-31

4.6.1.2 Effects on Terrestrial Resources (Non-Cooling 

System Impacts).............................................................. 4-31

4.6.1.3 Water Use Conflicts with Terrestrial Resources............... 4-33

4.6.2 No-Action Alternative....................................................................... 4-33

4.6.3 New Nuclear Alternative .................................................................. 4-34

4.6.4 IGCC Alternative ............................................................................. 4-34

4.6.5 NGCC Alternative............................................................................ 4-35

4.6.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-36

4.6.7 Purchased Power Alternative .......................................................... 4-36

4.7 Aquatic Resources......................................................................................... 4-37

4.7.1 Proposed Action .............................................................................. 4-37

4.7.1.1 GEIS Category 1 Issues .................................................. 4-38

4.7.1.2 Impingement and Entrainment of Aquatic Organisms ...... 4-38
Table of Contents

xi

4.7.1.3 Thermal Impacts on Aquatic Organisms .......................... 4-45

4.7.1.4 Water Use Conflicts with Aquatic Resources ................... 4-52

4.7.2 No-Action Alternative....................................................................... 4-53

4.7.3 New Nuclear Alternative .................................................................. 4-53

4.7.4 IGCC Alternative ............................................................................. 4-54

4.7.5 NGCC Alternative............................................................................ 4-54

4.7.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-55

4.7.7 Purchased Power Alternative .......................................................... 4-55

4.8 Special Status Species and Habitats.............................................................. 4-55

4.8.1 Proposed Action .............................................................................. 4-55

4.8.2 No-Action Alternative....................................................................... 4-57

4.8.3 New Nuclear Alternative .................................................................. 4-57

4.8.4 IGCC Alternative ............................................................................. 4-58

4.8.5 NGCC Alternative............................................................................ 4-58

4.8.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-59

4.8.7 Purchased Power Alternative .......................................................... 4-59

4.9 Historic and Cultural Resources..................................................................... 4-59

4.9.1 Proposed Action .............................................................................. 4-60

4.9.2 No-Action Alternative....................................................................... 4-62

4.9.3 New Nuclear Alternative .................................................................. 4-62

4.9.4 IGCC Alternative ............................................................................. 4-62

4.9.5 NGCC Alternative............................................................................ 4-63

4.9.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-63

4.9.7 Purchased Power Alternative .......................................................... 4-64

4.10 Socioeconomics............................................................................................. 4-64

4.10.1 Proposed Action .............................................................................. 4-64

4.10.2 No-Action Alternative....................................................................... 4-65

4.10.2.1 Socioeconomics .............................................................. 4-65

4.10.2.2 Transportation ................................................................. 4-66

4.10.3 New Nuclear Alternative .................................................................. 4-66

4.10.3.1 Socioeconomics .............................................................. 4-66

4.10.3.2 Transportation ................................................................. 4-67

4.10.4 IGCC Alternative ............................................................................. 4-67

4.10.4.1 Socioeconomics .............................................................. 4-67

4.10.4.2 Transportation ................................................................. 4-68

4.10.5 NGCC Alternative............................................................................ 4-68

4.10.5.1 Socioeconomics .............................................................. 4-68

4.10.5.2 Transportation ................................................................. 4-69

4.10.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-70

4.10.6.1 Socioeconomics .............................................................. 4-70

4.10.6.2 Transportation ................................................................. 4-70
Table of Contents

xii

4.10.7 Purchased Power Alternative .......................................................... 4-71

4.10.7.1 Socioeconomics .............................................................. 4-71

4.10.7.2 Transportation ................................................................. 4-71

4.11 Human Health................................................................................................ 4-72

4.11.1 Proposed Action .............................................................................. 4-72

4.11.1.1 Normal Operating Conditions........................................... 4-72

4.11.1.2 Environmental Impacts of Postulated Accidents .............. 4-76

4.11.2 No-Action Alternative....................................................................... 4-88

4.11.3 New Nuclear Alternative .................................................................. 4-89

4.11.4 IGCC Alternative ............................................................................. 4-89

4.11.5 NGCC Alternative............................................................................ 4-90

4.11.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-90

4.11.7 Purchased Power Alternative .......................................................... 4-90

4.12 Environmental Justice.................................................................................... 4-91

4.12.1 Proposed Action .............................................................................. 4-91

4.12.2 No-Action Alternative....................................................................... 4-93

4.12.3 New Nuclear Alternative .................................................................. 4-93

4.12.4 IGCC Alternative ............................................................................. 4-94

4.12.5 NGCC Alternative............................................................................ 4-95

4.12.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-95

4.12.7 Purchased Power Alternative .......................................................... 4-96

4.13 Waste Management....................................................................................... 4-97

4.13.1 Proposed Action .............................................................................. 4-97

4.13.2 No-Action Alternative....................................................................... 4-98

4.13.3 New Nuclear Alternative .................................................................. 4-98

4.13.4 IGCC Alternative ............................................................................. 4-98

4.13.5 NGCC Alternative............................................................................ 4-99

4.13.6 Combination Alternative (NGCC, Wind, Solar)................................. 4-99

4.13.7 Purchased Power Alternative .......................................................... 4-99

4.14 Evaluation of New and Potentially Significant Information.............................. 4-99

4.15 Impacts Common to All Alternatives............................................................. 4-100

4.15.1 Fuel Cycles.................................................................................... 4-100

4.15.1.1 Uranium Fuel Cycle ....................................................... 4-101

4.15.1.2 Replacement Power Plant Fuel Cycles.......................... 4-102

4.15.2 Terminating Power Plant Operations and Decommissioning ......... 4-102

4.15.2.1 Existing Nuclear Power Plant......................................... 4-102

4.15.2.2 Replacement Power Plants............................................ 4-103

4.15.3 Greenhouse Gas Emissions and Climate Change......................... 4-104

4.15.3.1 Greenhouse Gas Emissions from the Proposed 

Project and Alternatives................................................. 4-104

4.15.3.2 Climate Change Impacts to Resource Areas ................. 4-107
Table of Contents

xiii

4.16 Cumulative Impacts of the Proposed Action................................................. 4-113

4.16.1 Air Quality and Noise..................................................................... 4-114

4.16.1.1 Air Quality...................................................................... 4-114

4.16.1.2 Noise ............................................................................. 4-115

4.16.2 Geology and Soils ......................................................................... 4-116

4.16.3 Water Resources........................................................................... 4-116

4.16.3.1 Surface Water Resources.............................................. 4-116

4.16.3.2 Groundwater Resources................................................ 4-121

4.16.4 Terrestrial Resources .................................................................... 4-121

4.16.5 Aquatic Resources ........................................................................ 4-124

4.16.5.1 Energy Development ..................................................... 4-124

4.16.5.2 Future Urbanization and Transportation Development... 4-125

4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas ........ 4-125

4.16.5.4 Illinois Wildlife Conservation Plan .................................. 4-125

4.16.5.5 Conclusion..................................................................... 4-126

4.16.6 Historic and Cultural Resources .................................................... 4-126

4.16.7 Socioeconomics ............................................................................ 4-126

4.16.8 Human Health ............................................................................... 4-127

4.16.9 Environmental Justice ................................................................... 4-128

4.16.10 Waste Management ...................................................................... 4-128

4.16.11 Global Climate Change ................................................................. 4-129

4.16.12 Summary of Cumulative Impacts................................................... 4-131

4.17 Resource Commitments............................................................................... 4-133

4.17.1 Unavoidable Adverse Environmental Impacts................................ 4-133

4.17.2 Short-Term Versus Long-Term Productivity................................... 4-134

4.17.3 Irreversible and Irretrievable Commitments of Resources.............. 4-134

4.18 References .................................................................................................. 4-135

5.0 CONCLUSION ............................................................................................................ 5-1

5.1 Environmental Impacts of License Renewal..................................................... 5-1

5.2 Comparison of Alternatives .............................................................................. 5-1

5.3 Recommendation............................................................................................. 5-1

6.0 LIST OF PREPARERS ............................................................................................... 6-1

7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 

OF THIS SEIS ARE SENT .......................................................................................... 7-1

8.0 INDEX ......................................................................................................................... 8-1

COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW.......A-1

APPLICABLE LAWS, REGULATIONS, AND OTHER 

REQUIREMENTS.........................................................................................B-1

CONSULTATION CORRESPONDENCE .....................................................C-1

CHRONOLOGY OF ENVIRONMENTAL REVIEW 

CORRESPONDENCE ..................................................................................D-1
Table of Contents

xiv

ACTIONS AND PROJECTS CONSIDERED IN THE CUMULATIVE 

IMPACTS ANALYSIS...................................................................................E-1

U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 

OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 

LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 

LICENSE RENEWAL APPLICATION REVIEW............................................ F-1

TRANSPORTATION IMPACTS OF HIGH BURNUP FUEL..........................G-1
xv

FIGURES

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

Figure 1–2. Environmental Issues Evaluated for License Renewal ..................................... 1-5

Figure 2–1. Territories of MISO and PJM Interconnection................................................... 2-6

Figure 3–1. LSCS 50-mi (80-km) Radius Map .................................................................... 3-2

Figure 3–2. LSCS 6-mi (10-km) Radius Map ...................................................................... 3-3

Figure 3–3. LSCS Site Layout............................................................................................. 3-4

Figure 3–4. LSCS Plant Features ....................................................................................... 3-5

Figure 3–5. Closed-Cycle Cooling System with Cooling Pond ............................................ 3-7

Figure 3–6. LSCS Cooling Water Supply and Discharge Facilities...................................... 3-9

Figure 3–7. Site Physiography, LSCS Vicinity................................................................... 3-32

Figure 3–8. North-South Geologic Cross Section, LSCS Vicinity ...................................... 3-33

Figure 3–9. Bedrock Topography and Buried Valleys, LSCS Vicinity ................................ 3-34

Figure 3–10. The Upper Illinois River Basin and Drainage Basin Boundaries ..................... 3-38

Figure 3–11. LSCS Surface Water and Related Water Resource Features ........................ 3-39

Figure 3–12. LSCS Site Hydrogeologic Units...................................................................... 3-48

Figure 3–13. LSCS Groundwater Flow in Engineered Granular Fill .................................... 3-50

Figure 3–14. LSCS Hydrogeologic Cross-Section............................................................... 3-51

Figure 3–15. Icthyoplankton Sampling Location at the LSCS River Intake Structure........... 3-63

Figure 3–16. Sampling Locations in LSCS Aquatic Surveys ............................................... 3-64

Figure 3–17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS.................... 3-106

Figure 3–18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS............. 3-107

Illustration of Truck Stop Model....................................................................... G-6

xvii

TABLES

Table ES–1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 

License Renewal............................................................................................. xxiii

Table 2–1. Summary of Replacement Power Alternatives and Key Characteristics 

Considered in Depth ........................................................................................ 2-8

Table 2–2. Environmental Impacts of the Proposed Action and Alternatives.................... 2-25

Table 3–1. LSCS Site Land Uses by Area ....................................................................... 3-22

Table 3–2. Land Use within a 10-km (6-mi) Radius of LSCS ........................................... 3-23

Table 3–3. National Ambient Air Quality Standards ......................................................... 3-26

Table 3–4. LSCS Air Emissions (MT/year)....................................................................... 3-27

Table 3–5. Common Noise Sources and Noise Levels .................................................... 3-28

Table 3–6. Annual Surface Water Withdrawals and Returns to the Illinois River, 

LSCS ............................................................................................................. 3-41

Table 3–7. National Pollutant Discharge Elimination System-Permitted Outfalls, 

LSCS ............................................................................................................. 3-44

Table 3–8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion............................... 3-53

Table 3–9. State-Listed Species in LaSalle County ......................................................... 3-57

Table 3–10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River............ 3-67

Table 3–11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural 

History Electrofishing Surveys from 1957 through 2009................................. 3-68

Table 3–12. Fish Stockings in the LSCS Cooling Pond 2008-2014.................................... 3-70

Table 3–13. State-Listed Aquatic Species with the Potential To Occur in LaSalle 

County ........................................................................................................... 3-71

Table 3–14. Federally Listed Species and Designated Habitat in LaSalle County, 

Illinois............................................................................................................. 3-77

Table 3–15. LSCS Employees Residence by County ........................................................ 3-85

Table 3–16. Employment by Industry in the LSCS ROI (2014, 1-year estimates and 

2009-2013, 5-year estimates) ........................................................................ 3-86

Table 3–17. Major Employers in LaSalle County in 2009................................................... 3-86

Table 3–18. Estimated Income Information for the LSCS ROI (2014 estimates, 

unless otherwise indicated)............................................................................ 3-87

Table 3–19. Population and Percent Growth in LSCS ROI Counties 1980–2010, 

2014 (estimated), and Projected for 2020–2060 ............................................ 3-88

Table 3–20. Demographic Profile of the Population in the LSCS ROI in 2010 ................... 3-89

Table 3–21. Demographic Profile of the Population in the LSCS ROI in 2014 ................... 3-89

Table 3–22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of 

LSCS ............................................................................................................. 3-90

Table 3–23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 

within 50 mi (80 km) of LSCS (2012).............................................................. 3-92

Table 3–24. Housing in the LSCS ROI (2014 estimate)..................................................... 3-93

Table 3–25. Local Public Water Supply Systems............................................................... 3-94
Tables

xviii

Table 3–26. LSCS Power Block Tax Payments and Valuations 2007–2014 

(in dollars)...................................................................................................... 3-95

Table 3–27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total 

Levy............................................................................................................... 3-96

Table 3–28. Annual Payments to Illinois Emergency Management Agency 

2009–2014..................................................................................................... 3-97

Table 3–29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 

Annual Daily Traffic Count ............................................................................. 3-97

Table 4–1. Land Use and Visual Resource Issues............................................................. 4-2

Table 4–2. Air Quality and Noise ....................................................................................... 4-6

Table 4–3. Geology and Soils Issues............................................................................... 4-20

Table 4–4. Surface Water Resources Issues................................................................... 4-22

Table 4–5. Groundwater Issues....................................................................................... 4-24

Table 4–6. Terrestrial Resource Issues ........................................................................... 4-31

Table 4–7. Aquatic Resource Issues ............................................................................... 4-37

Table 4–8. Special Status Species and Habitat Issues .................................................... 4-55

Table 4–9. Federally Listed Species and Designated Habitat in LaSalle County, 

Illinois, and NRC Effect Determinations for Proposed LSCS License 

Renewal......................................................................................................... 4-57

Table 4–10. Historic and Cultural Resources Issue ........................................................... 4-60

Table 4–11. Socioeconomic NEPA Issues Affected by License Renewal .......................... 4-65

Table 4–12. Human Health Issues..................................................................................... 4-72

Table 4–13. Issues Related to Postulated Accidents ......................................................... 4-76

Table 4–14. LSCS CDF for Internal Events ....................................................................... 4-79

Table 4–15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 

for Internal Events.......................................................................................... 4-81

Table 4–16. LSCS Potentially Cost-Beneficial SAMAs ...................................................... 4-84

Table 4–17. Environmental Justice NEPA Issue................................................................ 4-91

Table 4–18. Waste Management Issues............................................................................ 4-97

Table 4–19. Issues Related to the Uranium Fuel Cycle ................................................... 4-101

Table 4–20. Issues Related to Decommissioning ............................................................ 4-103

Table 4–21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)......... 4-105

Table 4–22. Direct GHG Emissions from Operation of the Proposed Action and 

Alternatives.................................................................................................. 4-107

Table 4–23. Comparison of GHG Emission Inventories................................................... 4-131

Table 4–24. Summary of Cumulative Impacts on Resource Areas .................................. 4-131

Table 6–1. List of Preparers .............................................................................................. 6-1

Table A–1. Commenters on the Draft Supplemental Environmental Impact 

Statement ........................................................................................................A-2

Table B–1. Federal and State Requirements .....................................................................B-2

Table B–2. Licenses and Permits.......................................................................................B-7

Table C–1. ESA Section 7 Consultation Correspondence..................................................C-2

Table C–2. NHPA Correspondence....................................................................................C-3
Tables

xix

Table D–1. Environmental Review Correspondence ..........................................................D-1

Table E–1. Projects and Actions Considered in Cumulative Impact Analysis .....................E-1

Table F–1. LaSalle County Station CDF for Internal Events...............................................F-3

Table F–2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 

for Internal Events............................................................................................F-4

Table F–3. Summary of Major PRA Models and Corresponding CDF and LERF 

Results.............................................................................................................F-7

Table F–4. Dominant LSCS Contributors to Seismic CDF ............................................... F-12

Table F–5(a). Dominant LSCS Unit 1 Fire Zone Contributors to Fire CDF of 8.9×10-6

per year. ........................................................................................................F-14

Table F–5(b). Dominant LSCS Unit 2 Fire Zone Contributors to Fire CDF of 9.4×10-6

per year .........................................................................................................F-14

Table F–5. SAMA Cost-Benefit Screening Analysis for LSCS Station.............................. F-34

Table G–1. Transportation Route Information for Shipments from LSCS to the 

Proposed Yucca Mountain Repository Site ..................................................... G-4

Table G–2. RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters....................... G-5

Table G–3. Annual Normal (Incident-Free) Radiation Doses to Transport Workers 

and the Public from Shipping Spent Fuel from LSCS to the Proposed 

Yucca Mountain Repository Site, Normalized to Reference 

LWR (880 MWe (net))..................................................................................... G-6

Table G–4. Radionuclide Inventories Used in Transportation Accident Risk 

Calculations for the LSCS Reactors...............................................................G-10

Table G–5. Annual Spent Fuel Transportation Accident Impacts from Shipping 

Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 

Site, Normalized to Reference LWR Reactor (880 MWe (net)).......................G-11

xxi

EXECUTIVE SUMMARY

BACKGROUND

By letter dated December 9, 2014, Exelon Generation Company, LLC (Exelon) submitted an 

application to the U.S. Nuclear Regulatory Commission (NRC) to issue renewed operating 

licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20-year period.

Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 51.20(b)(2), the renewal of a 

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, in connection 

with the renewal of an operating license, the NRC shall prepare an EIS, which is a supplement 

to the Commission’s NUREG–1437, Generic Environmental Impact Statement (GEIS) for 

License Renewal of Nuclear Plants (dated June 2013).

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

process described in 10 CFR Part 51 by publishing a Notice of Intent to prepare a supplemental 

environmental impact statement (SEIS) and to conduct scoping. In preparation of this SEIS for 

LSCS, the NRC staff performed the following:

• conducted public scoping meetings on March 10, 2015, in Ottawa, Illinois;

• conducted a site audit at LSCS from May 5–7, 2015;

• reviewed Exelon’s Environmental Report (ER) and compared it to the GEIS; 

• consulted with Federal, State, Tribal, and local agencies;

• conducted a review of the issues following the guidance set forth in NUREG–1555,

Revision 1, Standard Review Plans for Environmental Reviews for Nuclear Power 

Plants, Supplement 1: Operating License Renewal, Final Report; and

• considered public comments received during the scoping process and received on 

the draft SEIS.

PROPOSED ACTION

Exelon initiated the proposed Federal action (i.e., issuance of renewed power reactor operating 

licenses) by submitting an application for license renewal of LSCS for which the existing 

licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023, respectively. 

The NRC’s Federal action is to decide whether to renew the licenses for an additional 20 years. 

The regulation at 10 CFR 2.109 states that, if a licensee of a nuclear power plant files an 

application to renew an operating license at least 5 years before the expiration date of that 

license, the existing license will not be deemed to have expired until the safety and 

environmental reviews are completed and until the NRC has made a final decision on whether 

to issue a renewed license for the additional 20 years.

PURPOSE AND NEED FOR ACTION

The purpose and need for the proposed action (i.e., issuance of renewed licenses) is to provide 

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

power plant operating licenses to meet future system generating needs. Such needs may be 

determined by other energy-planning decisionmakers, such as states, operators, and, where 

authorized, Federal agencies (other than the NRC). This definition of purpose and need reflects 
Executive Summary

xxii

the NRC’s recognition that, unless there are findings in the safety review required by the Atomic 

Energy Act of 1954, as amended, or findings in the National Environmental Policy Act of 1969, 

as amended, 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 as to whether a 

particular nuclear power plant should continue to operate.

ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL

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

environmental impacts from the proposed action are designated as SMALL, MODERATE, or 

LARGE. As established in the GEIS, Category 1 issues are those that meet all of the following 

criteria:

• The environmental impacts associated with 

the issue are 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.

• 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.

• Mitigation of adverse impacts associated with 

the issue is 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 Category 1 issues, no additional site-specific analysis is required in this SEIS unless new 

and significant information is identified. Chapter 4 of this SEIS 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 criteria for Category 1 issues; therefore, an additional site-specific 

review for these non-generic issues is required, and the results are documented in the SEIS. 

Neither Exelon 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. This conclusion is 

supported by the NRC staff’s review of the applicant’s ER and other documentation relevant to 

the applicant’s activities, the public scoping process, comments received, and the findings from 

the environmental site audit conducted by the NRC staff. Therefore, the NRC staff relied upon 

the conclusions of the GEIS for all Category 1 issues applicable to LSCS. 

The NRC staff did find new information regarding the Category 1 uranium fuel cycle issue

(Transportation), but the NRC staff determined that this new information is not significant and 

therefore it does not affect the conclusions for this issue presented in the GEIS. This new 

information is discussed in Section 4.15.1 and Appendix G of this SEIS.

Table ES-1 summarizes the Category 2 issues relevant to LSCS and the NRC staff’s findings 

related to those issues. If the NRC staff determined that there were no Category 2 issues 

applicable for a particular resource area, the findings of the GEIS, as documented in 

Appendix B to Subpart A of 10 CFR Part 51, are incorporated for that resource area.

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.
Executive Summary

xxiii

Table ES–1. Summary of NRC Conclusions Relating to Site-Specific Impacts of

License Renewal

Resource Area Relevant Category 2 Issues Impacts

Surface Water Resources Surface water use conflicts SMALL

Groundwater Resources

Groundwater Use Conflicts

Groundwater Quality Degradation

Radionuclides released to groundwater

SMALL

SMALL

SMALL

Terrestrial Resources

Effects on terrestrial resources (non-cooling 

system impacts)

Water use conflicts with terrestrial resources 

SMALL

SMALL

Aquatic Resources

Impingement and entrainment of aquatic 

organisms

Thermal impacts on aquatic organisms

Water use conflicts with aquatic resources

SMALL

SMALL to MODERATE(a)

SMALL

Special Status Species and 

Habitats

Threatened, endangered, and protected 

species and essential fish habitat No effect(b)

Historic and Cultural

Resources Historic and cultural resources No adverse effect(c)

Human Health Microbiological hazards to the public

Electric shock hazards

SMALL

SMALL

Environmental Justice Minority and low-income populations See note below(d)

Cumulative Impacts

Terrestrial Ecology

Aquatic Resources

Socioeconomics

Environmental Justice

Global Climate Change

All other resource areas

MODERATE to LARGE

MODERATE

See note below(e)

See note below(d)

MODERATE(f)

SMALL

(a) Thermal impacts would be SMALL for all aquatic resources in the Illinois River and SMALL for aquatic resources in 

the cooling pond, except for gizzard shad and threadfin shad. Gizzard shad and threadfin shad would experience

MODERATE thermal impacts in the cooling pond.

(b) For Federally protected species, the NRC reports the effects from continued operation of LSCS during the license 

renewal period in terms of its Endangered Species Act of 1973, as amended, findings of “no effect,” “may effect, 

but not likely to adversely effect,” or “may affect, and is likely to adversely affect.”

(c) The National Historic Preservation Act of 1966, as amended, requires Federal agencies to consider the effects of 

their undertakings on historic properties.

(d) There would be no disproportionately high and adverse impacts to minority and low-income populations.

(e) The contributory effects from the continued operation of LSCS during the license renewal period would have no 

new or increased impact on socioeconomic conditions beyond what is currently being experienced.

(f) The incremental impact from the contribution of greenhouse gas (GHG) emissions from continued operation of 

LSCS on global climate change would be SMALL. When compared to other baseload replacement power

generation sources assessed in this SEIS, the incremental addition of GHG emissions from continued operation of 

LSCS, when compared to global emissions, are negligible (SMALL) and would have a net, beneficial contribution 

to GHG emissions and global climate change impacts during the license renewal term. However, the cumulative 

impacts of global GHG emissions from past, present, and reasonably foreseeable future actions on global climate 

change are MODERATE.
Executive Summary

xxiv

SEVERE ACCIDENT MITIGATION ALTERNATIVES

Since severe accident mitigation alternatives (SAMAs) have not been previously considered in 

an environmental impact statement or environmental assessment for LSCS, 

10 CFR 51.53(c)(3)(ii)(L) requires Exelon to submit, with the ER, a consideration of alternatives

to mitigate severe accidents. SAMAs are potential ways to reduce the risk or potential impacts 

of uncommon, but potentially severe accidents. SAMAs may include changes to plant 

components, systems, procedures, and training.

The NRC staff reviewed Exelon’s ER evaluation of potential SAMAs and concluded that none of 

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

the extended period of operation. Therefore, the potentially cost-beneficial SAMAs identified

need not be implemented as part of the license renewal, pursuant to 10 CFR Part 54.

ALTERNATIVES

The NRC staff considered the environmental impacts associated with alternatives to license 

renewal. These alternatives include other methods of power generation, as well as not 

renewing the LSCS operating licenses (i.e., the no-action alternative). The NRC staff 

considered the following feasible and commercially viable replacement power alternatives:

• new nuclear power;

• coal-integrated gasification combined-cycle;

• natural gas combined-cycle (NGCC);

• combination alternative (NGCC, wind, and solar power); and

• purchased power.

The NRC staff initially considered a number of additional alternatives for analysis as alternatives 

to the license renewal of LSCS. The NRC staff later dismissed these alternatives because of

technical, resource availability, or commercial limitations that currently exist and that the NRC 

staff believes are likely to continue to exist when the current LSCS licenses expire. The 

no-action alternative and the effects it would have were also considered by the NRC staff.

Where possible, the NRC staff evaluated potential environmental impacts for these alternatives

located at both the LSCS site and some other unspecified alternate location. The NRC staff 

considered the following alternatives, but dismissed them:

• energy conservation and energy efficiency;

• supercritical pulverized coal;

• wind power;

• solar power;

• hydroelectric power;

• wave and ocean energy;

• geothermal power;

• municipal solid waste;

• biomass;
Executive Summary

xxv

• oil-fired power;

• fuel cells; and

• delayed retirement.

The NRC staff evaluated each alternative using the same resource areas that were used in 

evaluating impacts from license renewal.

RECOMMENDATION

The NRC staff’s recommendation is that the adverse environmental impacts of license renewal 

for LSCS are not so great that preserving the option of license renewal for energy-planning 

decisionmakers would be unreasonable. The NRC staff based its recommendation on the 

following:

• the analyses and findings in the GEIS;

• the ER submitted by Exelon;

• the NRC staff’s consultation with Federal, State, Tribal, and local agencies;

• the NRC staff’s independent environmental review; and

• the NRC staff’s consideration of public comments received during the scoping

process and received on the draft SEIS.

xxvii

ABBREVIATIONS AND ACRONYMS

AC alternating current

ACC averted cleanup and decontamination costs

ACHP Advisory Council on Historic Preservation

ADAMS Agencywide Documents Access and Management System

ADS automatic depressurization system

AEA Atomic Energy Act of 1954 (as amended)

AEC Atomic Energy Commission

ALARA as low as is reasonably achievable

APE area of potential effect

AQCR air quality control region

ASME American Society of Mechanical Engineers

ATWS anticipated transient(s) without scram

BLM Bureau of Land Management

BMP best management practice

BOC break outside containment

BPJ best professional judgement

BTA best technology available

BWR boiling water reactor

BWROG Boiling Water Reactor Owners Group

CAA Clean Air Act

CAES compressed air energy storage

CAFTA computer-aided fault tree analysis

CCS carbon capture and storage

CCF common cause failure

CDF core damage frequency

CDC Centers for Disease Control and Prevention

CECO Commonwealth Edison Company

CEQ Council on Environmental Quality

CET containment event tree

CFR Code of Federal Regulations

CH4 methane

Class B/C Class B and Class C low-level radioactive waste

CNWRA Center for Nuclear Water Regulatory Analysis
Abbreviations and Acronyms

xxviii

CO carbon monoxide

CO2 carbon dioxide

CO2e carbon dioxide equivalent

COL combined operating license

ComEd Commonwealth Edison

CRMP cultural resource management plan

CSCS core standby cooling system

CST condensate storage tank

CV containment vent

CWA Clean Water Act

CWS cooling water system

CZ containment remains intact

CZMA Coastal Zone Management Act

DBA design-basis accident

DI drywell intact

DC direct current

DELT deformities, erosions, lesions, or tumors

DMR discharge monitoring reports

DOE U.S. Department of Energy

EA EA Engineering, Science, & Technology, Inc.

EAL emergency action level

EcoCat ecological compliance assessment tool

ECCS emergency core cooling system

ECOS environmental conservation online system

Edwardsport Duke Energy Edwardsport Generation System

EEM external event multiplier

EFH essential fish habitat

EIA Energy Information Administration

EIS environmental impact statement

EMF electromagnetic field

EO executive order

EOPs emergency operation procedures

EPA U.S. Environmental Protection Agency

EPG emergency procedure guidelines

EPRI Electric Power Research Institute
Abbreviations and Acronyms

xxix

EPT Ephemeroptera, Plecoptera, & Trichoptera

ER Environmental Report

ESA Endangered Species Act of 1973, as amended

ESF engineered safety feature

ESRP Environmental Standard Review Plan, NUREG–1555, 

Supplement 1, Revision 1

FC containment flooding occurs with drywell vent

FEIS final environmental impact statement

FES final environmental statement

FESOP Federally Enforceable State Operating Permit

FIVE fire-induced vulnerability evaluation

FPIE full power internal event

FPS fire protection system

FR Federal Register

FRN Federal Register notice

FWS U.S. Fish and Wildlife Service

GEIS generic environmental impact statement

GHGs greenhouse gases

GI generic issue

GRWS gaseous radioactive waste system

GV combustible gas venting initiated

HAP hazardous air pollutants

HEP human error probability

HFCs hydrofluorocarbons

HFO high winds, floods, and other

H2O water

HPCS high pressure core spray

HR containment heat removal

HRA human reliability analysis

HRSG heat recovery steam generator

IAC Illinois Administrative Code

INAI Illinois Natural Areas Inventory

ICRP International Commission on Radiological Protection

ID identification

Idoneous Idoneous Consulting, Inc.
Abbreviations and Acronyms

xxx

IDNR Illinois Department of Natural Resources

IDOT Illinois Department of Transportation

IDPH Illinois Department of Public Health

IEMA Illinois Emergency Management Agency

IEPA Illinois Environmental Protection Agency

IGCC integrated gasification combined-cycle

IHPA Illinois Historic Preservation Agency

ILCS Illinois Compiled Statutes

INHS Illinois Department of Public Health

IORV inadvertent/stuck open relief valve

IPaC information for planning and conservation

IPCB Illinois Pollution Control Board

IPE individual plant examination

IPEEE individual plant examination(s) of external events

IRSF interim radioactive waste storage facility

IS containment isolated

ISFSI independent spent fuel storage facility

ISLOCA interfacing-systems loss-of-coolant accident

LDN day-night average sound intensity level

Leq equivalent sound intensity level

LERF large early release frequency

LLW low-level waste

Ln statistical sound level

LOCA loss-of-coolant accident

LOE lines of evidence

LOOP loss(es) of offsite power

LPCI low-pressure coolant injection

LPCS low-pressure core spray

LRA license renewal application

LRWS liquid radioactive waste system

LSCS LaSalle County Station, Units 1 and 2

LWRS light-water reactors

MAAP Modular Accident Analysis Program

MACCS2 MELCOR Accident Consequence Code System 2

MACR maximum averted cost risk
Abbreviations and Acronyms

xxxi

MATS Mercury and Air Toxics Standards

MBTA Migratory Bird Treaty Act

MISO Midcontinent Independent System Operator

MMACR modified maximum averted cost

MMPA Marine Mammal Protection Act

MMT million metric tons

MSA Magnuson–Stevens Fishery Conservation and Management Act, 

as amended through 2006

MSIV main steam isolation valve

MU Inventory Makeup Available

NAAQS National Ambient Air Quality Standards

NC no large containment failure

NCRP National Council on Radiation Protection and Measurements

NEI Nuclear Energy Institute

NEPA National Environmental Policy Act of 1969, as amended

NESC National Electric Safety Code

NETL National Energy Technology Laboratory

NGCC natural gas combined-cycle

NHPA National Historic Preservation Act of 1966, as amended

NIEHS National Institute of Environmental Health Sciences

NMFS National Marine Fisheries Service (of the National Oceanic and 

Atmospheric Administration)

NO2 nitrogen dioxide

NOx nitrogen oxide(s)

N2O nitrous oxide

NPDES National Pollutant Discharge Elimination System

NPS National Park Service

NRC U.S. Nuclear Regulatory Commission

NREL National Renewable Energy Laboratory

NRHP National Register of Historic Places

NRR Nuclear Reactor Regulation, Office of (NRC)

NSR new source review

NTTF Near Term Task Force

O3 ozone

OCR onsite cost risk
Abbreviations and Acronyms

xxxii

ODCM offsite dose calculation manual

OECR offsite economic cost risk

OP RPV Depressurization

OSHA Occupational Safety and Health Administration

PAM primary amoebic meningoencephalitis

Pb lead

PCB polychlorinated biphenyls

PDR population dose risk

PDS plant damage state

PEIS programmatic environmental impact statement

PFCS perfluorocarbons

PIMW potentially infectious medical waste

PNNL Pacific Northwest National Laboratory

PRA probabilistic risk assessment

PSD prevention of significant deterioration

PSDAR post-shutdown decommissioning activities report

PV photovoltaic

PWR pressurized water reactor

RAI request(s) for additional information

RB reactor building effectiveness

RCIC reactor core isolation cooling 

RCP reactor coolant pump

RCRA Resource Conservation and Recovery Act of 1976, as amended

REMP radiological environmental monitoring program

RHR residual heat removal

RHRSW residual heat removal service water

RMIEP risk methods integration and evaluation program

ROI region of influence

ROW right-of-way

RPV reactor pressure vessel

RRW risk reduction worth

RTO regional transmission organization

RX core melt arrested in-vessel

SAGS severe accident guidelines

SAMA severe accident mitigation alternative
Abbreviations and Acronyms

xxxiii

SAR safety analysis report

SBLC standby liquid control

SBO station blackout

SCPC supercritical pulverized coal

SCR spent selective catalytic reduction

SEIS supplemental environmental impact statement

SER safety evaluation report

SF6 sulfur hexafluoride

SHPO State Historic Preservation Officer

SHSR seismic hazard screening report

SNL Sandia National Laboratories

SO2 sulfur dioxide

SP suppression pool

SPC suppression pool cooling

SR supporting requirement

SRV safety relief valve

SWRS solid radioactive waste system

SSC structure, system, and component

SW service water

SWEL seismic walkdown equipment list

SWPPP storm water pollution prevention plan

SX essential service water

syngas synthesis gas

TD injection established to RPV and drywell

TMDL total maximum daily load

TRAGIS transportation routing analysis geographical information system

TS technical specification(s)

UHS ultimate heat sink

URE updating requirement evaluation

U.S. United States

USACE U. S. Army Corps of Engineers

USC United States Code

USFS U. S. Forest Service

UFSAR updated final safety analysis report

USGCRP U.S. Global Change Research Program
Abbreviations and Acronyms

xxxiv

USGS U.S. Geological Survey

VOC volatile organic compound

Vogtle Vogtle Electric Generating Plant

VPP OSHA Voluntary Protection Program

WEA averted offsite economic cost

WCP averted onsite cleanup cost

WHC Wildlife Habitat Council

WNS white-nose syndrome

WO averted onsite exposure cost

WOE weight of evidence

WPHA averted offsite exposure cost

WRP averted replacement power cost

WSA wet gas sulfuric acid

WW wetwell airspace failure
xxxv

UNITS OF MEASURE

ac acre(s)

cfs cubic foot (feet) per second

Ci/MTU curies per metric ton of uranium

dB decibels

oC degrees Celsius

oF degrees Fahrenheit

ft foot (feet)

fps feet per second

ft3 cubic foot (feet)

gpd gallon(s) per day

gpm gallon(s) per minute

gCe/kWh grams of carbon equivalent per kilowatt hour

ha hectare(s)

kg kilogram(s)

km kilometer(s)

km2 square kilometers

Kph kilometers per hour

kV kilovolt

kW kilowatt(s)

kWe kilowatt(s) electric

kWh/m2

/d kilowatt hours per square meter per day

lb pound(s)

Lpd liters per day

L/min liters per minute

MWd megawatt(s) day

MT metric tons

m meter(s)

m/s meter(s) per second

MTU metric ton of uranium

μm micrometers

m2 square miles

m3 cubic meter(s)

m3

/day cubic meters per day
Units of Measure

xxxvi

m3

/min cubic meters per minute

m3

/yr cubic meters per year

m3

/s cubic meters per second

mgd million gallons per day

mgy million gallons per year

mg/L milligrams per liter

mi mile(s)

mph mile(s) per hour

mGy milligray

mrad millirad

mrem millirem

mSv millisievert

MT metric ton

MW megawatt(s)

MWe megawatt(s) electric

MWh megawatt hour(s)

MWt megawatt(s) thermal

pCi/L picocuries per liter

ppm parts per million

person/mi2 persons per square mile

rem roentgen equivalent(s) man

RKm river kilometer

RM river mile

Sv sievert(s)

Tg teragrams

v volt(s)

yr year(s)
1-1

1.0 INTRODUCTION

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

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

the National Environmental Policy Act (NEPA)—the issuance or renewal of a nuclear power 

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

The Atomic Energy Act of 1954 (AEA) specifies that licenses for commercial power reactors can 

be granted for up to 40 years. NRC regulations (10 CFR 54.31) allow for an option to renew a 

license for up to an additional 20 years. The initial 40-year licensing period was based 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 license renewal based on whether the applicant has demonstrated that the environmental 

and safety requirements in the agency’s regulations can be met during the period of extended 

operation.

1.1 Proposed Federal Action

Exelon Generation Company, LLC (Exelon), initiated the proposed Federal action by submitting 

an application for license renewal of LaSalle County Station, Units 1 and 2 (LSCS), for which 

the existing licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023,

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

additional 20 years.

1.2 Purpose and Need for Proposed Federal Action

The purpose and need for the proposed action (issuance of renewed licenses) 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 other energy-planning decisionmakers. This definition of purpose and need 

reflects the NRC’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 (LRA), 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.

1.3 Major Environmental Review Milestones

Exelon submitted an Environmental Report (ER) (Exelon 2014a) as part of its 

LRA (Exelon 2014b) in December 2014. After reviewing the LRA and ER for sufficiency, the 

NRC staff published a Federal Register Notice of Acceptability and Opportunity for Hearing 

(Volume 80 of the Federal Register (FR), page 5822 (80 FR 5822)) on February 3, 2015. Also, 

on February 3, 2015, the NRC published another notice in the Federal Register (80 FR 5793) on 

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

The NRC staff held two public scoping meetings on March 10, 2015, in Ottawa, Illinois. In a 

letter dated July 2, 2015, the NRC issued a report entitled, “Environmental Impact Statement 

Scoping Process Summary Report, LaSalle County Station, Units 1 and 2, Brookfield Township,
Introduction

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LaSalle County, IL,” which includes both the comments received during the scoping process 

and the NRC staff’s responses to those comments (NRC 2015a).

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

audit at LSCS in May 2015. During the site audit, the NRC staff met with plant personnel, 

reviewed specific documentation, toured the facility, and met with interested local agencies. In 

a letter dated May 20, 2015, the NRC summarized that site audit and listed the attendees 

(NRC 2015b). Following the site audit, Exelon submitted a revision to the ER on July 31, 2015 

(ADAMS Accession No. ML15212A259), as well as responses to requests for additional 

information (RAIs) from the NRC staff on July 2, 2015 (ADAMS Accession No. ML15195A351).

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

draft supplemental environmental impact statement (SEIS) (NRC 2016). The draft was issued 

for public comment on February 2016 (81 FR 7378, NRC 2016). On March 22, 2015, the NRC 

staff conducted a public meeting in Ottawa, Illinois, to describe the results of the environmental 

review, respond to questions, and accept public comments. A 45-day comment period began 

on February 19, 2016, when the U.S. Environmental Protection Agency published a Notice of 

Availability of the draft SEIS (81 FR 8490). The comment period ended on April 4, 2016.

Comments received and the NRC staff responses to the comments are included in Appendix A 

of this SEIS. Based on the information gathered, the NRC staff amended the draft SEIS 

findings, as necessary, and published this final SEIS. Figure 1–1 shows the major milestones of 

the NRC’s LRA environmental review process.

Figure 1–1. Environmental Review Process

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

period of time with clear requirements to ensure safe plant operation for up to an additional 

20 years of plant life. The NRC staff conducts the safety review simultaneously with the 

environmental review. The NRC staff documents the findings of the safety review in a safety 
Introduction

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evaluation report (SER). The findings in the SEIS and the SER are both factors in the NRC’s 

decision to either grant or deny the issuance of a renewed license.

1.4 Generic Environmental Impact Statement

The NRC staff performed a generic assessment of the environmental impacts associated with 

license renewal to improve the efficiency of its license renewal review. NUREG–1437, Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS)

(NRC 1996, 1999, 2013), documents the results of the NRC staff’s systematic approach to 

evaluate the environmental consequences of renewing the licenses of individual nuclear power 

plants and operating them for an additional 20 years. The NRC staff analyzed in detail, and 

resolved, those environmental issues that could be resolved generically in the GEIS. The NRC 

originally issued the GEIS in 1996, issued Addendum 1 to the GEIS in 1999, and issued 

Revision 1 to the GEIS in 2013. Unless otherwise noted, all references to the GEIS include 

Addendum 1 and Revision 1 to the GEIS.

The GEIS establishes separate environmental impact issues for the NRC staff to independently 

verify. Of these issues, the NRC staff determined that some issues are generic to all plants 

(Category 1). Other issues do not lend themselves to generic consideration (Category 2 or 

uncategorized). The NRC staff evaluated these issues on a site-specific basis in the SEIS. 

Appendix B to Subpart A of 10 CFR Part 51 summarizes the NRC staff’s findings in the GEIS.

For each potential environmental issue, the NRC staff does the following in the GEIS:

• describes the activity that affects the environment;

• identifies the population or resource that is affected;

• assesses the nature and magnitude of the impact on the affected population 

or resource;

• characterizes the significance of the effect for both beneficial and adverse 

effects;

• determines whether the results of the analysis apply to all plants; and

• considers whether additional mitigation measures would be warranted for 

impacts that would have the same significance level for all plants.

The NRC established its standard of significance for impacts using the Council on 

Environmental Quality 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.

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.
Introduction

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

applied to all plants and whether additional mitigation measures would be warranted. Issues 

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

issues are those that meet the following criteria:

• 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.

• 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).

• 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. The process for identifying new and 

significant information for site-specific analysis is presented in Chapter 4. Site-specific issues 

(Category 2) are those that do not meet one or more of the criteria of Category 1 issues; 

therefore, additional site-specific review for these issues is required. A site-specific analysis is 

required for 17 of those 78 issues evaluated in the GEIS. Figure 1–2 illustrates this process. 

The results of that site-specific review are documented in the SEIS.
Introduction

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Figure 1–2. Environmental Issues Evaluated for License Renewal

1.5 Supplemental Environmental Impact Statement

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

operation of LSCS, alternatives to license renewal, and mitigation measures for minimizing 

adverse environmental impacts. Chapter 4 contains analysis and comparison of the potential 

environmental impacts from alternatives. Chapter 5 presents the NRC’s recommendation on 

whether the environmental impacts of license renewal are so great that preserving the option of 

license renewal would be unreasonable. The final recommendation considered comments 

received on the draft SEIS during the public comment period.

In the preparation of the SEIS for LSCS, the NRC staff carried out the following activities:

• reviewed the information provided in Exelon’s ER;

• consulted with Federal, State, Tribal, and local agencies; 
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• conducted an independent review of the issues during site audit; and

• considered the public comments received for the review (during the scoping

process) and received on the draft SEIS.

New information can be identified from many 

sources, including the applicant, the NRC, other 

agencies, or public comments. If a new issue is 

revealed, it is first analyzed to determine whether 

it is within the scope of the license renewal 

environmental evaluation. If the new issue is not 

addressed in the GEIS, the NRC staff would 

determine the significance of the issue and 

document the analysis in the SEIS.

1.6 Decisions to Be Supported by the SEIS

The decision to be supported by the SEIS is whether to renew the operating licenses for LSCS

for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103(a)(5), as 

follows:

In making a final decision on a license renewal action pursuant to Part 54 

of this chapter, the Commission shall determine whether or not the 

adverse environmental impacts of license renewal are so great that 

preserving the option of license renewal for energy planning 

decisionmakers would be unreasonable.

There are many factors that the NRC takes into consideration when deciding whether to renew 

the operating license of a nuclear power plant. The analyses of environmental impacts 

evaluated in this GEIS will provide the NRC’s decisionmaker (in this case, the Commission) with 

important environmental information for use in the overall decisionmaking process. There are 

also decisions outside the regulatory scope of license renewal that cannot be made on the basis 

of the GEIS analysis. These decisions include the following issues: changes to plant cooling 

systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and security, 

need for power, and seismicity and flooding (NRC 2013).

1.7 Cooperating Agencies

During the scoping process, no Federal, State, or local agencies were identified as cooperating 

agencies in the preparation of this SEIS.

1.8 Consultations

The Endangered Species Act of 1973, as amended (ESA) (16 U.S.C. 1531 et seq.); the

Magnuson–Stevens Fisheries Conservation and Management Act of 1996, as amended (MSA) 

(16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 

(NHPA) (54 U.S.C. 300101 et seq.), require Federal agencies to consult with applicable State 

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

fisheries, or historic and archaeological resources, respectively. The NRC consulted with the 

following agencies and groups; Appendix C provides a discussion of the consultation 

documents:

• U.S. Fish and Wildlife Service (FWS);

New and significant information. To merit 

additional review, information must be both 

“new” and “significant” (i.e., presenting a 

seriously different picture of the impacts from 

those envisioned in the GEIS) and bear on 

the proposed action or its impacts.
Introduction

1-7

• Illinois Historic Preservation Agency;

• Advisory Council on Historic Preservation;

• Ho-Chunk Nation;

• Miami Tribe of Oklahoma;

• Peoria Tribe of Indians of Oklahoma;

• Citizen Potawatomi Nation;

• Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki Nation;

• Sac and Fox Nation of Missouri in Kansas and Nebraska;

• Sac and Fox Nation;

• Pokagon Band of Potawatomi;

• Forest County Potawatomi;

• Hannahville Indian Community, Band of Potawatomi;

• Prairie Band Potawatomi Nation;

• Winnebago Tribe of Nebraska;

• Kickapoo Tribe in Kansas; and

• Kickapoo Tribe of Oklahoma.

1.9 Correspondence

During the course of the environmental review, the NRC staff contacted Federal, State, regional, 

local, and Tribal agencies listed in Section 1.8. Appendix C lists the correspondence associated 

with the ESA, MSA, and NHPA. Appendix D lists all other correspondence.

1.10 Status of Compliance

Exelon is responsible for complying with all applicable NRC regulations and other applicable 

Federal, State, and local requirements. Appendix F of the GEIS describes some of the major 

applicable Federal statutes. There are numerous permits and licenses issued by Federal, 

State, and local authorities for activities at LSCS. Appendix B contains further information about 

LSCS’s status of compliance.

1.11 Related Federal and State Activities

The NRC reviewed the possibility that activities of other Federal agencies might impact the 

renewal of the operating licenses for LSCS. There are no Federal projects that would make it 

necessary for another Federal agency to become a cooperating agency in the preparation of 

this SEIS. 

There are no known American Indian lands within 50 miles (mi) (80 kilometers (km)) of the 

LSCS. There are three Federally owned facilities within 50 mi (80 km) of the LSCS: (1) Fermi 

National Accelerator Laboratory, (2) Argonne National Laboratory, and (3) Joliet Army 

Ammunition Plant.
Introduction

1-8

Section 102(2)(C) of NEPA requires the NRC to consult with, and obtain comments from, any 

Federal agency that has jurisdiction by law or special expertise with respect to any 

environmental impact involved in the subject matter of the SEIS. For example, during the 

course of preparing the SEIS, the NRC consulted with the FWS. Appendix C lists all

consultation correspondences.

1.12 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.”

80 FR 5793. U.S. Nuclear Regulatory Commission. “LaSalle County Station, Units 1 and 2,

notice of intent to prepare an environmental impact statement and conduct the scoping process; 

public meetings and request for comment.” Federal Register 80(22):5793–5795.

February 3, 2015.

80 FR 5822. U.S. Nuclear Regulatory Commission. “LaSalle County Station, Units 1 and 2, 

license renewal application; opportunity to request a hearing and to petition for leave to 

intervene.” Federal Register 80(22):5822–5825. February 3, 2015.

81 FR 7378. U. S. Nuclear Regulatory Commission. “License Renewal Application for LaSalle 

County Station, Units 1 and 2.” Federal Register 81(28) 7378-7379. February 11, 2016.

81 FR 8490. U.S. Environmental Protection Agency. “Environmental Impact Statements; Notice 

of Availability.” Federal Register 81(33) 8490-84. February 19, 2016.

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

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

[Exelon] Exelon Generation Company, LLC. 2014a. Applicant’s Environmental Report—

Operating License Renewal Stage, LaSalle County Station. Exelon. December 9, 2014. 

Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 

ML14343A897.

[Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 

County Station, Units 1 and 2. Exelon. December 9, 2014. ADAMS No. ML14343A849. 

Magnuson–Stevens Fishery Conservation and Management Act of 1996, as amended. 

16 U.S.C. § 1801 et seq.

National Environmental Policy Act of 1969, as amended. 42 U.S.C. § 4321 et seq.

National Historic Preservation Act of 1966, as amended. 16 U.S.C. § 470 et seq.

[NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement

for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG–1437, 

Volumes 1 and 2. May 31, 1996. ADAMS Nos. ML040690705 and ML040690738.

[NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3—Transportation, Table 9.1, 

“Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants.”

In: Generic Environmental Impact Statement for License Renewal of Nuclear Plants. 

Washington, DC: NRC. NUREG–1437, Volume 1, Addendum 1. August 1999. ADAMS 

No. ML040690720.
Introduction

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[NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement

for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG–1437, Revision 1,

Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023.

[NRC] U.S. Nuclear Regulatory Commission. 2015a. Letter from B.D. Wittick (NRC), Branch 

Chief, to M.P. Gallagher (Exelon). Subject: Issuance of Scoping Summary Report Associated 

with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental 

Review (TAC Nos. MF5567 and MF5568). July 2, 2015. ADAMS No. ML15147A380.

[NRC] U.S. Nuclear Regulatory Commission. 2015b. Letter from B.D. Wittick (NRC), Branch 

Chief, to M.P. Gallagher (Exelon). Subject: Summary of the License Renewal Environmental 

Audit for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5567 and MF5568). 

May 20, 2015. ADAMS No. ML15132A674.

[NRC] U. S. Nuclear Regulatory Commission. 2016. Generic Environmental Impact Statement

for License Renewal of Nuclear Plants, Supplement 57, Regarding LaSalle County Station, 

Units 1 and 2, Draft Report for Comment. NUREG–1437, Supplement 57. February 2016. 

ADAMS No. ML16033A103.

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2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION

Although the U.S. Nuclear Regulatory Commission’s (NRC’s) decisionmaking authority in 

license renewal is limited to deciding whether or not to renew a nuclear power plant’s operating 

license, the NRC’s implementation of the National Environmental Policy Act of 1969 (NEPA), as 

amended (42 U.S.C. 4321 et seq.), requires consideration of the environmental impacts of 

potential alternatives to renewing a plant’s operating license. While the ultimate decision about 

which alternative (or the proposed action) to carry out falls to operator, state, or other non-NRC 

Federal officials, comparing the environmental impacts of renewing the operating license to the 

environmental impacts of alternatives allows the NRC to determine whether the environmental 

impacts of license renewal are so great that preserving the option of license renewal for 

energy-planning decisionmakers would be unreasonable (Title 10 of the Code of Federal 

Regulations (10 CFR) 51.95(c)(4)).

Energy-planning decisionmakers and owners of the nuclear power plant ultimately decide 

whether the plant will continue to operate, and economic and environmental considerations play 

important roles in this decision. In general, the NRC’s responsibility is to ensure the safe 

operation of nuclear power facilities and not to formulate energy policy or encourage or 

discourage the development of alternative power generation. The NRC does not engage in 

energy-planning decisions and makes no judgment as to which energy alternatives evaluated 

would be the most likely alternative in any given case.

The remainder of this chapter provides (1) a description of the proposed action, (2) a description 

of alternatives to the proposed action (including the no-action alternative), and (3) alternatives to 

LaSalle County Station, Units 1 and 2 (LSCS) license renewal that were considered and 

eliminated from detailed study. Chapter 4 of this plant-specific supplemental environmental 

impact statement (SEIS) compares the impacts of renewing the operating licenses of LSCS and 

continued plant operations to the environmental impacts of alternatives.

2.1 Proposed Action

As stated in Section 1.1 of this document, the NRC’s proposed Federal action is the decision of 

whether to renew the LSCS operating licenses for an additional 20 years. For the NRC to 

determine the impacts from continued operation of LSCS, an understanding of that operation is 

needed. Section 2.1.1 describes normal power plant operations during the license renewal 

term. LSCS is a two-unit, nuclear-powered steam-electric generating facility that began 

commercial operation in January 1984 (Unit 1) and October 1984 (Unit 2). The nuclear reactors 

at both units are General Electric boiling water reactors (BWRs), and together they produce an 

annual average net output of 2,327 megawatts electric (MWe) (Exelon 2014).

2.1.1 Plant Operations during the License Renewal Term

Most plant operation activities during license renewal would be the same as, or similar to, those 

occurring during the current license term (NRC 2013). Section 2.1.1 of NUREG–1437, Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS), 

Revision 1 (NRC 2013), describes the general types of activities that are carried out during the 

operation of a nuclear power plant, such as LSCS, as follows:

• reactor operation;

• waste management;
Alternatives Including the Proposed Action

2-2

• security;

• office and clerical work;

• surveillance, monitoring, and maintenance; and

• refueling and other outages.

As stated in the Exelon Generation Company, LLC’s (Exelon’s) Environmental Report (ER)

(Exelon 2014), LSCS will continue to operate during the license renewal term in the same 

manner as it does during the current license term except for, as appropriate, additional aging 

management programs to address structure and component aging in accordance with 

10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants.”

2.1.2 Refurbishment and Other Activities Associated with License Renewal

Refurbishment activities include replacement and repair of major systems, structures, and 

components. For example, replacement activities may include replacement of recirculation 

piping systems for BWRs. The intent of the major refurbishment class of activities characterized 

in the GEIS (NRC 2013) is to encompass actions that typically take place only once in the life of 

a nuclear plant, if at all. Refurbishment activities may have an impact on the environment 

beyond those that occur during normal operations and may require evaluation depending on the 

type of action and the plant-specific design.

In preparation for its license renewal application, Exelon performed an evaluation of LSCS

structures, systems, and components in accordance with 10 CFR 54.21, “Contents of 

application—technical information,” to identify whether any major refurbishment activities would 

be necessary to support the continued operation of LSCS during the proposed 20-year period of 

extended operation (Exelon 2014).

Exelon did not identify any major refurbishment or replacement activities needed to support the 

continued operation of LSCS beyond the existing operating license term (Exelon 2014). 

Therefore, these activities are not discussed under the proposed action in Chapter 4.

2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning after the 

License Renewal Term

NUREG–0586, Generic Environmental Impact Statement on Decommissioning of Nuclear 

Facilities: Supplement 1, Regarding the Decommissioning of Nuclear Power Reactors, Final 

Report, describes the impacts of decommissioning (NRC 2002). Most activities associated with 

plant operations would cease with reactor shutdown. Some activities (e.g., security and 

oversight of spent nuclear fuel) would remain unchanged, whereas others (e.g., waste 

management; office and clerical work; laboratory analysis; and surveillance, monitoring, and 

maintenance) would continue at reduced or altered levels. Systems dedicated to reactor 

operations would cease operations; however, impacts from their physical presence may 

continue if they are not removed after reactor shutdown. For multiple-unit sites, such as LSCS, 

if one unit is shut down, then shared systems may operate at reduced capacities. Impacts 

associated with dedicated systems that remain in place or shared systems that continue to 

operate at normal capacities would remain unchanged.

Decommissioning will occur whether LSCS is shut down at the end of its current operating 

license term or at the end of the period of extended operation. There are no site-specific issues 

related to decommissioning. The license renewal GEIS concludes that license renewal would 

have a negligible (SMALL) effect on the impacts of terminating operations and decommissioning 

on all resources.
Alternatives Including the Proposed Action

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2.2 Alternatives

As stated above, the NRC has the obligation to consider reasonable alternatives to the 

proposed action of renewing the licenses for the nuclear reactors at LSCS. To be reasonable, a 

replacement power alternative must be commercially viable on a utility scale and operational 

prior to the expiration of the reactor’s operating licenses, or expected to become commercially 

viable on a utility scale and operational prior to the expiration of the reactor’s operating licenses 

(NRC 2013). The 2013 GEIS update incorporated the latest information on replacement power 

alternatives; however, rapidly evolving technologies are likely to outpace the information 

presented in the GEIS. As such, a site-specific analysis of alternatives must be performed for 

each SEIS, taking into account changes in technology and science since the preparation of the 

GEIS.

Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 

not issue renewed licenses for LSCS). Sections 2.2.2.1–2.2.2.5 describe the characteristics of 

replacement power alternatives for LSCS.

2.2.1 No-Action Alternative

At some point, operating nuclear power plants will terminate operations and undergo 

decommissioning. The no-action alternative represents a decision by the NRC not to renew the 

operating license of a nuclear power plant beyond the current operating license term. Under the 

no-action alternative, the NRC does not renew the operating licenses, and the LSCS plant shuts 

down at or before the end of the current licenses in 2022 and 2023. After shutdown, plant 

operators will initiate decommissioning in accordance with 10 CFR 50.82, “Termination of 

License.”

Only those impacts that arise directly as a result of plant shutdown will be addressed in this 

SEIS. The environmental impacts from decommissioning and related activities are addressed in 

several other documents, including the decommissioning GEIS (NRC 2002); the license renewal 

GEIS, Chapter 4 (NRC 2013); and Chapter 4 of this SEIS. These analyses either directly 

address or bound the environmental impacts of decommissioning whenever Exelon ceases to 

operate LSCS.

Even with renewed operating licenses, LSCS will eventually shut down, and the 

environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time. 

As with decommissioning impacts, shutdown impacts are expected to be similar whether they 

occur at the end of the current license term or at the end of a renewed license term.

Termination of operations at LSCS would result in the total cessation of electrical power 

production. Unlike the alternatives described in Section 2.2.2, the no-action alternative does not 

meet the purpose and need of the proposed action because it does not provide a means of 

delivering utility scale power to meet future electric system needs. Given the current need for 

the power generated by LSCS, the no-action alternative would likely create a need for a 

replacement power alternative. A full range of replacement power alternatives (including new 

nuclear, fossil fuels, and renewable energy sources) are described in the following section, and 

their potential impacts are assessed in Chapter 4. Although the NRC’s authority only extends to 

the decision of whether to renew the LSCS operating licenses, the replacement power 

alternatives described in the following sections represent possible options for energy-planning 

decisionmakers should the NRC choose not to renew the LSCS operating licenses.
Alternatives Including the Proposed Action

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2.2.2 Replacement Power Alternatives

In evaluating alternatives to license renewal, the NRC considered energy technologies or 

options currently in commercial operation, as well as technologies not currently in commercial 

operation but likely to be commercially available by the time the current LSCS operating 

licenses expire. The current operating licenses for the LSCS, Units 1 and 2, expire on 

April 17, 2022, and December 16, 2023, respectively. Alternatives that are not likely to be 

constructed, permitted, and connected to the grid by the time the LSCS licenses expire were 

eliminated from detailed consideration.

Alternatives that cannot provide the equivalent of LSCS’s current generating capacity and, in 

some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 

reasonable alternatives, were not considered in detail. Each alternative removed from detailed 

study is briefly discussed, and the basis for its removal is provided in Section 2.3. In total, 

17 alternatives to the proposed action were considered (see text box) and then narrowed to the 

5 alternatives considered in Sections 2.2.2.1–2.2.2.5. The NRC staff evaluated the 

environmental impacts of these five alternatives and the no-action alternative. They are 

discussed in depth in Chapter 4 of this SEIS.

The GEIS presents an overview of some energy technologies but does not reach conclusions 

about which alternatives are most appropriate. Because many energy technologies are 

continually evolving in capability and cost and because regulatory structures have changed to 

either promote or impede development of particular alternatives, the analyses in this chapter 

may include updated information from the following sources:

• U.S. Department of Energy (DOE), U.S. Energy Information Administration (EIA),

• other offices within the DOE,

• U.S. Environmental Protection Agency (EPA),

• industry sources and publications, and

• information submitted by Exelon in its ER.

The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 

impacts across several impact categories: land use and visual resources, air quality and noise, 

geologic environment, water resources, ecological resources, historic and cultural resources, 

socioeconomics, human health, environmental justice, and waste management. Most 

site-specific issues (Category 2) have been assigned a significance level of SMALL, 

MODERATE, or LARGE. For ecological and historic and archaeological resources, the impact 

significance determination language is specific to the authorizing legislation (e.g., Endangered 

Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), and National Historic Preservation 

Act of 1966, as amended (16 U.S.C. 470 et seq.)). The order of presentation of the alternatives

is not meant to imply increasing or decreasing level of impact. Nor does it imply that an 

energy-planning decisionmaker would be more likely to select any given alternative.

To ensure that the alternatives analysis is consistent with state or regional energy policies, the 

NRC reviewed energy-related statutes, regulations, and policies within the LSCS region. As a 

result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 

as well as a combination that includes both of them.

Region of Influence

LSCS is owned and operated by Exelon and provides electricity to the region of influence (ROI) 

through transmission lines owned by Commonwealth Edison (ComEd) (Exelon 2014). ComEd 
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operates under the PJM Interconnection, LLC 

(PJM), a regional transmission organization 

that coordinates the movement of wholesale 

electricity in 13 states across the Midwest 

and Northeast (Exelon 2014). ComEd 

provides service to 3.8 million customers

across northern Illinois. Its service territory 

borders Iroquois County to the south, the 

Wisconsin border to the north, the Iowa 

border to the west, and the Indiana border to 

the east (ComEd 2015). However, electricity 

consumption in Illinois is not limited to 

electricity that is generated within the State. 

Although northern Illinois relies on electricity 

from ComEd, the rest of Illinois and 

surrounding states, which are not part of the 

PJM, are part of the Midcontinent 

Independent System Operator, Inc. (MISO) 

(see Figure 2–1) (Exelon 2014).

If renewed licenses were not issued, 

replacement power for LSCS would be 

required in northern Illinois. Electricity could 

be replaced by generation sources from a variety of locations. Electricity could be transported 

from within the PJM; however, the PJM in Illinois is geographically distant from the rest of the 

PJM region (see Figure 2–1). It is also possible that electricity within MISO could be purchased 

by PJM, and efforts are currently being made to increase coordination and deliverability 

between the regional transmission organizations (Ott 2013b). In addition, the State of Illinois 

has a renewable portfolio standard that includes a stipulation that eligible renewable resources 

must be procured from facilities located in Illinois or the States that adjoin Illinois (Wisconsin, 

Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable resources can be 

obtained only from other regions of the country if they are not available in Illinois or in the 

adjoining States (ILGA 2011).

Because replacement power would be required in northern Illinois, and any renewable energy 

resources would need to be procured from facilities in Illinois or the adjoining States, the NRC 

staff evaluated the impacts of locating replacement power facilities within the States of Illinois, 

Indiana, Iowa, Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the 

ROI for the NRC staff’s analysis of alternatives. The NRC assumes that replacement power 

would either be produced in northern Illinois within the PJM region or would be purchased by 

PJM from MISO.

In 2012, electric generators in the ROI had a net summer generating capacity of approximately 

179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 

(27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c).

In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 

(MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 

nuclear (21 percent). Although natural gas makes up nearly 30 percent of the installed 

generating capacity in the ROI, it provides only 6 percent of electricity in the region. 

Nonhydroelectric renewable energy produced 1.3 percent of the electricity in the ROI 

(EIA 2014b).

Alternatives Evaluated in Depth:

• new nuclear

• coal-integrated gasification combined-cycle

• natural gas combined-cycle

• combination alternative (wind power, natural 

gas combined-cycle, and solar power)

• purchased power

Other Alternatives Considered:

• energy efficiency and conservation

• supercritical pulverized coal

• wind power

• solar power

• hydroelectric power

• wave and ocean energy

• geothermal power

• municipal solid waste

• biomass

• oil-fired power

• fuel cells

• delayed retirement
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Figure 2–1. Territories of MISO and PJM Interconnection

Source: MISO-PJM undated

Renewable Energy Legislation in the Region of Influence

Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 

States; therefore, any legislation targeting renewable energy in these States could impact a 

State’s incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 

Missouri, Wisconsin, and Michigan) have legally mandated renewable energy programs. The 

State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 

energy requirements. The paragraphs below briefly outline each State’s program, including 

renewable energy goals and benchmarks.

In August 2007, Illinois adopted a renewable portfolio standard that requires the State’s utilities 

to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 

which must come from wind. Solar PV must comprise 6 percent of the annual requirement for 

calendar year 2015 and thereafter. Other eligible sources include biomass and existing 

hydroelectric power (DSIRE 2015a). The law also includes an energy efficiency standard that 

requires utilities to implement cost-effective energy efficiency measures to meet energy savings 

of 2 percent by calendar year 2016 and thereafter (ILGA 2011). For electric utilities (including 

ComEd), eligible resources must be located in Illinois; resources can be purchased from 

adjoining States only if there are insufficient in-State resources (ILGA 2011).

Iowa’s Alternative Energy Production Law requires the State’s two investor-owned utilities to 

generate a combined total of 105 MW of their generating capacity from renewable energy 

sources. A 2007 order allows the utilities to participate in renewable energy credit trading 

programs by distinguishing between renewable electricity production capacity used to comply 

with Iowa law and that which can be used to satisfy other states’ renewable portfolio standards 

(DSIRE 2014).

Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 

increase their use of renewable sources by 15 percent by 2021 and includes a provision 

specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 

energy. Resources can be purchased from outside Missouri, but renewable energy generated 

in-State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2015b).
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Wisconsin’s renewable portfolio standard requires utilities to produce 10 percent of their 

electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 

provision that allows electricity providers to create and sell or transfer renewable resource 

credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 

eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2015c).

Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 

10 percent of their retail electricity sales from renewable energy resources by 2015. 

The standard also allows energy efficiency and advanced cleaner energy systems to meet part 

of the requirement. Renewable energy credits can be purchased from in-State or out-of-State 

facilities, provided that the facilities are located within the retail electric service territory of a 

utility that is recognized by the Michigan Public Service Commission (DSIRE 2015d).

Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 

July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 

10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 

2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 

coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 

electricity from coal, and net-metered distributed generation facilities. Fifty percent of qualifying 

energy must come from within the State. Utilities that participate in the program and meet the 

program goals are eligible for incentives that are used to pay for the compliance projects

(DSIRE 2015e).

Kentucky is the only State in the ROI that does not have mandatory or voluntary renewable 

energy requirements.

Given known technological and demographic trends, the EIA predicts that 34 percent of 

electricity in the United States will be generated by coal in 2040 (EIA 2015). Natural gas 

generation rose from 16 percent in 2000 to 27 percent in 2013 and is projected to increase to 

31 percent in 2040 (EIA 2013a, 2015). Electricity generation from renewable energy is 

expected to grow from 13 percent of total generation in 2013 to 18 percent in 2040 (EIA 2015). 

However, there are uncertainties that could affect this forecast, particularly the implementation 

of policies aimed at reducing greenhouse gas emissions, which would have a direct effect on 

fossil fuel-based generation technologies.

The remainder of this section describes replacement power alternatives to license renewal

considered in depth. These include a new nuclear alternative in Section 2.2.2.1; a 

coal-integrated gasification combined-cycle (IGCC) alternative in Section 2.2.2.2; a natural gas 

combined-cycle (NGCC) alternative in Section 2.2.2.3; a combination natural gas, wind, and 

solar power alternative in Section 2.2.2.4; and a purchased power alternative in Section 2.2.2.5. 

Table 2–1 summarizes key design characteristics of the alternative technologies evaluated in 

depth. The environmental impacts of these alternatives are evaluated in Chapter 4.
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2-8

Table 2–1. Summary of Replacement Power Alternatives and 

Key Characteristics Considered in Depth(a)

New Nuclear 

Alternative IGCC Alternative NGCC Alternative

Combination 

Alternative

Summary of 

Alternative

Two-unit nuclear 

plant, each with 

1,120 MWe, for a total 

of 2,240 MWe

Four 618-MWe units, 

for a total of 

2,472 MWe

Five 560-MWe 

units, for a total of 

2,800 MWe

One 360 MWe 

NGCC unit; a 

1,813 MWe wind 

farm; and a 

227 MWe installed 

solar PV facility, for 

a total of 

2,400 MWe

Location An existing nuclear 

plant site or retired 

coal plant site outside 

Illinois. New 

transmission line(s) 

and other 

infrastructure 

upgrades may be 

required. Some 

facilities (e.g., support 

buildings, potable 

water supply, and 

sanitary discharge

structures) could be 

shared with existing 

plant.

On the LSCS site or 

at another existing 

power plant site. 

New transmission 

line(s) and other 

infrastructure 

upgrades may be 

required. Some 

facilities (e.g., support 

buildings, potable 

water supply, and 

sanitary discharge

structures) could be 

shared with existing 

plant.

On the LSCS site. 

New transmission 

line(s) and other 

infrastructure 

upgrades may be 

required; would 

require construction 

of a new or 

upgraded pipeline. 

Some facilities 

(e.g., support 

buildings, potable 

water supply, and 

sanitary discharge

structures) could be 

shared with existing 

plant.

The NGCC 

component would 

be located on the 

LSCS site. The 

wind and solar 

components would 

be spread across 

multiple sites 

throughout the ROI.

Cooling 

System

Closed-cycle with 

natural draft cooling 

towers. Cooling 

water withdrawal—

56 mgd; consumptive 

water use—42 mgd 

(NRC 2008).

Closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—25 mgd; 

consumptive water 

use—20 mgd 

(NETL 2013a).

Closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—

17 mgd; 

consumptive water 

use—13 mgd 

(NETL 2013a).

For the NGCC 

portion, 

closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

would be 

15 percent of that 

required for NGCC 

alternative. Minimal 

water use for wind 

and solar.

Land 

Requirements

556 ac (225 ha) 

(NRC 2008); 

520 ac (210 ha) for 

uranium mining and 

processing(b)

(NRC 2013)

2,000 ac (800 ha) for 

the major permanent 

facilities; 1,100 ac 

(450 ha) per year for 

mining (DOE 2010a)

94 ac (38 ha) for 

the plant, including 

pipelines 

(Exelon 2014); 

10,080 ac 

(4,079 ha) for gas 

extraction and 

collection 

(NRC 1996)

Wind farms would 

require 3,376 ac 

(1,366 ha) to 10,127 ac 

(4,098 ha) (WAPA and 

FWS 2013); solar PV 

facilities would require

7,397 ac (2,993 ha) 

(NRC 2013). For the 

NGCC portion, land use 

would remain the same 

at 94 ac (38 ha) 

(Exelon 2014).
Alternatives Including the Proposed Action

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New Nuclear 

Alternative IGCC Alternative NGCC Alternative

Combination 

Alternative

Work Force 3,500 workers 

during peak 

construction; 

812 workers during 

operations 

(NRC 2008)

4,600 workers 

during peak 

construction; 

420 workers during 

operations 

(DOE 2010a)

1,783 workers 

during peak 

construction; 

94 workers during 

operations 

(Exelon 2014)

Solar PV—600 workers 

during peak 

construction, 60 workers 

during operations 

(DOE 2010b). Wind—

931 workers during 

construction, 

566 workers during 

operations (DOE 2008). 

NGCC—number of 

construction and 

operations workers 

would be less than the 

NGCC alternative but 

would not be a linear 

reduction because of the 

need for a minimum 

number of workers 

regardless of the size of 

the plant.

Key: ac = acres, ha = hectares, IGCC = coal-integrated gasification combined-cycle (alternative), mgd = million 

gallons per day, MWe = megawatts electric, NGCC = natural gas combined-cycle (alternative), PV = photovoltaic, 

and ROI = region of influence.

(a) Because of the speculative nature of using purchased power to replace LSCS capacity and because of the 

inherent variability of characteristics associated with such an approach, this table does not include the purchased 

power alternative.

(b) This is normalized to model the light water reactor annual fuel requirement. Forty-two percent of this land 

requirement is temporarily committed land.

Sources: DOE 2008, 2010a, 2010b; Exelon 2014; NETL 2013a; NRC 1996, 2008, 2013; Ong et al. 2013; WAPA 

and FWS 2013

2.2.2.1 New Nuclear Alternative

In this section, the NRC staff describes the new nuclear alternative. The NRC staff evaluates 

the environmental impacts from this alternative in Chapter 4.

The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 

to license renewal. For example, nuclear generation currently provides 21 percent of electricity 

generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; of these, 

nine plants have received renewed licenses, and two plants have applied for renewed licenses 

from the NRC (including LSCS) (NRC 2015). In addition, there is interest in new nuclear power 

plant development in the region; combined operating license (COL) applications have been filed 

for two new nuclear power plants in the ROI. On July 24, 2008, Union Electric Company 

submitted a COL application for Callaway Plant, Unit 2, in Callaway County, Missouri, on the 

existing Callaway site (AmerenUE 2009). However, Ameren UE has since announced that they 

are canceling their COL application (Barker 2015). An application was also filed in 

September 2008 for Enrico Fermi Atomic Power Plant, Unit 3, in Monroe County, Michigan, on 

the existing Fermi site. On May 1, 2015, the NRC issued a COL authorizing DTE Electric 

Company to build and operate an economic simplified BWR at the Fermi site (Volume 80 of the 
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Federal Register, 26302 (80 FR 26302)). The NRC staff determined that there may be sufficient 

time for Exelon to prepare and submit an application, build, and operate two new nuclear units 

using a certified design before the LSCS licenses expire in April 2022 and December 2023. 

In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 

would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 

existing ancillary facilities at those locations, such as support buildings and transmission 

infrastructure. In 1987, Illinois enacted a moratorium preventing the construction of new nuclear 

power plants within the State. Until the moratorium is lifted, a new nuclear alternative would 

require siting elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the 

Vogtle Electric Generating Plant (Vogtle), Units 3 and 4 (located in Waynesboro, Georgia), COL 

environmental impact statement for technological parameters for the new nuclear alternative

because the Vogtle, Units 3 and 4, COL considers two new nuclear reactor units with a similar 

output as LSCS and is representative of the reactors that could be constructed in the ROI 

before LSCS’s licenses expire (NRC 2011). As such, the NRC staff assumed 

two Westinghouse AP1000 reactors with a net electrical output of 2,240 MWe would replace 

LSCS’s current reactors for this alternative. The NRC staff estimated that 324 ac (131 ha) of 

land would be required on a long-term basis because of permanent facilities, and an additional 

232 ac (94 ha) would be disturbed for temporary facilities, a laydown area, and storage of 

dredge material (NRC 2008).

The heat rejection demands of a new nuclear alternative would be similar to those of LSCS. 

The new reactors may require a new cooling system (including natural draft cooling towers and 

intake and discharge structures). The NRC staff assumes that water requirements for the new 

nuclear alternative would be similar to current water use at LSCS. A new onsite transmission 

line and drinking water wells may be required if insufficient infrastructure occurs on the site. 

Construction materials would be delivered by a combination of rail spur, truck, and barge, 

depending on the specific site location. It is possible that modifications would be required to 

deliver such materials, depending on the existing infrastructure at the site; modifications could 

include new rail lines or access roads.

The NRC staff also considered the installation of multiple small modular reactors as an 

alternative to renewing the LSCS licenses. The NRC established the Advanced Reactor 

Program in the Office of New Reactors because of considerable interest in small modular 

reactors along with anticipated license applications by vendors. Small modular reactors are 

approximately 300 MW or less, would have lower initial capacity than that of large-scale units, 

and would have siting flexibility for locations that are not large enough to accommodate 

traditional nuclear reactors (DOE undated). As of October 2015, no applications for small 

modular reactors have been submitted to the NRC. The DOE has estimated that the technology 

may achieve commercial operation by 2021 to 2025 (DOE undated). Because small modular 

reactors are not expected to be operational at a commercial scale until near the time LSCS’s 

licenses expire, it is unlikely that eight new small modular reactors (the number of units required 

to replace LSCS’s current output) could be constructed in the ROI; therefore, this analysis 

focuses on nuclear generation by larger nuclear units.

2.2.2.2 IGCC Alternative

In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 

environmental impacts from this alternative in Chapter 4.

Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 

49 percent of installed generation capacity and accounted for 67 percent of all electricity 

generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 

and combines modern coal gasification technology with both gas-turbine and steam-turbine 
Alternatives Including the Proposed Action

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power generation. The technology is cleaner than conventional pulverized coal plants because 

some of the major pollutants are removed from the gas stream before combustion. An IGCC 

power plant consists of coal gasification and combined-cycle power generation. Coal gasifiers 

convert coal into a gas (synthesis gas, also referred to as syngas), which fuels the 

combined-cycle power generating units. The combined-cycle system for a 618-MWe IGCC 

power plant includes two combustion turbines, two heat recovery steam generators, and a 

steam turbine. The combined-cycle units combust gas in one or more combustion turbines, and 

the resulting hot exhaust gas is then used to heat water into steam to drive a steam turbine. 

The steam turbine then uses the heat from the gas turbine’s exhaust through a heat recovery 

steam generator to produce additional electricity (DOE 2010a). This two-cycle process has a 

high rate of efficiency because the exhaust heat that would otherwise be lost is captured and 

reused. In addition, the power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and 

particulate emissions by removing constituents from the syngas before combustion. Nearly 

100 percent of the nitrogen from the syngas would be removed before combustion in the gas 

turbines and would result in lower nitrogen oxide emissions compared to conventional coal-fired 

power plants (DOE 2010a).

IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 

repowering project in Indiana and the Polk Power Station in Florida are two examples of 

operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 

and multiple new projects have been proposed or have recently begun operations in the 

United States. The Duke Energy Edwardsport Generation Station (Edwardsport) in Indiana is a 

618-MWe IGCC power plant in the ROI that began commercial operation in June 2013. Duke 

Energy estimates that the IGCC plant will produce 10 times as much power as the retired coal 

plant it replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and 

particulates. The IGCC plant will reduce carbon emissions per megawatt hour by nearly half 

compared to conventional coal-fired plants (Duke Energy 2013). In addition, Edwardsport has 

the potential for carbon capture and geologic sequestration. Space has been reserved at the 

site for carbon dioxide capture equipment (NETL 2013b).

Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 

reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 

proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 

carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 

Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 

active; these projects are in the planning stages, or they have begun construction. 

Thirteen projects have been proposed and subsequently canceled for a variety of reasons, 

including air quality issues, state laws and regulations, redirected focus on gas-fired generation 

and renewables, and unanticipated rising costs (NETL 2013c).

IGCC technology and proposed projects have experienced a number of setbacks and 

opposition, hindering IGCC’s ability to fully integrate into the energy market. The most 

significant roadblock is IGCC’s high capital cost compared to conventional coal-fired power 

plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 

Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 

support because of escalating cost estimates (Reuters 2012). Other issues include construction 

timeline overruns, a limited track record for reliable performance, and opposition from an 

environmental perspective.

Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 

staff considers IGCC technology to be a reasonable source of baseload power to replace LSCS

by the time its licenses expire in 2022 and 2023 because of the current regulatory framework 

and the number of active IGCC plants within the ROI. On August 3, 2015, EPA signed a final 
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rule for carbon pollution that would apply to new fossil fuel-fired power plants 

(80 FR 64661-65120). The action establishes performance standards for utility boilers and 

IGCC units based on partial implementation of a CCS system as a method of emission 

reduction. The emission limit for these sources is 1,305 lb carbon dioxide per megawatt hour 

(CO2/MWh), and any new coal-fired power plants could require CCS in order to achieve this

emission limit. 

Overall, the NRC staff considers IGCC power plants as an alternative to LSCS because the 

Edwardsport IGCC project in Indiana is currently in operation and because the Kemper County 

IGCC project in Mississippi is under construction. The technology parameters for these plants 

are considered the current state of technology and are used here to describe a hypothetical 

IGCC power plant located on an existing power plant site within the ROI.

To replace the electricity that LSCS generates, the NRC staff considered four IGCC units, each 

with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 

the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 

would burn a sub-bituminous coal based on the type of coal used in electric plants in Illinois. 

The NRC staff presumes that coal burned in Illinois will be representative of coal that would be 

burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 

units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 

removing constituents from the syngas. In addition, the units would be designed with the 

potential to add CCS later. Using CCS, carbon dioxide emission would be compressed and 

piped off site where it could be sold for beneficial use or geologic storage. 

The IGCC alternative would be located at an existing site (such as an existing power plant site) 

to maximize availability of infrastructure and to reduce other environmental impacts. Depending 

on the specific site location, there might be a need to construct new intake and discharge

facilities and a new cooling system. The IGCC alternative would use about the same amount of 

water as LSCS and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 

that the cooling system would use a closed-cycle system with mechanical draft cooling towers. 

This system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of 

water and would consume 20 million gpd (76 million Lpd). Onsite visible structures could 

include the boilers, exhaust stacks, intake and discharge structures, mechanical draft cooling 

towers, transmission lines, and an electrical switchyard. Construction materials would be 

delivered by a combination of rail spur, truck, and barge, depending on the specific site location. 

Modifications may be required to deliver such materials; modifications could include new rail 

lines or access roads.

The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 

renewing the LSCS licenses. SCPC was dismissed as the coal alternative because of new 

regulations aimed at limiting the environmental impacts from conventional pulverized coal 

plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC 

for analysis.

2.2.2.3 NGCC Alternative

In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 

environmental impacts from this alternative in Chapter 4.

Natural gas represents nearly 30 percent of installed generation capacity in the ROI but 

provides only 6 percent of all electrical power in the ROI (EIA 2014b, 2014c). Nationwide, the 

percentage of power generated by natural gas is expected to rise through 2040, although the 

actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 

NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 
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license renewal because it is a feasible, commercially available option for providing electrical 

generating capacity beyond the expiration of LSCS’s current licenses.

Baseload NGCC power plants have proven their reliability and can have capacity factors as high 

as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 

natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 

steam generator to produce additional electricity. This two-cycle process has a high rate of 

efficiency because the exhaust heat that would otherwise be lost is captured and reused. Like 

other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 

carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 

gases per unit of electrical output than conventional coal-powered plants.

To replace the electricity that LSCS generates, the NRC staff considered five NGCC units, each 

with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 

configuration consists of two combustion turbine generators, two heat recovery steam 

generators, and one steam turbine generator with mechanical draft cooling towers for heat

rejection. The power plant is assumed to incorporate a selective catalytic reduction system to 

minimize the plant’s nitrogen oxide emissions (NETL 2007).

This 2,800-MWe NGCC plant would consume 124 billion cubic feet (3,500 million cubic meters) 

of natural gas annually, assuming an average heat content of 1,021 British thermal units per 

cubic foot (EIA 2013c). Natural gas would be extracted from the ground through wells, and then 

it would be treated to remove impurities and blended to meet pipeline gas standards before 

being piped through the State pipeline system to the plant site. This NGCC alternative would 

produce relatively little waste, primarily in the form of spent catalysts used for control of nitrogen 

oxide emissions.

The NGCC alternative would be located on undeveloped land at LSCS to maximize availability 

of infrastructure and to reduce other environmental impacts. Depending on the specific site 

location, there might be a need to construct new intake and discharge facilities and a new 

cooling system. Because NGCC power plants generate much of their power from a gas-turbine 

combined-cycle plant and because the overall thermal efficiency of this type of plant is high, an 

NGCC alternative would require less cooling water than LSCS would. This system would 

withdraw 17 million gpd (64 million Lpd) of water and would consume 13 million gpd 

(49 million Lpd). The NRC staff assumes that the cooling system would use a closed-cycle

system with mechanical draft cooling towers. Onsite visible structures could include the cooling 

towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 

pipelines, and an electrical switchyard. Construction materials could be delivered by a 

combination of rail spur, truck, and barge. Modifications may be required to deliver such 

materials; modifications could include new rail lines or access roads.

2.2.2.4 Combination Alternative (NGCC, Wind, and Solar)

In this section, the NRC staff describes the combination alternative to the continued operation of 

LSCS consisting of an NGCC facility constructed at an existing power plant site and operating in 

conjunction with land-based wind farms and solar energy facilities, all of which would be located 

within the ROI. The NRC staff evaluates the environmental impacts from this alternative in 

Chapter 4.

To serve as an effective baseload power alternative to the LSCS reactors, this combination 

alternative must be capable of providing an equivalent amount of baseload power. For the 

purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar PV

facilities would comprise the combination alternative.
Alternatives Including the Proposed Action

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NGCC Portion of the Combination Alternative

To produce its required share of power (360 MWe), the NGCC portion, operating at an expected 

capacity factor of 85 percent (NETL 2007), would need to have a nameplate rating of 

approximately 425 MWe.

In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 

shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 

than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 

used for these “peaker plants” because natural gas combustion turbines can respond quickly; 

therefore, they tend to be used to meet short-term increases in electricity demand (EIA 2013d). 

A report prepared by CITI Research stated that gas-fired power plants can help overcome the 

intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 

gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 

combination alternative.

The NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would 

be constructed and installed at LSCS with a total net capacity of 360 MWe. The appearance of 

an NGCC unit would be similar to that of the full NGCC alternative considered in 

Section 2.2.2.3, although only one unit would be constructed. The NRC staff assumes that the 

NGCC portion of this alternative, which is assumed to be located at LSCS, would use existing 

electrical switchyards, substations, and transmission lines. Depending on the existing site 

conditions, it is possible that intake and discharge structures of the existing cooling system

could continue in service but would be connected to a new closed-cycle cooling system. For the 

purposes of this analysis, the NRC staff assumes that the NGCC portion of the combination 

would use mechanical draft cooling towers.

Wind Portion of the Combination Alternative

The NRC staff assumes that the wind-generated power from this combination alternative would 

come from land-based wind farms, which would be located in the ROI within the States of 

Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming 

a capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 

FWS 2013).

The American Wind Energy Association reports a total of more than 67,000 MW of installed 

wind energy capacity nationwide as of June 30, 2015 (DOE 2015). As of June 2015, Texas is 

by far the leader in installed land-based capacity with 15,635 MW. Two States in the ROI have 

the third and fifth largest installed capacity: Iowa with 5,708 MW, followed by Illinois with 

3,667 MW (DOE 2015). The installed wind capacity in the ROI has been increasing annually by 

1,000 MWe to 2,500 MWe in each of the past 8 years, for a total of over 13,000 MWe of 

additional wind capacity from 2007 to 2014 (DOE 2015). Therefore, the NRC staff considers 

6,042 MW of wind energy to be a reasonable amount by the time the LSCS licenses expire in 

2022 and 2023. As is the case with other renewable energy sources, the feasibility of wind 

resources serving as alternative baseload power is dependent on the location (relative to 

expected load centers), value, accessibility, and constancy of the resource. Wind energy must 

be converted to electricity at or near the point where it is extracted, and there are limited energy 

storage opportunities available to overcome the intermittency and variability of wind resources. 

At the current stage of wind energy technology development, wind resources in wind power 

class 3 and higher are suitable for most utility scale applications (NREL 2014a). Wind power 

class 3 is defined as having a wind speed of 15.7 miles per hour (7.0 meters per second) and a 

wind density of 500 watts per square meter at 164 ft (50 m) (NREL 2014a). Each State in the 

ROI, other than Kentucky, has wind resources meeting this power class, with the highest 

concentrations occurring in Iowa and Illinois (NREL 2015a).
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Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 2010. The size 

of turbine most frequently installed in the United States in recent years is the 1.5-MW turbine 

(WAPA and FWS 2013). For the purposes of this analysis, the NRC staff assumes wind 

turbines with a capacity of 1.79 MW. The capacity factors of land-based wind farms are lower 

than offshore wind farms (WAPA and FWS 2013). For the wind portion of the combination 

alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an estimated 

total net capacity of 1,813 MWe. Wind turbines must be well separated from each other to 

avoid interferences to wind flowing through the wind farm, resulting in wind farms requiring 

substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 1.2 ha) of 

land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and amount of 

land required between each turbine, approximately 3,376 turbines and 3,376 to 10,127 ac 

(1,366 to 4,098 ha) would be required for the wind portion of the combination alternative.

Wind energy’s intermittency affects its viability and value as a baseload power source. 

However, the variability of wind-generated electricity can be lessened if the proposed wind 

farms were located at a large distance from one another and were operated as interconnected 

wind farms, an aggregate controlled from a central point. Distance separation increases the 

probability that power will be produced at some of the wind farms at any given time (Archer and 

Jacobson 2007).

Solar Photovoltaic Portion of the Combination Alternative

The solar portion of the combination alternative would be generated through one or more solar 

PV energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the solar 

energy facilities would need a collective nameplate rating of 1,193 MWe. Solar PV technologies 

could be installed on building roofs at existing residential, commercial, or industrial sites or at 

larger standalone solar facilities.

Nationwide, growth in large solar PV facilities (greater than 5 MW) has resulted in an increase 

from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it is 

estimated that more than 11,000 MW of large solar PV projects have signed power purchase 

agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 50 MW or 

greater, although most are located in the southwestern United States (Mendelsohn et al. 2012). 

As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have renewable 

energy legislation that includes requirements for solar PV technology. Missouri’s renewable 

portfolio standard includes a provision specifying that 2 percent of the renewable portfolio 

standard requirement must be met by solar energy by 2021. Illinois’ renewable portfolio 

standard specifies that solar PV must comprise 6 percent of the annual requirement for 

compliance year 2015–2016 and thereafter. As of 2012, only 33 MW of solar energy capacity

had been installed in the ROI (EIA 2014c).

Solar PV resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter per day 

(kWh/m2

/day). The most viable solar resources are located in Missouri, Iowa, and southern 

Illinois and Indiana (NREL 2015b). Economically viable solar resources are considered to be 

6.75 kWh/m2

/day and greater (BLM and DOE 2010). As is the case with wind energy sources, 

the feasibility of solar energy resources serving as alternative baseload power is dependent on 

the location, value, accessibility, and constancy of the resource. Solar PV uses solar panels to 

convert solar radiation into usable electricity. Solar cells are formed into solar panels that can 

then be linked into PV arrays to generate electricity. The electricity generated can be stored, 

used directly, fed into a large electricity grid, or combined with other electricity generators as a 

hybrid plant. Solar PV can generate electricity whenever there is sunlight, regardless of 

whether the sun is directly shining on solar panels. Therefore, solar PV technologies do not 

need to directly face and track the sun, which has allowed solar PV systems to have broader 
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geographical use than concentrated solar power (Ardani and Margolis 2011). Because the ROI 

contains average solar PV resources and because solar PV is a commercially available option 

for providing electrical generating capacity, the NRC staff considers the construction of solar PV

facilities to be a reasonable alternative to license renewal when combined with wind and NGCC.

For the purposes of this analysis, the NRC staff assumes solar PV facilities with a capacity 

factor of 19 percent (Ardani and Margolis 2011). Solar PV facilities may require 5.7 ac (2.3 ha)

of land per megawatt. Although not all of this land would be cleared of vegetation and 

permanently impacted, it represents the land enclosed in the total site boundary of the solar 

facility (Ong et al. 2013). For the solar portion of this combination alternative, approximately 

6,749 ac (2,731 ha) would be required to support an installed net capacity of 227 MWe. In this 

analysis, the NRC staff does not speculate on the number and size of individual solar facilities, 

nor their locations within the ROI. However, as stated above, some of the output could be 

realized by solar PV installations on building roofs at existing residential, commercial, or 

industrial sites or at larger standalone solar facilities. To the extent that rooftop or 

building-integrated solar PV installations remain popular, land impacts would be relatively minor. 

Solar PV systems do not require water for cooling purposes, but a small amount of water is 

needed to clean the panels and for potable water for the workforce. Impacts identified in the 

U.S. Department of the Interior Bureau of Land Management (BLM) and DOE’s Solar Energy 

Programmatic Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012) provide 

information used in the analyses presented in the impact sections in Chapter 4.

2.2.2.5 Purchased Power Alternative

In this section, the NRC staff describes purchased power as an alternative to the continued 

operation of LSCS.

The impacts from purchased power would depend substantially on the generation technologies 

used to supply the purchased power. Impacts from operation of other electricity generators 

would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for LSCS

would be required in northern Illinois and could come from anywhere within Illinois or adjoining 

states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 

geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 

staff considers purchased power to be a feasible source of baseload power to replace LSCS by 

the time the licenses expire in 2022 and 2023.

Purchased power would likely come from the most common types of electricity generation within 

the ROI: coal, natural gas, nuclear, and wind. All these power sources are discussed as 

alternatives to license renewal of LSCS and are identified in Sections 2.2.2.2 to 2.2.2.4. 

Construction and operational impacts from these sources of electricity generation are 

considered in Chapter 4. Purchased power may require new transmission lines (which may 

require new construction) and may also rely on older and less-efficient power plants operating at 

higher capacities than they currently operate or on new facilities that would be constructed. 

During operations, impacts from nuclear, coal-fired, and natural gas-fired plants and from wind

and solar energy projects would be similar to those described under the new nuclear, coal, 

natural gas, and combination alternatives described in Chapter 4 for all resource areas.

2.3 Alternatives Considered but Dismissed

Alternatives to LSCS license renewal that were considered and eliminated from detailed study 

are presented in this section. These alternatives were eliminated because of technical resource 

availability or current commercial limitations. Many of these limitations would continue to exist 

when the current LSCS licenses expire.
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2.3.1 Energy Conservation and Energy Efficiency

Energy conservation can include reducing energy demand through behavioral changes or 

altering the shape of the electricity load and usually does not require the addition of new 

generating capacity. Conservation and energy efficiency programs are more broadly referred to 

as demand-side management.

Conservation and energy efficiency programs can be initiated by a utility, transmission 

operators, the state, or other load-serving entities. The State of Illinois’ renewable portfolio 

standard includes an energy efficiency portfolio standard that requires utilities to reduce electric 

usage by 2 percent of demand by 2015 (DSIRE 2015a), which is equivalent to 4 million MWh, 

only 20 percent of the amount that would be required to offset LSCS’s current electrical 

generation.

In general, residential electricity consumers have been responsible for the majority of peak load 

reductions, and participation in most programs is voluntary. Therefore, the existence of a 

program does not guarantee that reductions in electricity demand would occur. The GEIS

concludes that, although the energy conservation or energy efficiency potential in the 

United States is substantial, there are likely no cases where an energy efficiency or 

conservation program has been implemented expressly to replace or offset a large baseload 

generation station (NRC 2013). Although significant energy savings are possible in the ROI 

through demand-side management and energy efficiency programs, conservation and energy 

efficiency programs are not likely to replace LSCS as a standalone alternative; therefore, the 

NRC staff does not consider conservation and energy efficiency to be a reasonable alternative 

to license renewal.

2.3.2 Solar

Solar power, including solar PV and concentrated solar power technologies, produce power 

generated from sunlight. PVs convert sunlight directly into electricity using solar cells made 

from silicon or cadmium telluride. Concentrating solar power uses heat from the sun to boil 

water and produce steam to drive a turbine connected to a generator to produce electricity 

(NREL 2014b). To be considered a viable alternative, a solar alternative must replace the 

amount of electricity LSCS provides. Assuming a capacity factor of 19 percent (Ardani and 

Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 

energy facilities in the seven-State ROI.

In 2012, 33 MW of solar energy capacity was installed in the ROI (EIA 2014c). The DOE’s 

National Renewable Energy Laboratory (NREL) reports that the States in the ROI receive solar 

insolation of 4.0 to 5.0 kWh/m2

/day, which is considered low to average (NREL 2015b). For 

utility-scale development, insolation levels below 6.5 kWh/m2

/day are not considered 

economically viable given current technologies (BLM and DOE 2010). There is more potential 

for solar development using local PV applications, such as rooftop solar panels, than through 

utility-scale solar facilities. In addition, a solar facility can only generate electricity when the sun 

is shining. Energy storage can be used to overcome intermittency for concentrating solar power 

facilities; however, current and foreseeable storage technologies that have been paired with 

solar power facilities have a much smaller capacity than would be necessary to replace LSCS. 

Taking all of the factors above into account, it is unlikely that solar PV or concentrated solar 

power technologies could serve as baseload power in the ROI to replace LSCS’s current 

electricity output. Given the modest levels of solar energy available throughout the ROI, the 

lack of substantial installed solar capacity in the ROI and the weather-dependent intermittency 

of solar power, the NRC staff concludes that a solar power energy facility in the ROI would not 
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be a reasonable alternative to license renewal. The NRC staff described an alternative of solar 

power in combination with wind and an NGCC plant in Section 2.2.2.4.

2.3.3 Wind

Two States in the ROI have the third and fifth largest installed capacity in the Nation: Iowa with 

5,708 MW, followed by Illinois with 3,667 MW (DOE 2015). The installed wind capacity in the 

ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 8 years, for 

a total of over 13,000 MWe of additional wind capacity from 2007 to 2014 (DOE 2015). All of 

the wind energy facilities and the electricity generation from wind currently being produced in 

the ROI are land based. To be considered a viable alternative, a wind alternative must replace 

the amount of electricity LSCS provides. Assuming a capacity factor of 30 percent for 

land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 

would need to be generated by some combination of land-based and offshore wind energy 

facilities in the seven-State ROI.

As is the case with other renewable energy sources, the feasibility of wind resources serving as 

alternative baseload power is dependent on the location (relative to expected load centers), 

value, accessibility, and constancy of the resource. Wind energy must be converted to 

electricity at or near the point where it is extracted, and there are limited energy storage 

opportunities available to overcome the intermittency and variability of wind resource availability. 

Although wind power is intermittent and although individual facilities are unable to provide 

baseload power, it has been proposed that multiple interconnected wind installations separated 

by long distances could theoretically function as a virtual power plant and could provide 

baseload power since individual facilities would be exposed to different weather and wind 

conditions. To date, however, no states or utilities operate arrays of wind installations as virtual 

power plants.

Given the amount of wind capacity necessary to replace LSCS and the intermittency of wind 

power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 

the NRC staff also concludes that, when used in combination with other technologies with 

inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 

described such a possible combination alternative in Section 2.2.2.4.

2.3.3.1 Offshore Wind

The United States does not have any offshore wind farms in operation; however, approximately 

20 projects representing more than 2,000 MW of capacity are in the planning and permitting 

process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 

Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 

depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 

Ram 2010).

Although wind data suggest a potential for offshore wind farms in the Great Lakes, project costs 

likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 

(Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 

300 percent higher than land-based systems. In addition, based on current prices for wind 

turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 

above the current production costs from existing power generation facilities. In addition to cost, 

other barriers include the immature status of the technology, limited resource area, and high

risks and uncertainty (Tidball et al. 2010). Because no offshore wind capacity yet exists in 

either the Great Lakes or on the Atlantic Coast and because none appears likely to exist on a 

large commercial scale in the Great Lakes by 2022 (given the current state of development), the 

NRC staff finds that offshore wind will not be a reasonable alternative to LSCS.
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2.3.3.2 Wind Power with Storage

Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 

facilities, compressed air energy storage (CAES) is the technology most suited for storage of 

large amounts of energy. In CAES systems, electricity generated during low-demand periods 

can be stored by using a compressor to pressurize and store air; during high-demand periods, 

the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE report 

analyzed various power-generation sources, including wind, coupled with CAES systems 

(Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 

high voltage transmission, and a market for wholesale electric power and (2) availability of 

geology and wind resources. The results show that, within the ROI, the potential exists for 

one CAES site in northwestern Iowa. Without detailed wind-speed data, specific site 

information, and detailed information on the energy-storage capacity of the potential CAES site, 

estimating how much wind capacity would be necessary and determining whether it could 

provide for an all-wind alternative would be difficult. Furthermore, the NRC staff is not aware of 

a CAES project coupled with wind generation that is providing baseload power. Therefore, the 

NRC staff concludes that the use of CAES in combination with wind turbines to replace the 

LSCS power plant is unlikely.

2.3.3.3 Conclusion

Despite the relatively high reliability demonstrated by modern turbines, the recent technological 

advancements in turbine design and wind farm operation, and wind energy’s dramatic market 

penetrations of recent years, empirical data on wind farm capacity factors and wind energy’s 

limited ability to store power for delayed production of electricity cause the NRC staff to 

conclude that wind energy—on shore, off shore, or a combination thereof—could not serve as a 

discrete alternative to the baseload power supplied by the LSCS reactors. However, the NRC 

staff also concludes that, when used in combination with other technologies with inherently 

higher capacity factors, wind energy can provide a viable alternative. The NRC staff described 

such a possible combination alternative in Section 2.2.2.4.

2.3.4 Biomass

Biomass resources used for biomass-fired generation include agricultural residues, animal 

manure, wood wastes from forestry and industry, residues from food and paper industries, 

municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 

biomass-fired generation for baseload power depends on the geographic distribution, available 

quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 

NRC staff assumed that biomass would be combusted for power generation in the electricity 

sector. Biomass is also used for space heating in residential and commercial buildings and can 

be converted to a liquid form for use in transportation fuels (Haq undated).

In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 

could operate with capacity factors between 70 and 80 percent (NRC 2013). Although the ROI 

currently produces electricity from biomass fuels, the plants operating within the ROI generated 

less than 1 percent of the total power generation in 2011 (EIA 2014b). Based on the relatively 

low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 

the construction of several new biomass plants, could increase capacity by adding 2,327 MWe

of electricity from biomass-fired generation by the time LSCS’s licenses expire in 2022 and 

2023.

For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 

used for biomass conversion would be similar to fossil fuel plants, including the direct 

combustion of biomass in a boiler to produce steam (NRC 2013). Biomass generation is 
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generally more cost-effective when co-fired with coal plants (IEA 2007). Biomass-fired 

generation plants generally are small and can reach capacities of 50 MWe, which means that 

more than 40 new facilities would be required before the LSCS licenses expire. After 

reevaluating current technologies, the NRC staff finds biomass-fired alternatives as still unable 

to reliably replace the LSCS capacity. For this reason, the NRC staff does not consider 

biomass to be a reasonable alternative to LSCS license renewal.

2.3.5 Hydroelectric

Hydroelectric power uses the force of water to turn turbines that spin a generator to produce 

electricity. In a run-of-the-river system, the force of a river current provides the force to create 

the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 

created by dams and is released as needed to generate electricity.

The DOE’s Idaho National Environmental Engineering Laboratory (now Idaho National 

Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 

hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 

institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 

cultural, historical, and geological values, (2) Federal and state land use, and (3) legal 

protection issues, such as wild and scenic legislation and threatened or endangered fish and 

wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 

do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 

(ORNL 2012). These nonpowered dams serve various purposes, such as providing water 

supply to inland navigation.

The EIA reported that the States comprising the ROI generated 2,262 MW of electricity from 

hydroelectric power in 2012 (EIA 2014c). In order to replace LSCS’s current output, 

hydroelectric generation across the ROI would need to double by 2022. Although there is 

potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 

that the maximum levels of development would occur across the entire ROI by the time LSCS’s 

licenses expire in 2022 and 2023 because the generating capacity of hydroelectric power is 

projected to continue to decrease through 2040 (EIA 2013b). Given the decrease in projected 

power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 

power to be a reasonable alternative to license renewal.

2.3.6 Wave and Ocean Energy

Waves, currents, and tides are often predictable and reliable, making them attractive candidates 

for potential renewable energy generation. Four major technologies may be suitable to harness 

wave energy: terminator devices that range from 500 kilowatts to 2 MW, attenuators, point 

absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 

floating buoys to convert wave motion into mechanical energy, driving a generator to produce 

electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 

surface; waves then enter a tube and compress air that is used to drive a generator that 

produces electricity (NRC 2013). Some designs are undergoing demonstration testing at 

commercial scales, but none are currently used to provide baseload power (BOEM undated).

The Great Lakes do not experience large tides, and there is limited energy output for wave 

technologies in the Great Lakes. The Electric Power Research Institute (EPRI) published a 

document that assessed ocean wave energy resources in the United States. The Great Lakes 

were not included in the analysis, suggesting that the resource potential is not great enough to 

use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 
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infancy of the technologies in the Great Lakes support the NRC staff’s conclusion that wave and 

ocean energy technologies are not feasible substitutes for LSCS.

2.3.7 Fuel Cells

Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 

fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 

only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide

(depending on hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 

hydrocarbon resources. Natural gas is a typical hydrogen source.

Fuel cells are not economically or technologically competitive with other alternatives for 

electricity generation. EIA projects that fuel cells may cost $6,835 per installed kilowatt (total 

overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 

analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 

(approximately 10 MWe). Replacing the power LSCS provides would be extremely costly; it 

would require the construction of approximately 230 units and modifications to the existing 

transmission system. Given the immature status of fuel cell technology and high cost, the NRC 

staff does not consider fuel cells to be a reasonable alternative to LSCS license renewal.

2.3.8 Delayed Retirement

A delayed retirement alternative would consider deferring the retirement of generating facilities 

in Illinois and its six adjoining states that include MISO and PJM RTOs.

To maintain reliable operations, electric systems must be able to meet peak load requirements. 

To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013). 

The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 

requirement of 17.4 percent. However, recent EPA regulations may lead to increased coal plant 

retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 

retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 

below the reserve margin requirement (MISO 2011).

PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 

regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 

major population centers within the PJM region in the near future (Ott 2013a). Because the 

current generation mix has not resulted in the long-term commitment of generation needed for 

reliability, generation retirements that have occurred with short notice have created 

unanticipated reliability problems for PJM (Ott 2013a).

The EIA expects that more coal plant retirements will occur before 2016 than those previously 

predicted. These accelerated retirements are driven by low natural gas prices, slow growth in 

electricity demand, and the requirements of the Mercury and Air Toxics Standards that will 

require significant reductions in plant emissions (EIA 2014a, EPA 2015). Exelon also expects 

increased generation retirements for a variety of reasons, including increased operating costs 

for older facilities, increased environmental regulations and competition, and decreased load 

(Exelon undated). As generators are required to adhere to future regulations, some power 

plants may opt for early retirement of older units rather than incur the cost for compliance. 

Exelon has further stated that some of their nuclear fleet may be retired early because of low 

wholesale energy prices and current energy policy (Associated Press 2015). Because of the 

uncertain regulatory environment and concerns expressed by MISO and PJM concerning the 

retirement pace of coal power plants, the NRC staff does not consider delayed retirement to be 

a reasonable alternative to LSCS license renewal.
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2.3.9 Geothermal

Geothermal technologies extract the heat contained in geologic formations to produce steam to 

drive a conventional steam turbine generator. Facilities producing electricity from geothermal 

energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 

a potential source of baseload electric power. However, the feasibility of geothermal power 

generation to provide baseload power depends on the regional quality and accessibility of 

geothermal resources. Utility-scale geothermal energy generation requires geothermal 

reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 

300 kilowatts electric to 50 MWe and greater (TEEIC undated). Geothermal resources are 

concentrated in the western United States. Specifically, these resources are found in Alaska, 

Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 

Washington, and Wyoming. In general, most assessments of geothermal resources have been 

concentrated on these western states (DOE 2013b; USGS 2008). Geothermal resources are 

used in the ROI for heating and cooling purposes, but no electricity is currently being produced 

from geothermal resources in the ROI (EIA 2014c). Given the low resource potential in the ROI, 

the NRC staff does not consider geothermal to be a reasonable alternative to license renewal.

2.3.10 Municipal Solid Waste

Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 

heat, electricity, or fuel through combustion (EPA 2014b). The three types of combustion 

technologies include mass burning, modular systems, and refuse-derived fuel systems 

(EPA 2014a). Mass burning is the method used most frequently in the United States. The heat 

released from combustion is used to convert water to steam, which is used to drive a turbine 

generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 

captured through a filtering system (EPA 2014a). As of 2010, approximately 

86 waste-to-energy plants are in operation in 25 states, processing more than 28 million tons of 

waste per year (EPA 2014b). These waste-to-energy plants have an aggregate capacity of 

2,720 MWe, and although some plants have expanded to handle additional waste and produce 

more energy, no new plants have been built in the United States since 1995 (EPA 2014b). The 

average waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can 

operate at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste 

recovery facility that produces steam; Iowa has one waste-to-energy facility that produces 

10 MW of electricity; Michigan has three facilities that produce 89.7 MW of electricity; and 

Wisconsin has two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 

2010, the ROI had a municipal solid waste generating capacity of 132 MW. More than 

46 average-sized plants would be necessary to provide the same level of output as LSCS, 

almost doubling the national waste-to-energy generation.

The decision to burn municipal waste to generate energy is usually driven by the need for an 

alternative to landfills rather than energy considerations. Given the improbability that additional 

stable supplies of municipal solid waste would be available to support approximately 46 new 

facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 

municipal solid waste combustion to be a reasonable alternative to LSCS license renewal.

2.3.11 Petroleum

In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014c).

The variable costs of oil-fired generation tend to be greater than those of the nuclear or 

coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 
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natural gas-fired generation. The high cost of oil relative to natural gas has resulted in a steady 

decline in its use for electricity generation (EIA 2013a). Given the high cost of oil and the small 

generating capacity from oil-fired power plants in the ROI, the NRC staff does not consider 

oil-fired generation a reasonable alternative to LSCS license renewal.

2.3.12 Supercritical Pulverized Coal

In general, SCPC power plants are feasible, commercially available options for providing 

electrical generating capacity. Baseload coal units have proven their reliability and can sustain

capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 

that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 

to spin one or more turbines to generate electricity. Among the technologies available, 

pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 

for new coal-fired plants given their high operating temperatures and pressures that increase 

thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 

reducing environmental impacts (NETL undated).

As described in Section 2.2.3, EPA has signed a final rule for carbon pollution that would apply 

to new fossil fuel-fired power plants, including SCPC facilities (80 FR 64661–65120). The 

action establishes performance standards and has identified a CCS system as a method of 

emission reduction. The emission limit for these sources of 1,305 lb CO2/MWh, and any new 

coal-fired power plants could require CCS in order to achieve this emission limit.

In addition, given known technology and technological and demographic trends, EIA predicts 

that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 

(EIA 2013a). This does not consider the EPA rule described above but indicates a general 

trend away from coal-fired facilities in favor of natural gas-fired power plants due to falling 

natural gas prices. MISO projected that the EPA regulations could lead to increased coal plant 

retirements and estimated retirements between 3,000 MW to 12,600 MW, which could have a 

large impact on MISO’s reserve margin in the future (MISO 2011).

Although SCPC plants are currently the most widely used source of electricity generation within 

the ROI, given the potential for stringent air quality regulations and trends toward natural 

gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 

LSCS license renewal. Instead, the NRC staff describes an IGCC plant under the coal 

alternative in Section 2.2.2.2.

2.4 Comparison of Alternatives

In this chapter, the NRC staff considered the following alternatives to LSCS license renewal: 

new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 

natural gas, wind, and solar; and purchased power. The NRC also considered the no-action

alternative and its effects. The impacts for all alternatives to LSCS license renewal are 

discussed in Chapter 4 and displayed in Table 2–2 below.

The environmental impacts of license renewal and alternatives to license renewal, including 

other methods of power generation, and not renewing the LSCS operating licenses (the 

no-action alternative) were evaluated in the final SEIS. With the exception of aquatic and 

socioeconomic impacts, not renewing the operating license and shutting down LSCS would 

have SMALL impacts on all other resource areas. MODERATE impacts could occur in the 

cooling pond, because as water temperatures decline in the cooling pond, some fish 

populations such as stocked recreational species that thrived in warmer waters may experience 

population declines. Therefore, aquatic impacts could range from SMALL to MODERATE. 
Alternatives Including the Proposed Action

2-24

Socioeconomic impacts in local communities from the loss of jobs and tax revenue after LSCS 

shutdown could range from SMALL to LARGE.

With the exception of aquatic resources, the continued operation of LSCS during the license 

renewal term would have SMALL environmental impacts. Impacts on aquatic resources were 

SMALL, except for thermal impacts on gizzard shad and threadfin shad in the cooling pond. 

Impacts on these fish were MODERATE. Fish kills in the LSCS cooling pond would continue 

during the license renewal term and would decrease the shad population in the pond

immediately following the fish kill. This would have a noticeable effect on threadfin shad and 

gizzard shad populations. Fish kills, however, would not be destabilizing to these shad 

populations, because they tend to recover within a year. Because the cooling pond is a highly 

managed system, any cascading effects resulting from the loss of shad (such as a reduction in 

prey for stocked species, which in turn could affect a stocked species’ population) could be 

mitigated through the Illinois Department of Natural Resource’s annual stocking and continual 

management of the pond. Therefore, the impact on aquatic resources from the proposed action 

is SMALL to MODERATE.

The environmentally preferred alternative is the granting of a renewed license for LSCS. All 

other alternatives capable of meeting the needs currently served by LSCS entail potentially 

greater impacts than those of the proposed action of renewing the license for LSCS. To make 

up the lost power generation if a renewed license is not issued (the no-action alternative), one 

or a combination of alternatives would be implemented, all of which have greater impacts than 

the proposed action. Hence, the NRC staff concludes that the no-action alternative will have 

environmental impacts greater than or equal to those of the proposed license renewal action.
2-25

Table 2–2. Environmental Impacts of the Proposed Action and Alternatives

Impact Area 

(Resource)

LSCS

License 

Renewal 

(Proposed 

Action) No-Action7

New Nuclear 

Alternative

IGCC 

Alternative

NGCC 

Alternative

Combination 

Alternative 

(NGCC, Wind

and Solar)

Land Use SMALL SMALL SMALL TO 

MODERATE

SMALL TO 

LARGE

SMALL TO 

MODERATE

SMALL TO 

MODERATE

Visual Resources SMALL SMALL SMALL TO 

MODERATE

SMALL SMALL SMALL TO 

LARGE

Air Quality SMALL SMALL SMALL MODERATE MODERATE SMALL 

Noise SMALL SMALL SMALL SMALL TO 

MODERATE

SMALL SMALL TO 

MODERATE

Geologic 

Environment

SMALL SMALL SMALL SMALL SMALL SMALL 

Surface Water 

Resources

SMALL SMALL SMALL TO 

MODERATE

SMALL TO 

MODERATE

SMALL SMALL 

Groundwater 

Resources

SMALL SMALL SMALL SMALL SMALL SMALL 

Terrestrial Resources SMALL SMALL SMALL TO 

MODERATE

MODERATE 

TO LARGE

SMALL TO 

MODERATE

SMALL TO 

MODERATE

Aquatic Resources SMALL TO

MODERATE1

SMALL TO

MODERATE7

SMALL SMALL TO 

MODERATE

SMALL SMALL 

Special Status 

Species & Habitats

NO EFFECT SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 

Historic and 

Cultural Resources

SEE NOTE3 SMALL SMALL SMALL SMALL SMALL TO 

LARGE

Socioeconomics SMALL SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL 

Transportation SMALL SMALL SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

MODERATE

Human Health SMALL SMALL SMALL SMALL SMALL SMALL 
2-26

Impact Area 

(Resource)

LSCS

License 

Renewal 

(Proposed 

Action) No-Action7

New Nuclear 

Alternative

IGCC 

Alternative

NGCC 

Alternative

Combination 

Alternative 

(NGCC, Wind

and Solar)

Environmental 

Justice

SEE NOTE4 SEE NOTE5 SEE NOTE6 SEE NOTE6 SEE NOTE6 SEE NOTE6 

Waste Management 

and Pollution 

Prevention

SMALL SMALL SMALL SMALL TO 

MODERATE

SMALL SMALL 

Key: IGCC = coal-integrated gasification combined-cycle (alternative), NGCC = natural gas combined-cycle (alternative), NRHP 

Register of Historic Places, APE = area of potential effect, CRMP = Cultural Resource Management Plan, and IHPA = Illinois H

Preservation Agency.

(1) Thermal impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources 

MODERATE thermal impacts would primarily be experienced by gizzard and threadfin shad in the cooling pond.

(2) The magnitude of impacts could vary widely based on site selection and the presence or absence of special status species and 

alternative is implemented; therefore, the NRC staff cannot forecast a level of impact for this alternative.

(3) Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelon’s draft CRMP, (4) 

license renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource a

renewal would not affect any known historic properties (36 CFR 800.4(d)(1)).

(4) Continued operation of LSCS would not have disproportionately high and adverse human health and environmental effects on 

low-income populations.

(5) The no-action alternative could disproportionately affect minority and low-income populations.

(6) Based on this information and the analysis of human health and environmental impacts presented in this SEIS, it is not likely th

would have disproportionately high and adverse human health and environmental effects on minority and low-income populatio

determination would depend on the location, plant design, and operational characteristics of the alternative. Therefore, the NR

determine whether this alternative would result in disproportionately high and adverse human health and environmental effects 

low-income populations.

(7) Thermal impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources i

MODERATE impacts could occur in the cooling pond, because as water temperatures decline in the cooling pond, some fish po

stocked recreational species that thrived in warmer waters may experience population declines.
Alternatives Including the Proposed Action

2-27

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NREL/TP-6A20-56290. June 2013. 47 p. Available at 

<http://www.nrel.gov/docs/fy13osti/56290.pdf> (accessed 31 August 2015).

[ORNL] Oak Ridge National Laboratory. 2012. An Assessment of Energy Potential at 

Non-Powered Dams in the United States. Oak Ridge, Tennessee: ORNL. April 2012. 44 p. 

Available at <http://www1.eere.energy.gov/water/pdfs/npd_report.pdf> (accessed 

31 August 2015).

Ott A. 2013a. Centralized Capacity Markets in Regional Transmission Organizations and 

Independent System Operators. Norristown, Pennsylvania: PJM Interconnection, LLC. 

October 3, 2013. 33 p. Available at <http://www.pjm.com/~/media/about-pjm/who-weare/public-disclosures/

20131004-board-response-to-chairman-powelson-regarding-generation-retirements.ashx> 

(accessed 31 August 2015).

Ott A. 2013b. PJM/MISO Seams Coordination and Capacity Deliverability. Norristown, 

Pennsylvania: PJM Interconnection, LLC. June 20, 2013. 9 p. Available at 

<http://www.ferc.gov/industries/electric/indus-act/rto/pjm.pdf> (accessed 31 August 2015).

[Reuters] Thomson Reuters. 2012. “Southern, Duke push US coal gasification; others quit.” 

June 12, 2012. Available at <http://www.reuters.com/article/2012/06/12/

utilities-coal-gasification-idUSL1E8H78P420120612> (accessed 31 August 2015).

[TEEIC] Tribal Energy and Environmental Information Clearinghouse. Undated. “Utility-Scale 

and Direct Use Geothermal Energy Generation.” Available at 

<http://teeic.indianaffairs.gov/er/geothermal/restech/scale/index.htm> (accessed 

31 August 2015).

Tidball R, Bluestein J, Rodriguez N, Knoke S (ICF International). 2010. Cost and Performance 

Assumptions for Modeling Electricity Generation Technologies. Golden, Colorado: National 

Renewable Energy Laboratory. NREL/SR-6A20-48595. November 2010. 211 p. Available at 

<http://www.nrel.gov/docs/fy11osti/48595.pdf> (accessed 31 August 2015).

[USGS] U.S. Geological Survey. 2008. Assessment of Moderate- and High-Temperature 

Geothermal Resources of the United States. Menlo Park, California: USGS. Fact 

Sheet 2008-3082. 4 p. Available at <http://pubs.usgs.gov/fs/2008/3082/pdf/fs2008-3082.pdf> 

(accessed 31 August 2015).

[WAPA and FWS] Western Area Power Administration and U.S. Fish and Wildlife Service.

2013. Upper Great Plains Wind Energy Programmatic Environmental Impact Statement, Draft. 

DOE/EIS-0408. March 2013. 938 p. Available at 

<http://plainswindeis.anl.gov/documents/dpeis/Draft_UGP_Wind_Energy_PEIS.pdf> (accessed 

31 August 2015).

3-1

3.0 AFFECTED ENVIRONMENT

In this supplemental environmental impact statement (SEIS), the “affected environment” is the 

environment that currently exists at and around LaSalle County Station, Units 1 and 2 (LSCS). 

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 a discussion on how they have 

shaped the environment are presented here. The facility and its operation are described in 

Section 3.1. The affected environment is presented in Sections 3.2 to 3.13.

3.1 Description of Nuclear Power Plant Facility and Operation

LSCS is a two unit nuclear power plant located in LaSalle County, Illinois. It began commercial 

operation in January 1984 (Unit 1) and October 1984 (Unit 2). Generally, the U.S. Nuclear 

Regulatory Commission (NRC) staff drew information about LSCS’s facilities and operation from 

the Exelon Generation Company, LLC (Exelon), Environmental Report (ER) (Exelon 2014a).

3.1.1 External Appearance and Setting

The LSCS site is approximately 75 miles (mi) (120 kilometers (km)) southwest of downtown 

Chicago, Illinois, and approximately 26 mi (42 km) west of Exelon’s Braidwood Station in 

Braceville, Illinois, and 23 mi (37 km) southwest of the Dresden Nuclear Power Station near 

Morris, Illinois. Interstate Highway 80 is 8 mi (13 km) north of the site. Figure 3–1 presents the 

50-mi (80-km) area around LSCS.

The LSCS site is located in a rural and agricultural setting. However, the surroundings are 

dominated by many wind turbines, none of which is owned by Exelon. Each wind turbine is 

389 feet (ft) (119 meters (m)) tall (which includes the length of one of its three 126.5-ft (38.5-m) 

rotator blades). The town of Seneca lies 6 mi (10 km) northeast of LSCS. The town of 

Marseilles lies 7 mi (11 km) north-northwest of LSCS. The Illinois River is 5 mi (8 km) north of 

LSCS. The CSX Railroad, which runs parallel to, and slightly north of, the Illinois River, is the 

closest railroad line in this area. A 6-mi (10-km) rail spur connects LSCS to the Atchison, 

Topeka, and Santa Fe Railroad south of the site (Exelon 2014a). Figure 3–2 presents the 6-mi 

(10-km) area around LSCS.

The LSCS site is approximately 3,776 acres (ac) (1,528 hectares (ha)) of which approximately 

2,058 ac (833 ha) are the cooling pond. Underground pipelines approximately 3.5 mi (5.6 km) 

long connect the cooling pond to the Illinois River, which is the source of the plant’s makeup 

water and the receiving body of water for plant discharges. This pipeline corridor right-of-way

intersects the eastern portion of the Marseilles State Fish and Wildlife Area, which is managed 

by the Illinois Department of Natural Resources (IDNR) for hunting and wildlife habitat. County 

Road 6 (also known as North 21st Road) provides access to LSCS and runs along the site’s 

southern boundary (Exelon 2014a). Figure 3–3 presents the LSCS site layout.

The LSCS site’s main structures include two reactor buildings, an auxiliary building (which 

houses the control room), a turbine building, a diesel generator building, a switchyard, a training

building, an interim radioactive waste (radwaste) storage facility, a radwaste building, sewage 

and wastewater treatment facilities, and an independent spent fuel storage installation (ISFSI). 

The site’s tallest structure is a 400-ft (122-m) meteorological tower. The area of the LSCS site 

that is completely enclosed by physical barriers and that allows access only at designated 

control points is called the protected area. A physical protection program at the LSCS site 

includes surveillance, observation, and monitoring within the protected area (Exelon 2014a).

Figure 3–4 presents the LSCS plant features.
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3-2

Figure 3–1. LSCS 50-mi (80-km) Radius Map

Source: Exelon 2014a
Affected Environment

3-3

Figure 3–2. LSCS 6-mi (10-km) Radius Map

Source: Exelon 2014a
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3-4

Figure 3–3. LSCS Site Layout

Source: Exelon 2014a
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3-5

Figure 3–4. LSCS Plant Features

Source: Exelon 2014a
Affected Environment

3-6

3.1.2 Nuclear Reactor Systems

The nuclear reactor for each of the two LSCS units is a General Electric boiling water reactor

(BWR/5) with Mark II containment. Each LSCS reactor is licensed to produce core power of 

3,546 megawatts thermal. The annual mean net electrical power capacity for LSCS is 

2,327 megawatts electric. LSCS uses a 2,058-ac (833-ha) diked cooling pond for core cooling 

and holds appropriate permits to withdraw makeup water from, and discharges cooling pond 

blowdown water to the Illinois River (Exelon 2014a).

LSCS operates using low-enriched uranium dioxide fuel with enrichment not exceeding a 

nominal 5.0 percent by weight of uranium-235 and has been historically operated within a 

maximum analyzed fuel burnup rate of 62,000 megawatt-days per metric ton of 

uranium (MWd/MTU). In its ER, Exelon stated that, during some future fuel cycles, it expects 

the peak fuel burnup rate to exceed 62,000 MWd/MTU in some part-length fuel rods. 

Addendum 1 to Volume 1 of NUREG–1437, Generic Environmental Impact Statement for 

License Renewal of Nuclear Power Plants (GEIS) (NRC 1999), states that the environmental 

impacts would be small for transporting spent fuel enriched with up to 5-percent uranium-235 

with an average burnup for the peak rod of up to 62,000 MWd/MTU. It also states that, if peak 

fuel burnup is projected to exceed 62,000 MWd/MTU, license renewal applicants must submit 

an assessment of the implications for the environmental impacts. Exelon submitted an 

assessment of the environmental impacts of transporting spent fuel enriched with an average 

burnup for the peak rod exceeding 62,000 MWd/MTU in Section 4.13 of its ER. Appendix G of 

this document provides the NRC staff’s analysis of these projected environmental impacts. 

Refueling outages for LSCS, Units 1 and 2, are on a staggered 24-month schedule 

(Exelon 2014a).

3.1.3 Cooling and Auxiliary Water Systems

LSCS uses a closed-cycle, recirculating cooling system that includes an artificial cooling pond 

for heat dissipation. In this type of closed-cycle system, the cooling pond serves as the primary 

source of water to cool plant components and as the primary receiving body for excess heat. 

In BWRs like those used at LSCS, steam is produced directly in each reactor vessel. The 

steam passes through moisture separators and steam dryers and then flows to the turbine. 

Such systems contain only two heat transfer (exchange) loops. The primary loop transports the 

steam from the reactor vessel directly to the turbine, which generates electricity. The secondary 

cooling loop removes excess heat from the primary loop in the main condenser. From the 

condenser, the primary condensate is returned as feedwater to the reactor, and the secondary 

cooling loop removes the excess heat (NRC 2013). At LSCS, condenser cooling water is 

discharged directly to the cooling pond, where the heat is dissipated through mixing and 

evaporation (Exelon 2014a).

Cooling water that is not otherwise lost from the pond through evaporation or seepage is 

recirculated from the cooling pond through the condenser systems in a continuous loop. In 

addition, a portion of the water in the cooling pond is discharged as blowdown on a near 

continuous basis under normal conditions. (Blowdown is water that is diverted from the cooling 

system (i.e., cooling pond) to remove impurities that may degrade plant performance.) Total 

dissolved solids are the primary constituents of concern to prevent scale buildup on plant 

components. 

All water lost from the recirculating system must be replaced with fresh water; this water is 

referred to as makeup water (Exelon 2014a; NRC 2013). Makeup water for the onsite cooling 

pond is withdrawn from, and blowdown is discharged to, the Illinois River, which lies 3.5 mi 
Affected Environment

3-7

(5.6 km) north of LSCS’s cooling pond. The intake and blowdown pipelines are routed below 

ground through a common right-of-way corridor. Figure 3–5 provides a basic schematic 

diagram of a closed-cycle, recirculating cooling system that uses a cooling pond.

Figure 3–5. Closed-Cycle Cooling System with Cooling Pond

Source: Modified from NRC 2013, Figure 3.1–4

Groundwater is also used by LSCS for potable water, sanitary water, and demineralized water 

makeup systems. 

Unless otherwise cited, the NRC primarily drew information about LSCS’s cooling and auxiliary 

water systems from Exelon’s ER (Exelon 2014a, 2015p) and its Updated Final Safety Analysis 

Report (UFSAR) (Exelon 2014b). The NRC staff visited the facilities cited herein during the 

May 2015 environmental site audit (NRC 2015b). Descriptions of the individual plant cooling 

and auxiliary systems and components that interact with the environment are provided below.

Cooling Pond and Ultimate Heat Sink. Water for the circulating water system (CWS) for 

condenser cooling water and for the plant service water system are supplied directly from the 

cooling pond. 

The LSCS cooling pond is an engineered impoundment encompassing 2,058 ac (833 ha) with 

an average depth of 15 ft (4.7 m) (NRC 1978) (Figure 3–6). The pond has an elevation of 700 ft 

(213 m) above mean sea level (MSL) at normal pool elevation. At this water elevation, the 

cooling pond has a storage capacity of 31,706 acre-feet (39 million cubic meters (m3

)) of water. 

This impoundment was formed by constructing earthen dikes to enclose the north, east, and 

south sides of the pond; a natural levee created by existing topography forms the fourth side. 

Engineered fill consisting of silty-clay, taken from borrow areas within the pond basin, was used 

in the construction of these peripheral dikes. A perimeter drainage ditch designed to intercept 

runoff and to capture and direct seepage toward surface drainages and away from the dikes 

flanks the pond’s dikes (Exelon 2014b). 

Integral to the pond’s construction are three internal baffle or finger dikes (i.e., earthen berms), 

that total 22,623 ft (6,895 m) in length. These structures direct the flow of water from the 

discharge canal and through the pond to ensure that the coolest water is available for use by 

LSCS (Exelon 2014b) (Figure 3–6). The average residence time for water in the cooling pond is 

5.5 days (NRC 1978). 
Affected Environment

3-8

The peripheral dike system that encloses the cooling pond includes a 300-ft- (91-m)-wide 

auxiliary spillway structure. The spillway is located northwest of the main plant complex and is 

adjacent to the discharge canal. The structure is capable of passing a volume of 

1,069,000 gallons per minute (gpm) (2,380 cubic feet per second (cfs) or 67.2 meters per 

second (m/s)) of water associated with the probable maximum water level. Discharge from the 

structure flows north to South Kickapoo Creek, a tributary to the Illinois River (Exelon 2014b). 

A dedicated portion of the cooling pond located immediately adjacent to the LSCS intake canal 

serves as the plant’s ultimate heat sink (UHS). It is also known as the core standby cooling 

system (CSCS) pond and directly supplies the CSCS equipment cooling water system, as 

discussed below. This excavated area comprises 83 ac (34 ha) in size and is 5 ft (1.5 m) deep 

below grade. It can hold 460 acre-feet (567,000 m3

) of water. This volume of water is sufficient 

to supply 30 days of cooling water following safe shutdown from normal operating or accident

conditions. The CSCS pond can function even if the perimeter dikes of the cooling pond are 

breached (Exelon 2014b).

Illinois River Water Makeup System. Cooling pond makeup water is withdrawn via the river 

screen house located on the south bank of the Illinois River at Illinois River Mile (RM) 249.5 

(River Kilometer (RKm) 401.5) (Figure 3–6). The river screen house is situated approximately 

3.5 mi (5.6 km) north of the cooling pond. The structure is designed to withstand the 100-year 

flood of the Illinois River (Exelon 2014b).

The river screen house contains three makeup water pumps, each with a capacity of 

30,000 gpm (67 cfs or 1.9 cubic meters per second (m3

/s)). Two pumps are normally operated 

at all times to meet cooling pond makeup demands, with the third serving as a backup. 

However, when reduced evaporation demands allow (winter months), the pump discharge ball 

valves are closed to 30 degrees (one-third open) (Exelon 2015c). 

River water is first drawn through an intake flume in the bottom of the river and then into a 72-ft-

(22-m)-wide funnel inlet basin with concrete dam located 24 ft (7 m) from the shoreline frontage 

of the river screen house. The inlet is protected by a floating log boom to deflect river debris. 

From the inlet, water then enters the intake forebay of the screen house and passes first 

through two adjacent bar grills and then through vertical traveling screens with 3/8-inch (in.)

(0.95-centimeter (cm)) openings before entering the pumps (Exelon 2014a, 2015c). The bar 

grills are galvanized steel and measure 3/8 in. (0.95 cm) thick and 4 in. (10 cm) wide. The 

narrow dimension of each bar is oriented perpendicular to the incoming water flow, and the 

centerlines of the narrow dimension of adjacent bars are spaced 3 in. (7.6 cm) apart 

(Exelon 2015c).

Water velocity in the river intake channel is reported as ranging from 0.3 to 0.5 feet per second 

(fps) (0.10 to 0.15 m/s) with one pump operating and 0.6 to 1.0 fps (0.2 to 0.3 m/s) with two 

pumps operating. Flow velocity at the travelling screens ranges from about 0.5 to 0.9 fps 

(0.15 to 0.3 m/s) with one and two makeup pumps in full operation, respectively (NRC 1978; 

Exelon 2014a). In NRC’s Final Environmental Statement for the operating license of LSCS, the 

NRC staff estimated that the intake velocity at the face of the traveling screens would be 0.5 fps 

(0.2 m/s) 93 percent of the time and 1.0 fps (0.3 m/s) the remaining 7 percent of the time 

(NRC 1978). Exelon has not performed any operational studies to further characterize intake 

flow velocities (Exelon 2015c). Based on the assessment the NRC performed for LSCS’s 

operating license (NRC 1978), the velocity at the face of the traveling screens would typically be 

within the 0.5-fps (0.15-m/s) intake velocity now recommended by the U.S. Environmental 

Protection Agency (EPA) for protection of aquatic organisms (Volume 69 of the Federal 

Register, page 41576 (69 FR 41576)), although the velocity may be closer to 1.0 fps (0.3 m/s) 

during certain periods during operations.
Affected Environment

3-9

Figure 3–6. LSCS Cooling Water Supply and Discharge Facilities

Sources: Modified from Exelon 2014a, 2015p
Affected Environment

3-10

A backwash system removes debris from the river intake traveling screens, and trash rakes 

remove debris from bar grills. The backwash system can be set to operate in automatic or 

manual mode, but the system is normally left in automatic mode unless high debris loading 

requires manual cleaning. In automatic mode, cleaning is initiated when the measured 

differential water level across the screens reaches 4 in. (10 cm). With a differential water level 

of 6 in. (15 cm), the system switches to fast speed. A differential level in excess of 16 in. 

(40 cm) for at least 15 seconds will cause the associated makeup pumps to trip to prevent 

cavitation damage. Manual mode with either a slow or fast speed setting may be used during 

periods of high debris loading (Exelon 2015c). 

Collected debris, including any impinged biota, is deposited in a trash basket located outside the 

river screen house, with the debris ultimately disposed of in an offsite permitted landfill. The 

river screen house is not equipped with a fish return system. Screen backwash and other 

intermittent discharges from the screen house are discharged to the Illinois River through a 

National Pollutant Discharge Elimination System (NPDES)-permitted outfall (Outfall 002). The 

intake forebay of the facility has a floating oil boom to prevent any oil leaks from the screen 

house from entering the river. Section 3.5.1.3 of this SEIS presents additional information on 

water quality and LSCS’s NPDES permit. 

With all three river makeup water pumps in operation, LSCS’s maximum surface water makeup 

supply capacity is 90,000 gpm (200 cfs or 5.66 m3

/s), which is equivalent to 129.6 million 

gallons per day (mgd) (491,000 cubic meters per day (m3

/day)). Normal peak makeup 

withdrawal from the Illinois River, with two pumps operating, is 60,000 gpm (134 cfs or 

3.77 m3

/s) or 86.4 mgd (327,000 m3/day). Surface water use is detailed in Section 3.5.1.2. 

From the river screen house, intake water is pumped south to the northern end of the LSCS

cooling pond through a 60-in. (152-cm) below ground pipeline. Upon reaching the pond, the 

water is conveyed into the pond through a reinforced concrete discharge structure located on 

the north side of the pond’s discharge canal. The structure is designed to prevent erosion of the 

cooling pond dike (Exelon 2014b) (see Figure 3–6). 

The river intake pipeline is equipped with air and vacuum relief valves along its course to help 

guard against pressure surges and other conditions that sometimes occur due to elevation 

changes along its routing. Nevertheless, the makeup pipeline, which is not a safety-related 

structure, has experienced a number of breaks resulting in flooding and erosion of areas 

surrounding the break. To date, no pipeline breaks have affected reactor operation. Pipeline 

repairs typically involve establishing a temporary roadway to the location of the break, 

excavating to expose the broken pipe, removal and replacement of the broken pipe section, 

backfill of the excavation site, grading to return the surface to approximate the original contour

of the land surface, and stabilization of the excavation site and temporary roadway to prevent 

erosion pending revegetation. The most recent such break occurred on January 23, 2014. 

Exelon reported the break to both the Illinois Environmental Protection Agency (IEPA) and EPA

Region V in accordance with the reporting provisions of Exelon’s NPDES permit 

(Exelon 2015c).

To address issues associated with pipeline breaks, Exelon has performed maintenance, 

including replacing relief valves, and has installed instrumentation on the intake traveling 

screens to alert the LSCS control room operators to abnormal conditions. Exelon has also 

modified operating and response procedures and has implemented plans and procedures to 

prevent and quickly respond to any breaks. For example, operational procedures have been 

modified to include checks on pipeline integrity and to ensure necessary parts are maintained to 

replace a section of pipeline should a break occur (Exelon 2014a, 2015c). 
Affected Environment

3-11

CWS and Blowdown Discharge. The CWS provides cooling water to the main condensers. In 

addition to the condensers, the system includes the cooling pond, lake screen house, circulating 

water pumps, piping, valves, and related equipment. The system normally supplies water to the 

main condensers at temperatures ranging from 32 °F to a maximum of 100 °F (0 to 37.8 °C)

(Exelon 2014b). However, operating license technical specifications (TS) limit the temperature 

of the cooling water supplied to the facility from the UHS portion of the cooling pond within 

diurnal temperature limits based on the time of day, but that are no higher than 104 °F (40 °C) 

(NRC 2015e).

The main condenser of each unit requires 616,500 gpm (1,373 cfs or 38.8 m3

/s), or 888 mgd 

(3.36 million m3

/day) of circulating water flow to remove waste heat at 100-percent load. 

Cooling water is withdrawn from the cooling pond through the lake screen house, which is 

located at the west end of the intake canal (Figure 3–6). The lake screen house contains six 

circulating water pumps (three for each unit) that take suction from the service water tunnel 

(Exelon 2014a). Each pump has a capacity of 205,500 gpm (457.7 cfs or 12.9 m3

/s) (Exelon 

2015c), with two pumps normally in operation per unit to supply water to the condensers. Water 

first enters the intake forebays after passing through bar grills and traveling screens with 3/8-in. 

(0.95-cm) openings. The design water intake velocity at the screens is approximately 2.2 fps 

(0.7 m/s), assuming clean screens. Debris removed from the traveling screens by the screen 

backwash system and from the bar grills by trash rakes is collected in a trash basket and 

disposed of in an offsite permitted landfill. Similar to the river intake backwash system, the 

circulating water backwash system can be operated in either automatic or manual mode. When 

in automatic mode with a differential water level across the screens ranging between 0 and 6 in. 

(0 to 15 cm), a timer initiates a 3-minute wash cycle every 12 to 14 hours. With a differential 

level rising to between 6 and 10 in. (15 to 25 cm), a continuous backwash cycle starts at slow 

speed. The fast setting is triggered with a differential water level exceeding 10 in. (25 cm). 

Manual mode may be used during fish runs or other periods of high debris intake (Exelon 

2015c). Like the river screen house, the lake screen house has no fish return system 

(Exelon 2014a, 2014b). 

From the lake screen house, water is pumped through the main condenser of each unit. 

A chemical feed system, located in facilities adjacent to the lake screen house, injects biocide

and other chemical treatments to reduce biofouling, silting, and scale buildup in the condenser 

systems. After passing through the unit condensers, heated circulating water is returned to the 

cooling pond through the discharge canal. The nominal (design) temperature rise in the 

circulating water passing through the main condensers is approximately 26.7 °F (10 °C) 

(Exelon 2014b). 

As previously stated, a series of parallel dikes in the cooling pond direct and slow the rate of 

movement of the returned cooling water through the pond to facilitate residence time cooling 

processes so that the coolest water is available for uptake again at the lake screen house. 

This heat dissipation is necessary so that cooling pond blowdown to the Illinois River meets 

temperature limitations and mixing zone requirements under the Illinois thermal water quality 

standards (35 Illinois Administrative Code (IAC) 302) and Special Condition 3 of Exelon’s 

NPDES Permit No. IL0048151 (IEPA 2013). The permit also authorizes the discharge of 

various other effluent streams to the cooling pond in addition to condenser cooling water, as 

further described in Section 3.5.1.3 of this SEIS.

Blowdown combined with other comingled effluent streams flows through an open channel 

originating at the west shore of the cooling pond (UHS portion) and then northwest to a spillway 

adjacent to the LSCS discharge canal (see Figure 3–6). 
Affected Environment

3-12

The blowdown spillway connects to a 66-in. (168-cm) diameter pipeline through which the 

collected blowdown and other effluent streams travel underground via gravity flow. The 

blowdown pipeline can also receive processed liquid radioactive waste (radwaste), which may 

be discharged on a batch basis directly into the blowdown pipeline at a maximum rate of 

45 gpm (0.17 cubic meters per minute) (Exelon 2014a). Nevertheless, the radwaste discharge

line is equipped with a radiation monitor that will automatically close the radwaste discharge

valve in the event of a high-radiation signal (Exelon 2014b). 

The pipeline discharges into an approximately 500-ft- (150-m)-long discharge structure 

consisting of a plunge pool and rip-rapped lined swale that connects with the Illinois River at 

RM 249.4 (RKm 401) and just downstream of the LSCS river screen house (see Figure 3–6). 

The maximum blowdown rate of the system is equal to the maximum intake rate of 90,000 gpm 

(200 cfs or 5.66 m3

/s). However, motor-operated valves at both the river and lake ends of the 

discharge line can be used to isolate the pipeline for maintenance and are used to adjust the 

blowdown to an average of 58,000 gpm (129 cfs or 3.65 m3

/s) or less with a target annual 

average of 30,000 gpm (67 cfs or 1.89 m3

/s) (Exelon 2014a, 2014b). The blowdown discharge 

point is regulated under LSCS’s NPDES permit as Outfall 001 (see Section 3.5.1.3). 

Because the blowdown pipeline functions under gravity flow, it is less susceptible to surges and 

breakage than the river intake pipeline. It is also equipped with air and vacuum relief valves. 

Nevertheless, breaks do occur. The most recent such break occurred on July 13, 2012. Exelon

reported the break to both the IEPA and EPA Region V. As discussed above for the makeup 

pipeline, Exelon has implemented a program to reduce the frequency of breaks and their 

impacts on operations and the environment (Exelon 2015c). 

Plant Service Water System. The service water system provides cooling water for various 

nonsafety-related auxiliary systems and components, including cooling water for the turbine 

generator; various air conditioning condensers; and the fuel pool, turbine building, and reactor

building heat exchangers. It also supplies water for the lake screen house traveling screen 

backwash system and the radwaste system, and it is used to fill the fire protection system and 

serves as a backup fire water supply. Service water is normally supplied by four pumps, with a 

fifth pump serving as a backup, located in the lake screen house. Each pump has a capacity of 

16,000 gpm (35.6 cfs or 1.01 m3

/s). The pumps take suction from the lake screen house intake 

service water tunnel and discharge into a common header. Automatic backwash strainers 

remove any debris that might be passed through the circulating water screens. In addition, the 

system has two jockey pumps rated at 5,000 gpm (11.1 cfs or 0.31 m3

/s). These pumps are 

powered by an emergency diesel generator and are used to meet minimum flow requirements 

during a loss of offsite power. The service water is also treated by the chemical feed system to 

guard against biofouling, scale buildup, corrosion, and silting. Chemical injection occurs directly 

to the service water tunnel feed lines. All service water return flows are discharged back to the 

cooling pond (Exelon 2014a, 2014b). 

Fire Protection Water System. The cooling pond is the source of fire protection water for the 

LSCS fire hydrants, the water sprinkler and deluge systems, and the hose valve stations. 

One of two 75-gpm (0.17-cfs or 0.005-m3

/s) jockey pumps normally keep the system 

pressurized. If a system demand occurs, a 225-gpm (0.50-cfs or 0.014-m3

/s) intermediate 

pump is activated. If the demands of the intermediate pump are exceeded, the first of two 

diesel-driven pumps are automatically engaged. These pumps, each with a capacity of 

2,500 gpm (51 cfs or 1.44 m3

/s), are located in the lake screen house and take suction directly 

from the service water tunnel (Exelon 2014b). 

Core Standby Cooling System. This system is equivalent in purpose to the essential service 

water systems at other nuclear power plants and provides cooling water for the purpose of 
Affected Environment

3-13

cooling safety-related equipment necessary for safe shutdown of the reactors. This equipment 

includes the residual heat removal heat exchangers, pump seal coolers, and emergency diesel 

generators; the system also provides emergency spent fuel pool makeup water and a source of 

water for containment flooding for post-accident recovery. The CSCS withdraws cooling pond 

water from the UHS portion of the cooling pond (as discussed earlier) via the lake screen house 

service water tunnel. The water is chemically treated by the chemical feed system as previously 

described. As a safeguard against blockage of the traveling screens ahead of the service water 

channel, the system has a 54-in. (137-cm) bypass line that can be opened to directly supply 

CSCS water. All pumps and strainers for conveying emergency cooling water are located in 

watertight spaces within the basements of the various plant buildings (Exelon 2014a, 2014b). 

Potable Water System. LSCS uses groundwater from two deep wells (Nos. 1 and 2) to supply 

potable (drinking) water, sanitary water, and raw makeup water for the demineralized water 

system. The wells were installed during plant construction with completion depths of 1,629 ft 

(497 m) and 1,620 ft (494 m), respectively (Exelon 2014a). Each well has a pump capacity of 

300 gpm (1.14 cubic meters per minute) (Exelon 2014b). Water is stored in a 350,000-gallon 

(gal) (1,325-m3

) storage tank before distribution. The plant supply wells and LSCS’s 

groundwater use are further discussed in Section 3.5.2.2.

3.1.4 Radioactive Waste Management Systems

As part of normal operations and as a result of equipment repairs and replacements due to 

normal maintenance activities, nuclear power plants routinely generate both radioactive and 

nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes. 

There is also a class of waste, called mixed waste, which is both radioactive and hazardous. 

The systems used to manage (i.e., treat, store, and dispose of) these wastes are described in 

this section. Waste minimization and pollution prevention measures commonly employed at 

nuclear power plants are also discussed in this section.

All nuclear plants were licensed with the expectation that they would release very limited 

quantities of radioactive material to both the air and water during normal operation. However, 

NRC regulations require that gaseous and liquid radioactive releases from nuclear power plants 

must meet radiation dose-based limits specified in Title 10 of the Code of Federal Regulations

(10 CFR) Part 20, and the 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 effluents released by a nuclear power plant. All nuclear power 

plants use radioactive waste management systems to control and monitor radioactive wastes.

LSCS uses liquid, gaseous, and solid waste processing systems to collect and process, as 

needed, radioactive materials produced as a by-product of plant operations. The liquid and 

gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 

discharge into the environment. This is to ensure that the dose to members of the public from 

radioactive effluents is reduced to levels that are ALARA in accordance with NRC’s regulations. 

The radioactive material removed from the effluents is converted into a solid form for eventual 

disposal at a licensed radioactive disposal facility.

Exelon has a radiological environmental monitoring program (REMP) to assess the radiological 

impact, if any, to the public and the environment from radioactive effluents released during 

operations at LSCS. The REMP measures the aquatic, terrestrial, and atmospheric 

environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 

background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 

material, including radon) (Teledyne 2015).
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LSCS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 

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

effluents. These methods are used to ensure that radioactive material discharges from the plant 

meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 

the REMP (Exelon 2013d).

3.1.4.1 Radioactive Liquid Waste Management

LSCS Units 1 and 2 share a common liquid radioactive waste system (LRWS). The LRWS 

collects, monitors, and processes any potentially radioactive liquid wastes produced in the plant. 

The LRWS also recycles as much processed liquid waste as can be accommodated within the 

LSCS water balance. Although LSCS tries to limit any radioactive releases via the liquid 

pathway, discharges from the system are authorized and may occur if treated waste water is not 

needed for other plant uses. The LRWS is designed so that any liquid radioactive waste 

discharged from the site will have radioactive nuclide concentrations below the limits specified in 

10 CFR Part 20 and Appendix I to10 CFR Part 50.

Processing of liquids in the LRWS results in a clean product stream and a reject stream. The 

clean product stream returns water for use by the main plant systems via the condensate 

storage tanks if the water quality is found acceptable and if the plant has the need for the 

makeup water. Water in the reject stream is processed for disposal in the solid radioactive 

waste system. Unused treated waste water can be sent to a discharge tank and held until a 

discharge batch accumulates. Before any release of a discharge batch, it would be sampled 

and treated if necessary to ensure radionuclide concentrations and resulting radiation doses to 

LSCS personnel and the general public comply with NRC regulations in 10 CFR Part 20 and 

Appendix I to 10 CFR Part 50. The LWRS sends discharge batches directly into the cooling 

pond blowdown line. 

The LRWS consists of a waste processing subsystem, a floor drain processing subsystem, a 

chemical waste subsystem, and a sludge subsystem. All subsystems are shared by LSCS

Units 1 and 2. A vendor-provided liquid waste treatment system is also available to supplement 

the LRWS if needed.

The waste processing subsystem collects and processes water from sources such as 

equipment drains. This water is treated by settling, filtration, and demineralization. After 

treatment and sampling, the water is returned for reuse through the condensate storage tanks. 

The floor drain processing subsystem collects and processes water from the floor drain 

systems. After treatment and sampling, the water is returned for reuse through the condensate 

storage tanks. The chemical waste subsystem collects and processes water from areas like the 

laboratory drains and the radwaste building sump. After treatment and sampling, plant 

procedures are used to determine where the processed water goes, which may include 

discharge. The sludge subsystem is not a processing stream, but rather a group of tanks and 

associated pumps that serve as an interface between the LRWS and the solid radioactive waste 

handling system. After radioactive contaminants have been removed from the LRWS, 

concentrated, and treated or held up to allow radioactive decay if necessary, they are 

transferred to the solid radioactive waste system for processing, temporary storage, and 

shipment for disposal.

The use of these radioactive waste systems and the procedural requirements in the ODCM 

ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 

dose standards.

Dose estimates for members of the public are calculated based on radioactive liquid effluent 

release data and aquatic transport models. Exelon’s annual radiological effluent release report 
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contains the radioactive liquid effluents release data from LSCS and the resultant calculated 

doses. The NRC staff reviewed 5 years of radioactive effluent release data: 2010 through 2014 

(Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year period provides a data set that covers a 

broad range of activities that occur at a nuclear power plant, such as refueling outages, routine 

operation, and maintenance activities that can affect the generation of radioactive effluents. 

LSCS did not have any radioactive liquid effluent releases over the period of 2010 through 

2014. 

Since LSCS had no radioactive liquid effluent releases for the period of 2010 through 2014, its

radioactive liquid effluent control program showed that radiation doses to members of the public 

were controlled within the NRC’s and EPA’s radiation protection standards contained in 

Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190. Also, since LSCS had no 

radioactive liquid effluent releases for the period of 2010 through 2014, no adverse trends were 

observed in the dose levels.

Routine plant refueling and maintenance activities currently performed will continue during the 

license renewal term. Based on the past performance of the radioactive waste system to 

maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 

during the license renewal term.

3.1.4.2 Radioactive Gaseous Waste Management 

LSCS Units 1 and 2 share a common gaseous radioactive waste system (GRWS) with a 

common vent stack located on the roof of the containment building between the two units. The 

GRWS is designed to process and control radioactive gases and minimize the amount of 

radioactive gaseous material released into the environment. The gaseous radioactive wastes 

released consist primarily of xenon, argon, iodine, tritium, and carbon. The steam in a BWR 

plant such as LSCS contains impurities in the form of radioactive gases that are continuously 

removed during plant operation from the main condenser by an air ejector. This process is the 

major source of radioactive gases generated by LSCS (Exelon 2014a). The GRWS removes 

some radioactive gases and delays the release of other radioactive gases by adsorption on 

charcoal beds to allow time for radioactive decay. As a final step, the gaseous waste stream 

passes through a high efficiency particulate air filter, and is discharged through the common 

vent stack. Other plant facilities that are potential sources of radioactive gas emissions include 

the primary containment, the secondary containments (reactor buildings), the turbine buildings, 

and the radwaste building. The ventilation systems in each of these facilities have filtration and 

treatment systems that the air passes through before being discharged through the vent stack 

(Exelon 2014a).

The use of these radioactive waste systems and the procedural requirements in the ODCM 

ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 

dose standards.

Dose estimates for members of the public are calculated based on radioactive gaseous effluent 

release data and atmospheric transport models. Exelon’s annual radioactive effluent release 

report contains a detailed presentation of the radioactive gaseous effluents released from LSCS

and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 

release data: 2010 through 2014 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year 

period provides a data set that covers a broad range of activities that occur at a nuclear power 

plant, such as refueling outages, nonrefueling outage years, routine operation, and maintenance 

activities that can affect the generation of radioactive effluents. The NRC staff compared the 

data against NRC dose limits and looked for indication of adverse trends (i.e., increasing dose 

levels) over the period of 2010 through 2014. Since the radioactive gaseous effluents are 

released from a common vent stack shared by both Unit 1 and Unit 2, the resultant calculated 
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3-16

doses presented in the effluent release are divided in half to evaluate compliance with the 

Appendix I to 10 CFR Part 50 dose criteria. The following summarizes the calculated doses 

from radioactive gaseous effluents released from LSCS Units 1 and 2 during 2014:

Unit 1

• The air dose at the site boundary from gamma radiation in gaseous effluents from 

LSCS was 2.36×10−2 millirad (mrad) (2.36×10−4 milligray (mGy), which is well below 

the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

• The air dose at the site boundary from beta radiation in gaseous effluents from LSCS

was 1.10×10−3 mrad (1.10×10−5 mGy), which is well below the 20 mrad (0.2 mGy) 

dose criterion in Appendix I to 10 CFR Part 50.

• The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 

carbon-14 from LSCS was 4.56×10−1 millirem (mrem) (4.56×10−3 millisievert (mSv)), 

which is well below the 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR 

Part 50.

Unit 2

• The air dose at the site boundary from gamma radiation in gaseous effluents from 

LSCS was 2.36×10−2 mrad (2.36×10−4 mGy), which is well below the 10 mrad 

(0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

• The air dose at the site boundary from beta radiation in gaseous effluents from LSCS

was 1.10×10−3 mrad (1.10×10−5 mGy), which is well below the 20 mrad (0.2 mGy) 

dose criterion in Appendix I to 10 CFR Part 50.

• The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 

carbon-14 from LSCS was 4.56×10−1 mrem (4.56×10−3 mSv), which is well below the 

15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.

The NRC staff’s review of LSCS’s radioactive gaseous effluent control program showed that 

radiation doses to members of the public were controlled within NRC’s and EPA’s radiation 

protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 

40 CFR Part 190. No adverse trends were observed in the dose levels.

Routine plant refueling and maintenance activities currently performed will continue during the 

license renewal term. Based on the past performance of the radioactive waste system to 

maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 

expected during the license renewal term.

3.1.4.3 Radioactive Solid Waste Management

LSCS Units 1 and 2 share a common solid radioactive waste system (SRWS). The SRWS 

receives, dewaters, solidifies, packages, handles, and provides temporary storage facilities for 

all radioactive wet solid wastes prior to offsite shipment and disposal in accordance with NRC 

regulations in 10 CFR Parts 61 and 71. It also receives, decontaminates, compacts 

(as necessary), and provides temporary storage facilities for all radioactive dry wastes prior to 

offsite shipment and disposal (Exelon 2014a). Transportation of the radioactive solid waste is 

governed by the U.S. Department of Transportation regulations in 49 CFR Parts 171 to 178.

LSCS disposes of solid radioactive waste at facilities in Utah and Texas. LSCS also utilizes 

offsite vendor services in Tennessee for dry active waste processing, including compaction, 

incineration, thermal processing, and sorting of the dry active waste.
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LSCS Units 1 and 2 have a shared Interim Radwaste Storage Facility (IRSF) with the capacity 

to hold 270 containers of Class B and Class C (Class B/C) low-level radioactive wastes in two 

layers of 135 spots each. In 2011, LSCS Units 1 and 2 both received license amendments to 

allow their IRSF to store Class B/C waste from Braidwood, Byron, and Clinton Stations in 

addition to the wastes generated at LSCS. Exelon states that LSCS has sufficient excess 

storage capacity to accommodate extended storage of the Class B/C wastes generated by all 

four Exelon stations. Also, LSCS can ship Class B/C wastes for treatment and disposal to the 

Waste Control Specialists facility in Texas to reduce the demand for any extended onsite 

storage of those wastes. Therefore, storage capacity for low-level radioactive wastes should be 

sufficient for the length of the license renewal term. (Exelon 2014a)

LSCS infrequently generates small quantities of mixed waste (waste having both a hazardous 

component and radioactive component). The IEPA regulates the hazardous component of the 

waste and the Illinois Emergency Management Agency Division of Nuclear Safety and the NRC 

regulate the radioactive component. When generated, mixed wastes are accumulated in the 

Mixed Waste Storage Building before transport to a licensed offsite facility for treatment and 

disposal (Exelon 2014a).

LSCS has contracts to send its low-level waste (LLW) to two licensed LLW disposal sites: 

EnergySolutions in Clive, Utah, and Waste Control Specialists in Andrews, Texas. LSCS also 

sends certain wastes to Toxco Materials Management Center in Oak Ridge, Tennessee, and 

EnergySolutions in Oak Ridge, Tennessee for processing before disposal.

In 2014, 30 LLW shipments were made from LSCS for processing and disposal to the 

EnergySolutions Clive facility in Clive, Utah, the EnergySolutions Bear Creek facility in Oak 

Ridge, Tennessee, and the Toxco Materials Management Center in Oak Ridge, Tennessee. 

The total volume and radioactivity of LLW shipped offsite in 2014 was 1.23×103 m3

(4.34×104 cubic feet and 1.34×101 curies (4.95×105 megabecquerels), respectively 

(Exelon 2015b). Routine plant operation, refueling outages, and maintenance activities that 

generate radioactive solid waste will continue during the license renewal term. Radioactive 

solid waste is expected to be generated and shipped off site for disposal during the license 

renewal term.

3.1.4.4 Radioactive Waste Storage

Low-level radioactive waste (LLRW) is stored temporarily onsite before being shipped offsite for 

disposal at a licensed LLRW disposal facility. Exelon (2014a) stated that LSCS has sufficient 

capability to store Class B/C LLRW from Braidwood, Byron, and Clinton Stations in addition to 

LSCS Class B/C waste in the IRSF (Exelon 2014a). 

LSCS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 

storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 

approved dry cask storage containers onsite. The installation and monitoring of this facility is 

governed by NRC requirements 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.” The LSCS ISFSI will remain in place until the U.S. Department of Energy takes 

possession of the spent fuel and removes it from the site for permanent disposal or processing. 

Spent fuel transfers to the ISFSI began in 2010 when fuel from the spent fuel pool was placed 

in casks and transferred to the ISFSI storage pad. As of December 2014, there are 16 dry 

casks containing spent fuel on the ISFSI storage pad (Exelon 2015b).

3.1.4.5 Radiological Environmental Monitoring Program

Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 

environment from operations at LSCS.
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The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 

radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 

groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 

background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 

material, including radon). 

In addition to the REMP, LSCS has an onsite groundwater protection program designed to 

monitor the onsite plant environment for detection of leaks from plant systems and pipes 

containing radioactive liquid (Teledyne 2015). Information on the groundwater protection 

program is contained in Section 3.5.2 of this document.

The NRC staff reviewed 5 years of annual radiological environmental monitoring data: 

2010 through 2014 (Teledyne 2011, 2012, 2013, 2014, 2015). A 5-year period provides a data 

set that covers a broad range of activities that occur at a nuclear power plant, such as refueling 

outages, routine operation, and maintenance activities that can affect the generation and 

release of radioactive effluents into the environment. The NRC staff looked for indication of 

adverse trends (i.e., buildup of radioactivity levels) over the period of 2010 through 2014.

The NRC staff’s review of Exelon’s data showed no indication of an adverse trend in 

radioactivity levels in the environment. The data showed that there was no measurable impact 

to the environment from operations at LSCS.

3.1.5 Nonradioactive Waste Management Systems

Like any other industrial facility, nuclear power plants generate both hazardous and 

nonhazardous wastes that are not contaminated with radionuclides.

LSCS has a nonradioactive waste management program to handle its nonradioactive hazardous 

and nonhazardous wastes. The waste is managed in accordance with Exelon’s procedures. 

Listed below is a summary of the types of waste materials generated and managed at LSCS.

• LSCS is typically a small quantity hazardous waste generator; however, hazardous 

wastes are managed according to large quantity generator standards. LSCS has 

contracts in place to transfer hazardous waste to licensed offsite treatment and 

disposal facilities.

• LSCS’s nonhazardous wastes include potentially infectious medical waste (PIMW), 

used oil, grease, antifreeze, adhesives, and other petroleum-based liquids. PIMW is 

generated at a health facility onsite and can include used and unused hypodermic 

needles and syringes, as well as items contaminated with human blood. PIMW is 

considered a unique special waste category in Illinois and transportation and 

disposal of this waste is regulated under the Illinois Administrative Code (IAC) 

Title 35, Sections 1420 through 1422 and 1450 (35 IAC 1420-1422, 1450).

• Universal wastes, such as batteries and mercury-containing lamps are managed in 

accordance with 35 IAC 733 standards. Other used materials, such as, oils, metals, 

paper, and other recyclables are recycled according to Exelon procedures and 

Illinois regulations.

Exelon operates an onsite sewage treatment plant. Sewage treatment effluent is discharged to 

the LSCS cooling pond. Nonradioactive industrial wastewater is also processed at a separate 

onsite wastewater treatment plant and the treated effluent is discharged into the cooling pond. 

Cooling pond blowdown is discharged to the Illinois River under NPDES permit IL0048151 

(Exelon 2014a).
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3.1.6 Utility and Transportation Infrastructure

The utility and transportation infrastructure at nuclear power plants typically interfaces with 

public infrastructure systems available in the region. Such infrastructure includes utilities, 

including suppliers of electricity, fuel, and water, as well as roads and railroads that provide 

access to the site. The following sections briefly describe the existing utility and transportation 

infrastructure at LSCS.

3.1.6.1 Electricity

Nuclear power plants generate electricity for other users; however, they also use electricity to 

operate. Offsite power sources provide power to engineered safety features and emergency 

equipment in the event of a malfunction or interruption of power generation at the plant. 

Independent backup power sources provide power in the event that power is interrupted from 

both the plant and offsite power sources.

At LSCS, connections to the Commonwealth Edison Company (ComEd) 345-kilovolt (kV) 

system at the onsite switchyard provide offsite power sources for essential safety systems and 

emergency equipment (Exelon 2014b). The switchyard is arranged in a double ring bus such 

that offsite power to both units cannot be lost due to any single failure (Exelon 2014b). In the 

event of total loss of auxiliary power from offsite sources, onsite diesel generators serve as an 

independent source of power for safe shutdown (Exelon 2014b). LSCS has five diesel 

generators. Two diesel generators each are provided for Units 1 and 2. The other diesel 

generator serves essential auxiliary functions for either Unit 1 or 2. Each diesel generator is 

designed and installed to provide up to 4.16 kV of power, which is ample capacity to supply all 

power required for the safe shutdown of both units in the event of a total loss of offsite power 

(Exelon 2014b).

3.1.6.2 Fuel

The LSCS nuclear units are operated using low-enriched uranium dioxide fuel with enrichment 

not exceeding 5 percent by weight of uranium-235. At any given time, the LSCS units contain 

approximately 140 metric tons (MT) (308,600 pounds) of uranium fuel (Exelon 2015b). Exelon 

replaces about 36 percent of that fuel at each refueling, which occurs on a staggered 24-month 

cycle (Exelon 2014a). Fresh (i.e., unirradiated) fuel is brought to the site and stored onsite in 

the LSCS new fuel storage facility prior to installation in the reactor cores (Exelon 2014b). 

Exelon stores spent fuel in a spent fuel pool and an ISFSI. Nuclear fuel and radioactive waste 

systems are further described in Section 3.1.4.

In addition to nuclear fuel, LSCS requires diesel fuel to operate the emergency diesel power 

generators. To meet emergency demands, Exelon stockpiles diesel fuel and gasoline on the 

site. In total, LSCS has nominal onsite capacities to store as much as 204,080 gal 

(772,530 liters) of diesel fuel and gasoline for a variety of uses, including emergency diesel 

generators, diesel fire pumps, and plant vehicles (Exelon 2015b).

3.1.6.3 Water

In addition to cooling and auxiliary water (described in Section 3.1.3), nuclear power plants 

require potable water for sanitary and everyday uses by personnel (e.g., drinking, showering, 

cleaning, laundry, toilets, and eye washes). At LSCS, two deep wells supply the site with 

potable water. Water pumped from the wells is routed to an onsite vendor trailer, which 

deionizes the water and routes the water to a 1.3-million-liter (350,000-gal) storage tank. Water 

drawn from the storage tank may be used in either the demineralized water makeup system or 

the potable and sanitary water system. Water withdrawn for use in the potable water system 
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undergoes chlorination prior to entering the system. LSCS withdraws approximately 98 liters 

per minute (L/min) (26 gpm) from the wells for potable water and other uses (Exelon 2014a).

3.1.6.4 Transportation Systems

All nuclear power plants are served by controlled access roads. In addition to roads, many

plants also have railroad connections for moving heavy equipment and other materials. Some 

plants that are located on navigable waters, such as rivers, Great Lakes, or oceans, have 

facilities to receive and ship loads on barges.

At LSCS, County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road,

provides access to the site from the southern boundary. Major roads in the area include State 

Route 170 (SR-170), which lies 0.8 km (0.5 mi) east of the site, and Interstate 80 (I-80), which 

lies 13 km (8 mi) north of the site. Section 3.10.6 describes local transportation systems, 

including roadway access, in more detail.

Two major railway systems provide service near the LSCS site: the CSX Railroad runs parallel 

to and slightly north of the Illinois River, and a 10-km (6-mi) rail spur connects LSCS to the 

Atchison, Topeka, and Santa Fe Railroad south of the site. Exelon uses a portion of the onsite 

rail spur to transport spent fuel casks to the onsite storage area, but the spur has not been used 

to deliver equipment or materials to the site from external sources in many years. 

(Exelon 2015f)

LSCS lies south of the Marseilles Pool in the reach of the Illinois River between the Marseilles 

Lock and Dam at Marseilles, Illinois, and the Dresden Island Lock and Dam south of 

Channahon, Illinois (Exelon 2014a). These lock and dam sites are part of the Illinois Waterway, 

which flows from Chicago, Illinois, to Grafton, Illinois, slightly upstream from St. Louis, Missouri, 

and is composed of seven water systems: Illinois River, Des Plaines River, Chicago Sanitary 

and Shipping Canal, South Branch Chicago River, Cal-Sag Channel, Little Calumet River, and 

the Calumet River (USACE 2012). Much of the barge traffic in this area is dominated by 

transportation of agricultural products (grains, corn, and soybeans) and other commodities, such 

as cement and concrete (USACE 2012). Exelon (2015g) does not own or maintain a barge slip 

for LSCS and does not otherwise receive or ship equipment for LSCS by barge.

Major airports in the vicinity of LSCS include Chicago Midway International Airport, Chicago 

O’Hare International Airport, and Central Illinois Regional Airport, which lie approximately 93 km 

(58 mi) northeast, 100 km (60 mi) north-northeast, and 110 km (70 mi) south of the site, 

respectively. Additionally, Illinois Valley Regional Airport in Peru, Illinois, serves LaSalle 

County, and eight private airports in the county accommodate smaller cargo, passenger, and 

private aircraft (LaSalle County 2014).

3.1.6.5 Power Transmission Systems

ComEd owns and operates the 345-kV onsite switchyard that connects LSCS with the regional 

electric grid. From the switchyard, a total of six transmission lines extend to four substations. 

Two 345-kV lines travel 66 km (41 mi) north from the site to the Plano substation east of Plano, 

Illinois. Two 345-kV lines travel 100 km (62 mi) northeast to Braidwood Station, Units 1 and 2, 

in Braceville, Illinois. Two 138-kV lines are connected to the switchyard through a 345/138-kV 

transformer. One of the 138-kV line extends 27 km (17 mi) to Mazon, Illinois, and the other 

138-kV line extends 40 km (25 mi) to Streator, Illinois (AEC 1973; NRC 1978; Exelon 2015h).

For license renewal, the NRC (2013) evaluates as part of the proposed action the continued 

operation of those transmission lines that connect the nuclear power plant to the substation 

where electricity is fed into the regional power distribution system and transmission lines that 

supply power to the nuclear plant from the grid. During the environmental review, 
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Exelon (2015h) determined that the four electrical connections between the main plant and the 

LSCS switchyard are the only lines that fall within these categories. Accordingly, the NRC 

considers these lines to be in scope for the license renewal environmental review. These 

connections extend a distance of 1,300 ft (400 m) across flat, primarily gravel laydown areas 

and paved roads (Exelon 2015h). Because redundant offsite power is provided to LSCS 

through the LSCS substation, no offsite transmission lines supply power to the nuclear plant 

from the grid (Exelon 2015h). All of the in-scope transmission lines lie within the 

owner-controlled and industrial-use area of the site.

3.1.7 Nuclear Power Plant Operations and Maintenance

Maintenance activities conducted at LSCS 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 activities currently exist at LSCS 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 

inservice inspection and testing, and maintenance of water chemistry.

Additional programs include those carried out to meet TS surveillance requirements, those 

implemented in response to the NRC generic communications, and various periodic 

maintenance, testing, and inspection procedures. LSCS must periodically discontinue the 

production of electricity for outages supporting refueling, periodic in-service inspection and

testing, and maintenance activities. The LSCS reactor units are on staggered 24-month 

refueling cycles (Exelon 2014a).

3.2 Land Use and Visual Resources

3.2.1 Land Use

3.2.1.1 Onsite Land Use

The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 

Illinois (Exelon 2015p). The site lies 8 km (5 mi) south of the Illinois River, about 10 km (6 mi) 

southwest of Seneca, Illinois, and 120 km (75 mi) southwest of downtown Chicago.

(Exelon 2014a)

A cooling pond occupies the eastern side of the site and accounts for about half of the site area. 

The generating facilities and associated infrastructure (roads, parking lots, warehouses, 

switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac). This 

industrial area is surrounded by about 142 ha (350 ac) of undeveloped natural areas, including 

grassland, old field, shrub-scrub, and small forested fragments (Exelon 2015p).

On the southwest shore of the cooling pond, the IDNR operates the LaSalle Fish Hatchery 

under a lease agreement with Exelon. The hatchery encompasses approximately 18 ha (45 ac)

and includes several small buildings and 16 fish-rearing pools (Exelon 2014a).

A 5.6-km (3.5-mi) corridor for the makeup and blowdown pipelines—which travel underground 

from the Illinois River screen house south to the cooling pond—contains woodlands, pastures, 

and wetlands as well as mowed and maintained right-of-way for a portion of the 

LaSalle-to-Plano 345-kV transmission line (Exelon 2014a).

Table 3–1 lists site land uses, and Figure 3–3 depicts the site layout. Sections 3.1 and 3.6 

describe the developed and natural areas of the site in more detail, respectively.
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Table 3–1. LSCS Site Land Uses by Area

Land Use Area (in acres)(a) Percent

Open Water 1,976(b) 52.3

Developed, Open Space 120 3.2

Developed, Low Intensity 218 5.8

Developed, Medium Intensity 73 1.9

Developed, High Intensity 90 2.4

Barren Land 5 0.1

Deciduous Forest 386 10.2

Shrub/Scrub 17 0.5

Grassland/Herbaceous 473 12.5

Pasture/Hay 11 0.3

Cultivated Crops 346 9.2

Woody Wetlands 58 1.5

Emergent Herbaceous Wetlands 2 0.1

Total 3,776 100.0

(a) To convert acres to hectares, divide by 2.4711.

(b) Exelon used the 2011 National Land Cover Database (NLCD) to estimate acreage of site land uses. Of the 

3,776-acre site, the 2011 NLCD identified 1,976 acres as “open water,” most of which consists of the cooling 

pond. This number of acres is inconsistent with the 2,058 acres reported in ComEd’s Environmental Report 

that evaluated the operation of LSCS (ComEd 1977). However, because the methodologies used to estimate 

land use acreages are different between these documents and the NLCD, and because both methodologies 

are inherently uncertain, Exelon was unable to resolve the discrepancy between the cooling pond acreage 

estimates. It is possible that, in the 1977 Environmental Report, features such as dikes, screen house,

discharge canals, and storm water ponds were included in the cooling pond acreage estimate. Accordingly, 

all estimates should be considered approximate.

Source: Exelon 2015d

3.2.1.2 Coastal Zone

In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.; 

CZMA) to encourage and assist States and territories in developing management programs that 

preserve, protect, develop, and, where possible, restore the resources of the coastal zone 

(i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 

may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 

Great Lakes waters). Individual states are responsible for developing a Federally approved 

Coastal Management Plan and implementing a coastal management program in accordance 

with such a plan. In Illinois, the IDNR administers the coastal management program.

Section 307(c)(3)(A) of the CZMA requires that applicants for Federal permits whose proposed 

activities could reasonably affect coastal zones certify to the licensing agency (here, the NRC) 

that the proposed activity would be consistent with the state’s coastal management program. 

The regulations that implement the CZMA indicate that this requirement is applicable to renewal 

of Federal licenses for actions not previously reviewed by the state (15 CFR 930.51(b)(1)). 

LSCS is outside of the boundary of the Illinois coastal zone (IDNR 2011b, 2015c). Accordingly, 

a consistency determination is not required for the proposed LSCS license renewal.
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3.2.1.3 Offsite Land Use

Within a 10-km (6-mi) radius of the LSCS site, most lands are contained within LaSalle County; 

however, this radius also includes a small area of land in Grundy County to the east. Land use 

in this area is primarily agricultural. Cropland or pastures border the LSCS site to the east, 

south, and west. The Illinois River lies to the north of the site, and the bluffs overlooking the 

Illinois River are mostly forested. The river’s south bank floodplain includes agricultural fields 

and woodlots, while the north bank is more developed and includes parts of the incorporated 

towns of Seneca and Marseilles. The majority of land cover (about 70 percent) within 10 km 

(6 mi) is used for crop cultivation. Deciduous forest accounts for about 12 percent of land cover, 

and the remaining 18 percent is composed of various land cover types, including open water, 

developed land, wetlands, and grasslands. Table 3–2 characterizes the land uses within a 

10-km (6-mi) radius of LSCS.

Table 3–2. Land Use within a 10-km (6-mi) Radius of LSCS

Land Use

Area 

(in acres)(a) Percent

Open Water 2,915 4.0

Developed, Open Space 3,124 4.3

Developed, Low Intensity 2,676 3.7

Developed, Medium Intensity 451 0.6

Developed, High Intensity 256 0.4

Barren Land 84 0.1

Deciduous Forest 8,479 11.7

Evergreen Forest 4 0.0

Shrub/Scrub 43 0.1

Grassland/Herbaceous 2,165 3.0

Pasture/Hay 966 1.3

Cultivated Crops 50,755 70.2

Woody Wetlands 425 0.6

Emergent Herbaceous Wetlands 8 0.0

Total 72,351 100.0

(a) To convert acres to hectares, divide by 2.4711.

Source: Exelon 2015i

The IDNR manages three areas for public use and recreation within 10 km (6 mi) of LSCS. The 

LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling pond that is 

managed by the IDNR and open to the public for fishing and other recreational purposes 

(Exelon 2014a). The Marseilles State Fish & Wildlife Area is approximately 2.4 km (1.5 mi) 

north of the LSCS site. The IDNR (2015e) manages this 1,032-ha (2,550-acre) tract of 

predominantly wooded land for wildlife habitat and hunting. Illini State Park lies approximately 

10 km (6 mi) northwest of LSCS on the south bank of the Illinois River and encompasses 

206 ha (510 ac) (Exelon 2014a).
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LaSalle County, in which LSCS is located, is a predominantly agricultural county; 85 percent of 

the county’s 1,135 square miles (m2

) (294,000 ha or 726,400 ac) are in agricultural production 

(LaSalle County 2014). Much of the county’s agricultural lands were formerly prairie. LaSalle 

County’s major agricultural crops include corn, soybeans, and its major livestock commodities 

include cattle and calves, hogs and pigs, and sheep and lambs (LaSalle County 2014). The 

LaSalle County Comprehensive Plan (LaSalle County 2014) anticipates that the county will 

experience a slight (4 percent) increase in population over the next 15 years and reach an 

estimated 141,615 people by 2030. The county plans to manage its land resources in a manner 

that will preserve prime farmland and to encourage continued urban growth in areas where 

public infrastructure and services already exist so that farmland, open spaces, and natural and 

cultural resources are preserved.

3.2.2 Visual Resources

As described in the previous section, the LSCS site is located in a predominantly agricultural 

region. The site’s grade elevation is approximately 216 m (710 ft) above MSL, which is one of 

the highest points within a 3-km (5-mi) radius. The site’s generating facilities were built 60 m 

(200 ft) above the Illinois River floodplain elevation, which ranges from 152 to 155 m (500 to 

510 ft) above mean sea level. The tallest structures on the LSCS site are the meteorological 

tower and the station vent stack, which are 122 m (400 ft) tall and 113 m (370 ft) tall, 

respectively. The vent stack is painted with thick white and red horizontal stripes. The largest 

and most visible buildings on the site are the reactor and turbine buildings, which are 56 m (185 

ft) and 41 m (134 ft) tall, respectively (Exelon 2014a).

To the west and the southwest, the Grand Ridge Energy Center wind farm is situated on slightly 

higher ground (221 to 227 m (725 to 750 ft) above MSL) on a north-south ridgeline. A second 

wind farm, Top Crop I, is sited south and east of the Grand Ridge Energy Center. Wind turbines 

at these facilities stand 118.5 m (389 ft) tall and have rotor blades that are 38.5 m (126.5 ft) 

long. These two facilities’ 134 wind turbines dominate the viewscape in the vicinity of LSCS. 

(Exelon 2014a)

From most vantage points, the wind turbines are more noticeable than the LSCS buildings or 

facilities. A motorist travelling north on Highway 170 from Ranson, Illinois, to Seneca, Illinois,

would see wind turbines to the west, south, and east until the motorist crested the bluffs of the 

Illinois River at an elevation of about 200 m (650 ft) above MSL. The motorist would then lose 

sight of the turbines at the highway bridge that crosses the Illinois River, at which point the 

road’s elevation descends to approximately 152 m (500 ft) (Exelon 2014a).

3.3 Meteorology, Air Quality, and Noise

3.3.1 Meteorology and Climatology

LSCS is located in LaSalle County in northeastern Illinois, approximately 75 mi (125 km) 

southwest of downtown Chicago and 35 mi (56 km) southwest of Joliet, Illinois (Exelon 2014a). 

The regional climate is continental with cold winters; warm summers; and frequent short 

fluctuations in temperature, humidity, cloudiness, and wind direction (NCDC 2004). During fall, 

winter, and spring, the polar jet stream is located near or over northeastern Illinois, which 

causes large-scale synoptic storms to move through the area bringing precipitation, winds, and 

often dramatic temperature changes (NCDC 2004). Temperature and precipitation conditions 

vary widely throughout Illinois and between years. A wide range of temperature extremes is 

common in this region (NCDC 2015a). Tornadoes, thunderstorms, hail, and heat and cold 
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waves are common in the state, and flooding is the most damaging weather-related hazard in 

Illinois (NCDC 2004).

The NRC staff obtained climatological data collected at the Peoria, Illinois, airport station 

(KPIA), which is located approximately 62 mi (100 km) from LSCS. Additionally, LSCS 

maintains a meteorological monitoring program that includes a 400-ft (122-m) meteorological 

tower located approximately 0.5 mi (0.8 km) southeast of the reactor buildings. The tower 

measures wind direction, wind speed, temperature, and precipitation. Data from these stations 

were used to characterize the region’s climate and are presented below.

The prevailing wind direction, for the 1981 through 2010 timeframe, at the KPIA station was 

from the south-southwest (NCDC 2015a). The mean annual wind speed for the 1981 through 

2010 timeframe is 8.4 miles per hour (mph) (13.5 kilometers per hour (kph)), and the mean 

monthly wind speed ranges from 6.0 mph (9.7 kph) in August to 10.2 mph (16.4 kph) in March. 

The annual predominant wind direction from the meteorological tower at LSCS for the 

2010 through 2014 timeframe was from the south-southwest direction (for 2011 and 2012) and 

from the west-northwest direction (for 2010, 2013, and 2014) (Exelon 2015j). The mean annual 

wind speed at LSCS for the 2010 through 2014 timeframe is 10.4 mph (16.7 kph) 

(Exelon 2015j).

The mean annual temperature for the 1985 through 2014 period of record at the KPIA station is 

51.9 °F (11.1 °C), with a mean monthly temperature ranging from a low of 25.2 °F (-3.7 °C) in 

January to a high of 75.8 °F (24.3 °C) in July (NCDC 2015a). The hottest year over the period 

of record was in 2012, and coolest was in 1996. The mean annual temperature for the 2010 

through 2014 timeframe at LSCS is 50.7 °F (10.3 °C), with a mean monthly temperature ranging 

from a low of 22.5 °F (-5.3 °C) in January to a high of 75.4 °F (24.1 °C) in July (Exelon 2015j).

The mean total annual liquid precipitation for the 1985 through 2014 period of record measured 

at the KPIA station is 35.9 in. (91.2 cm). The wettest year for the period of record is 55.35 in. 

(140.6 cm) in 1990 (NCDC 2015a); the driest year from the same period is 22.16 in. (56.2 cm) in 

1988 (NCDC 2015a). Monthly precipitation amounts tend to be evenly distributed throughout 

the year and range from an average of 1.9 in. (4.8 cm) in January to 4.3 in. (10.9 cm) in May 

(NCDC 2015a). The mean total annual precipitation measurements taken at LSCS’s 

meteorological tower for the 2010 through 2014 timeframe is 29.83 in. (75.8 cm). Average 

monthly precipitation ranges from a low of 0.93 in. (2.4 cm) in January to a high of 5.89 in. 

(14.9 cm) in June (Exelon 2015j).

LaSalle County, where LSCS is located, experiences severe weather events, such as 

tornadoes, floods, and hail. For the 1950 through 2014 period of record, the following events 

have been recorded (NCDC 2015b):

• 40 tornado events,

• 26 flash floods events,

• 131 hail events, and

• 4 blizzard events.

3.3.2 Air Quality

Under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.), EPA has set 

primary and secondary National Ambient Air Quality Standards (NAAQS) (40 CFR Part 50) for 

six common criteria pollutants to protect sensitive populations and the environment. Primary 

standards specify maximum ambient concentration levels of the criteria pollutants aimed at 
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providing public health protection, including protecting the health of sensitive populations, such 

as asthmatics, children, and the elderly. Secondary standards specify maximum ambient 

concentration levels of the criteria pollutants aimed at providing public welfare protection, 

including protection against decreased visibility and damage to animals, crops, vegetation, and 

buildings. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen 

dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). Particulate matter 

is further categorized by size—PM10 (aerodynamic diameter of 10 micrometers (μm) or less) 

and PM2.5 (aerodynamic diameter of 2.5 μm or less). Table 3–3, identifies the NAAQS for the 

six common criteria pollutants.

Table 3–3. National Ambient Air Quality Standards

Pollutant

Primary/Secondary 

Standard Averaging Time Level

Carbon Monoxide (CO) Primary 8 hour 9 ppm

1 hour 35 ppm

Lead (Pb) Primary and Secondary Rolling 3-month average 0.15 μg/m3

Nitrogen Dioxide (NO2) Primary 1 hour 100 ppb

Primary and Secondary Annual 53 ppb

Ozone (O3) Primary and Secondary 8 hour 0.075 ppm

Particulate matter less than 

2.5 μm (PM2.5)

Primary Annual 12 μg/m3

Secondary Annual 15 μg/m3

Primary and Secondary 24 hour 35 μg/m3

Particulate matter less than 

10 μm (PM10)

Primary and Secondary 2 hour 150 μg/m3

Sulfur Dioxide (SO2) Primary 1 hour 75 ppb

Secondary 3 hour 0.5 ppm

Key: ppb = parts per billion, ppm = parts per million, μg/m3 = micrograms per cubic meter, and 

μm = micrometers. 

Source: EPA 2015d

EPA designates areas of “attainment” and “nonattainment” with respect to the NAAQS. Areas 

that have insufficient data to determine designation status are denoted as “unclassifiable.” 

Areas that were once in nonattainment, but are now in attainment, are called “maintenance” 

areas; these areas are under a 10-year monitoring plan to maintain the attainment designation 

status. States have primary responsibility for ensuring attainment and maintenance of the 

NAAQS. Under Section 110 of the CAA and related provisions, states are to submit, for EPA 

approval, State Implementation Plans that provide for the timely attainment and maintenance of 

the NAAQS.

Air quality designations are generally made at the county level. For the purpose of planning and 

maintaining ambient air quality with respect to the NAAQS, EPA has developed air quality 

control regions (AQCRs), which are intrastate or interstate areas that share a common airshed 

(40 CFR Part 81). LSCS is located in LaSalle County, Illinois. This County, along with an 

additional five neighboring Counties (Bureau, Lee, Marshall, Putnam, and Stark Counties) in 
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Illinois compose the North Central Illinois Intrastate AQCR (40 CFR 81.262). With regard to the 

NAAQS criteria pollutants, LaSalle County is designated as an attainment area for all NAAQS 

(40 CFR 81.314). The nearest designated nonattainment area is Grundy County, for the 8-hour 

ozone 2008 standard. The nearest designated maintenance area is Grundy County for the 

PM2.5 1997 standard. Grundy County is adjacent to LaSalle County, approximately 4 mi (6 km) 

from LSCS. Although Grundy County is adjacent to LaSalle County, it is not part of the same 

AQCR that LaSalle County belongs to.

Illinois air pollution control rules are issued under Title 35 of the IAC. Air emission sources at 

LSCS are regulated under a Federally Enforceable State Operating Permit (FESOP) (Permit 

No. 099802AAA, issued January 7, 2016) by the IEPA (IEPA 2016). A source is eligible for a 

FESOP (also known as “synthetic minor” air permit) if the potential to emit from the source 

triggers CAA permit program requirements but if maximum actual emissions are below, or can 

be restricted to remain below, major source thresholds. LSCS’s FESOP permit will expire in 

August 2025, and in accordance with the Illinois Environmental Protection Act of 1970 

(415 Illinois Compiled Statute (ILCS) 5/39), LSCS will need to submit an application for the 

renewal of the permit. 

Permitted sources at LSCS include 5 large diesel-fired generators (3,489 horsepower) and 

18 small diesel-fired emergency electric generators and pumps (less than 1,500 horsepower). 

The LSCS FESOP permit limits nitrogen oxides, carbon monoxide, particulate matter, volatile 

organic compounds, and/or the sulfur dioxide emissions as well as the fuel consumption from

permitted sources. LSCS has been in compliance with the requirements established in its 

FESOP permit, and there have been no reported violations in the past 5 years (Exelon 2015k; 

EPA 2015b). Emissions from permitted sources at LSCS are presented in Table 3–4. 

Permitted sources are intended to be used during emergency circumstances and only operated 

during routine surveillance and testing (Exelon 2015j). LSCS permitted annual emissions are 

less than 1 percent of the total 2011 emissions for LaSalle County. Air emissions for LaSalle 

County in 2011 for carbon monoxide, nitrogen oxides, sulfur dioxide, particulate matter less than 

10 μm, and particulate matter less than 2.5 μm were 1,213 tons, 2,308 tons, 611 tons, 832 tons, 

and 483 tons, respectively (EPA 2011). LSCS permitted annual emissions are less than 

1 percent of the total 2011 emissions for LaSalle County. 

Table 3–4. LSCS Air Emissions (MT/year)(a)

Pollutant 2008 2009 2010 2011 2012 2013

CO 1.10 1.76 1.65 1.52 2.01 1.6

SO2 0.0042 0.0017 0.0021 0.0017 0.0021 0.001

NOx 4.18 6.62 6.21 5.73 7.58 6.0

PM10 0.075 0.12 0.11 0.10 0.14 0.11

PM2.5 0.075 0.12 0.11 0.10 0.14 0.11

VOC 0.25 0.33 0.32 0.30 0.35 0.30

CO2 -(b) -(b) 315.79 295.46 390.91 308.3

Key: CO = carbon monoxide, NOx = nitrogen oxides, SO2 = sulfur dioxide, PM10 = particulate matter less than 

10 micrometers, PM2.5 = particulate matter less than 2.5 micrometers, and VOC = volatile organic compounds.

(a) To convert metric tons (MT) per year to tons per year, multiply by 1.1023.

(b) Carbon dioxide emissions reporting commenced in 2010; therefore, prior year emissions are not available. 

Sources: Exelon 2014a, 2015k
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On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases

(GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 

(CO2e) per year in the United States (74 FR 56260). Most small facilities across all sectors of 

the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 

to EPA. On June 3, 2010, EPA issued the Prevention of Significant Deterioration (PSD) and 

Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 2011, operating permits 

issued to major sources of GHGs under the PSD or Title V Federal permit programs must 

contain provisions requiring the use of best available control technology to limit the emissions of 

GHGs if those sources would be subject to PSD or Title V permitting requirements because of 

their non-GHG pollutant emission potentials and because their estimated GHG emissions are at 

least 75,000 tons per year of CO2e. As discussed above, LSCS is a synthetic minor source, 

and, as shown in Table 3–4, GHG emissions from sources at LSCS are below the GHG 

Mandatory Reporting (40 CFR Part 98) and Tailoring Rule thresholds. Section 4.15 of this SEIS

further discusses GHG emissions.

EPA issued the Regional Haze Rule to improve and protect visibility in national parks and 

wilderness areas from haze, which is caused by numerous, diverse sources located across a 

broad region (40 CFR 51.308-309). Specifically, Subpart D of 40 CFR Part 81 lists mandatory 

Class I Federal Areas where visibility is an important value. The Regional Haze Rule requires 

states to develop State Implementation Plans to reduce visibility impairment at Class I Federal 

areas. The nearest Class I Federal area for visibility protection is the Mingo National Wildlife 

Refuge, which is in Missouri approximately 306 mi (492 km) southwest of the LSCS site. EPA 

recommends that emission sources located within 62 mi (100 km) of a Class I area be modeled 

to consider adverse impacts (EPA 1992). Considering the distance to the nearest Class I area 

and the minor nature of air emissions from the site, there is little likelihood that ongoing activities 

at LSCS adversely affect air quality and air quality-related values (e.g., visibility or acid 

deposition) in any of the Class I areas.

3.3.3 Noise

Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 

in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 

to a reference level equal to a normal person’s threshold of hearing. Most people barely notice 

a difference of 3 dB or less (FHA 2011). Another characteristic of sound is frequency or pitch. 

Noise may be composed of many frequencies, but the human ear does not hear very low or 

very high frequencies. To represent noise as closely as possible to the noise levels people 

experience, sounds are measured using a frequency weighting scheme known as the A scale. 

Sound levels measured on this A scale are given in units of A-weighted decibels (dBA). Table 

3–5 presents common noise sources and their respective noise levels. Noise levels can 

become annoying at 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 

10 dBA sounds twice as loud (EPA 1981).

Table 3–5. Common Noise Sources and Noise Levels

Noise Source Noise Level (dBA)

Human hearing threshold 0

Soft whisper 30

Quiet residential area 40

Dishwasher 55–70

Lawn mower 65–95
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Noise Source Noise Level (dBA)

Blender 80–90

Ambulance siren, jet plane 120

Source: CHC undated

Several different terms are commonly used to describe sounds that vary in intensity over time. 

The equivalent sound intensity level (Leq) represents the average sound intensity level over a 

specified interval, often 1 hour. The day-night average sound intensity level (LDN) is a single 

value calculated from an hourly Leq over a 24-hour period, with the addition of 10 dBA to sound 

levels from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 

nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded “n” percent of the 

time during a given period. For example, L90, is the sound level exceeded 90 percent of the 

time and is considered the background level.

There are no Federal regulations1 for public exposures to noise (EPA 2015c). The EPA 

recommends day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for 

outdoors in residential areas (EPA 1974). However, these are not standards. The Federal 

Housing Administration has established noise assessment guidelines for housing projects and 

finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014). 

Sections 25 and 27 of the Illinois Environmental Protection Act of 1970 (Chapter 415)

established the authority to create noise regulations. The actual noise regulations are found in 

the IAC (Title 35, Subtitle H). These noise regulations have allowable octave-band sound levels 

according to emitting and receiving land class (Class A, B, and C) and time of day.

Major offsite noise sources in the vicinity of LSCS include vehicles, wind turbines, and 

agricultural equipment/machinery (Exelon 2015l). Common noise sources from nuclear power 

plant operations include transformers, loudspeakers, cooling towers, auxiliary equipment, and 

worker vehicles (NRC 2013). Major noise sources at LSCS include pumps, turbine building 

supply and exhaust fans, sirens, generators, transformers, and loudspeakers (Exelon 2015m). 

However, most of these noise sources are inside buildings, at approximately a 980-ft (300-m) 

distance from the site boundary, and/or are intermittent. The nearest resident is approximately 

0.7 mi (1.1 km) from the reactor buildings (Exelon 2014a). Exelon has not received any noise 

complaints from residents in the vicinity of LSCS (Exelon 2014a). Additional noise sensitive 

receptors nearby include the LaSalle Lake State Fish and Wildlife Area and Marseilles State 

Fish and Wildlife Area. LSCS is subject to, and in compliance with, Illinois noise pollution 

control regulations (Exelon 2015c, 2015m).

3.4 Geologic Environment

This section describes the current geologic environment of the LSCS site and vicinity, including 

landforms, geology, soils, and seismic conditions.

 1 In 1972, Congress passed the Noise Control Act of 1972 (42 U.S.C. 4901 et seq.) establishing a 

national policy to promote an environment free of noise that impacts the health and welfare of the 

public. However, in 1982, there was a shift in Federal noise control policy to transfer the responsibility 

of regulation noise to state and local governments. The Noise Control Act of 1972 was never rescinded 

by Congress, but it remains unfunded (EPA 2015c).
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3.4.1 Physiography and Geology

The site is located in an area that contains glacially deposited sediments overlying a bedrock 

surface. These deposits formed during successive periods of glaciation. The power block and 

the cooling pond are located on a glacial moraine (a depositional landform directly deposited by 

a glacier). This area has a flat gently rolling topography. The river screen house is located 

north of both the power block and cooling pond on the flat-lying river valley of the Illinois River. 

The river valley is approximately 3.5 mi (5.6 km) north of the site and is topographically 

separated from the glacial moraine by the bluffs along the Illinois River. The bluffs along the 

Illinois River are dissected by stream valleys that cut into the glacial sediments and drain north 

to the Illinois River. The maximum topographic relief between the site and the river is 

approximately 255 ft (78 m) (Exelon 2014a; USDA 2008) (Figure 3–7).

In the area of the power block and the cooling pond, the land is covered by a 4- to 8-ft (1.2- to 

2.4-m) layer of Richland Loess. The loess consists of windblown silt that has been weathered 

to slightly clayey silt. The Richland Loess is underlain by the Wedron Silty-Clay Till. The till was 

directly deposited by glacial activity. It consists of unsorted silt and clay sedimentary deposits. 

In localized areas, the till also contains scattered, disconnected bodies of sand and gravel. In 

the area of the plant buildings and cooling pond, the Wedron Silty-Clay Till ranges in thickness 

from 120 to 140 ft (37 to 43 m). Moving north from the plant buildings and the cooling pond to 

the river, the Wedron Silty-Clay Till decreases in thickness until it disappears near the Illinois 

River (Figure 3–8) (Exelon 2014a).

Below the LSCS site, the Wedron Silty-Clay Till is underlain by bedrock. The topography of the 

bedrock reflects the surface of the land before glaciation. This topography is now buried by 

glacially deposited sediments. The site is located between two bedrock valleys that are filled 

with the Wedron Silty-Clay Till and some alluvial sand and gravel deposits from ancient streams 

that flowed through the bedrock valleys before they were completely buried. One alluvium-filled 

buried valley runs east-west and is located between the plant facility and the Illinois River Bluff, 

and one valley is located south of the plant facility and trends northwest and southeast 

(Exelon 2014a, 2014b) (Figure 3–9).

The underlying bedrock consists of 4,500 ft (1,371 m) of dolomite, sandstone, and shale rock. 

In turn, these rocks are underlain by granites and metamorphic rocks to a great depth. The 

Pennsylvanian aged Carbondale Formation forms the top of the bedrock surface over most of 

the site area. It is composed of alternating strata of shale, sandstone, clay, coal, limestone, and 

siltstone (Exelon 2014a).

LaSalle County contains a number of geologic resources of economic importance. The County 

is one of a handful of locations that can easily access the St. Peter Sandstone Formation. The 

unique characteristics of this sandstone make it valuable for a number of commercial uses, 

including glass, sand filters, sand molding, and abrasives. It is also in high demand for the 

extraction of oil and gas using conventional horizontal drilling and shale fracking techniques. 

LaSalle County also contains commercial deposits of gravel and limestone. Limestone and 

gravel are used in concrete, agricultural limestone, and road surfaces. Clay is mined in the 

county to manufacture bricks, drain tile, and dinnerware. Coal is no longer mined in the County 

but historically was mined in bluffs along the Illinois River and around Streator, Illinois 

(Ataner and Butler 2013; LaSalle County 2014; USDA 2008).

The LSCS site is underlain by coal seams, limestone beds, and the St. Peter Sandstone. 

However, they lie too deep beneath the land surface to be economically accessed. No oil and 

gas deposits have been identified beneath the site.
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3.4.2 Soils

Eighty-five percent of the soil in LaSalle County is designated as prime farmland, and 9 percent 

is farmland of State importance (Exelon 2014a). Within the site boundary, almost all the soil is 

either silty loam or silty clay loam and is designated as prime farmland or farmland of State 

importance (Exelon 2014a; USDA 2008, 2015b).

Following initial construction of the facility, areas surrounding LSCS were graded to control 

runoff and to minimize erosion. Many areas were revegetated to support this effort

(Exelon 2014a).
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Figure 3–7. Site Physiography, LSCS Vicinity

Source: NRC Generated
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Figure 3–8. North-South Geologic Cross Section, LSCS Vicinity

(Elevation Exaggerated)

Source: Modified from Exelon 2014a
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Figure 3–9. Bedrock Topography and Buried Valleys, LSCS Vicinity

Source: Modified from Exelon 2014b
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3.4.3 Seismic Setting

The site is located in an area of Illinois that might experience slight damage from earthquakes

(FEMA 2015; Mid-America Earthquake Center 2009). A number of earthquakes (USGS 2013a, 

2013b, 2013c) have originated within Illinois, including the following:

• On May 26, 1909, a large earthquake knocked over many chimneys in Aurora and 

swayed buildings in Chicago.

• On July 18, 1909, an earthquake knocked down chimneys in Petersburg.

• On August 14, 1965, a sharp local earthquake knocked down chimneys in Elco, 

Unity, Olive Branch, and Olmstead.

• On November 9, 1968, a magnitude 5.3 earthquake was felt over the entire State of 

Illinois and in 22 other states.

Dozens of earthquakes originating outside Illinois have been felt inside the State without 

causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 

Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. Illinois can be affected by two 

major seismic zones, the Wabash Valley Seismic Zone and the New Madrid Seismic Zone. The 

Wabash Valley Zone lies between southeastern Illinois and southwestern Indiana about 322 mi 

(518 km) from the site. The New Madrid Seismic Zone is about 300 mi (483 km) from the site in 

southern Illinois, Missouri, Kentucky, and Tennessee. Of these two seismic zones, the New 

Madrid Seismic Zone is capable of producing very powerful earthquakes. If a large magnitude 

earthquake occurs in the New Madrid Seismic Zone, major damage could be experienced in 

southern Illinois (Missouri Department of Natural Resources 2013; USGS 2009).

The NRC requires every nuclear power plant to be designed for site-specific ground motions 

that are appropriate for its location. Nuclear power plants, including LSCS, Units 1 and 2, are 

designed and built to withstand site-specific ground motion based on their location and nearby 

earthquake activity. For LSCS, this includes earthquakes originating in either the Wabash 

Valley Zone or the New Madrid Seismic Zone (Exelon 2014a). The seismic design basis is 

established during the initial siting process using site-specific seismic hazard assessments. For 

each nuclear power plant site, applicants estimate a design-basis ground motion based on 

earthquake sources, wave propagations, and site responses; this estimate is then accounted for 

in the design of the plant. In this way, nuclear power plants are designed to withstand the 

maximum credible earthquake for a given site. Because methods of assessing seismic hazards 

evolve over time and the scientific understanding of earthquake hazards improve (NRC 2014b),

the NRC’s understanding of the seismic hazard for a given nuclear power plant may change 

over time. As new seismic information becomes available, the NRC evaluates the new 

information to determine whether changes are needed at existing plants or to NRC regulations. 

The NRC’s evaluation of the impact of seismic activity on a nuclear power plant is an ongoing 

process that is separate from the license renewal process.

On December 23, 2011, the Consolidated Appropriations Act (Public Law 112–074) was signed 

into law. Section 402 of the law directs the NRC to require reactor licensees to re-evaluate the 

seismic hazard at their sites against current applicable Commission requirements and 

thereafter, when appropriate, as determined by the Commission (NRC 2012). In 2012, the NRC 

required all licensees to re-evaluate the seismic hazards at their sites using updated seismic 

information and present-day regulatory guidance and methodologies (NRC 2012). The purpose 

of that request was to gather information to update the seismic hazards analysis to enable the 

NRC staff to determine whether individual site licenses should be modified, suspended, or 

revoked (NRC 2014a). On March 31, 2014, Exelon responded to this request and provided its 
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Seismic Hazard and Screening Report (SHSR) for LSCS (Exelon 2014d). On April 21, 2015,

the NRC staff issued an assessment (NRC 2015a) documenting its review of the Seismic 

Hazard and Screening Report. The NRC staff concluded that Exelon met the intent of the 

guidance for determining the re-evaluated seismic hazard and that it had provided an 

acceptable response to the request. In addition, the NRC staff directed Exelon to perform 

further seismic evaluations for NRC review.

3.5 Water Resources

3.5.1 Surface Water Resources

This section describes the current surface water resources within and near LSCS.

NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants

(GEIS) (NRC 2013), states that surface water encompasses all water bodies that occur above 

the ground surface, including rivers, streams, lakes, ponds, and man-made reservoirs or 

impoundments.

3.5.1.1 Surface Water Hydrology

The major surface water body in the region is the Illinois River, located approximately 4 mi 

(6.4 km) to the north of the LSCS main plant complex (see Figure 3–2). The LSCS site is 

situated within the lowermost portion of the Upper Illinois River Basin, which includes the 

10,949-mi2 (28,369-square-kilometer (km2

)) drainage area upstream from Ottawa, Illinois 

(Figure 3–10). The Illinois River is formed from the confluence of the Kankakee and Des 

Plaines Rivers at a point approximately 10 mi (16 km) east of Morris, Illinois. The main stem of 

the Illinois River is joined by the Fox River at Ottawa (Arnold et al. 1999; USGS 1998).

The Illinois River is also central to the Illinois Waterway, which provides for navigation from Lake 

Michigan to the Mississippi River and on to the Gulf of Mexico. The origins of this waterway 

began with the construction of canals from the lake to the Chicago and Illinois Rivers, beginning 

in the 1830s. Construction of the formal Illinois Waterway began in 1919 with the State of 

Illinois leading efforts in the upper part of the river basin and the U.S. Army Corps of Engineers

(USACE) in the lower part. Today, the Illinois Waterway includes part of the Chicago River, the 

Chicago Sanitary and Ship Canal, the Des Plaines River, and the Illinois River. Navigation is 

made possible by a series of eight major locks and dams and associated navigation pools along 

the Illinois River and its tributaries. Each pool is named for the dam downstream of each pool 

(Exelon 2014a; Talkington 1991). Along its length, the waterway contains a navigation channel 

at least 9 ft (2.7 m) deep and 300 ft (91 m) wide (Talkington 1991). In the vicinity of LSCS, at 

normal pool elevation, the river has a depth of 12 ft (3.7 m) and a width of 800 ft (244 m)

(Exelon 2014a).

LSCS is located along the Marseilles Pool portion of the Illinois River. The Marseilles Dam at 

Illinois RM 247 (RKm 397.5) is approximately 2.4 mi (3.9 km) downstream of the LSCS intake 

and discharge structures near RM 249.5 (RKm 401.5) (see Section 3.1.3). However, the lock 

itself is located a further 2.5 mi (4.0 km) downstream of the dam on a bypass canal (Marseilles 

Canal) (USACE 2014). The Dresden Island Lock and Dam is 22 mi (35 km) upstream of the 

LSCS intake structure at RM 271.5 (RKm 437) (Exelon 2014a). The Marseilles Dam is 24 ft 

(7.3 m) high, and the Dresden Dam is 22 ft (6.7 m) high (Talkington 1991).

In total, the main stem of the Illinois River flows for approximately 270 mi (439 km) through 

Illinois and ultimately discharges into the Mississippi River at Grafton, Illinois (Exelon 2014a; 

USGS 1994; Talkington 1991). However, when accounting for the other components of the 

Illinois Waterway, the total length of the river system is 327 mi (526 km) (Talkington 1991).
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The U.S. Geological Survey (USGS) maintains a gaging station on the Illinois River at 

Marseilles, Illinois (Station 05543500) and RM 246.5 (RKm 396.7). This station is 

approximately 3 mi (4.8 km) downstream from the LSCS river screen house intake and nearby 

discharge structure near RM 249.4 (RKm 401). The gaging station is also 0.5 mi (0.8 km) 

downstream of the Marseilles Dam and 6.9 mi (11 km) upstream from the confluence of the Fox 

River with the main stem of the Illinois River (Exelon 2014a; USGS 1999b, USGS 2015). 

The mean annual discharge measured at the USGS gage at Marseilles for water years 1920 

through 2014 is 10,750 cfs (304 m3

/s). For water year 2014, the mean discharge was 

11,190 cfs (316 m3

/s). The mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the 

period of record (USGS 2015). The 90 percent exceedance flow is an indicator value of 

hydrologic drought. It signifies a rate of streamflow that is equaled or exceeded 90 percent of 

the time, as compared to the average flow for the period of record. Based on average monthly 

flow over the period of record at the station, November is the low-flow month, and April is the 

high-flow month for the Marseilles Pool (USGS 2015).

Tributaries to the Illinois River in the immediate vicinity of LSCS include South Kickapoo Creek, 

Spring Brook, Deadly Run, Armstrong Run, and Hog Run (Figure 3–11). These headwater 

streams and manmade ditches drain the glacial upland on which LSCS is located and generally 

flow north toward the dissected bluffs of the river and across the river valley and into the Illinois 

River. The most extensive of these nearby tributaries is South Kickapoo Creek. With its 

headwaters on the northwest side of the LSCS property, this stream receives stormwater runoff,

cooling pond dike seepage collected by the LSCS perimeter drainage ditch, and overflow from 

the cooling pond auxiliary spillway (see Figure 3–6). The main channel of South Kickapoo 

Creek flows north to northwest from LSCS, with the main channel discharging to the Illinois 

River at a point approximately 3.5 mi (5.6 km) northwest of the LSCS cooling pond and 

approximately 0.4 mi (0.6 km) downstream of the LSCS blowdown discharge structure 

(Exelon 2014a).

On the northeast perimeter of the cooling pond is Armstrong Run. Armstrong Run previously 

drained much of the area that is now occupied by LSCS before plant construction. Like many of 

the manmade drainage channels (called “runs”) in the region, it was constructed to convey 

drainage collected by agricultural drain tile systems (NRC 1978). Armstrong Run now receives 

runoff and seepage collected from the northeast end of the peripheral dike drainage ditch. 

It discharges to the Illinois River at a point approximately 3.2 mi (5.1 km) northeast of the 

cooling pond and about 4.5 RM (7.2 RKm) upstream of the river screen house (Exelon 2014a).

As further described in Section 3.1.3, the dominant surface water feature within the LSCS site 

and vicinity is the 2,058- ac (833- ha) cooling pond (Figure 3–5 and 3–11). Other surface water 

features on the LSCS plant site include two stormwater management ponds (North and South 

Storm Water Ponds), two sewage treatment lagoons, and a collection of hatchery ponds as 

summarized below. The NRC staff visited the facilities cited herein during the May 2015 

environmental site audit (NRC 2015b).

The North and South Storm Water Ponds are located west of the LSCS main plant complex and 

receive stormwater runoff from the protected area, serving the north and south zones of the 

plant, respectively. Within the site, a system of ditches, storm drains, culverts, and underground 

storm sewers collect runoff and drainage from the protected area and convey much of it to 

either of the two ponds. Uncontaminated runoff from the north zone of the plant is conveyed to 

the North Storm Water Pond, with some runoff sources first passing through the Unit 2 oil-water

separator. A portion of the switchyard also drains toward the north zone, although most of the 

switchyard drains east to the cooling pond.
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Figure 3–10. The Upper Illinois River Basin and Drainage Basin Boundaries

Source: Modified from Arnold et al. 1999
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Figure 3–11. LSCS Surface Water and Related Water Resource Features

Source: Modified from Exelon 2014a, 2015p
Affected Environment

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Most runoff from the south zone enters the smaller South Storm Water Pond; this pond then 

discharges to the cooling pond discharge canal through internal Outfall H01. Before entering 

the pond, some flows first pass through the Unit 1 oil-water separator. The south pond also 

receives runoff from the firing range. Areas of the plant site to the northwest and south of the 

developed plant complex do not drain to the ponds but instead are drained by existing surface 

stream segments and ditches (Exelon 2014a, 2014f).

Stormwater management and pollution control at LSCS is subject to Exelon’s Storm Water 

Pollution Prevention Plan (SWPPP) (Exelon 2013e), which Exelon has implemented in 

accordance with Special Condition 8 of the site’s NPDES permit (IEPA 2013). The SWPPP 

applies to industrial stormwater runoff from the site, which is not otherwise process-related and 

not captured and processed by LSCS’s wastewater treatment facilities. It describes the best 

management practices, controls, inspection, and monitoring requirements, and the associated 

implementing procedures and personnel responsibilities for reducing pollutants in stormwater 

discharge and for ensuring compliance with the terms and conditions of the site NPDES permit 

(Exelon 2013e).

Two open sewage treatment lagoons provide primary and secondary treatment for LSCS’s

sanitary effluent. These lagoons are clay and geotextile-lined impoundments and are located to 

the north of the main plant complex adjacent to LSCS’s sewage treatment plant (as shown in 

Figure 3–3). Together, the NRC staff estimates the two impoundments cover an area of about 

1.6 ac (0.65 ha). After filtration and final disinfection in the sewage treatment plant, the final 

effluent from the treatment system is discharged into the cooling pond via NPDES internal 

Outfall B01 (Exelon 2014a, 2014f).

A cluster of 16 small fish-rearing ponds is located on the southwest shore of the cooling pond 

(see Figures 3–6 and 3–11). The NRC staff estimates that the ponds total approximately 29 ac 

(12 ha) of open water. These ponds comprise the LaSalle Fish Hatchery operated by the IDNR

on plant property and subject to a lease agreement with Exelon. The hatchery uses the cooling 

pond as a makeup water source. Runoff and drainage from the hatchery ponds flow back to the 

cooling pond and are ultimately subject to LSCS’s NPDES permit provisions 

(Exelon 2014a, 2014f). The LSCS site’s NPDES permit is further discussed in Section 3.5.1.3.

LSCS is not susceptible to riverine flooding because it is located upland and away from the 

Illinois River.

The grade elevation at the plant site is 710 ft (216 m) above MSL, and the floor elevation of the 

LSCS facilities is 710.5 ft (217 m) above MSL. The plant floor lies at an elevation that is 188 ft 

(57 m) above the level of a postulated probable maximum flood on the Illinois River 

(Exelon 2014a, 2014g). Although the river screen house is not a safety-related structure, it is 

designed to withstand the 100-year flood on the Illinois River. Its loss would not impact the 

ability to safely shut down the plant as water could still be drawn from the cooling pond and from 

the UHS portion of the cooling pond, as described in Section 3.1.3 of the SEIS (Exelon 2014a, 

2014b).

Furthermore, a failure of the peripheral dike system enclosing the cooling pond would not flood 

the power plant area because the onsite topography would cause cooling pond water to flow 

north and away from the plant following the existing drainage network (Exelon 2014a, 2014b).

3.5.1.2 Surface Water Use

LSCS withdraws surface water from the Illinois River as makeup water for the plant’s cooling 

pond. The cooling pond provides water for the plant’s circulating water, service water, and 

essential cooling water systems. Cooling pond blowdown and other permitted effluent streams 

are discharged back to the Illinois River via the plant’s primary NPDES outfall (Outfall 001) at a 
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3-41

point located about 900 ft (270 m) downstream from LSCS’s river intake structure and 

associated river screen house.

The maximum (nominal) surface water withdrawal rate for LSCS, Units 1 and 2, is 90,000 gpm 

(200 cfs or 5.66 m3

/s). This is equivalent to 129.6 mgd (491,000 m3/day). However, Exelon

reports in its ER that LSCS’s normal peak makeup withdrawal rate from the Illinois River is 

60,000 gpm (134 cfs or 3.77 m3

/s) or 86.4 mgd (327,000 m3/day). This rate assumes a 

two-pump operation with valves open at 100 percent. The third makeup pump located in the 

river screen house normally serves as a backup (see Section 3.1.3).

The NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that document 

the volume of surface water withdrawn from, and discharged back to, the Illinois River during 

the period 2009 to 2013 (Table 3–6). Based on these data, LSCS surface water withdrawals 

have averaged 24,745 million gallons per year (mgy) (93.7 million cubic meters per year 

(m3

/yr)). This is equivalent to an average withdrawal rate of approximately 105 cfs (2.96 m3/s or

67.8 mgd). Return discharges (blowdown) to the Illinois River have averaged 13,046 mgy 

(49.4 million m3

/yr), which is equivalent to an average discharge rate of about 55.3 cfs 

(1.56 m3

/s or 35.7 mgd). The difference between withdraw and discharge (i.e., approximately 

49.7 cfs (1.40 m3

/s)) generally reflects process consumptive use or other losses, evaporative

losses, and presumably seepage from the cooling pond. In total, these data indicate a 

consumptive use rate averaging 47 percent.

Table 3–6. Annual Surface Water Withdrawals and Returns to the Illinois River, LSCS

Year

Withdrawals 

(mgy) mgd cfs

Discharges 

(mgy) mgd cfs

2009 28,598.4 78.5 121 19,405.0 53.2 82.2

2010 25,876.8 70.9 110 13,686.0 37.5 58.0

2011 23,328.0 63.9 98.9 11,961.1 32.8 50.7

2012 28,857.6 79.1 122 14,005.7 38.4 59.4

2013 17,064.0 46.7 72.3 6,173.0 16.9 26.2

Average 24,745.0 67.8 105 13,046.1 35.7 55.3

Note: Reported and calculated values are rounded. To convert million gallons per year (mgy) to million cubic 

meters (m3), divide by 264.2. To convert, million gallons per day (mgd) to cubic feet per second (cfs), multiply by 

1.547.

Sources: Exelon 2011a, 2012a, 2013a, 2014a, 2014e

LSCS’s surface water withdrawals and consumptive water use are not subject to any water 

allocation or related permitting requirements at the present time. In 2006, the Governor of 

Illinois issued an executive order establishing a Statewide program for State and regional water 

supply planning and management, which included the development and approval of regional 

plans in designated Priority Water Quantity Planning Areas (State of Illinois 2006). LaSalle 

County, where LSCS is located, is not included within any of the three designated planning 

areas (Exelon 2014a; ISWS 2015a). Nevertheless, as referenced above, Exelon reports its 

surface water withdrawals to the State of Illinois under the State Illinois Water Inventory 

Program (Exelon 2014a; ISWS 2015b). Reporting is required in accordance with the Illinois 

Water Use Act of 1983 (525 ILCS 45) and its 2010 amendments. The general purpose and 

intent of the Act is “to establish a means of reviewing potential water conflicts before damage to 

any person is incurred and to establish a rule for mitigating water shortage conflicts.” The 
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2010 amendments to the Illinois Water Use Act added high-capacity intakes as subject to the 

Act’s water use reporting provisions. Such intakes are surface water intakes on a property in 

which the rate or capacity of water withdrawal of all intakes for the property is equal to, or in 

excess of, 100,000 gal (380 m3

) during any 24-hour period (525 ILCS 45).

Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 

cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 

Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 

and associated procedures to mitigate the impacts of summer drought and/or high river 

temperature and river low-flow conditions. Depending on predefined conditions set forth in the 

plan and implementing procedures, such actions may include a combination of monitoring and 

modeling of river intake and mixing zone temperatures; manipulation of the water level of the 

cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 

cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the TS

limits on condenser inlet temperature from the cooling pond (Exelon 2014a, 2015c).

Two other industrial facilities withdraw water from the Marseilles Pool of the Illinois River in the 

vicinity of LSCS (Figure 3–5) and are listed in the Illinois Water Inventory Program. These are 

Agrium U.S., Inc., and PCS Phosphate, Marseilles Operation. The volume of water withdrawn 

by these commercial facilities is not publicly available (Exelon 2014a). Because they are 

included in the State’s inventory, the NRC staff presumes that each facility withdraws in excess 

of 100,000 gpd (380 m3

). Both are also currently subject to NPDES individual permits 

(i.e., Permits IL0001708 and IL0036463). Based on reported return discharges to the Illinois 

River, it is estimated that Agrium’s surface water withdrawals are on the order of 5 mgd 

(18,900 m3

) (EPA 2015a).

The public water supply systems in the vicinity of LSCS (i.e., the city of Marseilles and the 

village of Seneca) do not withdraw water from the Illinois River but instead rely upon 

groundwater-supplied systems (Exelon 2014a) (see Section 3.5.2.2).

Surface water withdrawals within the Marseilles Pool have shown no significant effects on water 

availability to date (Exelon 2014a).

3.5.1.3 Surface Water Quality and Effluents

The Illinois Pollution Control Board (IPCB), a sister agency to the IEPA, promulgates water 

quality standards in the State. Two Sections of Title 35 of the IAC (35 IAC 302 and 35 IAC 303) 

contain the standards applicable to lakes and streams. Procedures that must be followed in 

using water quality standards to set NPDES permit limits appear in Section 309 (35 IAC 309).

Designated uses prescribed by 35 IAC 303 are those uses specified in water quality standards 

for each lake, river, stream, and groundwater resource. In designating uses for a waterbody, 

the IPCB considers the use and value of the waterbody for public water supply; propagation of 

fish, shellfish, and wildlife; and recreational, agricultural, industrial, and navigational purposes.

The main stem of the Illinois River is designated a “general use water” by the IPCB. Waters in 

the general use category must meet water quality standards protective of aquatic life, wildlife, 

agricultural use, and secondary contact use, as well as most industrial uses and aesthetic

quality (35 IAC 303.201). These standards pertain to pH; phosphorus; dissolved oxygen;

radioactivity (gross beta, strontium-90, and radium-226 and -228); various chemical constituents 

(metals and organic compounds); fecal coliform; and other toxic substances. In addition, a 

segment of the main stem of the Illinois River within LaSalle and Grundy Counties, and 

encompassing the entire Marseilles Pool on which LSCS is located, is afforded “enhanced 

dissolved oxygen protection.” Dissolved oxygen levels must be not less than 5.0 milligrams per 
Affected Environment

3-43

liter at any time during March through July and not less than 4.0 milligrams per liter at any time 

during August through February (35 IAC 302.206).

Over the last 150 years, water quality within the whole of the Illinois River Basin has historically 

suffered from rapid population growth; urbanization; and industrial development, including the 

conversion of prairie, wetlands, and forests. This change resulted in the discharge of untreated 

and inadequately treated sewage, the discharge of industrial pollutants and refuse, runoff of 

agricultural chemicals and sediments, and the alteration of the natural river hydrology due to 

navigation and flood control projects (Exelon 2014a; Talkington 1991).

Over the last 50 years, substantial improvements in water quality have occurred because of

municipal and industrial waste treatment and management efforts to address both point and 

nonpoint pollutant sources. Ongoing water quality concerns within the upper Illinois River Basin 

include the atmospheric deposition of pesticides and trace metals; endocrine disrupting 

compounds in surface and groundwater; nutrient enrichment of surface and groundwater; the 

transport and fate of pesticides, trace elements, and volatile organic compounds in surface and 

ground water; and the effects of urbanization on biodiversity, habitat, and water quality 

(USGS 1998).

Section 303(d) of the Federal Water Pollution Control Act (i.e., Clean Water Act of 1977, as 

amended (CWA) (33 U.S.C. 1251 et seq.)) requires the State of Illinois and other states to 

identify all “impaired” waters for which effluent limitations and pollution control activities are not 

sufficient to attain water quality standards in such waters. The Section 303(d) list includes those 

water quality-limited stream segments that require the development of total maximum daily 

loads (TMDLs) to ensure future compliance with water quality standards. The TMDLs specify 

the maximum amount of a pollutant that a waterbody can receive and still meet water quality 

standards. Once established, TMDLs are typically implemented through watershed-based 

programs administered by the State, primarily through the NPDES permit program and 

associated point and nonpoint source water quality improvement plans and associated best 

management practices. The IEPA has classified a 30.1-mi- (48.4-km)-long segment (IL_D-23) 

of the Illinois River between Morris and Ottawa, Illinois, that includes the LSCS site as impaired. 

This segment is listed as impaired because it does not meet designated uses for fish 

consumption due to polychlorinated biphenyls (PCBs) and mercury contamination. It is also 

impaired for primary contact recreation use due to fecal coliform bacteria (IEPA 2014b). Special 

Condition 13 of the NPDES permit for LSCS prohibits the discharge of PCBs in plant effluents 

(IEPA 2013). The river segment is classified as fully supporting its designated use for aquatic 

life. IEPA has assigned a medium priority for the development of TMDLs for segment IL_D-23

(IEPA 2014b).

As for other streams and runs in the vicinity of LSCS, IEPA (2014b) designates them as 

Category 3, which are waters for which no use-support determination can be made due to 

insufficient available data and/or information.

The LSCS cooling pond is included in the IEPA’s CWA Section 314 inventory of lakes and has 

also been designated as Category 3 (IEPA 2014b). However, LSCS’s cooling pond is defined 

by the State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 

definition, the cooling pond is not waters of the State under 35 IAC 301.440. Likewise, as 

defined in 40 CFR 230.3, pursuant to the Federal CWA, “waste treatment systems, including 

treatment ponds or lagoons designed to meet the requirements of the Clean Water Act” are 

explicitly excluded from the definition of “waters of the United States.” Therefore, the cooling 

pond is not subject to State or Federal water quality standards. Similarly, the LSCS 

closed-cycle, recirculating, cooling pond is exempt from impingement and entrainment

monitoring requirements under Section 316(b) of the CWA.
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To operate a nuclear power plant, licensees must comply with the CWA, including associated 

requirements imposed by EPA or the state as part of the NPDES permitting system under

Section 402 of the CWA, as well as state water quality certification requirements under 

Section 401 of the CWA. The EPA or the state, not the NRC, sets limits for effluents and 

cooling water system operational parameters in plant-specific NPDES permits. Nuclear power 

plants cannot operate without a valid NPDES permit and a current CWA Section 401 Water 

Quality Certification. The EPA has delegated responsibility to the State of Illinois for the 

administration of the NPDES program in Illinois. NPDES permits are issued by the IEPA on a 

5-year cycle.

LSCS is authorized to discharge various wastewater (effluent) streams, including cooling pond 

blowdown and stormwater under NPDES Permit IL0048151, reissued on July 5, 2013; the 

current permit expires on July 31, 2018 (Exelon 2014a; IEPA 2013). The permit specifies the 

discharge standards and monitoring requirements for effluent chemical and thermal quality 

through the plant’s outfalls to the Illinois River, as summarized in Table 3–7. The location of the 

LSCS’s primary outfall (001) to the Illinois River is shown in Figure 3–5.

Table 3–7. National Pollutant Discharge Elimination

System-Permitted Outfalls, LSCS

Outfall

Average Flow 

Rate (mgd)(a) Description

001(b,c,d,e) 34.9 Cooling Pond Blowdown; includes effluents from internal Outfalls A01 

through H01, as well as IDNR fish hatchery effluents; discharge to the 

Illinois River

A01(b,f,g) Intermittent Demineralizer Regenerant Wastes; includes makeup demineralizer 

regenerant wastes, off-specification demineralized water, makeup 

demineralizer maintenance wastewater, unit waterbox vacuum pump 

condensate, and radioactive waste (radwaste) treatment acid/caustic 

system drains discharges

B01(b,c,f,g,h) 0.06 Sewage Treatment Plant Effluent; includes sanitary wastewater and 

eyewash station wastewater

C01(b,c,f,g,i) 0.044 Wastewater Treatment System Effluent; includes nonsanitary drains 

composed of turbine building fire and miscellaneous nonradioactive 

wastewater sump, greensand filter backwash, diesel fuel storage and 

service water building sump, auxiliary boiler blowdown, water softener 

regenerant waste, demineralizer regenerant wastes, heat bay building 

roof area, fire protection system flushing and maintenance, service 

water system flushing and maintenance, domestic water system 

flushing and maintenance, clean condensate system flushing and 

maintenance, laboratory liquid wastes, station heat system condensate, 

diesel generator cooling water, standby liquid control test skid flush 

water, and groundwater

D01(f) Intermittent Cooling Water Intake Screen Backwash 

E01(b,f g,i) Intermittent Unit 1 and 2 Radwaste Treatment System Effluent; includes equipment 

and floor drains in the turbine, auxiliary, and reactor buildings, as well as 

condensate polisher waste from the turbine building and 

decontamination and laundry waste

F01(f) Intermittent Auxiliary Reactor Equipment Cooling and Flushing Water 

G01(f,j) Intermittent North Site Stormwater Runoff

H01(f,j) Intermittent South Site Stormwater Runoff
Affected Environment

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Outfall

Average Flow 

Rate (mgd)(a) Description

I01(b,f,g) Intermittent Reverse Osmosis System Reject Water and Greensand Filter 

Backwash

002(k) Intermittent Illinois River Makeup Water Intake Screen Backwash; includes river 

intake screen backwash; trench wash water; process sampling 

discharge; lake makeup pump gland leakoff; coolers/reliefs flow; lake 

makeup pump strainer backwash; air compressor receiver and prefilter 

drainage; dewatering pump discharge; fire protection water; and river 

screen house switchyard stormwater runoff, floor drains, and roof 

drains; discharge to the Illinois River at the river screen house

(a) To convert million gallons per day (mgd) to million cubic meters (m3), divide by 264.2.

(b) Flow is subject to monitoring and reporting in units of mgd as a monthly average and as a daily maximum on 

Discharge Monitoring Report (DMR) (NPDES permit Special Condition 1).

(c) pH is subject to limit of 6.0 to 9.0 (NPDES permit Special Condition 2).

(d) Temperature is subject to continuous monitoring and DMR reporting of maximum monthly, as well as with 

temperature limits and mixing zone criteria (NPDES permit Special Condition 3). The calculated temperature at 

the edge of the mixing zone is limited to no more than 5 °F (2.8 °C) higher than ambient river temperature. The 

temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent 

(i.e., 87.6 hours) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 

1.7 °C (3 °F). During the months of April through November, the calculated temperature outside the mixing 

cannot exceed 93 °F (34 °C).

(e) Total residual chlorine is subject to a limit of 0.05 milligrams per liter (NPDES permit Special Conditions 4 

and 16).

(f) This outfall is the NPDES permit internal monitoring point before the numbered point source outfall.

(g) Total suspended solids are subject to specified limits and monitoring.

(h) Carbonaceous biochemical oxygen demand is subject to specified limits and monitoring.

(i) Oil and grease are subject to specified limits and monitoring.

(j) Stormwater is subject to requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special 

Condition 8).

(k) Adequate maintenance of intake screen system is required to prevent discharge of floating debris back to the 

river. The stormwater portion is subject to the requirements of the Storm Water Pollution Prevention Plan 

(NPDES permit Special Condition 8).

Note: The release of complex metal-bearing waste streams and polychlorinated biphenyls (PCBs) from all outfalls 

is prohibited by NPDES permit Special Conditions 5 and 13, respectively. Special Condition 9 authorizes the use 

of water treatment additives that were requested by Exelon as part of the renewed NPDES permit application.

Source: IEPA 2013

As indicated in Table 3–7, the NPDES permit for LSCS requires Exelon to monitor and sample 

site effluents for various parameters in accordance with applicable effluent limits. Monitoring 

results are reported in monthly Discharge Monitoring Reports (DMRs) submitted to the State. 

The NRC staff reviewed the DMRs submitted by Exelon to the IEPA for the period 2010 through 

2014. This review encompassed the results of recorded maximum cooling pond blowdown 

temperatures to the Illinois River and associated calculations of river mixing zone temperatures 

as reported in the DMRs for the past 5 years (2010 through 2014) and as compiled by Exelon 

(Exelon 2015c). Based on the NRC staff’s review and Exelon’s responses to the NRC’s 

requests for additional information, LSCS has received no notices of violation associated with 

NPDES permitted discharges during the 2010 through 2014 time period. Nonetheless, Exelon 

recorded several unusual occurrences in its DMR reports. These included reports of a makeup 

pipeline line failure on January 29, 2010; a blowdown line failure on July 13, 2012; a makeup 
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pipeline line failure on January 25, 2013; a blowdown line air release valve failure on 

February 8, 2013; a makeup pipeline failure on May 21, 2013; and a makeup pipeline failure on 

January 23, 2014 (Exelon 2015c).

The DMR submittals also document actions taken to comply with provisional variances granted 

by the IEPA to Exelon with respect to LSCS’s effluent discharges to the Illinois River and 

associated river mixing zone temperature limits. Specifically, these variances 

(IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 

March, July, and August 2012, respectively, due to unusual weather conditions and associated 

high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 

meet the requirements of Special Condition 3 of LSCS’s NPDES permit. This limits the number 

of temperature excursion hours to 1 percent (87.6 hours) of the hours in a 12-month period,

ending with any month (see footnote d in Table 3–7). During the variance period(s), Exelon was 

required, in part, to continuously monitor both the discharge and receiving water temperatures 

and visually inspect all discharge areas at least three times each day to assess the impact on 

aquatic life. These thermal discharge excursions were not found to have any impact on aquatic 

life (Exelon 2015c).

An applicant (in this case, Exelon) for a Federal license to conduct activities that may cause a 

discharge of regulated pollutants into navigable waters of the United States is required by 

Section 401 of the CWA to provide the licensing agency (in this case, the NRC) with water 

quality certification from the state (in this case, the State of Illinois). This certification implies 

that discharges from the project or facility to be licensed will comply with CWA requirements and 

will not cause or contribute to a violation of state water quality standards. If the applicant has 

not received Section 401 certification, the NRC cannot issue a renewed license unless that state 

has waived the requirement. The NRC recognizes that some NPDES-delegated states explicitly 

integrate their 401 certification process with NPDES permit issuance. However, LSCS’s 

NPDES permit does not explicitly convey water quality certification under CWA Section 401.

By letter dated February 4, 2014, Exelon submitted an application to the IEPA Bureau of Water

that requested certification from the IEPA that renewal of Exelon’s NRC operating licenses for 

LSCS would not violate State water quality standards (Exelon 2014h). The IEPA Division of 

Water Pollution Control issued a letter to the NRC, and copied Exelon, which provides

Section 401 water quality certification for renewal of the operating licenses for LSCS. The 

certification was issued with the condition that Exelon shall be responsible for obtaining NPDES

permits required for wastewater or stormwater discharges to waters of the State (IEPA 2014c). 

As previously stated in this section, NRC licensees must comply with the CWA, including 

associated requirements imposed by EPA or the state, as part of the NPDES permitting system 

under CWA Section 402. The NRC staff concludes that the IEPA’s response provides the 

necessary certification pursuant to CWA Section 401.

To maintain LSCS’s surface water intake system on the Marseilles Pool of the Illinois River, 

Exelon conducts occasional maintenance dredging at the river screen house (Exelon 2014a). 

The need for maintenance dredging at the river screen house forebay is periodically evaluated 

in accordance with an Exelon operating procedure. Currently, needed dredging is conducted 

under a USACE Section 10 permit, which is issued pursuant to the Rivers and Harbors 

Appropriation Act of 1899 (33 U.S.C. 403) (USACE 2006). Dredging was most recently 

conducted in October 2013 in compliance with the provisions of the permit. Less than 100 cubic 

yards (76 m3

) of sediment was removed, and the material was dewatered and placed out of the 

floodplain near the screen house. Future maintenance dredging will be conducted as needed 

and with the necessary permits. Exelon does not expect to perform any dredging in the vicinity 

of the LSCS discharge channel during the license renewal term and does not anticipate the 

need to conduct any fill activities (Exelon 2015c).
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3.5.2 Groundwater Resources

This section describes the current groundwater resources at the LSCS site and in the vicinity.

3.5.2.1 Site Description and Hydrogeology

The site is characterized by five hydrogeologic units. By increasing depth, they are as follows:

• the Alluvial Aquifer,

• the Glacial Drift Aquitard,

• the Buried Bedrock Valley Aquifers,

• the Pennsylvanian Aquitard, and

• the Cambrian-Ordovician Aquifer System.

The hydrogeologic characteristics of these units are summarized in Figure 3–12.

Alluvial (stream) deposits are found beneath, and extend along each side of, the Illinois River. 

These deposits form the Alluvial Aquifer that lays on top of the bedrock (the Pennsylvanian 

Aquitard) (Figure 3–8). The river functions as a hydrologic boundary, which prevents 

groundwater within the Alluvial Aquifer from flowing from one side of the river to the other. The 

Alluvial Aquifer is generally 2 to 4 ft (0.6 to 1.2 m) thick, is located in the vicinity of the river 

screen house, and ranges from 3,500 to 4,800 ft (1,067 to 1,463 m) in width. Yields in the 

Alluvial Aquifer are restricted by the limited areal extent and thickness of the sand and gravel 

deposits that make up the aquifer. Small dependable yields suitable for domestic purposes are 

only locally available. The aquifer receives recharge primarily by precipitation and from the 

river. Well yields from the Alluvial Aquifer in the vicinity of the river screen house are most likely 

adequate only for domestic use (Exelon 2014a).

The Glacial Drift Aquitard is made up of the Richland Loess and the Wedron Silty-Clay Till 

(see Section 3.4.1). The aquitard largely consists of silty-clay till (unsorted sediment containing 

a range of grain sizes) with very low permeability. In the area of the plant buildings, the Glacial 

Drift Aquitard is over 200 ft (61 m) thick (CRA 2006). Any extractable groundwater in this 

aquitard is produced from thin discontinuous sand and gravel pockets that are recharged by the 

slow infiltration of precipitation through the silty-clay till. The volume of groundwater produced 

from these pockets is limited so that it is primarily used as a source of water for domestic or 

farm activities (Exelon 2014a).

As discussed in Section 3.4.1, the site is located between two buried bedrock valleys that 

contain alluvial deposits of sandy gravels and gravelly sands with lesser amounts of silt and clay 

in scattered thin layers. These alluvial deposits are overlain and merge with the Wedron 

Silty-Clay Till. They are recharged by the slow infiltration of precipitation through the thick 

overlying Glacial Drift Aquitard. Therefore, the volume of groundwater that can be produced 

from the Buried Bedrock Valley Aquifers is limited to supplying water for domestic or farm 

activities (Exelon 2014a).

The Pennsylvanian Aquitard forms the bedrock. It consists of alternating beds of shale, 

siltstone, underclay, sandstone, limestone, coal, and many gradational layers. Low permeability

shale and siltstone comprise more than 90 percent of the aquitard. In the area of the plant 

buildings, the Pennsylvanian Aquitard is approximately 176 ft (54 m) thick. Groundwater in the 

aquitard occurs under artesian conditions. Wells finished in the aquitard get water primarily 

from thin sandstone and limestone beds within the aquitard, which are recharged by seepage 

through the overlying shales and through the silty-clay till of the Glacial Drift Aquitard. In 

general, the sandstone and limestone beds within the aquitard can only supply enough water for 
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domestic or farm use because well yields are commonly less than 36 L/min (10 gpm) 

(Exelon 2014a).

Figure 3–12. LSCS Site Hydrogeologic Units

Source: Modified from Exelon 2014a

The Pennsylvanian Aquitard is underlain by the Cambrian-Ordovician Aquifer, which is an 

important aquifer in the region. Beneath the site, this aquifer is composed of the following strata 

(listed from shallowest to deepest):
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• Platteville Group,

• Glenwood—St. Peter Sandstone,

• Potosi Dolomite,

• Franconia Formation,

• Ironton Sandstone, and

• Galesville Sandstone.

At the site, the Cambrian-Ordovician Aquifer is approximately 1,090 ft (469 m) thick. Although 

numerous alternating layers of sandstones, limestone, and dolomites impart a heterogeneous 

character to the system, these units are hydraulically connected and behave as a single aquifer 

(Exelon 2014a). The Cambrian-Ordovician Aquifer is the most important supplier of public 

water in the region.

The Cambrian-Ordovician Aquifer is underlain by 450 ft (137 m) of the Eau Claire Formation 

Aquitard, which is underlain by 2,500 ft (762 m) of the Mt. Simon Aquifer. The Mt. Simon 

Aquifer is underlain by granitic and metamorphic rock.

In addition to the hydrogeologic units previously described, the plant area is directly underlain by 

engineered granular fill that has been placed on top of the Wedron Silty-Clay Till. The 

engineered granular fill underlies and surrounds the plant buildings and structures. It is 

composed of sand and gravel and silty clay and contains groundwater that is recharged by local 

precipitation. Because the underlying Wedron Silty-Clay Till has a very low permeability, 

groundwater in the granular fill flows laterally eastward until it discharges into the intake canal, 

or it flows laterally and discharges to the stormwater ponds and the discharge canal to the west 

(CRA 2006) (Figures 3–12 and 3–13).

3.5.2.2 Groundwater Use

LaSalle County has an adequate supply of groundwater to meet current needs for industrial, 

municipal, and domestic purposes. Regionally, the most abundant groundwater supplies are 

obtained from the Cambrian-Ordovician Aquifer (LaSalle County 2014).

At the site, water for potable usage is obtained from two cased onsite wells completed into the 

Cambrian-Ordovician Aquifer. These wells were installed in 1972 and 1974 in the area of the 

plant buildings. They were drilled to a depth of 1,620 and 1,629 ft (494 and 496 m) and cased 

to a depth of 921 and 989 ft (281 and 301 m) (Exelon 2014a, 2014b; ISGS 2015). Together the 

two wells withdraw groundwater at an average rate of 26.1 gpm (98.7 L/min) (Exelon 2014a). 
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Figure 3–13. LSCS Groundwater Flow in Engineered Granular Fill

Source: Modified from Exelon 2014a
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Figure 3–14. LSCS Hydrogeologic Cross-Section

(Elevation Exaggerated)

Source: Modified from CRA 2006
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Within 10 mi (16 km) of the LSCS site, almost all water used for public water supplies is 

obtained from the Cambrian-Ordovician Aquifer. However, the Village of Ransom withdraws

water from both the Cambrian-Ordovician Aquifer and from permeable zones in the 

Pennsylvanian Aquitard, and the Village of Grand Ridge obtains water from the Buried Bedrock 

Valley Aquifers. People in small communities within 10 mi (16 km) of the LSCS site that are not 

served by a public water supply system obtain water from individual wells in the glacial drift, the 

Pennsylvanian strata, or the upper portion of the Cambrian-Ordovician Aquifer (Exelon 2014a).

3.5.2.3 Groundwater Quality

In general, the quality of groundwater in the Alluvial Aquifer, the Glacial Drift Aquitard, the 

Buried Bedrock Valley Aquifers, the Pennsylvanian Aquitard, and the Cambrian-Ordovician 

Aquifer is suitable for public use and consumption. A search of Illinois State Geological Survey 

water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant 

buildings. With the exception of one well completed in the Pennsylvanian Aquitard, all these 

wells withdraw water from the Cambrian-Ordovician Aquifer (ISGS 2015).

In 1985, a condensate line broke in the area east-southeast of the LSCS reactor building. 

Tritium was detected near the broken line in groundwater near the surface. The line was 

repaired soon after it broke. In 1986, the highest tritium concentrations detected in the 

groundwater was approximately 11,000 picocuries per liter (pCi/L). Tritium concentrations in the 

groundwater near the broken line have declined to the point that, since 2007, tritium 

concentrations in the groundwater have been below the lower limit of detection (Exelon 2014a; 

Exelon Nuclear 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015).

In September 2001, a spill of water from a recycled condensate storage tank resulted in tritium

contamination into groundwater near the land surface. Tritium concentrations in the 

groundwater ranged from 766 to 1,280 pCi/L in 2006 (Exelon 2014a; Exelon Nuclear 2007). 

These concentrations are well below the EPA Maximum Contaminant Level for tritium of 

20,000 pCi/L. In 2014, tritium concentrations in the groundwater had further decreased below 

the lower limit of detection (Exelon Nuclear 2015).

Another leak from a recycled condensate tank was identified in 2010. The tank is located near 

the plant buildings and is underlain by 10 ft (3 m) of engineered granular fill. In turn, the fill is 

underlain by the Wedron Silty-Clay Till. Soon after the leak was detected, the tank was drained 

and repaired. The leak contaminated groundwater in engineered granular fill with condensate 

water that contained tritium. Contamination in the engineered granular fill is being addressed 

through natural monitored attenuation and by active remediation. Exelon is pumping 

contaminated groundwater from both a well and a French drain installed in the engineered 

granular fill and then discharging the recovered water into the cooling pond where it is greatly 

diluted to below the lower limit of detection (Exelon 2014a). Exelon has been monitoring the 

cleanup of the engineered granular fill using monitor wells. In June 2015, samples from all of 

the monitor wells recorded tritium concentrations below the EPA Maximum Contaminant Level 

for tritium of 20,000 pCi/L (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015; Exelon 2015a, 

2015c). Although the engineered granular fill has been contaminated with tritium and is being 

cleaned up, it is not an aquifer. No aquifers are known to have been contaminated by 

inadvertent releases of radionuclides to groundwater.

One “nonradiological” release to groundwater occurred in 1999 when an oil tank was discovered 

to have leaked. The spill was remediated, and on February 9, 2005, IEPA issued a letter of “No 

Further Remediation” for the cleanup activities (Exelon 2014a).
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3.6 Terrestrial Resources

3.6.1 LSCS Ecoregion

LSCS lies within the Illinois/Indiana Prairies Level IV Ecoregion. This ecoregion encompasses 

19,557 mi2 (50,652 km2

) in eastern and central Illinois and western Indiana (Woods et al. 2006). 

It is composed of vast glaciated, flat to rolling plains with terminal and recessional moraines, 

prairie potholes, and old lake beds. Historically, tallgrass prairie covered the majority of the land 

surface. Oak-hickory forests were common on moraines and floodplains, and marshes and wet 

prairies occurred in poorly drained areas. Beginning in the 19th century, agricultural land began 

to replace the natural vegetation, and it is now the dominant land type (Woods et al. 2006). 

Prairie remnants lack many natural ecosystem functions due to their small size, and areas of 

prairie restoration often lack forbs (broad-leaved herbs other than grass) or are overly 

dominated by big bluestem (Andropogon gerardii) (a grass) or Indiangrass (Sorghastrum 

nutans) (IDNR 2005). Historically, forests were dominated by oak (Quercus spp.), hickory 

(Carya spp.), elm (Ulmus spp.), ash (Fraxinus spp.), beech (Fagus spp.), and maple (Acer spp.) 

species (CEC 2008). Remaining forests are highly fragmented and are experiencing species 

composition shifts to sugar maple (A. saccharum) and other mesophytic species (IDNR 2005). 

This shift is in part due to fire suppression, which has favored species that do not rely on 

periodic fires as part of their life cycle (IDNR 2005). Many wetland areas have been drained for 

row crops, and agriculture now accounts for over 75 percent of land use within this ecoregion 

(IDNR 2005).

Table 3–8 lists representative wildlife for this ecoregion, as well as species that the Illinois 

Department of Natural Resources (IDNR) considers to be “critical” to the conservation and 

restoration of the region’s native habitats; species that are indicative of ecosystem health 

(known as “indicator species”); and species that are native to the region, but are now extirpated 

or imperiled.

The IDNR maintains the Illinois Wildlife Action Plan (IDNR 2005), which addresses native 

habitat and species decline and contains a statewide conservation plan.

Table 3–8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion

Wildlife representative of the ecoregion

American black bear

(Ursus americanus)

eastern bluebird

(Sialia sialis)

North American porcupine

(Erethizon dorsatum)

American redstart

(Setophaga ruticilla)

eastern chipmunk

(Tamias striatus)

raccoon

(Procyon lotor)

bobcat

(Lynx rufus)

eastern gray squirrel

(Sciurus carolinensis)

tree sparrow

(Passer montanus)

Canada warbler

(Cardellina canadensis)

gray fox

(Urocyon cinereoargenteus)

white-footed mouse

(Peromyscus leucopus)

coyote

(Canis latrans)

indigo bunting

(Passerina cyanea)

white-tailed deer

(Odocoileus virginianus)

Wildlife critical to the conservation and restoration of the ecoregion’s native habitats

American badger

(Taxidea taxus)

Henslow’s sparrow

(Ammodramus henslowii)

northern harrier

(Circus cyaneus)

eastern massasauga(a)

(Sistrurus catenatus)

Illinois chorus frog

(Pseudacris streckeri illinoensis)

ornate box turtle

(Terrapene ornata ornata)
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four-toed salamander

(Hemidactylium scutatum)

Indiana bat(b)

(Myotis sodalis)

red squirrel

(Sciurus vulgaris)

gray bat(a)

(Myotis grisescens)

Kirtland’s snake

(Clonophis kirtlandii)

short-eared owl

(Asio flammeus)

Wildlife indicative of ecosystem health (indicator species)

black rat snake

(Elaphe obsoleta obsoleta)

eastern meadowlark

(Sturnella magna)

prairie vole

(Microtus ochrogaster)

black-capped chickadee

(Poecile atricapillus)

great blue heron

(Ardea herodias)

red-headed woodpecker

(Melanerpes erythrocephalus)

eastern box turtle

(Terrapene carolina carolina)

horned lark

(Eremophila alpestris)

red-tailed hawk

(Buteo jamaicensis)

eastern kingbird

(Tyrannus tyrannus)

prairie king snake

(Lampropeltis calligaster 

calligaster)

tufted titmouse

(Baeolophus bicolor)

Extirpated or imperiled wildlife

American bison

(Bison bison)

Blanding’s turtle

(Emys blandingii)

Franklin’s ground-squirrel

(Poliocitellus franklinii)

(a) The eastern massasauga is a candidate for listing under the Endangered Species Act of 1973, as amended 

(ESA), and the gray bat is listed as endangered under the ESA. While these species occur within the 

Illinois/Indiana Prairies Level IV Ecoregion, the FWS (2015d) indicates that they do not occur within the area that 

would be affected by the proposed LSCS license renewal.

(b) The Indiana bat is Federally listed as endangered under the ESA and is discussed in detail in Section 3.8.

Sources: CEC 1997; IDNR 2005; WIken et al. 2011

3.6.2 LSCS Site Surveys, Studies, and Reports

A number of vegetation and wildlife surveys have been conducted on the LSCS site beginning 

with baseline surveys prior to LSCS construction in the early 1970s. This section summarizes 

these surveys in chronological order.

Baseline Terrestrial Surveys (1971–1972)

In July and December 1971, and April, July, and October 1972, baseline ecological studies were 

conducted at the LSCS site. The 1971 studies were primarily qualitative, and the 1972 studies 

gathered quantitative data on vegetation, mammals, birds, reptiles, and invertebrates present on 

the LSCS site. The ER for operation of LSCS (ComEd 1977) describes these studies and the 

associated results in detail.

Final Environmental Statement for Construction (1973)

In February 1973, the U.S. Atomic Energy Commission (AEC), the NRC’s predecessor agency, 

issued a Final Environmental Statement that evaluated the construction of LSCS (FES-C) 

(AEC 1973). Although no specific studies were conducted to support the preparation of the 

FES-C, the report briefly summarizes the terrestrial wildlife and habitats on the site, including 

those that were altered or destroyed during the construction of the cooling pond.

Terrestrial Monitoring during LSCS Construction (1974–1978)

Following the commencement of LSCS construction, ComEd commissioned NALCO 

Environmental Sciences to conduct a 5-year monitoring program to evaluate the effects of 
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temporary and permanent ecological disturbances related to construction from 1974 

through 1978. The ER for operation of LSCS (ComEd 1977) describes the results of the first 

2 years of this monitoring.

Final Environmental Statement for Operation (1978)

In November 1978, the NRC issued a Final Environmental Statement that evaluated the 

operation of LSCS (FES-O) (NRC 1978). The report includes updates to the terrestrial habitat 

and wildlife information presented in the FES-C based on the 5 years of terrestrial monitoring 

conducted during LSCS construction.

Wildlife Habitat Council Vegetation and Wildlife Surveys (2007)

In September 2007, Wildlife Habitat Council (WHC) biologists performed a baseline habitat 

survey for the Wildlife at Work program. The survey results are documented in the LSCS

Wildlife Management Plan (Exelon 2013b).

LSCS Wildlife Habitat Team Monitoring (Ongoing)

The LSCS Wildlife Habitat Team conducts periodic wildlife surveys of the site in the spring 

(April), summer (July), and fall (September) to monitor changes in wildlife communities and to 

document any new species found on the site. Results of periodic surveys are collected in 

Exelon’s Wildlife Management Plan (Exelon 2013b).

3.6.3 LSCS Site

The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 

Illinois. The cooling pond, generating facilities and associated infrastructure, and LaSalle Fish 

Hatchery occupy the majority (66 percent) of the site. The remaining areas are undeveloped 

and include the following terrestrial communities: forest, shrub-scrub, grassland, old-field, and 

wetlands.

A cooling pond occupies the eastern side of the site and accounts for about half of the site area. 

The generating facilities and associated infrastructure (roads, parking lots, warehouses, 

switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac)

(Exelon 2015p). This industrial area is surrounded by about 142 ha (350 ac) of undeveloped

natural areas, including grassland, old field, schub-scrub, and small forested fragments 

(Exelon 2015p).

3.6.3.1 Vegetation

Because the majority of the LSCS site is developed or occupied by the cooling pond, only small 

areas of terrestrial habitat occur on the site. An open grassy area lies between the cooling pond 

and the site’s industrial area. This area is bounded on the north by the discharge canal and on 

the south by the property boundary. Another grassy area lies to the southwest of the industrial 

area. These two areas have a few scattered trees (Exelon 2014a).

The makeup and blowdown pipeline corridor extends north from the cooling pond to the Illinois 

River and supports upland habitats, including shrub-scrub, forest, grassland, and old-fields, and 

scattered wetlands. Common tree species in the upland forest areas, which comprise the 

majority of the corridor, include white oak (Quercus alba), red oak (Q. rubra), shagbark hickory 

(Carya ovata), sugar maple, hop hornbeam (Ostrya virginiana), hawthorn (Crataegus spp.), 

black cherry (Prunus serotina), and American elm (Ulmus americana) (Exelon 2014a). The 

corridor widens as it approaches the Illinois River where it contains several small freshwater 

emergent and freshwater forested/scrub wetlands. These wetlands are discussed in 

Section 3.6.5.2.
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3.6.3.2 Wildlife

Mammals

During the baseline terrestrial surveys in 1971 and 1972, 29 species of mammals were recorded 

on the LSCS site. The most commonly observed mammals included raccoon (Procyon lotor), 

mink (Mustela vison), red fox (Vulpes fulva), gray fox (Urocyon cinereoargenteus), gray squirrel 

(Sciurus carolinensis), fox squirrel (Sciurus niger), beaver (Castor canadensis), muskrat 

(Ondatra zibethicus), eastern cottontail (Sylvilagus floridanus), and white-tailed deer 

(ComEd 1977). During the 2007 WHC baseline inventory of the LSCS site, coyote (Canis 

latrans), beaver, opossum (Didelphis virginiana), groundhog (Marmota monax), striped skunk 

(Mephitis mephitis), white-tailed deer, and gray squirrel were observed on the site (Exelon

2013b).

Birds

During the baseline terrestrial surveys in 1971 and 1972, 129 species of birds were recorded on 

or near the LSCS site. Of these, 41 are considered permanent residents, 45 are summer 

residents, 13 are winter residents, and 21 are transients (ComEd 1977). Permanent residents 

included mallard (Anas platyrhynchos), black duck (A. rubripes), red-tailed hawk (Buteo 

jamaicensis), red-shouldered hawk (Buteo lineatus), bald eagle (Haliaeetus leucocephalus), 

bobwhite (Colinus virginianus), ring-necked pheasant (Phasianus colchicus), killdeer 

(Charadrius vociferus), rock dove (Columba livia), mourning dove (Zenaida macroura), great 

horned owl (Bubo virginianus), short-eared owl (Asio flammeus), saw-whet owl (Aegolius 

acadicus), northern flicker (Colaptes auratus), red-bellied woodpecker (Melanerpes carolinus), 

red-headed woodpecker (M. erythrocephalus), horned lark (Eremophila alpestris), blue jay 

(Cyanocitta cristata), American crow (Corvus brachyrhynchos), black-capped chickadee 

(Poecile atricapillus), northern mockingbird (Mimus polyglottos), eastern bluebird (Sialia sialis), 

cedar waxwing (Bombycilla cedrorum), loggerhead shrike (Lanius ludovicianus), starling 

(Sturnus vulgaris), and house sparrow (Passer domesticus) (ComEd 1977). During the 2007 

WHC baseline inventory of the LSCS site, 15 species of birds were observed, all of which had 

been previously recorded as occurring on the site during baseline surveys (Exelon 2013b).

Reptiles and Amphibians

No reptiles or amphibians were collected on the LSCS site in the 1971 baseline surveys 

(ComEd 1977). In 1972, two Eastern plains garter snakes (Thamnophis radix radix) were 

observed in pastureland near an intermittent stream (ComEd 1977). The 2007 WHC baseline 

inventory did not include reptiles or amphibians.

3.6.4 LSCS Wildlife Management Plan

The LSCS Wildlife Management Plan (Exelon 2013b) outlines the goals and projects of LSCS’s 

Wildlife at Work program. Some of the plan’s past and planned wildlife habitat enhancement 

and conservation activities at the LSCS site include:

• planting native vegetation, including swamp white oak (Quercus bicolor) near the 

cooling pond,

• controlling invasive common reed (Phragmites australis) near the cooling pond,

• enhancing existing habitat for grassland nesting birds through seeding, mowing, and 

controlled burns,

• maintaining nesting boxes for eastern bluebirds, and
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• installing osprey (Pandion haliaetus) platforms near the cooling pond 

(Exelon 2014a).

Exelon (2015n), as a corporation, has been a member of the WHC since 2005, and Exelon first 

received WHC certification for its Wildlife at Work program at LSCS in November 2011.

3.6.5 Important Species and Habitats

3.6.5.1 Important Species

State-Listed Species

The Illinois Endangered Species Protection Act of 1972, as amended, makes illegal the transfer, 

sale, and possession of species (including skins and products) listed by the State as 

endangered or threatened. The Act establishes an Endangered Species Protection Board, 

which maintains a list of endangered and threatened species and advises the IDNR on the 

conservation of those species.

Within LaSalle County, the IDNR’s (2014b) Natural Heritage Database indicates that

28 State-listed terrestrial species (19 plants, 3 birds, 2 reptiles, 2 mammals, 1 insect, and 

1 amphibian) occur in the county (see Table 3–9). In September 2013, Exelon generated an 

IDNR Ecological Compliance Assessment Tool (EcoCAT) report that used Illinois Natural 

Heritage Database information to further refine the list of State-listed species that could occur 

on the LaSalle site and that could potentially be affected by the proposed license renewal. The 

EcoCAT report is included in Appendix C of the applicant’s ER (Exelon 2014a). The report 

indicates that there are no terrestrial State-listed species on or near the LSCS site that may be 

affected by the proposed license renewal. In a May 2014 letter to Exelon, the IDNR (2014c) 

confirmed that the EcoCAT report was accurate, and in its letter, the IDNR mentioned no 

records of State-listed terrestrial species on or near the site. Federally protected species are 

discussed in Section 3.8.

Table 3–9. State-Listed Species in LaSalle County

Common Name Species Name Status(a)

Amphibians

four-toed salamander Hemidactylium scutatum ST

Birds

cerulean warbler Dendroica cerulea ST

loggerhead shrike Lanius ludovicianus SE

upland sandpiper Bartramia longicauda SE

Insects

regal fritillary Speyeria idalia ST

Mammals

gray bat(b) Myotis grisescens SE

Indiana bat(b) Myotis sodalis SE

Plants

American brooklime Veronica americana SE
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Common Name Species Name Status(a)

bunchberry Cornus canadensis SE

cliff goldenrod Solidago sciaphila ST

decurrent false aster(b) Boltonia decurrens ST

fibrous-rooted sedge Carex communis ST

forked aster Aster furcatus ST

golden corydalis Corydalis aurea SE

hairy woodrush Luzula acuminata SE

hemlock panic grass Dichanthelium portoricense SE

long beech fern Phegopteris connectilis SE

pink corydalis Corydalis sempervirens SE

plantain-leaved sedge Carex plantaginea SE

queen-of-the-prairie Filipendula rubra SE

red pine Pinus resinosa SE

red-berried elder Sambucus racemosa ssp. 

pubens

SE

shadbush Amelanchier sanguinea SE

snowberry Symphoricarpos albus var. albus SE

spike Elliptio dilatata ST

weak bluegrass Poa languida SE

Reptiles

blanding's turtle Emydoidea blandingii SE

timber rattlesnake Crotalus horridus ST

(a) SE = State-endangered in Illinois; ST = State-threatened in Illinois

(b) These species are also Federally listed under the Endangered Species Act of 1973, as 

amended (ESA) and are discussed in detail in Section 3.8.

Source: IDNR 2014b

Although not listed as occurring in LaSalle County by the IDNR, Exelon (2014a) reports that it 

has observed the State-threatened peregrine falcon (Falco peregrinus) on the LSCS site. A pair 

of peregrine falcons nested on the roof of the auxiliary building several years ago. Exelon 

(2014a) personnel have not observed peregrine falcon nesting in recent years, but personnel 

occasionally observe peregrines in flight on the site. The FES-O (NRC 1978) notes the 

observance of a single peregrine falcon in November 1972 in an offsite woodland.

Bald Eagles

The bald eagle is protected under the Bald and Golden Eagle Protection Act (16 USC 668 

et seq.). This Federal act prohibits anyone from taking or disturbing bald eagles or golden 

eagles (Aquila chrysaetos), including their nests or eggs, without a U.S. Fish and Wildlife 
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Service (FWS)-issued permit. The bald eagle was observed near the LSCS site in April 1972, 

on the river’s north-facing bluffs (ComEd 1977; NRC 1978). However, Exelon (2014a) is not 

aware of bald eagle observations at the site in recent years.

Migratory Birds

The Migratory Bird Treaty Act of 1918, as amended (MBTA) (16 U.S.C. §§ 703 et seq.), is 

administered by the FWS. The Act prohibits anyone from taking native migratory birds, their 

eggs, feathers, or nests. The MBTA regulations define “take” to mean to pursue, hunt, shoot,

wound, kill, trap, capture, or collect, or any attempt to carry out those actions (50 CFR 10.12). 

However, take does not include habitat destruction or alteration. All Illinois State-listed species 

described in Section 3.6.3.2 and listed in Table 3–9 are protected under the MBTA.

3.6.5.2 Important Habitats

Illinois Natural Areas Inventory Sites

In its Illinois Natural Areas Inventory (INAI), the IDNR (2014a) identifies 28 LaSalle County sites 

as Category I (“high quality natural community and natural community restorations”), Category II 

(“specific suitable habitat for state-listed species or state-listed species relocations”), 

Category III (“State-dedicated Nature Preserves, Land and Water Reserves, & Natural Heritage 

Landmarks”), or a combination of the three categories. The 2013 EcoCAT report (contained in 

Appendix D of the applicant’s ER (Exelon 2014a)) indicates that one of these sites with 

terrestrial habitat lies near the LSCS site: Marseilles Hill Prairie.

The Marseilles Hill Prairie (INAI Site No. 1520) lies 3 mi (4.8 km) north of the LSCS main site 

boundary (Exelon 2015o). It is 39.71 ac (16.07 ha) in size and managed by the IDNR (2014a) 

to conserve prairie habitat. The IDNR (2014a) designates this INAI site as Category I.

State Parks and Wildlife Areas

The IDNR manages three areas for State parks or wildlife areas within 10 km (6 mi) of LSCS: 

LaSalle Lake State Fish & Wildlife Area, Marseilles State Fish & Wildlife Area, and Illini State 

Park. The LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling 

pond that is managed by the IDNR and open to the public for fishing and other recreational 

purposes (Exelon 2014a). The Marseilles State Fish & Wildlife Area is open to seasonal 

hunting of turkey (Meleagris gallopavo), pheasant, quail, dove, deer, rabbit, squirrel, and coyote 

(IDNR 2015e). Illini State Park provides habitat for a number deciduous trees, including hickory, 

ash (Fraxinus spp.), walnut (Juglans spp.), elm, cottonwood (Populus deltoids), oak, and maple, 

as well as white-tailed deer, eastern gray squirrels, opossums, beavers, raccoon, groundhogs, 

and a variety of waterfowl and songbirds (IDNR 2015b).

Wetlands

The National Wetlands Inventory Wetlands Mapper identifies eight small areas of freshwater 

emergent wetland and freshwater forested/scrub wetland on the LSCS site near the Illinois 

River that total about 10 ac (4 ha) (FWS 2015e). Common tree species in the freshwater 

forested/scrub wetland include American elm, black cherry, white oak, red oak, black oak, 

shagbark hickory, bitternut hickory (Carya cordiformis), hackberry (Celtis occidentalis), elm, 

willow (Salix spp.), and sycamore (Platanus occidentalis) (Exelon 2014a). The freshwater 

emergent wetlands contain cattail (Typha spp.), horsetail (Equisetum spp.), and other 

herbaceous vegetation (Exelon 2014a).

Managed Prairie Habitat

In partnership with Pheasants Forever, Inc., Exelon (2014a) actively manages 4 ha (10 ac) of 

native prairie to the west of the cooling pond.
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3.6.6 Invasive and Non-Native Species

The invasive common reed inhabits parts of the cooling pond, particularly along the pond’s 

western edge. In 2007, as part of its Wildlife at Work program, Exelon (2014a) began an effort 

to eradicate the species through mechanical harvesting and application of aquatic-safe 

herbicides.

3.7 Aquatic Resources

The aquatic communities of interest for the LSCS site occur in the Illinois River and in the site’s 

artificial cooling pond. The Illinois River lies 5 mi (8 km) north of the site. It supplies makeup 

water to LSCS’s cooling system and receives cooling system blowdown. The cooling pond is 

the site’s main source of cooling water and is the plant’s UHS. Section 3.1.3 describes the 

cooling system in detail, and Section 3.5.1 describes the surface water characteristics of the

Illinois River and the cooling pond.

The sections below describe the two main aquatic ecosystems at the LSCS site, the Illinois 

River and the LSCS cooling pond (see Sections 3.7.1 and 3.7.2, respectively). In addition, 

Section 3.7.3 describes State-listed species and important habitats and Section 3.7.4 describes 

non-native species. 

3.7.1 Illinois River

The Illinois River begins southwest of Chicago, at the confluence of the Des Plaines and 

Kankakee Rivers. It flows south until it reaches the Mississippi River north of St. Louis, 

Missouri. The total length of the Illinois River is approximately 322 mi (518 km) (IDNR 2011a).

The Illinois River’s watershed drains a total of 29,010 mi2 (75,136 km2

) from Illinois, Wisconsin, 

and Indiana (IDNR 2011a). Major tributaries include the Des Plaines, Fox, Kankakee, 

Vermilion, Mackinaw, Sangamon, Spoon, and La Moine rivers.

Prior to the 1800s, the Illinois River Basin was comprised of prairie savannas and oak-hickory 

forests. The river provided diverse aquatic habitats including backwater lakes, side channels, 

and a narrow main channel (USGS 1999a). The rapid expansion of agricultural activities 

throughout the 1800s and early 1900s converted wet and mesic (relatively well drained)

floodplain prairies to crop lands. This land use conversion resulted in increased erosion, 

sediment loading, and nutrient and herbicide transport to the Illinois River. Beginning in the 

1900s, several efforts occurred to divert water from Lake Michigan and construct navigation 

dams or levees to increase the navigability of the Illinois River to the Mississippi River and 

provide a navigable passage from Chicago (Lake Michigan) to the Gulf of Mexico (USGS 

1999a). As the population in Chicago continued to grow, sewage disposal and toxic waste 

disposal further contributed to the degradation of aquatic habitat in the Illinois River (Parker 

2014). By the 1960s, the biodiversity of fish within the upper Illinois River was low and 

freshwater mussels were nearly absent (Sietman et al. 2001). Pollution tolerant, non-native 

common carp (Cyprinus carpio) and goldfish (Carassius auratus) dominated fish populations 

(Parker 2014). Since the passage of the CWA in 1974, water quality within the Illinois River has 

improved and more diverse fish assemblages inhabit the upper Illinois River (Parker 2014). 

Similarly, freshwater mussels have recolonized portions of the upper Illinois River since the 

1980s (Sietman et al. 2001). 

Currently, a series of locks and dams along the Illinois River continue to limit habitat connectivity 

and fish passage along the Illinois River. Four of the locks and dams (Thomas J. O’Brien, 

Lockport, Brandon Road, and Dresden Island) are upstream of LSCS and four (Marseilles, 

Starved Rock, Peoria, and LaGrange) are downstream (USACE 1998). The closest locks and 
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dams to LSCS include the Dresden Island Lock and Dam, 22 mi (26 km) upstream of the LSCS 

intake, the Marseilles Dam, 2.4 mi (3.5 km) downstream of the LSCS discharge, and the 

Marseilles Lock, 4.9 mi (7.9 km) downstream of the LSCS discharge (USACE 1998, 2014; 

Exelon 2015c). 

In 2005, IEPA most recently classified the water quality within the Illinois River as “fair,” which 

means that the water quality has been impaired, and the water body meets the needs of a 

designated use most of the time (IDNR 2011a). Current factors that continue to contribute to 

the degradation of the Illinois River include the increase in invasive fish, accumulated 

sediments, continued sedimentation, and agricultural chemical runoff (USGS 1999a; 

Parker et al. 2005). 

3.7.1.1 Aquatic Communities in the Illinois River

Plankton

Plankton are small organisms that float or drift in rivers and other water bodies. Plankton is a 

primary food source for many fish, and other animals, and consists of bacteria, protozoans, 

certain algae, tiny crustaceans such as copepods, and many other organisms.

ComEd, the previous owner of LSCS, conducted surveys for plankton within the Illinois River 

both upstream and downstream of the LSCS discharge and river intake structures. ComEd

initially sampled plankton prior to operations, from August 1972 through January 1973, and 

again during construction, from February 1974 through November 1976. These studies are 

summarized in the Final Environmental Statement for Operations of LSCS (NRC 1978). 

Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 

one base of aquatic food webs by producing biomass from inorganic compounds and sunlight. 

As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 

recycling of nutrients and minerals.

Diatoms were the most abundant phytoplankton in the Illinois River near LSCS in the 1970s, 

and reached peak densities in August (NRC 1978). The most common diatom genera included 

Cyclotella, Melosira, and Stephanodiscus. The NRC staff noted that many of the diatoms

collected in preoperational studies were pollution tolerant (NRC 1978). Other phytoplankton 

followed similar trends with primary production peaking in August and dipping in winter months. 

The NRC staff is not aware of any additional phytoplankton surveys that have been conducted 

in the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.

Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past often called 

“blue-green algae”), heterotrophic microbes, other small organisms, and detritus that attach to 

submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 

source of nutrients to many bottom-feeding organisms.

During ComEd’s initial study prior to construction, diatom densities upstream of the LSCS

discharge and intake areas accounted for 75 percent of the total periphyton density in 

August 1972 and 100 percent in January 1973. The next dominant taxa was green algae, which 

accounted for 7 percent of the total periphyton density in 1972 and none of the total periphyton 

density in 1973. Downstream of the LSCS discharge and intake, diatom densities accounted for 

94 percent of the total periphyton density in August 1972 and 92 percent in January 1973, while 

the green algae accounted for 1 percent in 1972 and none in 1973 (NRC 1978). Diatoms were 

the dominant periphyton group during the warmer months (May, August, and November), 

whereas green algae was dominant during February from 1974 to 1976 (NRC 1978). Dominant 

diatom genera included Cyclotella, Navicula, and Nitzschia; dominant green algae genera 

included Stigeoclonium, Cladophora, Rhizoclonium, and Ulothrix (NRC 1978).
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The NRC staff is not aware of any additional periphyton surveys that have been conducted in 

the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.

Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water column 

and include ichthyoplankton (fish eggs and larvae) with no or limited swimming ability and larvae 

of benthic invertebrates. Zooplankton are important trophic links between primary producers 

(e.g., phytoplankton and periphyton) and carnivores (e.g., fish). 

During preoperational studies, copepods and rotifers dominated zooplankton samples both prior 

to and during construction (NRC 1978). Dominant copepod genera included Cyclops and 

Eucyclops, and dominant rotifer genera included Asplanchna, Brachionus, Filinia, Notholca, 

Polyarthra, and Synchaeta (NRC 1978). Peak densities for both copepods and rotifers 

generally occurred in August, and minimum densities generally occurred in February.

In 2014, EA Engineering, Science, and Technology, Inc. (EA) (2015) collected icthyoplankton 

samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 

samples using 0.5-m (1.6-ft) conical plankton nets with 505-μm mesh suspended from the 

forebay bridge in front of the river intake (see Figure 3–15). EA (2015) collected samples during 

the 2014 spawning season, from late April through August, when icthyoplankton densities would 

likely be highest. 
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Figure 3–15. Icthyoplankton Sampling Location at the LSCS River Intake Structure

Key: LSCS: LaSalle County Station; RSH: River Screen House

Source: EA (2015)

EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 

27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 

combined comprised 79 percent of the number of organisms within ichthyoplankton sample. 

EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was 

not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. 

The most common taxa by life stage included Ictiobinae (buffalo fish) yolk-sac larvae 

(24 percent), Cyprinidae (carps and minnows) yolk-sac larvae (23 percent), and common carp 

yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent 

of the icthyoplankton samples (EA 2015). 

Benthic Macroinvertebrates

Benthic macroinvertebrates include aquatic annelids (e.g., aquatic worms or oligochaetes, 

leeches), mollusks, crustaceans, and insect larvae that inhabit aquatic sediments and 
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submerged surfaces. They accelerate detrital decomposition and nutrient cycling, and serve as 

a food source for fish and other aquatic biota. ComEd, Exelon, and their contractors sampled 

benthic invertebrates during three time periods: preoperational studies from February through 

November, 1972 through 1976 (as summarized in NRC 1978); a 1999 study in response to low 

flow and high air temperatures (EA 2000); and a 2013 study in preparation for Exelon’s license 

renewal application (EA 2014). 

During the preoperational and the 2013 study, ComEd and Exelon sampled benthic 

macroinvertebrates at one location upstream of the river intake and blowdown discharge

(location 1), at one location immediately downstream of the blowdown discharge (location 2), 

and at two locations further downstream of the blowdown discharge (locations 3 and 4) (Figure 

3–16). ComEd and Exelon sampled each location with a Hester-Dendy artificial substrate 

sampler and a Ponar grab sampler (NRC 1978; EA 2014).

In 1999, Exelon also collected benthos using a Ponar grab at one site upstream and one site 

downstream of the blowdown discharge, similar to the sampling sites for the preoperational and 

2013 study. In addition, EA collected benthos using a Ponar grab at a second downstream site 

that was further downstream than South Kickapoo Creek (EA 2000).

Figure 3–16. Sampling Locations in LSCS Aquatic Surveys 

Source: EA 2014

Collections during preoperational studies resulted in the identification of 143 taxa (NRC 1978). 

Chironomidae and Oligochaeta were the most dominant groups. The most common 

oligochaete genera were Limnodrilus and Nais. The most abundant chironomid genera 

included Cryptochironomous, Dicrotendipes, Procladius, Cricotopus, and Orthocladius.

EA (2000) collected a total of 34 taxa from Ponar grab samples. Chironomidae and Oligochaeta 

were the most taxa-rich groups, with 12 taxa each. EA (2000) determined that the dominant

taxa at all sampling sites are considered tolerant to poor water quality. Both total richness and 

the number of Ephemeroptera, Plecoptera, and Trichoptera species, which are considered 
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intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) 

compared to upstream (location 1) of the intake and discharge structures. 

EA (2014) collected a total of 61 taxa from the Hester-Dendy artificial substrate collections. 

Chironomidae was the most taxa rich group with 21 taxa followed by Ephemeroptera and 

Bivalvia, with 8 taxa each. The dominant taxa from the Hester-Dendy collections included the 

following insect larvae: Dicrotendipes modestus (a non-biting midge), Maccaffertium integrum

(a mayfly), Cyrnellus fraternus (a caddisfly), and Dicrotendipes neomodestus. Among the 

10 most dominant taxa for the Hester-Dendy artificial substrate samples, only one taxon is 

considered tolerant of environmental degradation, Glyptotendipes (IEPA 1987; EA 2014). The 

remaining taxa are considered facultative to slightly intolerant to poor water quality (IEPA 1987;

EA 2014).

For the Ponar grab samples, Chironomidae was the most taxa rich group with 15 taxa, followed 

by 8 Bivalvia and 4 Ephemeroptera taxa. EA (2014) observed the highest taxa richness at 

locations 1 and 3 (20 to 29 taxa) as compared to locations 2 and 4 (16 to 27 taxa). Species 

richness among pollution sensitive Ephemeroptera, Plecoptera, and Trichoptera was similar 

among all locations, ranging from three to five taxa (EA 2014). At all sampling sites, EA (2014) 

observed dominant taxa that were relatively tolerant to poor water quality as well as dominant 

taxa that were relatively intolerant or facultative to poor water quality.

Fish

ComEd, Exelon, and their contractors sampled fish near LSCS during three time periods: 

preoperational studies from May through November, 1972 through 1976 (as summarized in 

NRC 1978); a post-operational study in response to low flow and high air temperatures in July 

through October, 1999 (EA 2000); and a post-operational study in August 2013 in preparation

for Exelon’s license renewal application (EA 2014). 

During both the preoperational and 2013 study, Exelon sampled fish at one location upstream of 

the river intake and blowdown discharge (location 1) and at two locations downstream of the 

blowdown discharge (locations 2 and 5), one of which was South Kickapoo Creek

(Figure 3–16). Exelon sampled fish at each sampling site by electrofishing in a downstream 

direction for 500 m (1,640 ft). In addition, Exelon seined for fish along the shoreline at all three 

locations using a 25-ft (8-m) long by 6-ft (2-m) deep seine with 0.19- in. (0.48-cm) mesh. 

Exelon hauled the seine along 15 m (49 ft) of shoreline in a downstream direction.

In 1999, EA also electrofished at one site upstream and one site downstream of the blowdown 

discharge, similar to the sampling sites for the preoperational and 2013 study. In addition, EA 

electrofished at second downstream site that was further downstream than South Kickapoo 

Creek (EA 2000). 

All three studies looked for external parasites or other abnormalities. EA (2000 and 2014) 

specifically examined all fish for external DELT (deformities, erosions, lesions, or tumors)

anomalies.

During the preoperational monitoring period, NRC (1978) determined that the most dominant 

species included emerald shiner (Notropis atherinoides), gizzard shad (Dorosoma cepedianum), 

common carp, green sunfish (Lepomis cyanellus), bluntnose minnow (Pimephales notatus), and 

white sucker (Catostomus commersonii) (see Table 3–10). Prior to operations, downstream 

collection stations generally had lower species abundance and higher species diversity than 

upstream stations (NRC 1978). The NRC (1978) concluded that the low species abundance

and diversity, low condition factors, and the degree of external parasitism and physical damage 

of the fishes in this area of the Illinois River were indicative of a poor quality aquatic 

environment. Barge traffic, habitat alteration, and heavy pollution loads contributed significantly 
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to the poor water quality in the Illinois River near LSCS, which primarily supported populations 

of pollution-tolerant fish in the 1970s (NRC 1978).

During the 1999 survey, EA (2000) collected 27 species and 1 hybrid for a total of 960 fish. The 

most commonly collected fish species included gizzard shad (24 percent), smallmouth buffalo 

(Ictiobus bubalus) (12 percent), spotfin shiner (Cyprinella spiloptera) (10 percent), green sunfish 

(9 percent) and bluegill (Lepomis macrochirus) (8 percent) (Table 3–10). EA (2000) observed a 

total of 63 fish (6.6 percent of the catch) with DELT anomalies. Channel catfish (Ictalurus 

punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest 

DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin 

erosion (52 percent) and deformities (38 percent). 

During the 2013 study, EA (2014) collected 12 fish species for a total of 1,295 fish. The most 

commonly collected species during electrofishing included gizzard shad (48 percent), spotfin 

shiner (16.5 percent), smallmouth buffalo (6 percent), golden redhorse (Moxostoma erythrurum) 

(5 percent), smallmouth bass (Micropterus dolomieu) (4 percent), and freshwater drum 

(4 percent; EA 2014) (Table 3–10). Gizzard shad dominated samples both upstream and 

downstream of the intake and discharge (EA 2014). The most commonly collected species 

during seining surveys included emerald shiner (83 percent), spotfin shiner (9.5 percent), 

bluntnose minnow (2 percent), and sand shiner (Notropis stramineus) (2 percent) (EA 2014) 

(Table 3–10). Emerald shiner dominated samples both upstream and downstream of the intake 

and discharge (EA 2014). EA (2014) observed DELT anomalies on 2 of the 1,295 fish collected 

(0.2 percent), both of which were eroded fins on freshwater drum. EA (2014) did not observe 

any external parasites or other abnormalities. 
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Table 3–10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River

Species Common Name

Commonly Collected Species(d)

1974-1976(a) 1999(b) 2013(c)

Cyprinidae

Cyprinella spiloptera spotfin (spottail)

shiner

X X X

Cyprinus carpio common carp X

Notropis atherinoides emerald shiner X X X

Notropis stramineus sand shiner X

Pimephales notatus bluntnose minnow X X

Pimephales vigilax bullhead minnow X X

Centrarchidae

Lepomis cyanellus green sunfish X X

Lepomis macrochirus bluegill X

Micropterus dolomieu smallmouth bass X

Catostomidae

Catostomus commersoni white sucker X

Ictiobus bubalus smallmouth buffalo X X

Moxostoma erythrurum golden redhorse X

Atherinopsidae

Labidesthes sicculus brook silverside X

Clupeidae

Dorosoma cepedianum gizzard shad X X X

Sciaenidae

Aplodinotus grunniens freshwater drum X

(a) NRC 1978

(b) EA 2000

(c) EA 2014

(d) X = one of the six most commonly collected species, based on the number of individuals collected during 

electrofishing or seining sampling within a single time period. Note that a species may still have been observed 

during the collection period even if it was not one of the six most commonly collected species.

Sources: NRC 1978; EA 2000, 2014

Common carp and white sucker were commonly collected during preoperational studies but 

were not commonly collected during the 1999 or 2013 study. Ohio EPA (1987) classifies both of 

these species as pollution tolerant. Brook silverside (Labidesthes sicculus), freshwater drum, 

sand shiner, smallmouth bass, smallmouth buffalo, golden redhorse, and bluegill were among 
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the commonly collected species in the 1999 or 2013 studies but were not commonly collected in 

the preoperational studies. Five of these seven species (brook silverside, sand shiner, 

smallmouth bass, golden redhorse, and bluegill) are native species that are sensitive to declines 

in water quality or habitat degradation (Lerczak 1996; Smith 2002).

These results are consistent with other fish surveys (Lerczak 1996; McClelland et al. 2012) 

within the upper Illinois River that since the mid-1950s through 1990s and the 2000s, show a 

decline in fish species that are tolerant of poor water quality and an increase in fish species that 

are sensitive to habitat degradation. For example, Lerczak (1996) examined fish population 

data from the Illinois Natural History Survey (INHS), which began monitoring fish populations in 

the Illinois River in 1957. Since 1957, INHS conducted annual electrofishing surveys at set 

locations throughout the entire Illinois River, including sampling locations approximately 1 RM 

downstream of the LSCS river intake, within the vicinity of the LSCS river intake, and 11 RM 

upstream of the LSCS river intake. Within the upper 50 mi (80 km) of the Illinois River, which 

includes LSCS, Lerczak (1996) concluded that common carp, which is pollution tolerant, has 

become less common while bluegill, which is intolerant to degraded habitats, has become more 

common. For example, in the 1960s, INHS captured an average of 35 common carp per hour 

as compared to 6 common carp per hour in the 1990s. Bluegill increased from averages of less 

than 1 per hour in the 1960s to 12 per hour in the 1990s. Lerczak (1996) also noted that in the 

1990s, fish communities were more evenly distributed among a greater number of species than 

in the 1960s. For example, in 1962 and 1963, four species comprised 95 percent of all catches: 

gizzard shad, emerald shiner, common carp, and goldfish—a species with pollution tolerance 

similar to common carp. In 1995, 10 species comprised 95 percent of all catches including 

several species that are sensitive to habitat degradation, such as the bluegill, largemouth bass 

(Micropterus salmoides), and several species of small minnows.

McClelland et al. (2012) also examined fish populations during three time periods from 1957 

through 2009 based on INHS data. Table 3–11 describes the species that contributed to 

approximately 90 percent of all electrofishing catches in the Illinois River (McClelland 

et al. 2012). The NRC staff further classified fish as either pollution tolerant or intolerant. In 

addition, the NRC staff determined whether McClelland reported increases or decreases in the 

relative abundance of each species over time. The NRC staff notes that these general trends 

were not assessed using regression analyses or other statistical analyses. The most common 

species during the 1957 through 1969 surveys (common carp, gizzard shad, emerald shiner, 

and goldfish) are considered pollution tolerant species and the relative abundance of these 

species has generally declined over time. All pollution intolerant species listed in 

Table 3–11 have generally increased over time. These data suggest that water quality within 

the Illinois River has improved over time, allowing species that are pollution sensitive to 

increase in relative abundance. 

Table 3–11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural History 

Electrofishing Surveys from 1957 through 2009 

Species(a) Common Name 1957–1969 1970–1989 1990–2009 Trend(c)

Pollution Tolerant Species(b) Percent of Catch

Cyprinus carpio common carp 24.9 16.4 7.6 ↓

Dorosoma cepedianum gizzard shad 20.4 23.0 16.2 ↓

Notropis atherinoides emerald shiner 19.3 10.7 10.6 ↓

Carassius auratus goldfish 6.6 2.2 - ↓

Cyprinus carpio x

Carassius auratus

common carp x goldfish 3.0 - - ↓
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Species(a) Common Name 1957–1969 1970–1989 1990–2009 Trend(c)

Lepomis cyanellus green sunfish 2.4 6.3 5.3 ↑

Ictiobus cyprinellus bigmouth buffalo 1.8 1.8 1.3 ↓

Ameiurus melas black bullhead 1.4 - - ↓

Pimephales vigilax bullhead minnow - - 2.9 ↑

Pimephales notatus bluntnose minnow - - 2.3 ↑

Lepomis humilis orangespotted sunfish - - 1.2 ↑

Aplodinotus grunniens freshwater drum - 3.8 4.8 ↑

Pollution Intolerant Species(b) Percent of Catch

Lepomis macrochirus bluegill 2.8 6.2 13.1 ↑

Micropterus salmoides largemouth bass 2.2 5.1 6.4 ↑

Pomoxis nigromaculatus black crappie 1.8 4.2 2.9 ↑

Ictalurus punctatus channel catfish - 3.5 5.6 ↑

Morone chrysops white bass - 2.9 2.8 ↑

Micropterus dolomieu smallmouth bass - - 1.4 ↑

Notes: (-) = Fish species not part of 90 percent of the catch during specified time period

(a) Species ordered by decreasing relative abundance based on McClelland et al 2012; species contributed to 

approximately 90 percent of all electrofishing catches in the Illinois River and could be classified as either pollution 

tolerant or intolerant.

(b) Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015.

(c) Inclines or declines in the relative abundance of each species are general trends; the NRC staff did not evaluate 

these trends using regression analyses or other statistical analyses.

Sources: Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi 

DNR 2015; McClelland et al. 2012

3.7.2 LSCS Cooling Pond

As described in Section 3.5, the 2,058-ac (833-ha) cooling pond was created in 1978 by 

pumping water from the Illinois River into the excavated pond. Exelon leases a large portion of 

the LSCS cooling pond to the IDNR, which maintains the leased portion of the LSCS cooling 

pond as an outdoor recreation area for public use and fishing. IDNR has actively managed fish 

populations in the LSCS cooling pond since 1984 (Exelon 2014a). For example, IDNR surveys 

the cooling pond each year and determines which fish to stock based on fishermen preferences, 

fish abundance, different species’ tolerance to warm waters, predator and prey dynamics, and 

other factors (Exelon 2002, 2014a, 2015c). The cooling pond can be characterized as a highly 

managed ecosystem in which IDNR fish stocking and other human activities primarily influence 

the species composition and population dynamics. 

3.7.2.1 Aquatic Community in the Cooling Pond

IDNR stocks the LSCS cooling pond each year. In 1981, IDNR’s fish hatchery located adjacent 

to the cooling pond started operations (EA 2002). IDNR assumed management of the hatchery 

in 1984. Initially, IDNR stocked the LSCS cooling pond with largemouth bass and bluegill 

(EA 2002).

Currently, commonly stocked species include largemouth bass, smallmouth bass, black crappie 

(Pomoxis nigromaculatus), white crappie (Pomoxis annularis), channel catfish, blue catfish 
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(Ictalurus furcatus), striped bass hybrid (Morone saxatilis x M. chrysops), walleye (Sander 

vitreus), and bluegill (See Table 3–12; Exelon 2002 and 2015c). Because of the high water 

temperatures experienced in the summer months, introductions of warm-water species, such as 

largemouth bass and blue catfish, have been more successful than introductions of cool-water 

species, such as walleye and muskellunge. 

In addition to the stocked species, gizzard shad and threadfin shad (Dorosoma petenense)—

together called “shad”—also occur in the cooling pond. Shad are not recreationally fished, and 

IDNR does not currently stock these fish. IDNR stocks some recreationally fished species that 

consume shad (e.g., catfish and striped bass) in part to limit the size of shad populations 

(Exelon 2002).

Table 3–12. Fish Stockings in the LSCS Cooling Pond 2008-2014

Species(a)

Common 

Name 2008 2009 2010 2011 2012 2013 2014

Annual 

Average Percent

Lepomis 

macrochirus

bluegill 55,466 11,740 84,661 364,731 73,681 25,031 100,130 102,206 40%

Micropterus 

salmoides

largemouth 

bass

66,395 51,207 50,434 30,470 84,166 48,753 2,660 47,726 19%

Morone saxatilis 

hybrid

striped 

bass hybrid

80,889 68,404 41,284 52,642 0 20,580 26,047 48,308 19%

Ictalurus 

furcatus

blue catfish 18,560 34,452 19,800 23,368 0 0 18,200 22,876 9%

Micropterus 

dolomieu

smallmouth 

bass

25,365 21,155 21,118 22,733 20,683 22,354 20,582 21,999 9%

Lepomis 

microlophus

redear 

sunfish

34,151 0 4,830 4,830 0 0 0 14,604 6%

(a) Species are ordered by relative abundance (highest to lowest).

Sources: Exelon 2014a; IDNR and Exelon 2014; Exelon 2015c

3.7.2.2 Cooling Pond Fish Kill Events

LSCS has had four reportable fish kills in the cooling pond since 2001, including fish kills in 

July 2001, June 2005, June 2009, and August 2010 (Exelon 2014a, 2015c). The temperature in 

the cooling pond during these events ranged from 93 °F (33.9 °C) to 101°F (38.3 °C) 

(Exelon 2001, 2009, 2010). In addition, several smaller non-reportable fish kills have occurred 

when the cooling pond was 95 °F (35 °C) or above (Exelon 2015c). Exelon attributes these fish 

kills to high cooling pond temperatures as a result of high summer temperatures combined with 

low winds and high humidity, as described below (Exelon 2001, 2009, 2010).

The largest fish kill occurred in July 2001 when IDNR reported approximately 94,500 dead fish 

due to high temperatures that peaked at 98.2 °F (36.9 °C) (Exelon 2001). IDNR found the 

maximum temperature in the cooling pond discharge canal to be 120 °F (48.9 °C) and dissolved 

oxygen levels to range from 6.2 to 18.8 parts per million. The majority of dead fish (96 percent) 

were gizzard shad (90,800) (Exelon 2001). IDNR identified other dead fish to include 

1,279 carp, 1,143 smallmouth buffalo, 610 freshwater drum, 345 channel catfish, 238 striped 

bass hybrid, 93 smallmouth bass, 24 walleye, 13 bluegill, 12 white bass (Morone chrysops), 
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6 yellow bullhead catfish (Ameiurus natalis), and 4 yellow bass (M. mississippiensis) 

(Exelon 2001). 

In a June 2005 fish kill, IDNR counted 1,515 dead fish, including 1,439 striped bass hybrids 

(95 percent), 36 smallmouth bass (2 percent), 20 walleye (1 percent),11 channel catfish (less 

than 1 percent), 4 blue catfish (less than 1 percent), 3 yellow bass (less than 1 percent), and 

2 sauger (less than 1 percent) (Exelon 2015c). The LSCS cooling pond peaked at 95 °F (35 °C) 

during the fish kill (Exelon 2015c). 

In the June 2009 fish kill, 3,000 to 4,000 gizzard shad comprised 99 percent of the dead fish 

(Exelon 2009). Exelon (2009) also observed 26 smallmouth bass, 4 striped bass, and 

4 walleye. Immediately prior to and during the fish kill, the LSCS cooling pond increased 10 °F 

from 83 °F (28 °C) on June 20 to 93 °F (34 °C) on June 23.

In the August 2010 fish kill, IDNR concluded that over 90 percent of the dead fish were small 

threadfin and gizzard shad less than 3 in. (8 cm) long (Exelon 2010). IDNR also observed dead 

carp, striped bass hybrids, walleye, and smallmouth bass (Exelon 2010). The LSCS cooling 

pond peaked at 101.3 °F (38.5 °C) the day before the fish kill.

3.7.3 Important Species and Habitats

3.7.3.1 State-Listed Species

IDNR lists 35 fish and 26 mussel species as State-endangered or threatened (IDNR 2015a). Of

these, IDNR (2014b) indicates that 7 species (5 fish, 2 mussels) occur in LaSalle County (see 

Table 3–13).

Table 3–13. State-Listed Aquatic Species with the Potential To Occur in LaSalle County

Recorded Occurrences

Near LSCS

Species Common Name State Status(a)

Preoperational Studies (b)Starved Rock or Marseilles Pool(c)LSCS River Intake(d)

Fish

Fundulus diaphanous banded killifish ST x x

Moxostoma carinatum river redhorse ST

Moxostoma valenciennesi greater redhorse SE

Notropis heterolepis blacknose shiner SE

Notropis texanus weed shiner SE

Mussels

Alasmidonta viridis slippershell ST

Elliptio dilatata spike ST
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Recorded Occurrences

Near LSCS

Species Common Name State Status(a)

Preoperational Studies (b)Starved Rock or Marseilles Pool(c)LSCS River Intake(d)

(a) SE = State-endangered in Illinois; ST = State-threatened in Illinois

(b) NRC 1978

(c) McClelland and Sass 2007; Fritts 2013

(d) EA 2014, 2015; Exelon 2015c, 2015p

Sources: NRC 1978; IDNR 2014b; McClelland and Sass 2007; Fritts 2013; EA 2014, 2015; Exelon 2014a, 2015c

Banded killifish. Banded killifish occur in clear glacial lakes, streams, or tributaries, often near 

vegetation (Nyboer et al. 2006). This fish forms small schools near the surface of weedy lakes 

(Nyboer et al. 2006). In recent years, this species has been documented in the Illinois River 

(McClelland and Sass 2007; McClelland et al. 2012). In 2006, the INHS collected two banded 

killifish at RM 241.5 in the Starved Rock Pool sampling area, approximately 8 RM (13 Rkm) 

downstream of the LSCS river intake (McClelland and Sass 2007). However, from 1993 

through 2012, the INHS did not observe banded killifish in the Marseilles Pool sampling area, 

which included sampling locations approximately 1 RM (1.6 Rkm) downstream of the LSCS river 

intake, within the vicinity of the LSCS river intake, and 11 RM (18 Rkm) upstream of the LSCS 

river intake (Fritts 2013). 

In 2014, EA (2015) collected a juvenile banded killifish during an impingement and entrainment

study at the LSCS river intake. In response to this collection, EA Engineering submitted a 

scientific collectors report to IDNR on March 9, 2016 (EA 2016; NRC 2016a). This species was 

not collected during preoperational surveys (NRC 1978) or during operational studies in 1999 

and 2013 (EA 2000, 2014).

River Redhorse. The river redhorse inhabits large river systems, including impoundments and 

pools, in areas of moderate to swift current and clean gravel substrate (NatureServe 2014a). 

Barbour et al. (1999) classify this species as an insectivore that is intolerant of pollution and 

other environmental stressors. INHS electrofishing surveys that began in 1957 have 

documented this species in the Illinois River (McClelland and Sass 2007). However, from 1993 

through 2012, INHS did not observe river redhorse in the Marseilles Pool sampling area, which 

included sampling locations approximately 1 RM (1.6 RKm) downstream of the LSCS river 

intake, within the vicinity of the LSCS river intake, and 11 RM (18 RKm) upstream of the LSCS 

river intake (Fritts 2013). The river redhorse was not collected during preoperational surveys 

(NRC 1978) or operational surveys in 1999 and 2013 (EA 2000, 2014). From 2013 through 

2015, EA (2015) conducted an impingement and entrainment study near the LSCS river intake. 

Although EA (2015) collected several Moxostoma fish that were not identified to species, EA 

(2015) concluded that these species were most likely the more common Moxostoma spp., such 

as shorthead, golden, silver, and black redhorse, given that these common species were 

conclusively identified during the study. 
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Greater Redhorse. The greater redhorse inhabits lakes and large rivers with sandy to rocky 

pools (Nyboer et al. 2006). This fish was considered extirpated in Illinois until it was observed in 

the upper Illinois River basin in 1985 (Nyboer et al. 2006). IDNR (2014b) recorded three 

observations of this species in LaSalle County, most recently in July 2004. This species is rare 

in the Illinois River, and INHS did not observe this species from 1957 through 2006 at any 

sampling station in the Illinois River (McClelland and Sass 2007). This species was not 

collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 

(EA 2000, 2014), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from

1993 through 2012 (Fritts 2013). From 2013 through 2015, EA (2015) conducted an 

impingement and entrainment study near the LSCS river intake. Although EA (2015) collected 

several Moxostoma fish that were not identified to species, EA (2015) concluded that these 

species were most likely the more common Moxostoma spp., such as shorthead, golden, silver, 

and black redhorse given that these common species were conclusively identified during the

study. 

Blacknose shiner. The blacknose shiner inhabits clear vegetated lakes, and pools and runs of 

clear streams (Nyboer et al. 2006). Increased turbidity and decreases in aquatic vegetation 

have contributed to the decline of this species (Nyboer et al. 2006). IDNR (2014b) recorded two 

observations of this species in LaSalle County, most recently in October 2013. This species is 

rare in the Illinois River and INHS did not observe this species from 1957 through 2006 at any 

sampling station in the Illinois River (McClelland and Sass 2007). This species was not 

collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 

(EA 2000, 2014), an impingement and entrainment study at the LSCS river intake from 2013 

through 2015 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling 

area from 1993 through 2012 (Fritts 2013).

Weed shiner. In Illinois, the weed shiner inhabits clear sand-bottom creeks with some 

submerged vegetation (Nyboer et al. 2006). IDNR (2014b) recorded one observation of this 

species in LaSalle County, most recently in October 2013. This species is rare in the Illinois 

River and INHS did not observe this species from 1957 through 2006 at any sampling station in 

the Illinois River (McClelland and Sass 2007). This species was not collected during 

preoperational surveys (NRC 1978), operational studies in 1999 and 2013 (EA 2000, 2014), an 

impingement and entrainment study at the LSCS river intake from 2013 through 2015 

(EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 1993 

through 2012 (Fritts 2013).

Slippershell. The slippershell is a freshwater mussel that inhabits small to medium sized 

streams where it is usually found buried in sandy substrates in shallow water

(Nyboer et al. 2006). IDNR (2014b) recorded five observations of this species in LaSalle 

County, most recently in October 2013. In 1994, 1995, and 1999, Sietman et al. (2001) 

conducted freshwater mussel surveys in the Illinois River from RM 232.0 to 271.2 (RKm 373 to 

436), including the Starved Rock and Marseilles Pools sampling areas. Sietman et al. (2001) 

did not collect this species during the surveys. Similarly, this species was not observed in 2013 

when IDNR collected 14,850 live mussels, representing 23 species, near the Marseilles Dam 

after a boating accident (Kanter 2013). This species was not collected during LSCS

preoperational surveys (NRC 1978), operational studies in 2013 (EA 2014), or during 

impingement and entrainment studies at the LSCS river intake from 2013 through 2015 (EA 

2015).

Spike. The spike is a freshwater mussel that inhabits shoals of medium streams to large 

rivers, reservoirs, and lakes with sand and gravel substrates (Minnesota DNR 2014). It is 

distributed throughout the eastern United States, the Mississippi River system, and portions of 

the Great Lakes (NatureServe 2014b). IDNR (2014b) recorded one observation of this species 
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in LaSalle County in August 2010. This species was not collected during LSCS preoperational 

surveys (NRC 1978); the freshwater mussel survey from RM 232.0 to 271.2 in 1994, 1995, and 

1999 (Sietman et al. 2001); IDNR’s collection of mussels near the Marseilles Dam in 2013 

(Kanter 2013); operational studies in 2013 (EA 2014); or during impingement and entrainment

studies at the LSCS river intake from 2013 through 2015 (EA 2015).

3.7.3.2 Important Habitats

LaSalle Lake State Fish and Wildlife Area is part of the 2,058 ac (833 ha) cooling pond. As 

described above in Section 3.7.2, IDNR manages this area for public boating and fishing.

The Marseilles State Fish and Wildlife Area occurs approximately 1.5 mi (2.4 km) north of the 

LSCS site and the makeup and blowdown pipeline corridor right-of-way crosses the eastern 

portion of the area. The Marseilles State Fish and Wildlife Area is a 1,032-ha (2,550-ac) area 

managed by IDNR for hunting and wildlife habitat (IDNR 2015d). It is a joint-use area with the 

Illinois Department of Military Affairs, and periodically used by the Illinois National Guard for 

training (IDNR 2015d). 

3.7.4 Non-Native and Nuisance Species

Several non-native species, including the common carp, goldfish, and Asian carps 

(Hypophthalmichthys spp.), have been introduced into the Illinois River (McClelland et al. 2012). 

Common carp and goldfish have been present in the vicinity of LSCS prior to operations

(McClelland et al. 2012; Exelon 2014a). Both species dominated non-native fish collections in 

INHS’s long term monitoring surveys from 1957 and 1985 (McClelland et al. 2012). Common 

carp and goldfish are tolerant of degraded aquatic habitats and can tolerate low levels of 

dissolved oxygen and high water turbidity. 

Beginning in 1985, the number of non-native fish observed in the Illinois River increased 

(McClelland et al. 2012). Species documented in the Illinois River since 1985 include grass 

carp (Ctenopharyngodon idella), bighead carp (Hypophthalmycthys nobilis), silver carp 

(Hypophthalmycthys molitrix), round goby (Neogobius melanostomus), white perch (Morone 

americana), and the white perch-yellow bass hybrid (M. americana x M. mississippiensis) 

(McClelland et al. 2012). 

In addition to fish, Exelon has documented the occurrence of invertebrate non-native and 

nuisance species near the river intake, the cooling pond intake, and within the cooling system. 

Bryozoans are aquatic invertebrates that grow into large sessile colonies. Zebra mussels are 

native to the Black and Caspian Seas, and have invaded Europe and North America. These 

organisms can cause biofouling of LSCS’s underwater piping systems or water intakes. In 

1996, Exelon discovered bryozoans at the cooling pond screen house and removed the colony 

by using a continuous chlorination treatment. In 2010, Exelon observed the bryozoan 

Plumatella reticulata in the Unit 1 cooling water system and unidentified bryozoans at the river 

intake and in the cooling pond (HDR 2011). Within the past 5 years, Exelon has continued to 

regularly observe bryozoan colonies and zebra mussels at both the river intake and the cooling 

pond intake, and limits the growth of these organisms by using biocides (HDR 2012, 2013, 

2014; Exelon 2014a). When necessary, Exelon also follows procedures to remove zebra 

mussels manually.

3.8 Federally Protected Species and Habitats

Because NRC’s issuance of a renewed license for power plants is a Federal action, the NRC’s 

National Environmental Policy Act (NEPA) process considers species and habitats that are 

protected under Federal acts and possibly affected by license renewal. Federal acts that 
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protect species and habitats possibly affected by the renewal of a nuclear plant license include 

the Endangered Species Act of 1973, as amended (ESA); the Bald and Golden Eagle 

Protection Act of 1940, as amended; the Migratory Bird Treaty Act of 1918, as amended; the 

Magnuson-Stevens Fishery Conservation and Management Act, as amended (MSA); and the 

Marine Mammal Protection Act of 1972, as amended. Of these, the NRC has direct 

responsibilities only under the ESA and MSA. No species protected under the MSA, which 

protects habitat for certain marine and anadromous fish species, occur near LSCS. Species 

protected under the ESA are discussed in this section, and species protected under other 

Federal acts where the NRC has no direct responsibilities and under State acts are discussed in 

Section 3.6 for terrestrial resources and Section 3.7 for aquatic resources.

Section 7(a)(2) of the ESA states that each Federal agency shall, in consultation with and with 

the assistance of the Secretary (Secretary of Commerce or Secretary of the Interior, as 

appropriate), insure that any action authorized, funded, or carried out by that agency is not likely 

to jeopardize the continued existence of any listed species or result in the destruction or 

adverse modification of designated critical habitat. In fulfilling these requirements, each agency 

is to use the best scientific and commercial data available. Section 7 of the ESA sets out the 

consultation process, which is further implemented by regulation (50 CFR Part 402). The ESA 

makes it unlawful for a person to take a listed animal without a permit, where “take” under the 

ESA is defined as “to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or 

attempt to engage in any such conduct.” Through regulations, the term “harm” is defined as “an 

act which actually kills or injures wildlife.” Such an act may include significant habitat 

modification or degradation where it actually kills or injures wildlife by significantly impairing 

essential behavioral patterns, including breeding, feeding, or sheltering (50 CFR 17.3). Listed 

plants are not protected from take, although collecting or maliciously harming them on Federal 

land is illegal.

The FWS and the National Marine Fisheries Service jointly administer the ESA. The FWS 

manages the protection of and recovery efforts for listed terrestrial and freshwater species, and 

the National Marine Fisheries Service manages the protection of and recovery efforts for listed 

marine and anadromous species, of which none occur in the Illinois River near LSCS.

3.8.1 Action Area

The ESA regulations at 50 CFR 402.02 define “action area” to mean all areas to be affected 

directly or indirectly by the Federal action and not merely the immediate area involved in the 

action. The action area essentially bounds the analysis of ESA-protected species because 

species that occur within the action area may be affected by the Federal action, while species 

that do not occur within the action area would likely not be affected by the Federal action. The 

NRC staff recognizes that, although the action area is stationary, Federally listed species can 

move in and out of the action area. For instance, a migratory fish species could occur in the 

action area periodically and then travel to freshwater streams to spawn. Similarly, a flowering 

plant known to occur near, but outside of, the action area could appear within the action area 

over time if its seeds are carried into the action area by wind, water, or animals. Thus, in its 

analysis, the NRC staff considers not only those species known to occur directly within the 

action area but also those species that may passively or actively move into the action area. The 

NRC staff then considers whether the life history of each species makes the species likely to 

move into the action area where it could be affected by the proposed LSCS license renewal. 

Depending on habitat requirements, migration patterns, or other biological or physical 

requirements, different species may require different action areas.

The LSCS site occupies about 1,528 ha (3,776 ac) in Marseilles, La Salle County, Illinois 

(Exelon 2015p), about 8 km (5 mi) south of the Illinois River (Exelon 2014a). A cooling pond on 
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the eastern side of the site accounts for about half of the site area. A 5.6-km (3.5-mi) corridor 

for the makeup and blowdown pipelines—which travel underground from the Illinois River 

screen house south to the cooling pond—connects the cooling pond with the Illinois River, from 

which LSCS withdraws makeup water and discharges blowdown (Exelon 2014a). The intake 

structure on the Illinois River has bar grills, traveling screens with 3/8 in. (9.5 mm) openings, 

and no fish return system (Exelon 2014a). 

For Federally protected terrestrial species, the action area is the site, including the water intake 

and discharge pipe ROW, and areas immediately around the site that could include natural 

populations affected by plant operations. Within the action area, Federally listed terrestrial 

species could experience impacts such as habitat disturbance associated with transmission 

lines, exposure to radionuclides, and other direct and indirect impacts associated with station, 

cooling system, and in-scope transmission line operation and maintenance (NRC 2013).

For Federally protected aquatic species, the action area is the site and the Illinois River in the 

area affected by water withdrawal and discharge as well as the range of any species affected by 

water withdrawal and discharge. The license renewal of nuclear plants action can affect 

Federally listed aquatic species in several ways, such as impingement or entrainment of 

individuals into the cooling system, alteration of the riverine environment through water level 

reductions, changes in dissolved oxygen, gas supersaturation, eutrophication, thermal 

discharges from cooling system operation, habitat loss or alteration from dredging, and 

exposure to radionuclides (NRC 2013a).

3.8.2 Federally Protected Species and Habitats Considered

Exelon’s ER (2014a) documents correspondence between Exelon and the FWS about the 

effects of the proposed LSCS license renewal on Federally listed species. In July 2014, the 

FWS concurred with Exelon’s March 2014 conclusion that license renewal would not adversely 

affect any Federally listed species and noted that Exelon should consider an additional species: 

Northern long-eared bat, a proposed species known to occur in the plant vicinity. In 

August 2014, Exelon submitted a biological evaluation including the northern long-eared bat, 

and the FWS concurred with Exelon’s conclusion that license renewal would not affect any 

Federally listed species. Exelon (2014a, Appendix D) includes copies of this correspondence.

In late February 2015, NRC staff filled in an online form for an updated protected species list for 

LSCS on FWS’s Environmental Conservation Online System, Information for Planning and 

Conservation. The FWS (2015b) responded with a list of threatened and endangered species

that may be affected by the LSCS license renewal. In October 2015, the NRC staff checked the 

FWS (2015a) online Illinois County distribution of listed species for updates. Exelon (2014a) 

reports that “no federally listed species have been observed on the LSCS property.” Terrestrial 

and wildlife studies conducted by Exelon associated with LSCS that may have discovered and 

reported Federally listed species are described in Section 3.6.2 of this SEIS.

Exelon commissioned several aquatic monitoring studies in the past, and none of them reported 

Federally listed species in the Illinois River near LSCS. EA (2000) reported the results of a 

1999 monitoring study at three locations in the Illinois River upstream and downstream of the 

LSCS intake and discharge in late summer. Fish were sampled by electrofishing and seining 

and benthic macroinvertebrates by Ponar grab. The physical condition of fish put the study area 

in the poorest category using Ohio criteria, and a benthic macroinvertebrate (macrobenthos) 

community indicative of poor conditions was present. No Federally listed threatened or 

endangered species were observed.

EA (2014) reported results of fish and macrobenthos monitoring above and below LSCS in 

summer 2013 and compared results with past studies. Fish were sampled by electrofishing and 
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seining and benthic macroinvertebrates by Ponar grab, kick net samplers, and artificial

substrate samplers. No Federally listed threatened or endangered species were observed. 

EA (2015) reported results of impingement sampling from April 2014 through March 2015 and 

entrainment sampling in April through August 2014. No Federally listed fish or shellfish species 

were observed in entrainment or impingement samples.

Table 3–14 shows Federally listed species that may occur in LaSalle County near LSCS and 

habitat notes. Descriptions of the species follow.

Table 3–14. Federally Listed Species and Designated Habitat in LaSalle County, Illinois

Group

Federally Listed 

Species Common Name

Federal 

Status(a) Habitat

Mussels Plethobasus 

cyphyus

sheepnose 

mussel

E Shallow areas in larger rivers and 

streams.

Flowering 

Plants

Boltonia 

decurrens

decurrent false 

aster

T Moist, sandy floodplains and prairie 

wetlands along the Illinois River.

Platanthera 

leucophaea

eastern prairie 

fringed orchid

T Mesic prairie, wetlands, sedge 

meadows, marsh edges, and bogs with 

full sun and little to no woody 

encroachment.

Delea foliosa leafy prairieclover

E Prairie remnants on thin soil over 

limestone.

Mammals Myotis sodalis Indiana bat E Caves, mines (hibernacula); small

stream corridors with well-developed 

riparian woods; upland forests 

(foraging).

Myotis 

septentrionalis

northern longeared batT Hibernates in caves and mines -

swarming in surrounding wooded areas 

in autumn. Roosts and forages in

upland forests and woods.

Critical Habitat

Myotis sodalis Indiana bat Blackball Mine

(a) E=endangered; T=threatened

Sources: FWS 2015b, 2015a

Sheepnose Mussel (Plethobasus cyphyus). The FWS listed the sheepnose mussel (also called 

just sheepnose) as endangered on March 13, 2012, with an effective date of April 12, 2012, but 

could not designate critical habitat at that time (77 FR 14914). The sheepnose mussel is a 

freshwater mussel in the family Unionidae. According to Parmalee and Bogan (1998), adult 

mussels may reach 11 to 12 cm (4.3 to 4.8 in.) in length. Adult mussels are found partially or 

completely buried in the substrate. They are suspension feeders and eat bacteria, algae, 

microscopic animals, and detritus (77 FR 14914). Sheepnose is found in large rivers in gravel 

or mixed sand and gravel (INHS 2013). Further, in unimpounded rivers, sheepnose mussels 

can be found in less than 0.6 m (2 ft) of water and in relatively fast currents. In reservoirs, 

sheepnose mussels occupy depths of 3.6 to 4.6 m (12 to 15 ft) (Parmalee and Bogan 1998), 

though they have also been reported at depths exceeding 6 m (20 ft) (77 FR 14914). 

Sheepnose mussels are long-lived and can live nearly 100 to 200 years (FWS 2013b).
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Like other unionids, sheepnose has an unusual life cycle. After fertilization, the eggs live in 

special gill chambers of the females and develop into microscopic larvae called glochidia. 

Females brood the glochidia. When the glochidia are ready, the female expels the glochidia, 

which then must attach to the host fish’s gills or fins to complete development by enclosing 

themselves in a cyst (encysting). They drop off the host fish as newly transformed juveniles. 

The sauger (Sander canadensis) is the only known natural host for sheepnose mussel 

glochidia. The FWS (77 FR 14914) reports that in laboratory studies, sheepnose glochidia 

have successfully transformed on several other species, including fathead minnow (Pimephales 

promelas), creek chub (Semotilus atromaculatus), central stoneroller (Campostoma anomalum), 

and brook stickleback (Culaea inconstans), although interactions between these species and 

sheepnose may be rare and infrequent in nature due to habitat preferences. The FWS (2015c) 

identifies golden shiner (Notemigonus crysoleucas) as another possible host species.

The sheepnose mussel is found across the Southeast and the Midwest, although it has been 

eliminated from about two-thirds of its range. Today, the sheepnose mussel is found in 

Alabama, Illinois, Indiana, Iowa, Kentucky, Minnesota, Mississippi, Missouri, Ohio, 

Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.

In a study for Exelon, EA (2014) sampled fish, benthic invertebrates, and physical and chemical 

parameters during summer 2013 in the Illinois River both upstream and downstream of LSCS

and compared the results to past studies for LSCS in 1974 through 1978 and 1999. EA 

sampled fish using electrofishing and seines and benthic invertebrates using artificial substrate 

samples and a grab sampler. EA found no threatened or endangered fish or macroinvertebrate 

species, including endangered mussels, near LSCS in this study or in past studies. 

Exelon (2014a) reports not observing any Federally listed species at LSCS.

Decurrent False Aster (Boltonia decurrens). Decurrent false aster is a flowering perennial plant 

in the aster family. The aster-like flowers appear from the tall (typically about 1.5 m (60 in.) or 

more), bushy plants from August to October, and the flower rays range in color from white to 

pale violet. “Decurrent” refers to leaf stem bases that run down along the stem where they 

attach. Decurrent false aster lives in the wet prairies in disturbed alluvial ground and open 

shores of floodplain forests along the Illinois and Mississippi Rivers, and historically ranged from 

LaSalle, Illinois, downstream to St. Louis, Missouri, on the Mississippi River. In 1988, the FWS

proposed to list the species as threatened (53 FR 5598) because it found only 12 extant 

populations remaining in 5 Illinois counties and one Missouri County. In addition, destruction 

and modification of the floodplain forest along the Illinois and Mississippi Rivers due to wetland 

drainage and agricultural expansion threatened survival of the species. In November 1988, the 

FWS determined the decurrent false aster to be a threatened species under the ESA but did not 

designate critical habitat (53 FR 45858). At that time, the FWS thought the species to be 

extirpated from 13 counties in Illinois and 3 counties in Missouri. Twelve remaining extant 

populations were located along the Illinois River in Morgan, Schuyler, Fulton, and Marshall 

Counties; one population along the Mississippi River in St. Clair County; and two populations in 

St. Charles County, Missouri. It was often found in disturbed alluvial soil where the forest 

overstory and understory are open due to frequent flooding. It prefers moist, sandy areas 

around natural lakes in the Illinois River floodplain, but these areas now receive 2 or 3 in. (5 to 

7.5 cm) of silt per year due to extensive row crop agricultural practices and numerous levee 

systems that increase the amount of silt deposited on river banks during floods, and the silt 

prevents seed germination. 

The FWS initiated 5-year status reviews of decurrent false aster in 1990 and 2011, requested 

new information on the species, and found no reason to change the ESA threatened status. In 

its Recovery Plan that incorporated new information, FWS (1990) reported 18 known 

populations for this species in Illinois and 2 in Missouri, although not all were self-sustaining. In 
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its 2012 5-year Review, FWS (2012b) found that research since the Recovery Plan indicated 

that this species may best be described as a metapopulation (a group of spatially separated 

populations of the same species that interact at some level) that colonizes and disappears from 

available habitat patches. In a metapopulation, as local populations fluctuate in size, they 

become vulnerable to extinction during periods when their numbers are low, and the regional 

persistence of the species depends on the existence of a metapopulation. Elimination of much 

of the metapopulation structure can increase the chance of regional extinction of the species.

The plant’s abundance appears to fluctuate widely in response to annual changes in site 

conditions and the dynamic Illinois River hydrology. In a metapopulation model of decurrent 

false aster (Smith et al. 2005), flood pulses characterized by spring floods and midsummer 

periods of low water maintain subpopulations and help establish new sub-populations. The 

flood pulses provide necessary disturbance and reduce competition to facilitate the colonization 

of habitats. Impoundment of the Illinois River and periodic prolonged high water events during 

the growing season have reduced available habitat and contributed to the species’ decline. The 

FWS has not reported extant populations in LaSalle County and Exelon (2014a) reports no 

threatened or endangered species on the LSCS site.

Eastern Prairie Fringed Orchid (Platanthera leucophaea). The eastern prairie fringed orchid is 

1 of at least 200 North American orchid species and is a perennial herb. Plants are about 8 to 

40 in. (0.2 to 1 m) tall. An upright leafy stem carries a flower cluster called an inflorescence. 

The 3- to 8-in. (76- to 200-cm) lance-shaped leaves sheath the stem. Each plant has one single 

flower spike composed of 5 to 40 creamy white flowers, and the blossoms often rise just above 

the height of the surrounding grasses and sedges. Blooming occurs in late June and early July. 

Night-flying hawkmoths (family Sphingidae) pollinate the nocturnally fragrant flowers 

(FWS 2013a).

This species typically inhabits tallgrass prairies east of the Mississippi River that have 

calcareous silt loam soils and calcareous wetlands with open portions of fends, sedge 

meadows, marshes, and bogs. While once numerous and widespread, populations have 

declined with the disappearance of eastern prairies by conversion of habitat for crop fields, 

grazing, intensive and continuous hay mowing, drainage, and related human uses. Other 

reasons for the decline include succession to woody vegetation, competition from non-native 

species, and over-collection. Remaining populations tend to be small, unprotected, and 

unmanaged. The FWS designated the eastern prairie fringed orchid as an endangered species

in 1989 (54 FR 39857) and in 2012 initiated a 5-year status review of the listing (77 FR 38762). 

The FWS did not designate critical habitat for this species. Exelon (2014a) reports not 

observing any Federally listed species on the LaSalle site.

Leafy Prairie-Clover (Delea foliosa). The FWS listed the leafy prairie-clover as endangered 

throughout its range in 1991 (56 FR 19953), when it was known to be present only in two sites 

in Alabama, nine sites in Tennessee, and three sites in Illinois. The FWS did not designate 

critical habitat for leafy prairie-clover. The species is perennial and a member of the pea family 

(Fabaceae). The plants grow erect stems about 0.5-m (1.5-ft) tall, on the end of which grow 

small purple flowers in dense spikes. Flowering begins in August, and seeds ripen in early 

October, after which the above-ground portion of the plant dies while the below-ground portion 

survives the winter (56 FR 19953).

This plant is typically found in dry prairies, often in dolomitic soils. In Illinois, leafy prairie-clover 

was originally known from six counties in the northeastern part of the State, but by 1991 only 

three populations were known in the State, all in Will County in prairie remnants along the 

Des Plaines River (56 FR 19953). The U.S. Forest Service (USFS) (undated a) lists the 

reasons for its decline as plant and habitat loss from inundation by dams, road work, and 
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right-of-way management, including herbicide effects; botanical and horticultural collection; 

off-road vehicle impacts to plants and habitat; predation by deer and rabbits; encroachment of 

woody plants; and severe drought. Its habitat is being lost as dolomite prairies are being 

converted to industrial, commercial, and residential uses (USFS undated b). Recovery efforts 

by a partnership of the FWS (Chicago Field Office), the USFS, the Forest Preserve District of 

Will County, the Department of the Army (Joliet Training Area), the IDNR, the Forest Preserve 

District of Kane County, and Midewin National Tallgrass Prairie are underway in northeastern 

Illinois (USFS undated b). Exelon (2014a) reports not observing any Federally listed species on 

the LSCS site.

Indiana Bat (Myotis sodalis). The FWS listed the Indiana bat as endangered in 1967 

(32 FR 4001). The FWS designated critical habitat for the Indiana bat in 1976 (41 FR 41914) to 

include 11 caves and 2 mines in six states, including a cave in LaSalle County, Illinois. The 

Indiana bat is an insectivorous, migratory bat that inhabits the central portion of the Eastern 

United States and hibernates colonially in caves and mines. The decline of Indiana bats is 

attributed to urban expansion, habitat loss and degradation, human-caused disturbance of 

caves or mines, insecticide poisoning, and white-nose syndrome (WNS) (FWS 2011; 

Pruitt and TeWinkel 2007).

During summer months, reproductive female bats tend to roost in colonies under slabs of 

peeling tree bark or cracks within trees in forest fragments, often near agricultural areas 

(Pruitt and TeWinkel 2007). Colonies may also inhabit closed-canopy, bottomland deciduous 

forest; riparian habitats; wooded wetlands and floodplains; and upland communities 

(Pruitt and TeWinkel 2007). Maternity colonies typically consist of 60 to 80 adult females 

(Whitaker and Brack 2002). Colonies occupy multiple trees for roosting and rearing young 

(Watrous et al. 2006) and, once established, usually return to the same areas each year 

(Pruitt and TeWinkel 2007). Nonreproductive females and males do not roost in colonies during 

the summer; they may remain near the hibernacula or migrate to summer habitat 

(Pruitt and TeWinkel 2007). A hibernaculum is an area where bats gather and hibernate in 

winter. High-quality summer habitat includes mature forest stands containing open 

subcanopies, multiple moderate- to high-quality snags, and trees with exfoliating bark 

(Farmer et al. 2002). In summer, bats forage for insects along forest edges, riparian areas, and 

in semi-open forested habitats. In the winter, Indiana bats rely on caves for hibernation. The 

species prefers hibernacula in areas with karst (limestone, dolomite, and gypsum), although it 

may also use other cave-like locations, such as mines.

The Indiana Bat Recovery Plan (Pruitt and TeWinkel 2007) indicates that Indiana bats are 

distributed across 36 of the 102 counties in Illinois. Twenty-two winter hibernacula (16 extant, 

4 of uncertain status, and 2 historic) are located throughout these counties. Additionally, 

29 extant maternity colonies occur in Illinois, and adult males, nonreproductive females, or both 

have been captured during summer surveys within 26 of the 36 counties. For 2011, the 

FWS (2009) estimated that Illinois’s total population of Indiana bats was 54,095 individuals. 

According to more recent estimates, the Illinois population of Indiana bats has increased by 

almost 2,000 over in 2011 to 55,956 individuals (FWS 2012a). Exelon (2014a) reports not 

observing any Federally listed species on the LSCS site.

Northern Long-Eared Bat (Myotis septentrionalis). In December 2013, the FWS (78 FR 72058) 

found that listing of the northern long-eared bat as an endangered species under the ESA was 

warranted. Earlier in October 2013, the FWS (78 FR 61046) had found that it could not 

determine critical habitat for this species. The FWS listed the northern long-eared bat as 

threatened throughout its range on April 2, 2015 (80 FR 17974). The following information is 

from those listing documents. The northern long-eared bat is a medium-sized bat species with 

average adult body weights of 5 to 8 grams (0.2 to 0.3 ounces), adult body lengths between 
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77 to 95 mm (3.0 to 3.7 in.) and wingspans between 228 and 258 mm (8.9 to 10.2 in.). Adult fur 

is typically brown, darker on top than below. The range includes much of the eastern and north 

central United States (it occurs in 39 states) and all Canadian provinces west to the southern 

Yukon Territory and eastern British Columbia. Throughout the majority of this range, however, it 

is patchily distributed, and historically it was less common in the southern and western part of its 

range than in the northern portion. The bats gather and hibernate in winter typically in mines 

and caves, where they are now usually found only in low numbers. They migrate out of the 

hibernacula in summer, when they forage at night and roost during daylight in small numbers in 

live and dead trees and change roosts often. Their diet includes moths, flies, leafhoppers, 

caddisflies, and beetles, although the diet differs geographically and seasonally, and an 

individual can consume 3,000 insects each night. Mating occurs in the autumn and birthing in 

May or June. Mature forests are an important habitat type for northern long-eared bats, 

although they occasionally act as forager over forest clearings and along roads. The northern 

long-eared bat has experienced a sharp decline, estimated at approximately 99 percent from 

hibernaculum data, in the northeastern portion of its range due to the recent emergence of a 

fungal disease known as white-nose syndrome (WNS) (currently called Geomycetes 

destructans), and the FWS expects similar declines in the western part of its range as this 

disease spreads. The FWS (2013c) confirmed the existence of WNS in northern long-eared 

and little brown bats from LaSalle and Monroe Counties, Illinois. Human activities that threaten 

this species include constructing physical barriers at cave accesses and destruction of habitat 

through mining, flooding, vandalism, development, timber harvest, and other activities. 

Exelon (2014a) reports not observing any Federally listed species on the LSCS site.

Summary of the Occurrence of Listed Species within the Action Area. The six species listed in 

Table 3–14 are under the FWS’s jurisdiction within LaSalle County, although the information is 

not specific to the LSCS site. For the six species identified for LaSalle County, the NRC staff 

did not identify any within the action area after review of the ER (Exelon 2014a), a site visit that 

included discussions with site staff and review of onsite documents, and published and online 

sources. Sections 3.6, Terrestrial Resources, and 3.7, Aquatic Resources, summarize the 

ecological surveys performed on and near the LSCS site that would detect protected species. 

Exelon (2014a) reports not observing any Federally listed species on the LSCS site. Given the 

available information, the NRC staff concludes that the six species are unlikely to occur within 

the action area.

3.9 Historic and Cultural Resources

This section discusses the cultural background and the known historic and cultural resources

found on or near LSCS. The discussion is based on a review of historic and cultural resource 

surveys and other background information on the region surrounding LSCS. In addition, a 

records search was performed via the Illinois Historic Preservation Agency (IHPA) to obtain the 

most updated information about historic and cultural resources in the region. 

The Area of Potential Effect (APE) is the area at the LSCS power plant site, the transmission 

lines up to the first substation, and immediate environs that may be affected by the license 

renewal decision and land-disturbing activities associated with continued reactor operations. 

For this analysis, the first substation (345 kV LSCS switchyard) is located on the LSCS site 

(Exelon 2014a). The APE may extend beyond the immediate environs in instances where 

land-disturbing maintenance and operations activities during the license renewal term or 

refurbishment activities could potentially have an effect. In the case of LSCS, the APE includes 

the corridor between the cooling pond and the Illinois River containing the makeup and 

blowdown water pipelines within the site boundary. These pipelines traverse a distance of 

approximately 5.6 km (3.5 mi) from the cooling pond to the Illinois River. See Figure 3–3.
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3.9.1 Cultural Background

Human occupation near the LSCS site is generally characterized according to the following 

chronological sequence (Pauketat 1993):

• Paleo-Indian Period (12,000 – 10,000 before present (BP)),

• Archaic Period (10,000 – 3,000 BP),

• Woodland Period (3,000 – 1,100 BP),

• Mississippian Period (1,100 – 400 BP (ca. A.D. 900 – 1600)), and

• Protohistoric/Historic Period (400 – present (ca. A.D. 1600 – present)).

Paleo-Indian Period (12,000 – 10,000 B.P.). The earliest evidence of people living in Illinois 

dates to the Paleo-Indian Period. Paleo-Indian sites are generally found upland or on river 

terraces and are characterized by specific types of projectile points (i.e., fluted Clovis and 

Folsom points) and stone tools such as gravers, scrapers or large blades. These artifacts often 

occur in association with mastodon remains, suggesting a reliance on megafauna 

(e.g., mammoth, ground sloth, and saber-tooth tiger) for subsistence along with plants, small 

game, birds, and amphibians. Social organization consisted of small, highly nomadic bands of 

hunter-gathers, leaving Paleo-Indian sites with little detailed archaeological information 

(Neusius and Gross 2007; Pauketat 1993).

Archaic Period (10,000 – 3,000 B.P.). The Archaic Period was a time of major climatic shifts as 

colder environments transitioned to warmer environments similar to modern conditions. In 

response to this shift, new technologies and subsistence strategies were developed during this 

time. The Archaic Period is often divided into early, middle, and late subperiods. The Early 

Archaic Period is characterized by a shift from nomadic to sedentary settlement patterns, with 

central base camps located on river terraces and smaller hunting camps located in upland 

areas. This subperiod also shows an increased reliance on wild plant foods, small game, and 

aquatic resources. The Middle Archaic Period is characterized by an increased number of 

settlement sites on high stream terraces, which may reflect population increases. While 

subsistence and settlement patterns remained fairly similar to the Early Archaic Period, artifact 

assemblages suggest increased exploitation of aquatic resources as well as new artifacts such 

as pecked and ground stone tools used for intensive processing of nuts; banner stones that 

signaled the innovation of a new projectile technology called the atlatl or spear-thrower; and 

grooved axes. The Late Archaic Period is characterized by an increase in the number and size 

of settlement sites, which indicates an increase in population and a more sedentary lifestyle. 

New features of Late Archaic artifact assemblages, such as crude ceramic vessels, represent a 

shift towards increased reliance on horticulture as a subsistence strategy, although hunting and 

gathering would have continued (Fagan 2005; Neusius and Gross 2007; Pauketat 1993).

Woodland Period (3,000 – 1,100 B.P.). The Woodland Period is also often divided into early, 

middle, and late periods. However, the distinction between the early and middle period is not 

fixed. The Woodland Period is marked by an increase in more permanent settlements, changes 

in burial practices, increased cultivation of plants such as sunflowers and cucurbits 

(e.g., squashes, gourds, melons), and a rise in the manufacture and use of pottery 

(Fagan 2005). During the Middle Woodland Period, the large and complex Hopewell Culture 

emerged in the northeastern and Midwestern United States, including Illinois. This culture is 

characterized by settlement in villages, increased reliance on intensive horticulture, burial 

mounds, and long distance trade networks. These long distance networks allowed the trade of 

exotic materials, such as marine shells from the Gulf Coast, obsidian from the Rocky Mountains, 

copper from Lake Superior, and mica from the Appalachian Mountains far outside their 
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immediate locations. Evidence of the Illinois Hopewell culture is found primarily in the bluffs and 

floodplains of the Illinois River Valley. The burial mounds of this period often included central 

features, lined with logs, and filled with grave goods. Different burial treatments within the 

mounds point to social stratification within society, but through sex and age rather than 

hereditary lineage (Neusius and Gross 2007). The Late Woodland Period is characterized by 

an increase in settlement sites, which suggests (a) a rise in population, or (b) a change in 

settlement patterns from large, centralized village sites to smaller, dispersed habitation sites, or 

both (Fagan 2005).

Mississippian Period (1,100 – 400 B.P. (ca. A.D. 900 – 1600)). The Mississippian Period is 

characterized by major changes in settlement, subsistence patterns, and social structure. Large 

highly centralized chiefdoms with permanent settlements sites supported by numerous satellite 

villages emerged during this period. The platform mound, a new ceremonial earthen mound 

appeared in association with these permanent settlements. Platform mounds, burial mounds, 

and defensive structures, such as moats and palisades, were often constructed in clusters in 

settlements of this period and were common in the larger river valleys of the Midwest. 

Mississippian Period subsistence relied heavily on maize agriculture, as well as hunting and 

gathering. Long distance trading increased and craft specialists produced highly specialized 

lithic and ceramic artifacts, beadwork and shell pendants (Fagan 2005). Examples of 

Mississippian Period occupation within LaSalle County is the Starved Rock State Park area. 

Starved Rock is a 1,065 ha (2,632 ac) area along the south bank of the Illinois River between 

the towns of LaSalle and Ottawa, Illinois. Mississippian period artifacts have been found in 

some 62 sites in the region surrounding Starved Rock State Park with 16 sites recorded in the 

park itself (DOI 1998).

Protohistoric/Historic Period (A.D. 1600 – Present). The end of the Mississippian Period is 

characterized by severe social, political, and demographic changes that resulted from indirect 

and direct contact with Europeans. In particular, it is believed that the introduction of European 

infectious diseases such as smallpox, typhoid, and influenza severely decimated Native 

American populations, which had no immunity to these diseases. The spread of these 

diseases, which were fatal to large numbers of Native Americans, resulted in the widespread 

abandonment of villages and a concurrent collapse of Native American socioeconomic 

networks, such that by the time of widespread European contact and settlement, the 

Mississippian chiefdoms were gone (Fagan 2005). During the historic period, Illinois was 

primarily populated with a confederation of tribes known as the Illinois, or Illiniwek, and the 

Miami tribe. During the 1700s and early 1800s, new tribes migrated to Illinois, including the

Iroquois, Fox (Mesquakie), Ioway, Kickapoo, Mascouten, Piankashaw, Potawatomi, Sauk, 

Shawnee, Wea, and Winnebago. Competition for resources led to sporadic war among the 

Illinois, surrounding tribes, and European immigrants to the area for approximately the next 

120 years (ISM 2002). In approximately 1673, French explorers traveled along the Mississippi 

River and up the Illinois River to present-day LaSalle County. Robert Cavalier, also known as 

Louis de La Salle, made the first European settlement in LaSalle County. French influence in 

the Illinois territory began to wane by the mid-1700s due to being ejected from the area by the 

British. Illinois became part of the Northwestern Territory at the close of the American 

Revolution. LaSalle County was organized by the Illinois legislature during the 1830–1831 

legislative session (Baldwin 1877). The State of Illinois joined the Union in 1818. The area 

surrounding the LSCS site has principally been used for agriculture and coal mining from this 

period onward (Exelon 2014a).
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3.9.2 Historic and Cultural Resources

LSCS historic and cultural resources include prehistoric era and historic era archaeological

sites, historic districts, and buildings, as well as any site, structure, or object that may be 

considered eligible for listing on the National Register of Historic Places (NRHP). Historic and 

cultural resources also include traditional cultural properties that are important to a living 

community of people for maintaining their culture. “Historic property” is the legal term for a 

historic or cultural resource that is eligible for listing on the NRHP.

A review of databases maintained by the National Park Service (NPS) indicates that there are 

31 properties listed in the NRHP within LaSalle County, including three that have been 

designated as National Historic Landmarks (DOI 2015). These historic properties reflect the 

historic cultural contexts for the LSCS property and include Starved Rock State Park, and 

structures and districts dating from the mid-18th through mid-20th centuries. None of the 

historic properties is located within the boundaries of the LSCS property (DOI 2015). The 

closest NRHP site is the Illinois and Michigan Canal (NR200462), approximately 5 mi (8 km) to 

the north of the plant.

A number of surveys of the LSCS site were conducted between 1972 and 1994. In 1972, a 

Phase I archaeological survey was done by the Illinois Archaeological Survey of the LSCS 

site—originally known as the Collins Generating Station. Five sites were discovered on LSCS 

property. However, these sites were not recorded or evaluated because, in 1972, isolated finds 

were not recognized as sites and therefore not evaluated. Three of the sites were assigned 

Illinois Archaeological Survey accession numbers—LS00207, LS00208, and LS00209. The 

1972 survey concluded that construction of the LSCS would not significantly affect 

archaeological resources (Exelon 2014a). These findings were accepted by the NRC in its Final 

Environmental Statement for LSCS issued in 1978 (NRC 1978). In 1993, the Illinois 

Department of Military Affairs did a survey to support the siting of a military training area 

immediately northwest of LSCS. This survey found 48 archaeological sites, one of which is 

located on the LSCS site—LS00514. This site was also determined not to be NRHP eligible 

(Exelon 2014a).

The NRC staff searched the Illinois State Archaeological Site Files, a database maintained by 

the Illinois State Historic Preservation Officer, and identified the LSCS sites listed in the 

1972 and 1993 surveys as well as one additional site—LS00527—which was determined to be 

NRHP ineligible. No other cultural resources within the current confines of the LSCS site were 

identified (NRC 2015c).

3.10 Socioeconomics

This section describes current socioeconomic factors that have the potential to be directly or 

indirectly affected by changes in operations at LSCS. LSCS, and the communities that support 

it, can be described as a dynamic socioeconomic system. The communities supply the people, 

goods, and services required to operate the nuclear power plant. Power plant operations, in 

turn, supply wages and benefits for people and dollar expenditures for goods and services. The 

measure of a community’s ability to support LSCS operations depends on its ability to respond 

to changing environmental, social, economic, and demographic conditions.

3.10.1 Power Plant Employment and Expenditures

The socioeconomics region of influence (ROI) is defined by the areas where LSCS employees 

and their families reside, spend their income, and use their benefits, thus affecting the economic 

conditions of the region. Exelon employs a permanent workforce of approximately 
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890 employees and 30 long-term contract employees (Exelon 2014a). Approximately 

83 percent of LSCS employees reside in a three-county area in northeastern Illinois in Grundy, 

LaSalle, and Will Counties. Most of the remaining 17 percent of the workforce are spread 

among 23 other counties in Illinois, with numbers ranging from 1 to 40 employees per county 

(Exelon 2015q). Given the residential locations of LSCS employees, the most significant effects 

of plant operations are likely to occur in Grundy, LaSalle, and Will Counties.

Table 3–15 summarizes the LSCS workforce geographic distribution. The focus of the 

socioeconomic impact analysis in this SEIS is, therefore, on the impacts of continued LSCS 

operations on these three counties, also termed the ROI.

Table 3–15. LSCS Employees Residence by County

County Number of Employees Percentage of Total

Illinois

Bureau 12 1

Cook 10 1

Grundy 161 18

Kendall 38 4

LaSalle 490 55

Livingston 40 5

Will 86 10

Other counties 52 6

Total 889 100

Source: Exelon 2015q

Exelon purchases goods and services to facilitate LSCS operations. While specialized 

equipment and services are procured from a wider region, some proportion of the goods and 

services used in plant operations are acquired from within the ROI. These transactions fuel a 

portion of the local economy, as jobs are provided and additional local purchases are made by 

plant suppliers.

The LSCS units are on staggered 24-month refueling cycles lasting approximately 25 days 

each. During refueling outages, site employment typically increases by an additional 

800 temporary workers (Exelon 2014a). Approximately 75 to 80 percent of the outage workers 

are permanent residents of the ROI. The remaining 20 to 25 percent stay in Morris, Ottawa, or 

Joliet, Illinois (Exelon 2014a).

3.10.2 Regional Economic Characteristics

This section presents information on employment and income in the LSCS socioeconomic ROI. 

Grundy and LaSalle counties are predominantly rural with agricultural and forested land 

comprising the majority (90 percent) of the land use in the county. Conversely, Will County is 

more urban with developed land comprising about 34 percent of total land area in the county 

(USDA 2015a).

3.10.2.1 Employment and Income

From 2010 to 2014, the labor force in the LSCS ROI decreased approximately 0.8 percent to 

approximately 440,000. However, the number of employed persons increased by about 
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3.4 percent, to approximately 406,000. Consequently, the number of unemployed people in the 

ROI decreased by 33.6 percent, by approximately 17,000 persons to approximately 33,000, or 

about 7.6 percent of the current workforce—down from 11.3 percent in 2010 (BLS 2015).

According to the U.S. Census Bureau’s (USCB’s) 2014 “American Community Survey 1-Year 

Estimates” for LaSalle and Will Counties and 2009-2013 “American Community Survey 5-Year 

Estimates” for Grundy County, the educational, health, and social services industry represented 

the largest employment sector in the socioeconomic ROI (22.8 percent) followed by 

manufacturing and retail (both at 12 percent) (USCB 2015a). A list of employment by industry in 

each county of the ROI is provided in Table 3–16.

Table 3–16. Employment by Industry in the LSCS ROI

(2014, 1-year estimates and 2009-2013, 5-year estimates)

Industry Grundy(a) LaSalle(b) Will(b) Total Percent

Total employed civilian workers 22,931 47,159 342,888 412,978 –

Agriculture, forestry, fishing, hunting, and mining 334 1,645 1,488 3,467 0.8

Construction 1,920 2,556 21,997 26,473 6.4

Manufacturing 2,872 7,495 39,037 49,404 12.0

Wholesale Trade 760 1,015 10,581 12,356 3.0

Retail Trade 2,677 7,030 40,265 49,972 12.1

Transportation, warehousing, and utilities 2,215 3,157 25,581 30,953 7.5

Information 268 397 7,992 8,657 2.1

Finance, insurance, 

real estate, rental, and leasing

1,037 2,348 22,388 25,773 6.2

Professional, scientific, management, 

administrative, and waste management services

1,559 3,081 34,365 39,005 9.4

Educational, health, and social services 4,893 10,252 78,846 93,991 22.8

Arts, entertainment, recreation, accommodation, 

and food services

2,566 3,737 31,560 37,863 9.2

Other services (except public administration) 936 3,026 16,930 20,892 5.1

Public administration 894 1,420 11,858 14,172 3.4

(a) 2009-2013 “American Community Survey 5-Year Estimates.”

(b) 2014 “American Community Survey 1-Year Estimates.”

Source: USCB 2015a

Major employers in LaSalle County, the county in which LSCS is located, are listed in 

Table 3–17. Exelon is shown as the largest employer in the county.

Table 3–17. Major Employers in LaSalle County in 2009

Employer Number of Employees

Exelon Generation 890

OSF, Saint Elizabeth Medical Center 730
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Employer Number of Employees

PetSmart 500

Clover Technology Group 450

HR Imaging 425

Office Max 375

SABIC Innovative Plastics 275

Kohl’s 270

Seattle Sutton Healthy Eating 170

Mitsuboshi Belting 168

Pilkington Industries 157

Tyson’s 130

U.S. Silica 130

Source: Ottawa Area Chamber of Commerce & Industry, 2009

Estimated income information for the LSCS ROI is presented in Table 3–18. According to the 

USCB’s 2014 American Community Survey 1-year estimates, 10.5 percent of families and 

14.4 percent of individuals in Illinois were living below the Federal poverty threshold and the 

median household and per capita income for Illinois was $57,444 and $30,417, respectively 

(USCB 2015b). In the socioeconomic ROI, people living in LaSalle County had median 

household and per capita incomes below the State average. The median household and per 

capita income average in LaSalle County was $50,432 and $25,129, respectively, with 

9.6 percent of families and 13.3 percent of individuals living below the poverty level. 

Conversely, Will County had a higher median household and per capita income average 

($74,828 and $32,148, respectively) and a lower percentage of families (6.3 percent) and 

individuals (7.9 percent) living below the official poverty level. According to the USCB’s 

“2011-2013 American Community Survey 3-Year Estimates,” Grundy County also had higher 

median household and per capita income averages ($63,978 and $28,465, respectively) and 

lower percentages of families (7.2 percent) and individuals (9.4 percent) living below the poverty 

level than the State of Illinois and LaSalle County (USCB 2015b).

Table 3–18. Estimated Income Information for the LSCS ROI

(2014 estimates, unless otherwise indicated)

Grundy(b) LaSalle Will Illinois

Median household income (dollars)(a) 63,978 50,432 74,828 57,444

Per capita income (dollars)(a) 28,465 25,129 32,148 30,417

Individuals living below the poverty level (percent) 9.4 13.3 7.9 14.4

Families living below the poverty level (percent) 7.2 9.6 6.3 10.5

(a) In 2012 inflation adjusted dollars.

(b) 2011-2013 American Community Survey 3-Year Estimates.

Source: USCB 2015b.
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3.10.2.2 Unemployment

According to the USCB’s 2014 American Community Survey estimates, the unemployment 

rates in LaSalle County and the State of Illinois were 8.1 and 10.5 percent, respectively. 

Comparatively, the Will County unemployment rate during this same time period was 

6.0 percent. According to the USCB’s 2013 American Community Survey 3-year estimates, the 

unemployment rates in Grundy County was 9.6 percent (USCB 2015c).

3.10.3 Demographic Characteristics

According to the 2010 Census, an estimated 103,000 people lived within 20 mi (32 km) of 

LSCS, which equates to a population density of approximately 81 persons per square mile 

(persons/mi2

) (CAPS 2014). This translates to a Category 3, “least sparse” population density 

using the GEIS measure of sparseness (60 to 120 persons/mi2 within 20 mi). An estimated 

1,926,000 people live within 50 mi (80 km) of LSCS with a population density of approximately 

245 persons/mi2 (CAPS 2014). This translates to a Category 4 “in close proximity” population 

density, using the GEIS measure of proximity (greater than or equal to 190 persons/mi2 within 

50 mi). Therefore, LSCS is located in a high population area based on the GEIS sparseness 

and proximity matrix.

Table 3–19 shows population projections and percent growth from 1980 to 2060 in the 

three-county LSCS ROI. The ROI population continues to increase over the past two decades 

(2000 and 2010). Based on forecasts, the population is expected to continue these trends at 

moderate to high rates. Population projections for years 2020 through 2040 shown in the table 

were developed for the Illinois Department of Transportation.

Table 3–19. Population and Percent Growth in LSCS ROI Counties 1980–2010, 2014 

(estimated), and Projected for 2020–2060

Year

Grundy County LaSalle County Will County

Population

Percent 

change Population

Percent 

change Population

Percent 

change

1980 30,582 – 112,033 – 324,460 –

1990 32,337 5.7 106,913 -4.6 357,313 10.1

2000 37,535 16.1 111,509 4.3 502,266 40.6

2010 50,063 33.4 113,924 2.2 677,560 34.9

2014 50,425 0.7 111,241 -2.4 685,419 1.2

2020 61,265 22.4 118,178 3.7 868,986 28.3

2030 72,463 18.3 121,928 3.2 1,146,722 32.0

2040 83,665 15.5 125,686 3.1 1,366,456 19.2

2050 94,864 13.4 129,439 3.0 1,624,858 18.9

2060 106,064 11.8 133,193 2.9 1,873,593 15.3

Sources: Decennial population data for 1980-2010, and estimated 2014 (USCB 2015d); projections for 2020-2040 

Illinois Department of Transportation (IDOT 2012); 2050-2060 calculated.

The 2010 Census demographic profile of the three-county ROI population is presented in Table 

3–20. According to the 2010 Census, minorities (race and ethnicity combined) comprised 

28.6 percent of the total three-county population. The largest minority populations in the ROI 
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were Hispanic or Latino of any race (14.1 percent) and Black or African American (9.2 percent) 

(USCB 2015e).

Table 3–20. Demographic Profile of the Population in the LSCS ROI in 2010

Grundy LaSalle Will ROI

Total Population 50,063 113,924 677,560 841,547

Race (percent of total population, Not-Hispanic or Latino)

White 88.9 88.3 67.2 71.4

Black or African American 1.2 1.8 11.0 9.2

American Indian & Alaska Native 0.1 0.2 0.1 0.1

Asian 0.6 0.7 4.5 3.7

Native Hawaiian & Other Pacific Islander 0.0 0.0 0.0 0.0

Some other race 0.0 0.0 0.1 0.1

Two or more races 0.9 1.0 1.4 1.3

Ethnicity

Hispanic or Latino 4,096 9,135 105,817 119,048

Percent of total population 8.2 8.0 15.6 14.1

Minority population (including Hispanic or Latino ethnicity)

Total minority population 5,537 13,379 221,983 240,899

Percent minority 11.1 11.7 32.8 28.6

Source: USCB 2015e

According to the USCB’s 2014 American Community Survey estimates, since 2010 minority 

populations in the ROI were estimated to have increased by approximately 17,700 persons and 

now comprise 30.5 percent of the ROI population (see Table 3–21). The largest increase 

occurred in the Hispanic or Latino population (nearly 8,900 persons since 2010, an increase of 

7.5 percent). The next largest increase in minority population was Asian, an increase of 

approximately 5,800 persons or 18.5 percent from 2010 (USCB 2015f).

Table 3–21. Demographic Profile of the Population in the LSCS ROI in 2014

Grundy LaSalle Will ROI

Total Population 50,425 111,241 685,419 847,085

Race (percent of total population, Not-Hispanic or Latino)

White 87.4 86.9 65.3 69.5

Black or African American 1.4 2.1 11.3 9.5

American Indian & Alaska Native 0.1 0.2 0.1 0.1

Asian 0.8 0.9 5.3 4.4

Native Hawaiian & Other Pacific Islander 0.0 0.0 0.0 0.0

Some other race 0.0 0.0 0.0 0.0

Two or more races 1.0 1.0 1.4 1.4
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Grundy LaSalle Will ROI

Ethnicity

Hispanic or Latino 4,667 9,854 113,470 127,991

Percent of total population 9.3 8.9 16.6 15.1

Minority population (including Hispanic or Latino ethnicity)

Total minority population 6,351 14,558 237,731 258,640

Percent minority 12.6 13.1 34.7 30.5

Source: USCB 2015f

3.10.3.1 Transient Population

Within 50 mi (80 km) of LSCS, colleges and recreational opportunities attract daily and seasonal 

visitors who create a demand for temporary housing and services. In 2015, approximately 

57,000 students attended colleges and universities within 50 mi (80 km) of LSCS 

(NCES 2015a).

Based on “2009-2013 American Community Survey 5-Year Estimates,” approximately 

23,000 seasonal housing units are located within 50 mi (80 km) of LSCS. Of those, 1,785 were 

located in the LSCS ROI. Table 3–22 presents information about seasonal housing for the 

counties located all or partly within 50 mi (80 km) of LSCS.

Table 3–22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of LSCS

County(a) Total Housing Units

Vacant Housing Units: for 

Seasonal, Recreational, 

or Occasional Use Percent

Illinois

Bureau 15,679 216 1.4

Cook 2,176,266 16,059 0.7

DeKalb 40,983 246 0.6

DuPage 356,217 1,125 0.3

Ford 6,259 7 0.1

Grundy 20,027 187 0.9

Iroquois 13,452 200 1.5

Kane 182,145 623 0.3

Kankakee 45,135 436 1.0

Kendall 40,415 35 0.1

LaSalle 49,905 744 1.5

Lee 15,035 313 2.1

Livingston 15,851 55 0.3

McLean 69,979 390 0.6

Marshall 5,905 405 6.9
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County(a) Total Housing Units

Vacant Housing Units: for 

Seasonal, Recreational, 

or Occasional Use Percent

Illinois

Ogle 22,558 377 1.7

Peoria 83,162 114 0.1

Putnam 3,084 375 12.2

Tazewell 57,608 164 0.3

Will 237,806 854 0.4

Woodford 15,207 109 0.7

Total 3,472,678 23,034 1.6

(a) Counties within 50 mi (80 km) of LSCS with at least one block group located within the 50-mi (80-km) radius.

Note: ROI counties are in bold italics.

Source: USCB 2015g

3.10.3.2 Migrant Farm Workers

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 rural areas of the United States. 

Others may be permanent residents living near LSCS and travel from farm to farm harvesting 

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 minority and 

low-income workers would be “underrepresented” in the decennial Census population counts.

In the 2002 Census of Agriculture, farm operators were asked for the first time whether or not 

they hired migrant workers—defined as a farm worker whose employment required travel—to 

do work that prevented the migrant workers from returning to their permanent place of residence 

the same day. The Census is conducted every 5 years and results in a comprehensive 

compilation of agricultural production data for every county in the nation.

Information about migrant and temporary labor (working less than 150 days) was collected in 

the 2012 Census of Agriculture. Table 3–23 supplies information about migrant and temporary 

farm labor within 50 mi (80 km) of LSCS. According to the 2012 Census, approximately 

12,000 farm workers were hired to work for less than 150 days and were employed on 

5,563 farms within 50 mi (80 km) of LSCS. The county with the highest number of temporary 

farm workers (1,101) on 253 farms was DeKalb County, Illinois (NASS 2015).
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Table 3–23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 

within 50 mi (80 km) of LSCS (2012)

County(a)

Number of Farms 

with Hired Farm 

Labor(b)

Number of Farms 

Hiring Workers for 

Less Than 150

Days(b)

Number of Farm 

Workers Working 

for Less Than 

150 Days(b)

Number of 

Farms 

Reporting 

Migrant Farm 

Labor(b)

Illinois

Bureau 357 308 877 7

Cook 55 32 195 0

DeKalb 338 253 1,101 7

DuPage 38 29 258 3

Ford 175 136 329 4

Grundy 144 119 258 0

Iroquois 482 385 909 2

Kane 220 133 472 3

Kankakee 258 225 837 17

Kendall 127 99 263 2

LaSalle 526 411 933 8

Lee 271 224 506 1

Livingston 459 369 840 3

McLean 565 422 951 2

Marshall 137 110 303 1

Ogle 318 240 534 0

Peoria 199 162 546 4

Putnam 53 44 (D) 0

Tazewell 265 215 735 3

Will 278 212 694 3

Woodford 298 242 685 1

Total 5,563 4,370 12,226 71

(a) Counties within 50 mi of LSCS with at least one block group located within the 50 mi radius.

(b) Table 7. Hired farm Labor – Workers and Payroll: 2012.

ROI counties are in bold italics. (D) Indicates that data was withheld to avoid disclosing data for individual farms.

Source: 2012 Census of Agriculture – County Data (NASS 2015)

A total of 71 farms, in the 50-mi (80 km) radius of the LSCS, reported hiring migrant workers in 

the 2012 Census. Kankakee County, Illinois, reported the most farms with migrant farm labor 

(17 farms) (NASS 2015).

3.10.4 Housing and Community Services

This section presents information regarding housing and local public services, including 

education and water supply.
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3.10.4.1 Housing

Table 3–24 lists the total number of occupied and vacant housing units, vacancy rates, and 

median value in the ROI. Based on USCB’s 2014 American Community Survey estimates,

there were nearly 310,000 housing units in the ROI, of which nearly 285,000 were occupied. 

The median values of owner-occupied housing units in the ROI range from $121,700 in LaSalle 

County to $209,400 in Will County. The vacancy rate also varied considerably between the 

three counties, from 6.6 percent in Will County to 13.9 percent in LaSalle County 

(USCB 2015h).

Table 3–24. Housing in the LSCS ROI (2014 estimate)

Grundy(a) LaSalle Will ROI

Total housing units 20,078 49,867 239,857 309,802

Occupied housing units 18,119 42,956 224,012 285,087

Total vacant housing units 1,959 6,911 15,845 24,715

Percent total vacant 9.8 13.9 6.6 8.0

Owner occupied units 13,706 32,020 180,129 225,855

Median value (dollars) 178,200 121,700 209,400 195,073

Owner vacancy rate (percent) 3.2 1.4 0.9 1.1

Renter occupied units 4,413 10,936 43,883 59,232

Median rent (dollars/month) 953 685 1,054 978

Rental vacancy rate (percent) 5.4 11.9 4.4 5.9

(a) 2011–2013 “American Community Survey 3-Year Estimates.”

Source: USCB 2015h

3.10.4.2 Education

Grundy County has 12 public school districts with 24 public schools and approximately 

13,000 students during the 2013-2014 school year. LaSalle County, the county in which LSCS

is located, has 26 public school districts with 47 public schools and approximately 

17,000 students during the 2013-2014 school year. Will County has 30 public school districts 

with 171 public schools and approximately 117,000 students during the 2013-2014 school year 

(NCES 2015b).

3.10.4.3 Public Water Supply

The City of LaSalle pumps and treats groundwater. The city's water treatment and distribution

system serves the City of LaSalle. The City of LaSalle treatment plant has a treatment capacity 

of approximately 500,000 gallons per day. Water and wastewater treatment services are 

provided by a number of townships and municipalities in LaSalle County which service 

residential, commercial, and industrial customers. Other residents within the county are served 

by private, onsite well and wastewater disposal systems.

Table 3–25 lists the largest public water suppliers in Grundy, LaSalle, and Will Counties and 

provides water source and population served for those suppliers. Most of the major public water 

suppliers in Grundy, LaSalle, and Will Counties obtain their supplies from groundwater. 

Currently, there is excess capacity in every major public water system in the three counties.
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Table 3–25. Local Public Water Supply Systems

Public Water System Source Population Served(a)

Grundy County

Coal City Groundwater 5,587

Diamond Groundwater 2,200

Minooka Groundwater 10,924

Morris Groundwater 12,000

LaSalle County

Illinois American-Streator Surface water 19,000

LaSalle Groundwater 9,700

Marseilles Groundwater 4,800

Mandota Groundwater 7,272

Oglesby Groundwater 4,000

Ottawa Groundwater 18,307

Peru Groundwater 11,000

Seneca Groundwater 2,371

Utility Inc. – Lake Holiday Groundwater 6,479

Exelon/LaSalle Groundwater 1,000

Will County

Aqua Illinois – University Park Groundwater 6,913

Aqua Illinois – Willowbrook Groundwater 3,422

Breecher Groundwater 4,359

Braidwood Groundwater 6,191

Channahon Groundwater 9,160

Crest Hill Groundwater 20,837

Crete Groundwater 8,259

Elwood Groundwater 2,300

Frankfort Groundwater 24,648

Illinois American – Homer Township Surface water purchased 22,036

Illinois American – West Suburban Surface water purchased 66,429

Joliet Groundwater 147,589

Lockport Groundwater 24,839

Lockport Township Water System Groundwater 2,610

Manhattan Groundwater 6,000

Mokena Surface water purchased 19,500

Monee Groundwater 5,148

New Lenox Surface water purchased 24,394

Peotone Groundwater 4,142

Plainfield Surface water purchased 36,600

Romeoville Groundwater 52,000
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Public Water System Source Population Served(a)

Shorewood Groundwater 15,615

Southeast Joliet Groundwater 2,000

Stateville Correctional Center Groundwater purchased 3,500

Wilmington Surface water 5,724

(a) Safe Drinking Water Search for the State of Illinois (EPA 2015e).

Source: EPA 2015

3.10.5 Tax Revenues

Exelon pays taxes on LSCS property to LaSalle County, public schools, libraries, townships, 

districts, and other taxing authorities. Property taxes paid by Exelon for LSCS for the years of 

2007 through 2013 are listed in Table 3–26. As shown in the table, total property tax payments 

for the reported years fluctuated from year to year. 

Property taxes paid on LSCS are based partially on settlement agreements for the valuation of 

the power block, with the remaining land taxed on the assessment of fair market value, as 

established by Illinois State tax law. Power block tax payments have been approximately 

98 percent of the total tax payment. Settlement agreements in 1999 and 2006 covered the 

years 2000 through 2004 and 2005 through 2008, respectively. Negotiations for the next 

settlement agreement began in 2009 and was not completed until mid-2013. Consequently, 

without the settlement agreement, the LaSalle County tax assessor increased the assessed 

value of the LSCS power block, which resulted in sharply increased tax payments by Exelon. 

As shown in Table 3–26, tax payments more than doubled in 2009 in keeping with the increased 

assessment of the power block made by the County Assessor, as affirmed or amended on 

appeal by the LaSalle County Board of Review. Based on independent appraisals, Exelon 

appealed the assessments for tax years 2009 through 2012 to the Illinois Property Tax Appeal 

Board because the company did not believe the assessments accurately reflected the value of 

the LSCS power block. In July 2013, Exelon and all taxing bodies agreed to a new long-term 

settlement agreement that sets the Equalized Assessed Value of the LSCS power block for the 

next 7 years, starting with the 2013 tax year. The settlement agreement was fully executed and 

approved by the Court for the 13th Judicial District in LaSalle County, Illinois, in February 2014. 

At the request of all parties, the Property Tax Appeal Board dismissed the appeals with 

prejudice in May 2014 (Exelon 2014a).

Exelon intends to negotiate additional tax settlement agreements during the license renewal 

term, as it helps the company and taxing authorities plan for future income revenue and 

expenditures (Exelon 2014a).

Table 3–26. LSCS Power Block Tax Payments and Valuations 2007–2014 (in dollars)

Year

Equalized Assessed 

Value Inferred Fair Market Value Taxes Paid by Exelon

2007 235,000,000(a) 1,566,700,000 12,258,540

2008 235,000,000(a) 1,566,700,000 12,181,812

2009 525,000,000(b) 3,571,500,000 24,595,282

2010 525,000,000(b) 3,571,500,000 24,652,781
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Year

Equalized Assessed 

Value Inferred Fair Market Value Taxes Paid by Exelon

2011 504,000,000(b) 3,360,000,000 23,888,466

2012 488,250,000(b) 3,255,000,000 23,383,171

2013 485,000,000(a) 3,233,333,333 23,749,334

2014 455,000,000(a) 3,233,333,333 22,490,721

(a) Under settlement agreement.

(b) Set by Board of Review.

Source: Exelon 2014, 2015c, 2016

Taxes paid in 2013 to local taxing bodies constitute between 94 percent and less than 1 percent 

of the total levy for any individual taxing body, as shown in Table 3–27. Tax payments under 

any new settlement agreement would likely continue at similar percentages (Exelon 2014a).

Table 3–27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total Levy

Taxing Body

Exelon Payment 

(dollars)

Total levy 

(dollars)

Percent of total 

levy (%)

Brookfield Township 76,547 81,290 94

Brookfield Township Road 409,211 432,957 94

South Prairie Park District 32,009 35,118 91

Allen-Brookfield District 34,719 39,041 89

Seneca Grade School # 170 6,424,862 7,330,695 87

Seneca High School # 160 8,816,393 10,602,732 83

Seneca Library 608,884 731,132 83

Seneca Fire-Ambulance 491,752 633,545 78

Marseilles Fire District 536,095 777,223 69

Illinois Valley Community College # 513 1,790,079 8,027,119 22

LaSalle County 4,772,514 23,342,931 20

Allen Fire District 5,354 151,128 3

Allen Township 2,913 97,044 3

Allen Township Road 3,950 128,063 3

Allen Township School # 65 20,340 1,125,258 2

City of Marseilles 697 963,696 < 1

Grand Ridge School # 95 364 2,289,613 < 1

Marseilles Library 53 70,300 < 1

Ottawa High School # 140 288 12,691,310 < 1

Reddick Library 32 2,289,613 < 1

Streator High School # 40 3,645 5,512,552 < 1

Village of Ransom 136 36,982 < 1

Source: Exelon 2015r
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In addition, Exelon makes annual payments to the Illinois Emergency Management Agency for 

LSCS. These annual payments are listed in Table 3–28. Smaller amounts are paid on an 

intermittent and voluntary basis to local emergency management agencies and government 

agencies that participate in emergency management activities.

Table 3–28. Annual Payments to Illinois Emergency Management Agency 2009–2014

Year Amount Paid (dollars)

2009 3,356,117

2010 3,575,454

2011 3,790,603

2012 4,084,540

2013 4,084,540

2014 4,014,846

Source: Exelon 2015s

Exelon anticipates no change in State or local tax laws, rates or assessments that would result 

in notable future increases or decreases in property taxes or other payments to State or local 

governments with respect to LSCS during the license renewal term. However, new property tax 

settlement agreements could result in higher or lower property tax assessments and higher or 

lower property tax payments.

3.10.6 Local Transportation

The region surrounding LSCS has a highly developed roadway network. Interstate 80 (I-80) 

runs east and west approximately 8 mi (13 km) north of LSCS. Interstate 55 runs northeast to 

southwest approximately 15 mi (24 km) east of LSCS. US-51/I-39 runs north and south 

approximately 21 mi (35 km) west of LSCS. Interstate 80 and I-55 provide access to the LSCS 

site from Chicago to the northeast.

County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, runs parallel to 

LSCS’s southern boundary and provides access to the LSCS site. State Highway 170 is 0.5 mi 

(0.8 km) east of the site and County Road 30, also known as East 25th Road, is slightly west of 

the site. The CSX Railroad is the closest railroad line to LSCS. It runs parallel to and slightly 

north of the Illinois River. A 6 mi (10 km) rail spur connects LSCS to the Atchison, Topeka, and 

Santa Fe Railroad south of the site (Exelon 2014a).

Table 3–29 lists commuting routes to the LSCS site and average annual daily traffic volume 

values. The average annual daily traffic values represent traffic volumes for a 24-hour period 

factored by both the day of the week and the month of the year.

Table 3–29. Major Commuting Routes in the Vicinity of LSCS: 

2013-2014 Average Annual Daily Traffic Count

Roadway and Location

Average Annual Daily 

Traffic (AADT)

County Road 6 (North 21st Road) near LSCS 2,200

County Road 6 (North 21st Road) and Illinois 170 (East 29th Road) 1,800

Illinois 170 (East 29th Road) between River Street and US 6 in Seneca 7,500
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Roadway and Location

Average Annual Daily 

Traffic (AADT)

I-80 at US 6 30,200

County Road 30 (East 25th Road) and County Road 6 (North 21st Road) 1,350

County Road 30 (East 25th Road) and County Road 15 (Main Street) 3,800

County Road 15 (Main Street) in Marseilles 6,600

County Road 15 (Rutland Street) 5,200

I-80 at County Road 15 (Rutland Street) 29,100

I-80 at Illinois 23 (Columbus Street) 30,100

Illinois 23 (Columbus Street) south 18,500

Illinois 23/71 (Columbus Street) in Ottawa 12,300

Illinois 23/71 (Columbus Street) over Illinois River 27,500

Illinois 23 (Bloomington Avenue) and County Road 6 (East Main Street) 6,500

County Road 6 (East Main Street) 2,650

Source: Illinois DOT 2015

3.11 Human Health

3.11.1 Radiological Exposure and Risk

As required by NRC regulation 10 CFR 20.1101, Exelon has a radiation protection program 

designed to protect onsite personnel, including employees, contractor employees, visitors, and 

offsite members of the public from radiation and radioactive material generated at LSCS.

The radiation protection program is extensive and includes, but is not limited to the following:

• Organization and Administration (i.e., a Radiation Protection Manager who is 

responsible for the program and having trained and qualified workers),

• Implementing procedures,

• ALARA Program to minimize dose to workers and members of the public,

• Dosimetry Program (i.e., measure radiation dose of plant workers),

• Radiological Controls (i.e., protective clothing, shielding, filters, respiratory 

equipment, and individual work permits with specific radiological requirements),

• Radiation Area Entry and Exit Controls (i.e., locked or barricaded doors, interlocks, 

local and remote alarms, personnel contamination monitoring stations),

• Posting of Radiation Hazards (i.e., signs and notices alerting plant personnel of 

potential hazards),

• Record Keeping and Reporting (i.e., documentation of worker dose and radiation 

survey data),
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• Radiation Safety Training (i.e., classroom training and use of mockups to simulate 

complex work assignments),

• Radioactive Effluent Monitoring Management (i.e., control and monitor radioactive 

liquid and gaseous effluents released into the environment),

• Radioactive Environmental Monitoring (i.e., sampling and analysis of environmental 

media, such as air, water, vegetation, food crops, direct radiation, and milk to 

measure the levels of radioactive material in the environment that may impact human 

health), and

• Radiological Waste Management (i.e., control, monitor, process, and dispose of 

radioactive solid waste).

Regarding the radiation exposure to LSCS personnel, the NRC staff reviewed the data 

contained in NUREG–0713, “Occupational Radiation Exposure at Commercial Nuclear Power 

Reactors and Other Facilities 2014: Forty-Seventh Annual Report” (NUREG–0713, Volume 36) 

(NRC 2016b). This report, which was the most recent available at the time of this review, 

summarizes the occupational exposure data through 2014 that are maintained in the NRC’s 

Radiation Exposure Information and Reporting System database. Nuclear power plants are 

required by 10 CFR 20.2206 to report their occupational exposure data to the NRC annually.

NUREG–0713 calculates a 3-year average collective dose per reactor for all nuclear power 

reactors licensed by the NRC. The 3-year average collective dose is one of the metrics that the 

NRC uses in the Reactor Oversight Program to evaluate the applicant’s ALARA program. 

Collective dose is the sum of the individual doses received by workers at a facility licensed to 

use radioactive material over a 1-year time period. There are no NRC or EPA standards for 

collective dose. Based on the data for operating BWRs like those at LSCS, the average annual 

collective dose per reactor was 119 person-rem. In comparison, LSCS had a reported annual 

collective dose per reactor of 162 person-rem.

In addition, as reported in NUREG–0713, for 2014, no worker at LSCS received an annual dose

greater than 2.0 rem (0.02 Sv), which is less than half of the NRC occupational dose limit of 

5.0 rem (0.05 Sv) in 10 CFR 20.1201.

3.11.2 Chemical Hazards

The use, storage, and discharge of chemicals, biocides, and sanitary wastes, as well as minor 

chemical spills are regulated by state and Federal environmental agencies. Chemical hazards 

to LSCS’s workers during the license renewal term are expected to be minimized by 

implementing good industrial hygiene practices as required by Federal and State regulations. 

Discharges of chemical and sanitary wastes are monitored and controlled as part of the LSCS’s 

NPDES permit IL0048151 to minimize impacts to the public and the environment 

(Exelon 2014a).

3.11.3 Microbiological Hazards

Nuclear plants such as LSCS that discharge thermal effluents to cooling ponds, lakes, canals, 

or rivers have the potential to promote the increased growth of thermophilic microorganisms, 

which could result in adverse health effects for plant workers and the public. Microorganisms of 

particular concern include several types of bacteria (Legionella spp., Salmonella spp., 

Shigella spp., thermophilic fungi, and Pseudomonas aeruginosa) and the free-living amoeba 

Naegleria fowleri.
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Nuclear plant workers can be exposed to Legionella spp. when performing maintenance 

activities on plant cooling systems if workers inhale cooling tower vapors because vapors are 

often within the optimum temperature range for Legionella growth. Plant personnel most likely 

to come in contact with Legionella aerosols would be workers who clean biofilms off of 

condenser tubes, cooling towers, and related system components or equipment. Exposure of 

the public to Legionella from nuclear plant operations is generally not a concern because 

Legionella exposure would be confined to a small area of the site within the protected area. 

LSCS does not have cooling towers so exposure of workers to Legionella is unlikely.

The public can be exposed to the thermophilic microorganisms Salmonella, Shigella, 

P. aeruginosa, and N. fowleri during swimming, boating, or other recreational uses of 

freshwater. If a nuclear plant’s thermal effluent enhances the growth of thermophilic 

microorganisms, recreational users could experience an elevated risk of exposure when using 

waters near the plant’s discharge. 

3.11.3.1 Thermophilic Microorganisms of Concern

Legionella is a genus of common warm water bacteria that occurs in lakes, ponds, and other 

surface waters, as well as some groundwater sources and soils. The bacteria are pathogenic to

humans when aerosolized and inhaled into the lungs. Approximately 2 to 5 percent of those 

exposed in this way to Legionella develop an acute bacterial infection of the lower respiratory 

tract known as Legionnaires’ disease (Pearson 2003). Optimal growth occurs in stagnant 

surface waters with biofilms or slimes that range in temperature from 35 to 45 °C (95 to 113 °F), 

though the bacteria can persist in waters from 20 to 50 °C (68 to 122 °F) (Pearson 2003). 

Elderly and immunocompromised individuals are most susceptible to Legionnaires’ disease 

(Pearson 2003). According to data from the Centers for Disease Control and Prevention (CDC) 

(CDC 2011a) from 2000 through 2009, New England and Mid-Atlantic states generally had the 

highest number of reported legionellosis cases each year.

Approximately 2,000 serotypes of Salmonella spp. cause the bacterial infection salmonellosis in 

humans. Of these, the serotypes Typhimurium and Enteritidis are the most common in the 

United States (CDC 2010a). Salmonellosis is most common in summer months, and it is 

transmitted through contact with food, water, or animals contaminated with human or animal 

feces (CDC 2010a). The bacteria have an optimal growth temperature of 37 °C (98.6 °F) but 

can grow at temperatures ranging from 6 to 46 °C (43 to 115 °F) (Albrecht 2013a). Studies 

examining the persistence of Salmonella spp. outside of a host have found that Salmonella can 

survive for several months in water and in aquatic sediments (Moore et al. 2003).

Shigella is a genus of bacteria species that causes shigellosis (i.e., bacterial dysentery), which 

is spread through consuming fecal-contaminated food or water, by swimming in contaminated 

water, or by contact with an infected person through contaminated feces and unhygienic 

handling of food. Its optimum growth temperature is 37 °C (98.6 °F), though it can grow in water 

temperatures ranging from 10 to 40 °C (50 to 104 °F) (Albrecht 2013b). Shigellosis is most 

common in summer months and among toddlers age 2 to 4 who are not fully toilet trained and in 

childcare settings (CDC 2013e).

Pseudomonas aeruginosa is a free-living bacterium found in soil, water, sewage, plant surfaces 

and the skin of healthy individuals. It is most commonly linked to infections transmitted in 

healthcare settings. However, as a waterborne pathogen, it can cause ear infections 

(i.e., “swimmer’s ear”), eye infections, and skin rashes after exposure to contaminated hot tubs, 

swimming pools, or other recreational waters (CDC 2013a). Its optimum growth temperature is 

37 °C (98.6 °F), though it can grow at temperatures as high as 42 °C (107.6 °F) (Todar 2004). 

P. aeruginosa almost exclusively infects immunocompromised individuals or already injured or 

inflamed sites on the skin (Todar 2004).
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Naegleria fowleri is a free-living amoeba that occurs in warm lakes, rivers, or hot springs. It is 

the causative agent of human primary amoebic meningoencephalitis (PAM). Infection occurs 

when contaminated freshwater enters the nose, and the amoeba migrates to brain tissue; the 

ensuing illness is usually fatal (CDC 2013b). N. fowleri grows best at higher temperatures up to 

46 °C (115 °F) (CDC 2013b), though it has also been isolated from thermally altered waters 

surrounding power plant discharges at temperatures ranging from 35 to 41 °C (95 to 105.8 °F) 

(Stevens et al. 1977).

3.11.3.2 Prevalence of Waterborne Diseases Associated with Recreational Waters

From 2002 through 2011, the CDC (2003, 2004a, 2005, 2006a, 2007, 2008a, 2009, 2010b, 

2011b, 2012) reported an average of 2,774 cases of Legionnaires’ disease per year, of which 

between 28 and 151 per year were reported from Illinois.

The Illinois Department of Public Health (IDPH) indicates that approximately 1,500 to 

2,000 cases of salmonellosis are reported in the State each year (IDPH 2009), and the 

overwhelming majority of salmonellosis cases are foodborne (CDC 2010a). The CDC reports 

biannually on waterborne disease outbreaks associated with recreational waters. A review of 

the past 10 available data years (1999 through 2008) of these reports indicates that no 

outbreaks or cases of waterborne Salmonella infection from recreational waters occurred in the 

United States during this timeframe (CDC 2002, 2004b, 2006b, 2008b, 2011c). From 2006 to 

2013, all CDC-reported salmonellosis outbreaks have been caused by contaminated produce, 

meats, or prepared foods or through contact with contaminated animals (CDC 2013d).

Approximately 1,300 confirmed cases of shigellosis are reported in Illinois each year 

(IDPH 2013). CDC reports (2002, 2004b, 2006b, 2008b, 2011c) indicate that less than a 

dozen shigellosis outbreaks have been attributed to lakes, reservoirs, and other recreational 

waters in the past 10 available data years (1999 through 2008). None of these cases was

in Illinois.

Infections attributed to Pseudomonas aeruginosa are most commonly contracted in pools, spas, 

and hot tubs. No cases of infection linked to contaminated recreational waters in the 

United States have been reported within the past 10 available data years (1999 through 2008) 

(CDC 2002, 2004b, 2006b, 2008b, 2011c).

The N. fowleri-caused disease, PAM, is rare in the United States. Since 1962, between zero 

and eight cases of PAM have been reported to the CDC annually, and no cases have been 

reported in Illinois (CDC 2013c).

3.11.4 Electromagnetic Fields

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 found to be a 

problem at most operating plants and generally is not expected to be a problem during the 

license renewal term. However, a site-specific review is required to determine the significance 

of the electric shock potential along the portions of the transmission lines that are within the 

scope of this SEIS.

In the GEIS, the NRC found that without a review of the conformance of each nuclear plant 

transmission line with National Electrical Safety Code® (NESC®) criteria, it was not possible to 

determine the significance of the electric shock potential (IEEE 2002). 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 
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assessment of the impact of the proposed action on the potential shock hazard from the 

transmission lines 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 NESC 

for preventing electric shock from induced currents. The NRC uses the NESC criteria and the 

applicant’s adherence to those criteria during the current operating license as a baseline to 

assess the potential human health impact of the induced current from an applicant’s 

transmission lines. As discussed in the GEIS, the issue of electric shock is of small significance 

for transmission lines that are operated in adherence with the NESC criteria. 

As discussed in Section 3.1.6 of this SEIS, transmission lines that are within the scope of the 

NRC’s license renewal environmental review are limited to those transmission lines that connect 

the nuclear plant to the substation where electricity is fed into the regional distribution system 

and transmission lines that supply power to the nuclear plant from the grid (NRC 2013). 

As indicated by Exelon in its ER, no offsite transmission lines are in-scope for the environmental 

review for license renewal. The only transmission lines that are in scope for license renewal are 

onsite; the lines from the LSCS power block to the LSCS switchyard (Exelon 2014a). The 

public does not have access to this area and could not come into contact with these lines. 

Therefore, there is no potential shock hazard to members of the public from these transmission 

lines. As discussed in Section 3.11.5 of this SEIS, LSCS maintains an occupational safety 

program in accordance with the Occupational Safety & Health Administration regulations for its 

workers, which includes protection from acute electric shock.

3.11.5 Other Hazards

Two additional human health issues are addressed in this section: physical occupational 

hazards and electric shock hazards.

Nuclear power plants are industrial facilities that have many of the typical occupational hazards 

found at any other electric power generation facility. Workers at or around nuclear power plants 

would be involved in some electrical work, electric power line maintenance, repair work, and 

maintenance activities and exposed to some potentially hazardous physical conditions 

(e.g., falls, excessive heat, cold, noise, electric shock, and pressure). The issue of physical 

occupational hazards is generic to all nuclear power plants.

The Occupational Safety and Health Administration (OSHA) is responsible for developing and 

enforcing workplace safety regulations. OSHA was created by the Occupational Safety and 

Health Act of 1970 (29 USC 651 et seq.), which was enacted to safeguard the health of 

workers. With specific regard to nuclear power plants, plant conditions that result in an 

occupational risk, but do not affect the safety of licensed radioactive materials, are under the 

statutory authority of OSHA rather than the NRC as set forth in a Memorandum of 

Understanding (53 FR 43950) between the NRC and OSHA. Occupational hazards can be 

minimized when workers adhere to safety standards and use appropriate protective equipment; 

however, fatalities and injuries from accidents can still occur. LSCS maintains an occupational 

safety program in accordance with the OSHA regulations for its workers, which includes 

protection from acute electric shock.

LSCS participates in the OSHA Voluntary Protection Program (VPP) (OSHA 2015a). The VPP 

recognizes employers and workers in the private industry and Federal agencies who have 

implemented effective safety and health management systems and maintain injury and illness 

rates below national Bureau of Labor Statistics averages for their respective industries. In the 

VPP, management, labor, and OSHA establish cooperative relationships at workplaces that 

have implemented a comprehensive safety and health management system. Approval into VPP 

is OSHA’s official recognition of the outstanding efforts of employers and employees who have 
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achieved exemplary occupational safety and health (OSHA 2015b). LSCS holds the “Star” 

rating in the VPP, which indicates “participants whose safety and health management systems 

operate in a highly effective, self-sufficient manner and meet all VPP requirements. Star is the 

highest level of VPP participation” (OSHA 2008).

3.12 Environmental Justice

Under Executive Order (EO) 12898 (59 FR 7629), Federal agencies are responsible for 

identifying and addressing, as appropriate, disproportionately high and adverse human health 

and environmental impacts on minority and low-income populations. Independent agencies, 

such as the NRC, are not bound by the terms of EO 12898 but are, as stated in 

paragraph 6-604 of the EO, “requested to comply with the provisions of [the] order.” 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, “The Commission is 

committed to the general goals set forth in EO 12898, and strives to meet those goals as part of 

its NEPA review process.”

The Council on Environmental Quality (CEQ) provides the following information in 

Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 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 employed 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 employed 

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 employed 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 low-income populations that 

could result from the operation of LSCS during the renewal term. In assessing the impacts, the 

following definitions of minority individuals and populations and low-income population were 

used (CEQ 1997):

Minority individuals

Individuals who identify themselves as members of the following population 

groups: Hispanic or Latino, American Indian or Alaska 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, White and Asian.
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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 P60, on Income and Poverty.

3.12.1 Minority Population

According to 2010 Census data, approximately 21 percent of the population residing within a 

50-mi (80-km) radius of LSCS identified themselves as minority individuals. The largest minority 

group was Hispanic or Latino (of any race) (9.7 percent), followed by Black or African American 

(6.4 percent) (USCB 2015e).

According to USCB’s (USCB’s) 2010 Census data, minority populations in the socioeconomic 

ROI (LaSalle, Grundy, and Will Counties) composed 28.6 percent of the total three-county 

population (see Table 3–20). Figure 3–17 shows predominantly minority population block 

groups, using 2010 Census data for race and ethnicity, within a 50-mi (80-km) radius of LSCS.

Census block groups were considered minority population block groups if the percentage of the 

minority population within any block group exceeded 21 percent (the percent of the minority

population within the 50-mi radius of LSCS). A minority population exists if the percentage of 

the minority population within the block group is meaningfully greater than the minority 

population percentage in the 50-mi (80-km) radius. Approximately 400 of the census block 

groups located within the 50-mi (80-km) radius of LSCS have meaningfully greater minority 

populations.

As shown in Figure 3–17, minority population block groups (race and ethnicity) are mostly 

clustered near Chicago, Illinois. None of the block groups near to LSCS have meaningfully 

greater minority populations.

According to the USCB’s “2014 American Community Survey 1-Year Estimates,” since 2010, 

minority populations in the ROI increased by approximately 17,700 persons (an increase of 

7.4 percent) and now comprise 30.5 percent of the ROI population (see Table 3–21). The 

largest increases occurred in the Hispanic or Latino population (an increase of approximately 

8,900 persons or 7.5 percent) and Asian population (an increase of approximately 

5,800 persons or 18.5 percent) (USCB 2015b).

3.12.2 Low-Income Population

According to 2010 American Community Survey data, 9 percent of individuals residing within a 

50-mi (80-km) radius of LSCS were identified as living below the Federal poverty threshold in 

2010 (USCB 2015e). The 2010 Federal poverty threshold was $22,113 for a family of four.

Figure 3–18 shows the location of predominantly low-income population block groups within a 

50-mi (80 km) radius of LSCS. Census block groups were considered low-income population 

block groups if the percentage of individuals living below the Federal poverty threshold within 

any block group exceeded the percent of the individuals living below the Federal poverty 

threshold within the 50-mi radius of LSCS. Approximately 490 of the 1,269 census block groups 
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located within the 50-mi (80-km) radius of LSCS have meaningfully greater low-income 

populations.

As shown in Figure 3–18, low-income population block groups are evenly distributed around 

LSCS. The LSCS site is not located in a low-income population block group. The nearest 

low-income population block group is located south and east of the block group containing 

LSCS.

According to the USCB’s “2014 American Community Survey 1-Year Estimates,” 10.5 percent 

of families and 14.4 percent of individuals in Illinois were living below the Federal poverty 

threshold and the median household and per capita incomes for Illinois was $57,444 and 

$30,417, respectively (USCB 2015b). In the socioeconomic ROI, people living in LaSalle 

County had median household and per capita incomes below the State average. The median 

household and per capita income averages in LaSalle County were $50,432 and $25,129, 

respectively, with 9.6 percent of families and 13.3 percent of individuals living below the poverty 

level. In comparison to the State of Illinois and LaSalle County, Will County had higher median 

household and per capita income averages ($74,828 and $32,148, respectively) and lower 

percentages of families (6.3 percent) and individuals (7.9 percent) living below the poverty level 

(USCB 2015b). According to the USCB’s “2011-2013 American Community Survey 3-Year 

Estimates,” Grundy County also had higher median household and per capita income averages 

($63,978 and $28,465, respectively) and lower percentages of families (7.2 percent) and 

individuals (9.4 percent) living below the poverty level than the State of Illinois and LaSalle 

County (USCB 2015b).
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Figure 3–17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS

Source: USCB 2015e
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Figure 3–18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS

Source: USCB 2015e
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3.13 Waste Management and Pollution Prevention

3.13.1 Radioactive Waste

As discussed in Section 3.1.4 of this SEIS, LSCS uses liquid, gaseous, and solid waste

processing systems to collect and treat, as needed, radioactive materials produced as a 

byproduct of plant operations. Radioactive materials in liquid and gaseous effluents are 

reduced prior to being released into the environment so that the resultant dose to members of 

the public from these effluents is well within NRC and EPA dose standards. Radionuclides that 

can be efficiently removed from the liquid and gaseous effluents prior to release are converted 

to a solid waste form for disposal in a licensed disposal facility.

3.13.2 Nonradioactive Waste

Waste minimization and pollution prevention are important elements of operations at all nuclear 

power plants. Licensees are required to consider pollution prevention measures as dictated by 

the Pollution Prevention Act (Public Law 101-508) and Resource Conservation and Recovery 

Act of 1976, as amended (Public Law 94-580) (NRC 2013).

As described in Section 3.1.5, LSCS has a nonradioactive waste management program to 

handle nonradioactive waste in accordance with Federal, State, and corporate regulations and 

procedures. LSCS has waste minimization measures in place, as verified during the site visit 

conducted by the NRC staff in May 2015. This program includes appropriate recycling, thereby 

effecting waste reduction.

LSCS has a Storm Water Pollution Prevention Plan (SWPPP) that identifies potential sources of 

pollution that may affect the quality of storm water discharges from each permitted outfall. The 

SWPPP also describes practices that are used to reduce pollutants in storm water discharges to 

assure compliance with the site’s NPDES permit. As part of LSCS’s Spill Prevention Control 

and Countermeasure Plan, measures are in place to monitor areas within the site that have the 

potential for spills of regulated substances, such as oil (Exelon 2014a).

3.14 References

10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

protection against radiation.”

10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

production and utilization facilities.”

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 61. Code of Federal Regulations, Title 10, Energy, Part 61, “Licensing 

requirements for land disposal of radioactive waste.”

10 CFR Part 71. Code of Federal Regulations, Title 10, Energy, Part 71, “Packaging and 

transportation of radioactive material.”

10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, “Licensing 

requirements for the independent storage of spent nuclear fuel, high-level radioactive waste, 

and reactor-related Greater than Class C waste.”

15 CFR Part 930. Code of Federal Regulations, Title 15, Commerce and Foreign Trade, 

Part 930, “Federal consistency with approved coastal management programs.”
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40 CFR Part 50. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 

“National primary and secondary ambient air quality standards.”

40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 50, 

“National Primary and Secondary Ambient Air Quality Standards,” Washington, DC. 

40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 51, 

“Requirements for Preparation, Adoptions, and Submittal of Implementation Plans." 

Washington, D.C.

40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

"Designation of areas for air quality planning purposes."

40 CFR Part 98. Code of Federal Regulations, Title 40, Protection of Environment, Part 98, 

“Mandatory Greenhouse Gas Reporting”.

40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

“Environmental radiation protection standards for nuclear power operations.”

40 CFR Part 230. Code of Federal Regulations, Title 40, Protection of Environment, Part 230,

“Section 404(b)(1) Guidelines for Specification of Disposal Sites for Dredged or Fill Material.”

49 CFR Parts 171–178. Code of Federal Regulations, Title 49, Transportation, Subchapter C—

Hazardous Materials Regulations and “Specifications for packagings.”

50 CFR 17.3. U.S. Fish and Wildlife Service. 2006. “Endangered and Threatened Wildlife and 

Plants; Definitions.”

50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

“Interagency Cooperation—Endangered Species Act of 1973, as Amended.”

32 FR 4001. U.S. Fish and Wildlife Service. 1967. “Endangered Species.” Federal 

Register 32(48):4001. March 11, 1967.

41 FR 41914. U.S. Fish and Wildlife Service. 1976. “Endangered and Threatened Wildlife and 

Plants; Determination of Critical Habitat for American Crocodile, California Condor, Indiana Bat, 

and Florida Manatee.” Federal Register 41(187):41914–41916. September 24, 1976.

53 FR 43950. U.S. Department of Labor. “Memorandum of Understanding Between the 

Nuclear Regulatory Commission and the Occupational Safety and Health Administration; 

Worker Protection at NRC-licensed Facilities.” Federal Register 53 (210):43950-43952. 

October 31, 1988.

53 FR 5598. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 

Plants; Proposal to Determine Boltonia decurrens (Decurrent false aster) to be a Threatened a 

Threatened Species. Federal Register 53(37):5598-5602. February 25, 1988.

53 FR 45858. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 

Plants; Determination of Threatened Status for Boltonia decurrens (Decurrent False Aster). 

Federal Register 53(219):45858-45861. November 14, 1988.

54 FR 39857. U.S. Fish and Wildlife Service. 1989. Endangered and Threatened Wildlife and 

Plants; Determination of Threatened Status for Eastern and Western Prairie Fringed Orchids. 

Federal Register 54(187):29857-39863. September 28, 1989.

56 FR 19953. U.S. Fish and Wildlife Service. 1991. Endangered and Threatened Wildlife and 

Plants; Dalea foliosa (Leafy Prairie-Clover) Determined to be Endangered. Federal Register

56(84):19953-19959. May 1, 1991. 
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59 FR 7629. Executive Order No. 12898. “Federal actions to address environmental justice in 

minority populations and low-income populations.” Federal Register 59(32):7629–7634. 

February 16, 1994.

69 FR 52040. U.S. Nuclear Regulatory Commission. “Policy statement on the treatment of 

environmental justice matters in NRC regulatory and licensing actions.” Federal Register

69(163):52040–52048. August 24, 2004.

69 FR 41576. U.S. Environmental Protection Agency. “National Pollutant Discharge 

Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake 

Structures at Phase II Existing Facilities.” Federal Register 69(131):41576–41693. 

July 9, 2004.

74 FR 56260. Environmental Protection Agency. “Mandatory Reporting of Greenhouse 

Gases.” Federal Register 74(209): 56260-56519. October 30, 2009.

75 FR 31514. Environmental Protection Agency. “Prevention of Significant Deterioration and 

Title V Greenhouse Gas Tailoring Rule.” Federal Register 75(106):31514-31608.

77 FR 14914. U.S. Fish and Wildlife Service. “Endangered and Threatened Wildlife and Plants: 

Determination of Endangered Status for the Sheepnose and Spectaclecase Mussels 

Throughout Their Range.” Federal Register 77(49):14914-14949. March 13, 2012.

77 FR 38762. U.S. Fish and Wildlife Service. 2012. Endangered and Threatened Wildlife and 

Plants; 5-Year Status Reviews of Seven Listed Species. Federal Register

77(126):38762-38764. June 29, 2012.

78 FR 61046. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 

Plants; 12-Month Finding on a Petition To List the Eastern Small-Footed Bat and the Northern 

Long-Eared Bat as Endangered or Threatened Species; Listing the Northern Long-Eared Bat as 

an Endangered Species; Proposed Rule. Federal Register 78(194):61046-61080. 

October 2, 2013.

78 FR 72058. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 

Plants; Listing the Northern Long-Eared Bat as an Endangered Species. Federal Register

78(231):72058-72059. December 2, 2013.

80 FR 17974. U.S. Fish and Wildlife Service. “Endangered and Threatened Wildlife and 

Plants; Threatened Species Status for the Northern Long-Eared Bat with 4(d) Rule.” Federal 

Register 80(63):17974-8033. April 2, 2015.

35 IAC 1420.140(a). Illinois Administrative Code, Title 35, Environmental Protection, Part 1420, 

General Provisions, Section 140, Prohibitions.

35 IAC 201. Illinois Administrative Code, Title 35, Environmental Protection, "Subtitle B," Air 

Pollution Control Board Subchapter a, "Permits and General Provisions," Part 201 Permit and 

General Provisions.

35 IAC 301. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 

Pollution," Chapter I, "Pollution Control Board," Part 301, “Introduction.” Illinois Pollution Control 

Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulationsTitle35.aspx> (accessed 21 August 2015).

35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 

Pollution," Chapter I, "Pollution Control Board," Part 302, “Water Quality Standards.” Illinois 

Pollution Control Board. Available at 

<http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations-Title35.aspx> 

(accessed 21 August 2015).
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35 IAC 303. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, “Water 

Pollution,” Chapter I, “Pollution Control Board,” Part 303, “Water Use Designations and Site 

Specific Water Quality Standards.” Illinois Pollution Control Board. Available at 

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LaSalle County Station, Marseilles, Illinois. June 2013. In Letter from M.P. Gallagher, Vice 

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Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. 

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[Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 

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NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

LU-01. July 2, 2015. ADAMS No. ML15195A373.
Affected Environment

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[Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 

License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

LU-02. July 2, 2015. ADAMS No. ML15195A374.

[Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 

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NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

LU-03. July 2, 2015. ADAMS No. ML15195A375.

[Exelon] Exelon Generation Company, LLC. 2015g. Letter from M.P. Gallagher, Vice President 

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NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

LU-04. July 2, 2015. ADAMS No. ML15195A376.

[Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice President 

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NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

LU-05. July 2, 2015. ADAMS No. ML15195A377.

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NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

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Review Requests for Additional Information. Response to Request for Additional Information 

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NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

MA-01. July 2, 2015. ADAMS No. ML15195A344.
Affected Environment

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[Exelon] Exelon Generation Company, LLC. 2015k. Letter from M.P. Gallagher, Vice President 

License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:

LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

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MA-05. July 2, 2015. ADAMS No. ML15195A348.

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LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

Review Requests for Additional Information. Response to Request for Additional Information 

MA-09. July 2, 2015. ADAMS No. ML15195A353.

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4-1

4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS

4.1 Introduction

In this chapter, the U.S. Nuclear Regulatory Commission (NRC) evaluates the environmental 

consequences of the proposed action (i.e., license renewal of LaSalle County Station, Units 1 

and 2 (LSCS)), including the (1) impacts associated with continued operations similar to those 

that have occurred during the current license terms; (2) impacts of various alternatives to the 

proposed action; (3) impacts from the termination of nuclear power plant operations and 

decommissioning after the license renewal term (with emphasis on the incremental effect 

caused by an additional 20 years of operation); (4) impacts associated with the uranium fuel 

cycle; (5) impacts of postulated accidents (design-basis accidents and severe accidents); 

(6) cumulative impacts of the proposed action; and (7) resource commitments associated with 

the proposed action, including unavoidable adverse impacts, the relationship between 

short-term use and long-term productivity, and irreversible and irretrievable commitment of 

resources. The NRC also considers new and potentially significant information on 

environmental issues related to operation during the renewal term.

NUREG–1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants

(GEIS) (NRC 2013d) identifies 78 issues to be evaluated in the license renewal environmental 

review process. Generic issues (Category 1) rely on the analysis presented in the GEIS, unless 

otherwise noted. Applicable site-specific issues (Category 2) have been analyzed for LSCS and 

assigned a significance level of SMALL, MODERATE, or LARGE. Section 1.4 of this 

supplemental environmental impact statement (SEIS) provides an explanation of the criteria for 

Category 1 and Category 2 issues, as well as the definitions of SMALL, MODERATE, and 

LARGE. Resource-specific impact significance level definitions are provided where applicable. 

4.2 Land Use and Visual Resources

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on land use and visual resources.

4.2.1 Proposed Action

Section 3.2 describes land use and visual resources in the vicinity of the LSCS site. Table 4–1 

identifies the issues that apply to land use and visual resources during the proposed license 

renewal period. The GEIS (NRC 2013d) discusses these issues in Section 4.2.1. The GEIS 

does not identify any site-specific (Category 2) land use or visual resource issues.

The NRC staff did not identify any new and significant information related to the generic 

(Category 1) land use and visual resource issues during the review of the applicant’s 

Environmental Report (ER) (Exelon 2014a), the site audit, or the scoping process. Therefore, 

the NRC staff expects no impacts associated with these issues beyond those discussed in the 

GEIS. The GEIS concludes that the impact level for each of these issues is SMALL.
Environmental Consequences and Mitigating Actions

4-2

Table 4–1. Land Use and Visual Resource Issues

Issue GEIS Section Category

Land Use

Onsite land use 4.2.1.1 1

Offsite land use 4.2.1.1 1

Offsite land use in transmission line right-of-ways (ROWs)(a) 4.2.1.1 N/A(b)

Visual Resources

Aesthetic impacts 4.2.1.2 1

(a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid. As 

described in Section 3.1.6, all in-scope transmission lines subject to the evaluation of environmental impacts for 

license renewal are located within the LSCS site property boundary.

(b) This issue does not apply to LSCS because no offsite transmission lines are within the scope of license renewal. 

Section 3.1.6 describes the in-scope transmission lines.

Source: Table B–1 in Appendix B, Subpart A, to Title 10 of the Code of Federal Regulations (10 CFR) Part 51

4.2.2 No-Action Alternative

4.2.2.1 Land Use

If LSCS were to shut down, the impacts to land use would remain similar to those during 

operations until the plant is fully decommissioned. Temporary buildings and staging or laydown 

areas may be required during large component and structure dismantling. LSCS is likely to 

have sufficient space within previously disturbed areas for these needs; therefore, no additional 

land would need to be disturbed that would result in changes to current land uses. The GEIS

(NRC 2013d) notes that land use impacts could occur in other areas beyond the immediate 

nuclear plant site as a result of the no-action alternative if new power plants are needed to 

replace lost capacity. The NRC staff did not identify any impacts that may result at LSCS

beyond those discussed in NUREG–0586, and the NRC staff concludes that the no-action 

alternative is unlikely to noticeably alter or have more than minor effects on land use. Thus, the 

NRC staff concludes that the impacts of the no-action alternative on land use during the 

proposed license renewal term would be SMALL. 

4.2.2.2 Visual Resources

If LSCS were to shut down, visual resource impacts would remain similar to those experienced 

during operations until the site is fully decommissioned. Thus, the NRC staff concludes that the 

impacts of the no-action alternative on visual resources would be SMALL.

4.2.3 New Nuclear Alternative

4.2.3.1 Land Use

The new nuclear alternative assumes that Exelon would build a new nuclear facility in Indiana, 

Iowa, Michigan, Missouri, Kentucky, or Wisconsin at an existing power plant site. Construction 

of the facility would require an estimated 324 ac (131 ha) for permanent buildings and facilities 

and an additional 232 ac (94 ha) for temporary facilities, laydown areas, and other temporary 
Environmental Consequences and Mitigating Actions

4-3

land disturbances. Additional offsite land would be required for uranium mining, although this 

impact would result in no net change in land use impacts from those that would be associated 

with the proposed license renewal of LSCS.

During construction, the use of an existing power plant site would maximize the availability of 

existing infrastructure and minimize disruption to land that had not been previously disturbed for 

industrial uses. However, given the land requirements, some undisturbed or non-industrial-use 

lands would likely be affected or converted to industrial areas. Such impacts would likely be 

noticeable within the direct footprint of the facility but would not result in changes that would 

destabilize surrounding land uses such that those lands would no longer function for their 

designated uses. Accordingly, the NRC staff concludes that construction impacts would be 

MODERATE.

Operation of a new nuclear facility would incur impacts similar to those assessed for the 

proposed LSCS license renewal, which the NRC staff concludes, in Section 4.2.1, would be 

SMALL.

Overall, impacts of a new nuclear alternative on land use would be MODERATE during 

construction and would be SMALL during operation.

4.2.3.2 Visual Resources

Because the facility would be located on an existing power plant site, visual resource impacts of 

most new buildings and infrastructure would be minimal. The construction of natural draft 

cooling towers would be the largest visual impact because both the towers themselves and the 

plume could be visible from a distance. The magnitude of this impact would vary based on the 

topography of the chosen site and surrounding area. The NRC staff concludes that the impacts 

to visual resources from construction and operation of a new nuclear alternative would be 

SMALL to MODERATE.

4.2.4 IGCC Alternative

4.2.4.1 Land Use

The integrated gasification combined-cycle (IGCC) alternative assumes that the new facility 

would be built at an existing power plant site in Illinois, including the LSCS site, or at another 

power plant site in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. The facility 

would require 2,000 ac (800 ha) of land to construct the facility. If the facility were to be sited on 

the LSCS site, the area currently occupied by the LSCS facilities, the undeveloped areas 

immediately surrounding the facility, and the area occupied by the Illinois fish hatchery would be 

affected. Exelon would also need to acquire adjacent parcels of land to provide the full 

complement of acreage required for the IGCC facility. Additional offsite land would be required 

for coal mining, although this impact would be partially offset by the elimination of land used for 

uranium mining to supply fuel to LSCS.

During construction, the use of an existing site would maximize availability of existing 

infrastructure. However, construction would likely significantly affect surrounding natural areas 

on the site and within purchased adjacent land parcels because it would require the clearing 

and grading of these areas for industrial use. Whether sited on the LSCS site or elsewhere, the 

large footprint of the facility would likely require the conversion of land to industrial use from 

other land uses. Accordingly, construction would likely noticeably alter land uses, and the large 

area of land required for the IGCC facility could destabilize important attributes or functions of 

sensitive lands, such as nearby wetlands, if present. Accordingly, the NRC staff concludes that 

construction impacts would be MODERATE to LARGE.
Environmental Consequences and Mitigating Actions

4-4

Operation of an IGCC facility would likely not incur additional land use changes; therefore, 

operational impacts would be SMALL.

Overall, impacts of an IGCC alternative on land use would be MODERATE to LARGE during 

construction, depending on the location and types of lands affected by construction, and would 

be SMALL during operation.

4.2.4.2 Visual Resources

Because the IGCC facility would be located on an existing industrial site, additional visual 

resource impacts would be minimal. The visibility of the plant stacks and mechanical draft 

cooling towers would vary based on the topography of the chosen site and surrounding area. 

Some temporary visual impacts may occur during construction from cranes and other 

construction equipment that may be visible off site. During operation, cooling tower plumes 

could create noticeable visual impacts. The NRC staff concludes that the impacts from the 

construction and operation of an IGCC alternative on visual resources would be SMALL.

4.2.5 Natural Gas Combined-Cycle Alternative

4.2.5.1 Land Use

The natural gas combined-cycle (NGCC) alternative assumes that a new NGCC facility would 

be built at the LSCS site. The facility would require 94 ac (38 ha) of land and would be sited on 

the undeveloped land immediately surrounding the LSCS. Some infrastructure upgrades could 

be required, as well as a new or upgraded pipeline, which would affect additional land. 

Additional offsite land would be required for gas extraction and collection, although this impact 

would be partially offset by the elimination of land used for uranium mining to supply fuel to 

LSCS.

During construction, the use of the existing site would maximize the availability of existing 

infrastructure. However, construction would convert natural areas to industrial use because the 

new facility would be built outside the existing industrial footprint. Although these land use 

changes would be noticeable, construction would be unlikely to destabilize important attributes 

of surrounding lands, due to the small size of the facility footprint. Accordingly, the NRC staff 

concludes that construction impacts would be MODERATE.

Operation of an NGCC facility would likely not incur additional land use changes; therefore, 

operational impacts would be SMALL.

Overall, impacts of the NGCC alternative on land use would be MODERATE during construction 

and would be SMALL during operation.

4.2.5.2 Visual Resources

Because the NGCC facility would be located on an existing industrial site, additional visual 

resource impacts would be minimal. The mechanical draft cooling towers would likely not be 

taller than other buildings on site. Some temporary visual impacts may occur during 

construction from cranes and other construction equipment that may be visible off site. During 

operation, cooling tower plumes could create some visual impacts in the immediate vicinity of 

the facility. The NRC staff concludes that the impacts from the construction and operation of an 

NGCC alternative on visual resources would be SMALL.
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4.2.6 Combination Alternative (NGCC, Wind, Solar)

4.2.6.1 Land Use

The NGCC component of the combination alternative would have the same land requirements 

as discussed for the NGCC alternative in Section 4.2.5.1. Accordingly, the impacts to land use 

would be similar to those concluded for the NGCC alternative and, therefore, would be 

MODERATE during construction and SMALL during operation.

The wind component of this alternative would require an estimated 3,376 to 10,127 ac 

(1,366 to 4,098 ha) of land at onshore wind farm sites and agricultural cropland across the 

region of influence (ROI). However, the majority of this land would only be temporarily disturbed 

during construction. Permanently disturbed land would hold the wind turbines, access roads, 

and transmission lines and would account for 5 to 10 percent of the estimated required acreage. 

Land used for equipment laydown and turbine component assembly and erection could be 

returned to its original state following construction. Given the large footprint of the wind 

component, land use could be affected, although most land uses, such as agriculture, could 

continue once the wind turbines are operational. Land use impacts for the wind component 

would range from SMALL to MODERATE depending on the amount and types of land that 

would be affected by wind turbine construction.

The solar component would require an estimated 7,397 ac (2,993 ha) of land across the ROI. 

The majority of solar installations could be installed on building roofs at existing residential, 

commercial, or industrial sites or at larger standalone solar facilities; therefore, only a little land 

would possibly be required for construction. However, the exact magnitude of impacts on land 

use would depend on the amount of land that must be converted for construction of solar 

installations. Unlike wind power, solar-powered installations often cannot be collocated with 

existing land uses (such as in crop-producing agricultural fields). The impacts of the solar 

component of this alternative on land use would range from SMALL to MODERATE, depending 

on the amount and types of land that would be affected by construction of the solar installations.

The NRC staff concludes that the overall impacts of the combination alternative on land use 

would be SMALL to MODERATE. This range is primarily the result of the variability in land 

required for the wind and solar components.

4.2.6.2 Visual Resources

Visual resource impacts for the NGCC component of this alternative would be similar to or less 

than those described in Section 4.2.5.2 for the NGCC alternative and, therefore, would be 

SMALL. Visual resources would be significantly affected by construction of the wind 

component. Although specific effects would vary based on the topography and remoteness of 

the wind turbine locations, the visual impact of wind energy is often one of the most significant 

energy-generating visual impacts and could range from MODERATE to LARGE. The visual 

impacts of the solar component would also vary, based on the topography of the area, but the 

NRC staff expects these impacts to be minimal because individual solar installations are not tall 

or expansive, and many of the installations could be constructed on building roofs at existing 

residential, commercial, or industrial sites. Larger standalone solar facilities could have a 

greater visual impact, depending on the location, but the impacts of the solar component would 

likely be SMALL overall. The NRC staff concludes that the impacts of the combination 

alternative on visual resources would be SMALL to LARGE. This range is primarily the result of 

the potential visual impacts from the wind component of the alternative.
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4.2.7 Purchased Power Alternative

4.2.7.1 Land Use

The purchased power alternative would have wide ranging impacts that are hard to specifically 

assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind 

across many different sites in the ROI. This alternative would likely have little-to-no construction 

impacts because it would include power from already existing power generating facilities. The 

construction of additional transmission lines could affect land uses if the lines require the 

clearing of new transmission line corridors. However, if collocated with existing lines, 

transmission-line construction would be unlikely to alter existing land uses. The types of 

operational impacts from this alternative would be similar to the effects discussed in the 

preceding alternative sections. This alternative would be more likely to intensify already existing 

effects at power generating facilities than create wholly new effects on land use. Existing 

facilities would likely have best management practices (BMPs) and other procedures in place to 

ensure that effects to the environment during operations are minimized. The NRC staff 

concludes that the impacts on land use from the purchased power alternative would be SMALL.

4.2.7.2 Visual Resources

The purchased power alternative would likely not result in the construction of any buildings or 

facilities or any other changes to existing visual resources. Visual impacts from transmissionline construction could be minimized by collocating lines within existing transmission line 

corridors. The NRC staff concludes that the purchased power alternative would not have 

noticeable impacts on visual resources, and as such, would be SMALL.

4.3 Air Quality and Noise

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on air quality and noise conditions.

4.3.1 Proposed Action

4.3.1.1 Air Quality

Section 3.3 describes the meteorological, air quality, and noise conditions in the vicinity of 

LSCS. Table 4–2 identifies two Category 1 air quality issues that are applicable to LSCS: 

(1) air quality impacts (all plants) and (2) air quality effects of transmission lines. There are no 

Category 2 issues for air quality. The Category 1 issue, air quality effects of transmission lines, 

considers the production of ozone and nitrogen oxides (NOx); the GEIS (NRC 2013d) found that 

minute and insignificant amounts of ozone and nitrogen oxides are generated during the 

transmission of power to the nuclear plant from the grid. The Category 1 issue, air quality 

impacts (all plants), considers the air quality impacts from continued operation and 

refurbishment associated with license renewal.

Table 4–2. Air Quality and Noise

Issue GEIS Section Category

Air quality impacts (all plants) 4.3.1.1 1

Air quality effects of transmission lines 4.3.1.1 1

Noise impacts 4.3.1.2 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51
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The NRC staff did not identify any new and significant information during the review of LSCS’s 

ER (Exelon 2014a), the site audit, or the scoping process. As a result, the NRC did not identify 

any information or impacts related to these issues that would change the conclusions presented 

in the GEIS. Therefore, there are no impacts related to these issues beyond those discussed in 

the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL.

4.3.1.2 Noise

One Category 1 noise issue is applicable to LSCS: noise impacts (Table 4–2). The 1996 GEIS

(NRC 1996) concluded that noise was not a problem at operating plants and that it was not 

expected to be a problem at any nuclear plant during the license renewal term. The GEIS 

(NRC 2013d) did not identify new information that would alter this conclusion; therefore, impacts 

are expected to be SMALL. The NRC staff did not identify any new and significant information 

during the review of LSCS’s ER (Exelon 2014a, 2015j), the site audit, or the scoping process. 

As a result, the NRC did not identify any information or impacts related to this issue that would 

change the conclusions presented in the GEIS. Therefore, there are no impacts related to this 

issue beyond those discussed in the GEIS. The GEIS concludes that the impact level for this 

issue is SMALL.

4.3.2 No-Action Alternative

4.3.2.1 Air Quality

When the plant stops operating, there will be a reduction in emissions from many activities 

related to plant operation, such as the use of stationary combustion sources (i.e., diesel 

generators and pumps) and vehicle traffic (i.e., employee and delivery vehicles). Therefore, if 

emissions decrease, the impact on air quality from shutting down LSCS would be SMALL.

4.3.2.2 Noise

When the plant stops operating, there will be a reduction in noise from activities related to plant 

operations, such as the turbines, switchyard/transformers, sirens, loudspeakers, and vehicle 

traffic (i.e., employee and delivery vehicles). As activity from noise sources is reduced below 

levels associated with operation of LSCS, impacts would be SMALL.

4.3.3 New Nuclear Alternative 

4.3.3.1 Air Quality 

This alternative includes the construction and operation of two Westinghouse AP1000 reactors,

each with an approximate generating capacity of 1,120 megawatts electric (MWe). Due to the 

moratorium preventing the construction of new nuclear power plants within Illinois, the new 

nuclear alternative would have to be located elsewhere in the ROI (Indiana, Iowa, Michigan, 

Missouri, Kentucky, and Wisconsin) at an existing nuclear plant or retired coal site to maximize 

the use of existing infrastructure. Because the new nuclear alternative could be located 

anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) 

would be located within a designated attainment area.

Construction of the new nuclear plant would result in temporary impacts on local air quality. 

During the construction phase, the primary sources of air emissions would consist of engine 

exhaust and fugitive dust emissions. Engine exhaust emissions would be from heavy 

construction equipment and commuter, delivery, and support vehicular traffic traveling within, to, 

and from the facility. Fugitive dust emissions would be from soil disturbances by heavy 

construction equipment (e.g., earthmoving, excavating, and bulldozing); vehicle traffic on 

unpaved surfaces; concrete batch plant operations (if any); and wind erosion to a lesser extent. 
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Air emissions include criteria pollutants (i.e., particulate matter, nitrogen oxide, carbon 

monoxide, and sulfur dioxide); volatile organic compounds (VOCs); hazardous air pollutants 

(HAPs), and greenhouse gases (GHGs). Small quantities of VOC and HAP emissions would be 

released from equipment refueling; organic solvents used in cleaning, onsite storage, and use of 

petroleum-based fuels; onsite maintenance of the heavy construction equipment; and certain 

painting and other construction-finishing activities.

Air emissions would be intermittent and would vary, based on the level and duration of a specific 

activity throughout the construction phase. Based on the State and Federal permits and 

regulated practices for managing air emissions from construction equipment and temporary 

stationary sources, controlling fugitive dust, and inspecting vehicles and traffic management 

plans, the NRC staff expects that potential impacts on air quality from building a nuclear power

plant would be minimal. Because air emissions from construction activities would be limited, 

local, and temporary, the NRC staff concludes that the overall air quality impacts associated 

with construction of a new nuclear alternative would be SMALL.

Operation of a new nuclear generating plant would result in similar air emissions to those at 

LSCS. Nuclear power plants do not burn fossil fuels to generate electricity. Sources of air 

emissions include stationary combustion sources (e.g., diesel generators and diesel pumps), 

cooling towers, and mobile sources (e.g., worker vehicles, onsite heavy equipment and support 

vehicles, and delivery of materials and disposal of wastes). Air pollutants emitted from 

stationary combustion sources (e.g., criteria pollutants, VOCs, HAPs, and GHGs) and from 

cooling towers (particulate matter as drift) associated with operating a nuclear power plant 

would be permitted in accordance with state and Federal regulatory requirements. As noted in 

Section 3.3, LSCS maintains a Federally Enforceable State Operating Permit (also known as a 

“synthetic minor” air permit). A synthetic minor source has the potential to emit air pollutants in 

quantities at or above the major source threshold levels but has accepted Federally enforceable 

limitations to keep the emissions below such levels. Because air emissions would be similar for 

a new nuclear plant, the NRC staff expects similar air permitting conditions and regulatory 

requirements. Subpart P of 40 CFR 51.307 contains the visibility protection regulatory 

requirements, including the review of the new sources that may affect visibility in any Federal 

Class I area. If a new nuclear plant were located near a mandatory Class I area, additional air 

pollution control requirements may be required.

In general, most stationary combustion sources at a nuclear power plant would operate only for 

limited periods, often for periodic maintenance testing. Thus, emissions from stationary 

combustion sources would fall far below the threshold for major sources (100 U.S. short tons 

per year) and the threshold for mandatory GHG reporting (25,000 metric tons (MT) per year). 

The NRC staff expects similar air emissions for combustion sources from a new nuclear plant as 

are currently being emitted from LSCS (Exelon 2014a), as follows:

• carbon monoxide (CO)—2.2 tons (2 MT),

• nitrogen oxides (NOx)—8.4 tons (7.6 MT),

• sulfur dioxide (SO2)—0.002 tons (0.002 MT),

• particulate matter (PM10)—0.15 tons (0.14 MT), and

• particulate matter (PM2.5)—0.15 tons (0.14 MT).

Additional particulate matter emissions would result from cooling tower operation and worker 

vehicles commuting to and from the plant. However, a nuclear power plant located in the ROI 

would use cooling water taken from a nearby river or lake, which would have relatively low 

concentrations of total dissolved solids. In addition, modern cooling towers would be equipped 
Environmental Consequences and Mitigating Actions

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with drift eliminators to minimize the loss of cooling water from the tower via drift. Thus, 

particulate matter emissions from cooling towers would be anticipated to be minimal.

The NRC staff evaluated potential impacts on air quality associated with criteria pollutants and 

GHG emissions from operating a new nuclear alternative. The NRC staff determined that the 

impacts would be minimal. Therefore, the NRC staff concludes that the impacts of operation of 

a new nuclear alternative on air quality from emissions of criteria pollutants and GHGs would be 

SMALL. 

The NRC staff concludes that the air quality impacts associated with construction and operation 

of a new nuclear alternative would be SMALL.

4.3.3.2 Noise

Construction of a new nuclear power plant is similar to that of other large industrial projects and 

involves many noise-generating activities. In general, noise emissions vary with each phase of 

construction, depending on the level of activity, the mix of construction equipment for each 

phase, and site-specific conditions. Noise propagation to receptors is affected by several 

factors, including source-receptor configuration; land cover; meteorological conditions 

(i.e., temperature, relative humidity, and vertical profiles of wind and temperature); and 

screening (e.g., topography and natural or manmade barriers). Typical construction equipment, 

such as dump trucks, loaders, bulldozers, graders, scrapers, air compressors, generators, and 

mobile cranes, would be used, and pile-driving and blasting activities would take place during 

the construction of a new nuclear power plant. Other noise sources include commuter, delivery, 

and support vehicular traffic traveling within, to, and from the facility.

During the construction phase, a variety of construction equipment would be used and at 

varying duration. Noise emissions from construction equipment are predicted to be in the 

85- to 100-dBA range (FHWA 2006); however, noise levels attenuate rapidly with distance. 

At a 0.5-mi (0.8-km) distance from construction equipment, 85 to 90-dBA noise levels can drop 

to 51 to 61 dBA (NRC 2002). Additionally, noise abatement and controls can be incorporated to 

reduce noise impacts. Accounting for attenuation from the construction site and noise controls, 

predicted noise levels can exceed the U.S. Environmental Protection Agency (EPA) guideline of 

55 dBA but can be less than the U.S. Department of Housing and Urban Development 

acceptable noise level guideline of 65 dBA. Based on the temporary nature of construction 

activities, consideration of noise attenuation from the construction site to residences, the 

location and characteristics (i.e., ground cover), and good noise control practices, the NRC staff 

concludes that the potential noise impacts of construction activities from a new nuclear 

alternative would be SMALL.

During the operation phase, noise sources from the new nuclear power plant would include 

cooling towers; transformers; turbines; pumps; compressors; other auxiliary equipment 

(e.g., standby generators); and vehicular traffic (e.g., commuting, delivery, and support), similar 

to those for LSCS discussed in Section 3.3.2 of this SEIS.

Although the plant layout and the distance from primary noise sources to the nearby receptors 

at LSCS might be different from those at a new nuclear alternative site and the new nuclear 

alternative will likely have cooling towers, the NRC staff does not expect noise impacts for a 

new nuclear plant to be any greater than those analyzed for the existing LSCS site. Although 

there would be noise generated by the impact of falling water associated with the cooling tower, 

noise from fans would not occur because the cooling tower would be a natural draft cooling 

tower, thus resulting in lower noise levels. Therefore, the noise impacts from operations of a 

new nuclear plant located within the ROI region would be SMALL.
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The NRC staff concludes that the noise impacts associated with construction and operation of a 

new nuclear alternative would be SMALL.

4.3.4 IGCC Alternative

4.3.4.1 Air Quality 

This alternative includes the construction and operation of four IGCC units with a total output of 

2,472 MWe and a capacity factor of 85 percent. The new power plant is assumed to be located 

at an existing power plant site(s). These sites could be located in Illinois (including the LSCS

site) or other adjoining States in the ROI (i.e., Indiana, Iowa, Michigan, Missouri, Kentucky, and

Wisconsin). New infrastructure and infrastructure upgrades would depend on specific-site 

locations. Because the IGCC alternative could be located anywhere within the seven-state ROI, 

it is unknown at this time whether the specific site(s) would be located within a designated 

attainment area. If the IGCC alternative were to be located at LSCS, it would be located in 

LaSalle County; LaSalle County is designated as an attainment area for all National Ambient Air 

Quality Standards (NAAQS) (40 CFR 81.314).

Construction of an IGCC plant would be similar to that of other large industrial projects and 

involves many activities similar to those for a new nuclear alternative presented in Section 4.3.3. 

Construction of an IGCC plant would result in the release of various criteria pollutants 

(i.e., particulate matter, nitrogen oxides, carbon monoxide, and sulfur dioxide); VOCs; HAPs; 

and GHGs from operation of internal combustion engines in construction vehicles, equipment, 

delivery vehicles, and vehicles used by the commuting construction workforce. In addition, soil 

disturbance activities, such as earthmoving and material handling, would generate fugitive dust. 

The onsite storage and dispensing of vehicle and equipment fuels result in VOC releases. Air 

emissions would be intermittent and would vary, based on the level and duration of a specific 

activity throughout the construction phase. Construction lead times for IGCC plants are 

estimated to be 3 years (NETL 2013). Impacts would be localized, intermittent, and short lived, 

and adherence to standard construction BMPs would mitigate such impacts. The NRC staff 

concludes that construction-related impacts on air quality from an IGCC alternative would be of 

relatively short duration and would be SMALL.

The sources of air emissions during operation include heat recovery steam generator (HRSG) 

stacks, the wet gas sulfuric acid (WSA) exhaust system, acid gas removal process 

startup/shutdown vents, startup stacks, flares, material-handling equipment, and mechanical 

draft cooling towers (DOE 2010a). The HRSG stacks would release the most emissions. 

Auxiliary boilers and diesel-driven pumps would also generate emissions on an infrequent basis.

Compared to conventional coal-fired power plants, the proposed IGCC power plant would 

reduce sulfur dioxide, nitrogen oxides, mercury, and particulate matter emissions by removing 

constituents from the synthetic gas (syngas) (i.e., gasifiers convert coal into a gas)

(DOE 2010a). The IGCC alternative would also result in lower nitrogen oxide emissions 

because nearly 100 percent of the fuel-bound nitrogen from the syngas would be removed from 

the syngas before combustion in the gas turbine. Sulfur removal technology would remove 

more than 99 percent of the sulfur in the syngas. The use of sulfide-activated carbon could 

remove more than 92 percent of mercury from the syngas. More than 99.9 percent of 

particulate matter emissions would be removed from the syngas using high-temperature, 

high-pressure filtration.

Various Federal and state regulations aimed at controlling air pollution would affect an IGCC 

alternative located in the seven-state ROI. A new IGCC plant would qualify as a new major 

source because of its potential to emit greater than 100 tons per year of criteria pollutants and 

would be subject to the requirements of a new source review (NSR) permitting program under 
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the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.) (EPA 2015f). An NSR 

permit or construction permit would specify emission limits for each pollutant, along with 

monitoring and reporting requirements; specifications for fuel and control equipment; and 

monitoring and performance testing for the IGCC units, auxiliary boiler, and WSA process. The 

new IGCC plant would be required to secure a Title V operating permit from the state agency.

An NSR review would limit emissions for criteria pollutants and would reflect existing ambient air 

quality at the selected location. An analysis regarding NAAQS compliance would be conducted 

at the specific site location. The IGCC alternative also would need to comply with the standard 

of performance for new stationary sources set forth in Subpart Da, “Standards of Performance 

for Electric Utility Steam Generating Units,” of 40 CFR Part 60.

If the IGCC alternative were located close to a mandatory Class I area, additional air pollution 

control requirements would be necessary (Subpart P of 40 CFR Part 51) as mandated by the 

Regional Haze Rule. Within the ROI, there are five Class I Federal areas, including Mammoth 

Cave National Park in Kentucky (40 CFR 81.411), Isle Royale National Park and Seney 

Wilderness Area in Michigan (40 CFR 81.414), and Hercules-Glades Wilderness Area and 

Mingo Wilderness Area in Missouri (40 CFR 81.416). The rule could apply to the IGCC 

alternative but would depend on specific site location(s). If the IGCC alternative were to be 

located at the LSCS, the nearest Class I Federal area for visibility protection is the Mingo 

National Wildlife Refuge, which is approximately 306 mi (492 km) southwest of LSCS.

Air emissions for the IGCC alternative were estimated based on emission factors presented in 

Table 4.3–1 in the GEIS (NRC 2013d). The resulting estimated emissions are as follows:

• sulfur dioxide (SO2)—820 tons (740 MT) per year,

• nitrogen oxides (NOx)—3,000 tons (2,720 MT) per year,

• particulate matter (PM10)—480 tons (435 MT) per year,

• carbon monoxide (CO)—2,045 tons (1,850 MT) per year, and

• carbon dioxide equivalent (CO2e)—14.3 million tons (13.0 million MT) per year.

The IGCC alternative would produce 820 tons (740 MT) per year of sulfur dioxide and 

3,000 tons (2,072 MT) per year of nitrogen oxides. The IGCC plant would have to comply with 

Title IV of the CAA (42 U.S.C. 7651) reduction requirements for sulfur oxides and nitrogen 

oxides, which are the main precursors of acid rain and are the major causes of reduced 

visibility. Title IV establishes maximum sulfur oxide and nitrogen oxide emission rates from the 

existing plants and a system of sulfur oxide emission allowances that can be used, sold, or 

saved for future use by the new plants. The new plant would be subjected to the continuous 

monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. 

The Cross-State Air Pollution Rule (Volume 76 of the Federal Register, page 48208 

(76 FR 48208)) requires 27 states (including Indiana, Iowa, Michigan, Missouri, Kentucky, and 

Wisconsin) to improve air quality and requires power plants to reduce annual sulfur dioxide 

and/or nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. A 

new IGCC plant would be subject to these additional rules and regulations.

The IGCC alternative would emit approximately 14.3 million tons (approximately 13 million MT) 

per year of CO2e emissions. The plant would be subjected to the continuous monitoring 

requirements for carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued 

a final rule tailoring the criteria that determine which stationary sources and modifications to 

existing projects become subject to permitting requirements for GHG emissions under the 

prevention of significant deterioration (PSD) and Title V Federal permit programs of the CAA
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(77 FR 41051). Beginning January 2, 2011,2 operating permits issued to major sources of GHG 

under the PSD or Title V permit programs must contain provisions requiring the use of best 

available control technology to limit the emissions of GHGs, if those sources would be subject to 

PSD or Title V permitting requirements because of their non-GHG pollutant emission potentials 

and if their estimated GHG emissions are at least 75,000 tons per year of CO2e. If the IGCC 

alternative meets PSD or Title V permitting requirements for non-GHG pollutant emissions and 

the GHG emission thresholds established in the rule, GHG emissions from this alternative would 

be regulated under the PSD and Title V permit programs.

In response to the Consolidated Appropriations Act of 2008 (Public Law 110–161), EPA issued 

final mandatory GHG reporting regulations for major sources effective in December 2009 

(74 FR 56260). Major sources are defined as those sources emitting more than 25,000 MT per 

year of all GHGs. An IGCC alternative would be subject to these reporting regulations with or 

without carbon capture. On January 8, 2014, EPA issued a proposal for GHG emissions from 

new fossil fuel-fired electric utility steam generating units (79 FR 1430). It also proposes 

standards of performance for IGCC units that burn coal. The performance standards are based 

on partial implementation of carbon capture and sequestration (CCS) as the best system of 

emission reduction. The EPA issued final standards that limit GHG emissions from newly 

constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units 

and stationary combustion turbines on October 23, 2015 (Clean Power Plan; 80 FR 64510). 

The IGCC alternative may be subject to these standards.

An IGCC alternative also would be subject to the Mercury and Air Toxics Standards (MATS) 

final rule, which was finalized by EPA on December 16, 2011 (77 FR 9304). Standards for 

emissions of heavy metals (i.e., mercury, arsenic, chromium, and nickel) and acid gases 

(i.e., hydrochloric acid and hydrofluoric acid) are set by MATS. Mercury is the most prominent 

HAP emitted and is subject to regulation by the MATS rule. New IGCC units are required to 

meet a mercury emission limit of 0.003 lb per gigawatt hour (Subpart UUUUU of 

40 CFR Part 63). The NRC staff estimates that an IGCC alternative replacing the electrical 

output of LSCS would generate 0.03 ton (0.02 MT) of mercury per year.

The impact from sulfur dioxide, nitrogen oxide, particulate matter, and carbon monoxide 

emissions would be significant and would be subject to Title V permitting. GHG emissions also 

would be noticeable and significant; GHG emissions would be much larger than the threshold in 

the EPA GHG Tailoring Rule (77 FR 41051), and GHG emissions may be regulated under the 

PSD and Title V permit programs that would trigger a regulated NSR. In the near future, carbon 

dioxide emissions could be reduced considerably if CCS technology were installed.

As a result of the significant criteria air emissions, a major air emission source, and significant 

GHG emissions, the NRC staff concludes that the air quality impacts associated with operation 

of an IGCC alternative would be MODERATE.

The NRC staff concludes that the overall air quality impacts associated with construction and 

operation of an IGCC alternative would be MODERATE.

 2 On June 23, 2014, the U.S. Supreme Court issued a decision that EPA may not treat GHGs as an air 

pollutant for purposes of determining whether a source is a major source required to obtain a PSD or 

Title V permit but could continue to require PSD and Title V permits otherwise required, based on 

emissions of conventional pollutants. In July 2014, EPA issued a memorandum in response to the 

Supreme Court’s decision and acknowledged that, although the decision is pending judicial action, EPA 

will no longer require PSD or Title V permits for GHG-emitting sources that are not sources subject to 

PSD or Title V permits based on emissions of conventional pollutants (e.g., nitrogen oxides and carbon 

monoxide) (EPA 2015b).
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4.3.4.2 Noise

Construction of an IGCC plant is similar to that of other large industrial projects, and 

construction-related noise sources would be virtually the same as those for construction of the 

nuclear alternative. However, the construction period for the IGCC alternative would be shorter, 

and activities would be scattered over a wider area as compared with construction of a nuclear 

alternative. Consequently, with construction-related noise for the nuclear alternative as a 

bounding condition, the NRC staff concludes that construction-related noise impacts associated 

with the IGCC alternative would be SMALL.

Operation of an IGCC plant would introduce mechanical sources of noise that would be audible 

off site. Continuous sources include the mechanical equipment associated with normal plant 

operations and mechanical draft cooling towers. Mechanical draft cooling towers may result in 

greater sound levels than natural draft cooling towers as a result of the mechanical noise 

associated with the movement of fans. However, mechanical draft cooling towers can be 

equipped with fans with sound attenuators. Intermittent sources include the equipment related 

to coal handling, solid waste disposal, transportation related to coal and lime/limestone delivery, 

and the commuting of plant employees. Noise associated with rail delivery of coal and 

lime/limestone would extend beyond the plant site boundary and would be most significant for 

residents living in the vicinity of the facility and along the rail route. Transportation-related noise 

sources have the potential for causing impacts, as these noise sources reach beyond the plant 

site boundary. Noise impacts associated with rail delivery are predicted to be in the 

80- to 96-dBA range (NRC 2002).

As a result of additional noise associated with both the mechanical cooling towers and the rail 

line and unknown distance from primary noise sources to nearby sensitive receptors, the NRC 

staff concludes that the potential offsite noise impacts on residents in the vicinity of an operating 

IGCC alternative site would range from SMALL to MODERATE

The NRC staff concludes that the overall potential impacts of noise associated with construction 

and operation of the IGCC alternative and the rail line are considered to range from SMALL to 

MODERATE.

4.3.5 NGCC Alternative

4.3.5.1 Air Quality 

This alternative includes the construction and operation of five NGCC 560-MWe units (total 

2,800 MWe) and a capacity factor of 85 percent. These sites could be located at an existing 

power plant site in the ROI (including the LSCS site). Some infrastructure upgrades may be 

required and would require construction of a new or upgraded pipeline. Using existing power 

plant sites maximizes availability of infrastructure and reduces disruption to land and 

populations. Because the NGCC alternative could be located anywhere within the seven-state 

ROI, it is unknown at this time whether the specific site(s) would be located within a designated 

attainment area. If the NGCC alternative were to be located at LSCS, it would be located in 

LaSalle County; LaSalle County is designated as an attainment area for all NAAQS 

(40 CFR 81.314).

Construction of an NGCC power plant would be similar to that of other large industrial projects. 

Construction of an NGCC power plant would result in the release of various criteria pollutants 

(i.e., particulate matter, nitrogen oxides, carbon monoxide, and sulfur dioxide); VOCs; HAPs; 

and GHGs from the operation of internal combustion engines in construction vehicles, 

equipment, delivery vehicles, and vehicles used by the commuting construction workforce. In 

addition, onsite soil disturbance activities, such as earthmoving and material handling, would 
Environmental Consequences and Mitigating Actions

4-14

generate fugitive dust. Releases of VOCs will also result from the onsite storage and 

dispensing of vehicle and equipment fuels. Air emissions would be intermittent and would vary,

based on the level and duration of a specific activity throughout the construction phase. 

Gas-fired power plants are constructed relatively quickly; construction lead times for NGCC 

plants are around 2 to 3 years (EIA 2011; OECD/NEA 2005). Impacts would be localized, 

intermittent, and short lived, and adherence to standard construction BMPs would mitigate such 

impacts. Therefore, the NRC staff concludes that construction-related impacts on air quality 

from an NGCC alternative would be of relatively short duration and would be SMALL.

Operation of the NGCC plant could result in significant emissions of certain criteria pollutants, 

including carbon monoxide, nitrogen oxides, and particulate matter. The sources of air 

emissions during operation include gas turbines through HRSG stacks and mechanical draft 

cooling towers. An analysis regarding NAAQS compliance would be conducted at the specific 

site location. Various Federal and state regulations aimed at controlling air pollution would 

affect an NGCC alternative located in the seven-state ROI. An NGCC plant would be subject to 

NSR permitting program requirements to ensure that air emissions are minimized and that the 

local air quality is not substantially degraded (EPA 2015e). The new NGCC plant would be 

required to secure a Title V operating permit from the state agency. The NGCC plant would 

need to comply with the standards of performance for stationary combustion turbines set forth in 

Subpart KKKK of 40 CFR Part 60. If the NGCC alternative were located close to a mandatory 

Class I area, additional air pollution control requirements would be required (Subpart P of 

40 CFR Part 51), as mandated by the Regional Haze Rule. A detailed discussion of these 

Federal and state regulations is provided in Section 4.3.4 (see the air quality operation 

discussion for the IGCC alternative).

Air emissions for the NGCC alternative were estimated using emission factors developed by the 

U.S. Department of Energy’s (DOE’s) National Energy Technology Laboratory (NETL) NGCC 

analysis (NETL 2010). Assuming a total gross capacity of 2,800 MWe and a capacity factor 

of 0.85, the resulting estimated NGCC emissions are as follows:

• sulfur dioxide (SO2)—32 tons (29 MT) per year,

• nitrogen oxides (NOx)—700 tons (635 MT) per year,

• particulate matter (PM10)—51 tons (46 MT) per year,

• carbon monoxide (CO)—72 tons (65 MT) per year, and

• carbon dioxide equivalent (CO2e)—9.0 million tons (8.2 million MT) per year.

The NGCC alternative would produce 32 tons (29 MT) per year of sulfur dioxide and 700 tons 

(635 MT) per year of nitrogen oxides. The new plant would be subjected to the continuous 

monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. A

new NGCC plant would be subject to the additional rules and regulations set forth in the 

Cross-State Air Pollution Rule (see Section 4.3.4 above).

The NGCC alternative would emit approximately 9.0 million tons (approximately 8.2 million MT) 

per year of CO2e. The plant would be subjected to the continuous monitoring requirements for 

carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued a final rule 

tailoring the criteria that determine which stationary sources and modifications to existing 

projects become subject to permitting requirements for GHG emissions under the PSD and 

Title V programs of the CAA (77 FR 41051). Beginning January 2, 2011, operating permits 

issued to major sources of GHG under PSD or Title V Federal permit programs must contain 

provisions requiring the use of best available control technology to limit the emissions of GHGs,

if those sources would be subject to PSD or Title V permitting requirements because of their 
Environmental Consequences and Mitigating Actions

4-15

non-GHG pollutant emission potentials and if their estimated GHG emissions are at least 

75,000 tons per year of carbon dioxide equivalent (CO2e) emissions. If the NGCC alternative 

meets PSD or Title V permitting requirements for non-GHG pollutant emissions and the GHG 

emission thresholds established in the rule, GHG emissions from this alternative would be 

regulated under the PSD and Title V permit programs. Furthermore, the NGCC alternative 

would be subject to the carbon dioxide emission performance rate standard and best system of 

emission reduction set forth in the Clean Power Plan aimed at reducing carbon pollution from 

power plants (see Section 4.3.4 above).

In response to the Consolidated Appropriations Act of 2008 (Public Law 110–161), EPA issued 

final mandatory GHG reporting regulations for major sources effective in December 2009 

(74 FR 56260). Major sources are defined as those emitting more than 25,000 MT per year of 

all GHGs. An NGCC alternative would be subject to these reporting regulations with or without 

carbon capture.

In December 2000, EPA issued regulatory findings on emissions of HAPs from electric utility 

steam-generating units (65 FR 79825). These findings indicated that natural gas-fired plants 

emit HAPs, such as arsenic, formaldehyde, and nickel and stated the following:

[T]he impacts due to HAP emissions from natural gas-fired electric utility steam 

generating units were negligible based on the results of the study. The 

Administrator finds that regulation of HAP emissions from natural gas-fired 

electric utility steam generating units is not appropriate or necessary 

[65 FR 79825].

Mercury is not emitted from NGCC power plants because natural gas used as fuel does not 

contain mercury.

Nitrogen oxide emissions from an NGCC alternative would be significant and subject to Title V 

permitting. GHG emissions also would be noticeable and significant; carbon dioxide emissions 

would be much larger than the threshold in the EPA GHG Tailoring Rule. Therefore, the NRC 

staff concludes that the overall air quality impacts associated with operation of an NGCC 

alternative would be MODERATE.

The NRC staff concludes that the overall air quality impacts associated with construction and 

operation of an NGCC alternative would be MODERATE.

4.3.5.2 Noise

The construction-related noise sources for an NGCC alternative would be virtually the same as 

those for construction of the IGCC alternative. Construction vehicles and equipment associated 

with the construction of the NGCC plant would generate noise; these impacts would be 

intermittent and would last only through the duration of plant construction. Noise emissions 

from common construction equipment would be in the 85- to 100-dBA range (FHWA 2006). 

However, noise abatement and controls can be incorporated to reduce noise impacts. The 

NRC staff concludes that construction-related noise impacts associated with the NGCC 

alternative would be SMALL.

Noise impacts from operations would include mechanical draft cooling towers, transformers, 

turbines, pumps, compressors, exhaust stacks, the combustion inlet filter house, condenser 

fans, high-pressure steam piping, and vehicles (Saussus 2012). As discussed under the IGCC 

alternative, mechanical draft cooling towers can be equipped with fans with sound attenuators. 

Pipelines delivering natural gas fuel could be audible off site near gas compressor stations, but 

such noise impacts would be similar to impacts already occurring in the vicinity of the existing 

pipeline to which the new NGCC site would connect. Most noise-producing equipment is 

located inside the power block buildings, and no outside fuel-handling activities will occur. 
Environmental Consequences and Mitigating Actions

4-16

Minor offsite noise sources could include pipeline compressor stations. The NRC staff 

concludes that operation-related noise impacts from the NGCC alternative would be SMALL.

The NRC staff concludes that construction- and operation-related noise impacts from the NGCC 

alternative would be SMALL.

4.3.6 Combination Alternative (NGCC, Wind, Solar)

The combination alternative relies on NGCC-, wind-, and solar-generating capacity. The solar 

photovoltaic (PV) portion would consist of a total net capacity of 227 MWe; the onshore wind 

portion would consist of a total net capacity of 1,813 MWe; and the NGCC portion would consist 

of a total net capacity of 360 MWe. The NGCC portion of this alternative would be located at 

LSCS and in an attainment area (LaSalle County) for all NAAQS. The solar and wind portion of 

this alternative would be located in Illinois or other adjoining States in the ROI (i.e., Indiana, 

Iowa, Michigan, Missouri, Kentucky, and Wisconsin).

4.3.6.1 Air Quality 

Air emissions associated with the construction of the NGCC portion of the combination 

alternative are similar to the NGCC alternative but due to its smaller size, would be 

proportionally reduced. As discussed in Section 4.3.5.1, construction activities for an NGCC 

alternative would cause some temporary impacts to air quality from dust generation during 

operation of the earth-moving and material-handling equipment and exhaust emissions from 

worker vehicles and construction equipment. These emissions include criteria pollutants, 

VOCs, GHGs, and small amounts of HAPs. However, these impacts would be localized, 

intermittent, and short lived, and adherence to standard construction BMPs would mitigate such 

impacts. The NRC staff concludes that construction-related impacts on air quality from an 

NGCC portion of the combination alternative would be of relatively short duration and would be 

SMALL.

For the wind portion of the combination alternative, the total estimated land requirement would 

be between 3,376 and 10,127 ac (1,366 to 4,098 ha), but only a small percentage of the 

committed land area (5 to 10 percent or less) would be disturbed by construction activities 

because wind turbines need to be separated from one another to maximize energy production 

and to avoid wake turbulences created by upwind turbines. Construction of the wind portion of 

the combination alternative would involve a number of activities, including road and 

staging/laydown area construction, land clearing, topsoil stripping, earth-moving operations, 

grading, ground excavation, drilling, foundation treatment, erecting wind turbines, ancillary 

building/structure construction, and electrical and mechanical installation. For most wind energy 

facilities, the site preparation phase would last for only a few months, followed by a year-long 

construction phase (depending on the size of the wind energy facilities) (Tegen 2006). Air 

emissions associated with construction activities result from fugitive dust from soil disturbances 

and engine exhaust from heavy equipment and vehicular traffic. These emissions include 

criteria pollutants, VOCs, GHGs, and HAPs. Dust-suppression methods and other mitigation

measures could reduce impacts from fugitive dust. The wind portion of the combination 

alternative would have no power block that would otherwise require intensive construction 

activities. Accordingly, the heavy equipment used, workforce, level of activities, and 

construction duration would be substantially lower than other alternatives. Therefore, the NRC 

staff concludes that the overall air quality impacts associated with construction of the wind 

portion of the combination alternative would be SMALL.

Construction of the solar portion of the combination alternative would cause temporary impacts 

to air quality from fugitive dust from soil disturbances and engine exhaust from heavy equipment 

and vehicular traffic. Air emissions associated with construction activities include criteria 
Environmental Consequences and Mitigating Actions

4-17

pollutants, VOCs, GHGs, and HAPs to a lesser amount. Dust-suppression methods and other 

mitigation measures could reduce impacts from fugitive dust. The solar PV portion of the 

combination alternative would have no power block that would otherwise require intensive 

construction activities. Accordingly, the number of heavy equipment and workforce, level of 

activities, and construction duration would be substantially lower than those for other 

alternatives. Therefore, the NRC staff concludes that the overall air quality impacts associated 

with construction of the solar PV portion of the combination alternative would be SMALL.

Air emissions associated with the operation of the NGCC portion of the combination alternative 

are similar to the NGCC alternative in Section 4.3.5.1 but are reduced proportionally because its 

generating capacity is approximately 13 percent of the NGCC alternative.

Air emissions for the NGCC alternative were estimated using emission factors developed by 

DOE’s NETL NGCC analysis (NETL 2010). Assuming a total gross capacity of 425 MWe and a 

capacity factor of 0.85, the resulting estimated NGCC emissions are as follows:

• sulfur dioxide (SO2)—4.9 tons (4.8 MT) per year,

• nitrogen oxides (NOx)—106 tons (96 MT) per year,

• particulate matter (PM10)—7.7 tons (57.0 MT) per year,

• carbon monoxide (CO)—10.9 tons (9.9 MT) per year, and

• carbon dioxide equivalent (CO2e)—1.3 million tons (1.2 million MT) per year.

Estimated annual emissions of sulfur dioxide, nitrogen oxides, carbon monoxide, and particulate 

matter would be lower than the major source threshold. Furthermore, the NGCC portion of this 

alternative would be located at LSCS and would be a designated attainment area (LaSalle 

County) for all NAQQS. Therefore, the overall air quality impacts associated with operation of 

the NGCC portion of the combination alternative would be SMALL.

Air emissions from the operation of wind energy facilities would include minor dust and engine 

exhaust emissions from vehicles and heavy equipment associated with site inspections, 

maintenance activities, and wind erosion from cleared land and access roads. The types of 

emission sources and pollutants during operation would be similar to those during construction, 

but emissions would be much less during operation. The NRC staff concludes that the overall 

air quality impacts associated with the operation of the wind portion of the combination 

alternative would be SMALL.

In general, air emissions associated with the operation of solar energy facilities are negligible 

because no fossil fuels are burned to generate electricity. Emissions from solar fields would 

include fugitive dust and engine exhaust emissions from vehicles and heavy equipment 

associated with site inspections, maintenance activities (e.g., panel washing or replacement), 

and wind erosion from cleared lands and access roads. The types of emission sources and 

pollutants during operation would be similar to those during construction, but emissions would 

be much lower during operation. These emissions should not cause exceedances of air quality 

standards or have any impacts on climate change. The NRC staff concludes that the overall air 

quality impacts associated with the operation of the solar PV portion of the combination 

alternative would be SMALL.

The overall air quality impacts associated with construction and operation of the combination 

alternative would be SMALL.
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4.3.6.2 Noise

The construction-related noise sources for the NGCC portion of the combination alternative 

would be virtually the same as those for construction of the NGCC alternative. The construction 

period for the NGCC portion would be shorter, and the level of construction activities would be 

less extensive than for the NGCC alternative. Consequently, the NRC staff concludes that 

construction-related noise impacts associated with the NGCC portion of the combination 

alternative would be SMALL.

Construction of the wind portion of the combination alternative would involve a number of 

activities, as described above. The wind portion of the combination alternative would have no 

power block that would otherwise require intensive construction activities. Accordingly, the 

number of heavy equipment and workforce, level of activities, and construction duration would 

be substantially lower than other alternatives. Considering these factors, the NRC staff 

concludes that construction-related noise impacts associated with the wind portion of the 

combination alternative would be SMALL.

Construction of the solar PV portion of the combination alternative would involve a number of 

activities. The solar PV portion of the combination alternative would have no power block that 

would otherwise require intensive construction activities. Accordingly, the number of heavy 

equipment and workforce, level of activities, and construction duration would be substantially 

lower than other alternatives. Considering these factors, the NRC staff concludes that 

construction-related noise impacts associated with the solar PV portion of the combination 

alternative would be SMALL.

Besides noise from the power block area, cooling towers, and vehicular traffic, operation-related 

noise for the NGCC portion would include limited outdoor waste-handling activities. Pipelines 

delivering natural gas fuel could be audible off site near gas compressor stations, but such 

sound impacts would be similar to impacts already occurring in the vicinity of the existing 

pipeline to which the new NGCC site would connect. Most noise-producing equipment is 

located inside the power block buildings, and no outside fuel-handling activities would occur. 

The NRC staff concludes that operation-related noise impacts from the NGCC portion of the 

combination alternative would be SMALL.

Noise impacts from wind generation operations would include aerodynamic noise from the 

turbine rotors and mechanical noise from the turbine drive-train components. Noise levels are 

dependent on the wind and atmospheric conditions, which vary with time, and site-specific 

conditions, including the number and size of wind turbines, their layout, their distance to nearby 

sensitive receptors, land cover, and topography. Wind turbine noise levels can reach 105 dBA; 

however, studies show that at approximately 1,000 ft (300 m) from a wind turbine, noise levels 

can reach 43 dBA (GE 2010; Hessler 2011). Therefore, masking effects of background noise

should be taken into consideration. Unless noise from wind turbines is masked by high 

background levels (e.g., near major highways or industrial complexes), it can be noticeable and 

annoying at farther distances. One study indicated that, for the same A-weighted sound level, 

proportions of respondents annoyed by wind turbine noise are higher than for other community 

noise, such as aircraft, road, or railway traffic, and that the proportion of respondents annoyed 

by the noise increases more rapidly (Pedersen and Persson Waye 2004). Therefore, the NRC 

staff concludes that operation-related noise impacts from the wind portion of the combination 

alternative would be SMALL to MODERATE, depending on the layout and location of the wind 

facility and on its distance to nearby sensitive receptors.

The solar PV portion of the combination alternative would have no power block and cooling 

towers; therefore, there would be a minimal number of noise sources with low-level noises. 

Noise sources include small-scale cooling systems to dissipate heat from solar module 
Environmental Consequences and Mitigating Actions

4-19

assemblies, solar tracking devices, inverters, transformers, and vehicle traffic for maintenance 

and inspection. Because of minimal noise-generating activities, noise from a solar PV facility 

would be anticipated to be inaudible or barely perceptible at the facility boundaries. Considering 

the minimum number of sources with low-noise levels and the area size of the solar PV facility, 

the NRC staff concludes that operation-related noise impacts from the solar PV portion of the 

combination alternative would be SMALL.

The noise impacts associated with construction and operation of the combination alternative 

would be SMALL to MODERATE.

4.3.7 Purchased Power Alternative

4.3.7.1 Air Quality

As discussed in Section 2.2.2.5, purchased power would come from common types of existing 

technology (i.e., coal, natural gas, and nuclear) within the ROI, and the construction of new 

facilities to replace LSCS would be unlikely. Construction of new transmission lines would result 

in additional amounts of air emissions. Air emissions associated with the construction of 

transmission lines would be from operation of the earth-moving and material-handling 

equipment and exhaust emissions from worker vehicles and construction equipment. These 

emissions include criteria pollutants, VOCs, GHGs, and HAPs. However, these impacts would 

be temporary and would not likely be high. For purchased power from existing plants, the 

impacts on air quality are expected to be SMALL because change to existing plant operations 

would be minimal.

If new facilities were to be constructed for purchased power, the impact on air quality would 

depend on the plant technology constructed and the air quality status (i.e., attainment, 

nonattainment, or maintenance status) where the generating plant is located because air 

emissions can vary substantially based on the alternative air quality standards. For instance, 

natural gas- and coal-fired plants emit higher amounts of nitrogen oxides, sulfur oxides, 

particulate matter, and carbon dioxide than nuclear power plants do. Purchased power from 

new nuclear plants would not have noticeable impacts on air quality. New natural gas- and 

coal-fired plants would have noticeable impacts on air quality as a result of the higher amounts 

of air emissions. Furthermore, if the plant is sited in a designated nonattainment or 

maintenance area, emission impacts from plant operation can be greater than those for a 

designated attainment area.

Based on the above, impacts on air quality from purchased power from new plants would be 

SMALL to MODERATE.

4.3.7.2 Noise

Purchased power from existing electricity generating facilities would not have noticeable 

impacts on noise because change to existing plant operations would be minimal. Purchased 

power from new generating facilities could have impacts on noise. Construction and operation 

of new facilities could result in additional noise sources, including mechanical equipment 

associated with normal plant operations and vehicular traffic. Additionally, construction of new 

transmission lines could increase noise levels. Increase in noise levels from construction of 

new transmission lines and new facilities would be dependent on the distance of residents to the 

noise sources. Noise levels from operation would also be dependent on the type of technology;

for instance, operation of nuclear or wind power. Therefore, impacts from purchased power on 

noise would be SMALL to MODERATE.
Environmental Consequences and Mitigating Actions

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4.4 Geologic Environment

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on geologic and soil resources.

4.4.1 Proposed Action

Section 3.4 describes the local and regional geologic environment of the LSCS site. Table 4–3

identifies the issue related to geology and soils that is applicable to the LSCS site during the 

license renewal term. 

Table 4–3. Geology and Soils Issues

Issue GEIS Section Category

Geology and Soils 4.4.1 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

The NRC staff did not identify any new and significant information associated with the 

Category 1 geology and soils issue identified in Table 4–3 during the review of the applicant’s 

ER, the site audit, the scoping process, or the evaluation of other available information. As a 

result, the staff did not identify any information or impacts related to this issue that would 

change the conclusions presented in the GEIS (NRC 2013d). For this issue, the GEIS 

concludes that the impacts are SMALL. It is expected that there would be no incremental 

impacts related to this Category 1 issue during the renewal term beyond those discussed in the 

GEIS; therefore, the impacts associated with this issue are SMALL.

4.4.2 No-Action Alternative

There would not be any impacts to the geology and soils at the LSCS site with the shutdown of 

the facility. With the shutdown of the facility, no additional land would be disturbed. Therefore, 

impacts would be SMALL.

4.4.3 New Nuclear Alternative

For the new nuclear alternative, the impacts on geology and soil resources would occur during 

construction, and no additional land would be disturbed during operations. During construction, 

sources of aggregate material, such as crushed stone and sand and gravel, would be required 

to construct buildings, foundations, roads, and parking lots. These resources would likely be 

obtained from commercial suppliers using local or regional sources. Land clearing during 

construction and the installation of power plant structures and impervious surfaces would 

expose soils to erosion and would alter surface drainage. Best management practices would be 

implemented in accordance with applicable permitting requirements to reduce soil erosion. 

These practices would include the use of sediment fencing, staked hay bales, check dams, 

sediment ponds, riprap aprons at construction and laydown yard entrances, mulching and 

geotextile matting of disturbed areas, and rapid reseeding of temporarily disturbed areas. 

Removed soils and any excavated materials would be stored on site for redistribution, such as 

for backfill, at the end of construction. Construction activities would be temporary and localized. 

Therefore, the impacts of the new nuclear alternative on geology and soil resources would be 

SMALL.
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4.4.4 IGCC Alternative

For the IGCC alternative, the impacts on geology and soil resources would occur during 

construction, and no additional land would be disturbed during operations. Geologic 

construction material would be obtained, and BMPs would be applied as described in the new 

nuclear alternative in Section 4.4.3. Therefore, the impacts of the IGCC alternative on geology 

and soil resources would be SMALL.

4.4.5 NGCC Alternative

For the NGCC alternative, the impacts on geology and soil resources would occur during 

construction, and no additional land would be disturbed during operations. Geologic 

construction material would be obtained, and BMPs would be applied as described in the new 

nuclear alternative in Section 4.4.3. Therefore, the impacts of the NGCC alternative on geology 

and soil resources would be SMALL.

4.4.6 Combination Alternative (NGCC, Wind, Solar)

For the combination NGCC, wind, and solar alternative, the impacts on geology and soil 

resources would occur during construction, and no additional land would be disturbed during 

operations. Geologic construction material would be obtained, and BMPs would be applied as 

described in the new nuclear alternative in Section 4.4.3. The solar PV and the wind farm part 

of this alternative would require a large amount of land. However, much of the land would be 

undisturbed because road and facility construction would disturb only a small fraction. 

Therefore, the impacts of the combination NGCC, wind, and solar alternative on geology and 

soil resources would be SMALL.

4.4.7 Purchased Power Alternative

The impacts of the purchased power alternative are likely to be bounded by the impact 

descriptions of the other alternatives. Purchased power is likely to come from existing facilities, 

or if new facilities are constructed, it would likely be from one of the previously discussed 

alternatives. These alternatives have SMALL impacts. Therefore, the impact of this alternative 

on geology and soil resources would be SMALL.

4.5 Water Resources

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on surface water and groundwater resources.

4.5.1 Proposed Action

4.5.1.1 Surface Water Resources

Section 3.5.1 describes surface water resource-related aspects and conditions relevant to the 

LSCS site. Table 4–4 identifies the Category 1 (generic) and Category 2 surface water use and 

quality issues applicable to LSCS. 
Environmental Consequences and Mitigating Actions

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Table 4–4. Surface Water Resources Issues

Issue GEIS Section Category

Surface water use and quality (non-cooling system impacts) 4.5.1.1 1

Altered current patterns at intake and discharge structures 4.5.1.1 1

Scouring caused by discharged cooling water 4.5.1.1 1

Discharge of metals in cooling system effluent 4.5.1.1 1

Discharge of biocides, sanitary wastes, and minor chemical spills 4.5.1.1 1

Surface water use conflicts (plants with cooling ponds or cooling towers 

using makeup water from a river)

4.5.1.1 2

Effects of dredging on surface water quality 4.5.1.1 1

Temperature effects on sediment transport capacity 4.5.1.1 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

Generic Surface Water Resources Issues

The NRC staff did not identify any new and significant information associated with the 

Category 1 surface water issues identified in Table 4–4 during the review of the applicant’s ER 

(Exelon 2014a, 2015j), the applicant’s responses to the NRC’s requests for additional 

information (RAIs), the scoping process, the results of the environmental site audit, or the 

evaluation of other available information as documented under Section 3.5.1 of this SEIS. As a 

result, no information or impacts related to these issues were identified that would change the 

conclusions presented in the GEIS (NRC 2013d). For these issues, the GEIS concludes that 

the impacts are SMALL. It is expected that there would be no incremental impacts related to 

these Category 1 issues during the renewal term beyond those discussed in the GEIS;

therefore, the impacts associated with these issues are SMALL.

The Category 2 (Table 4–4) issue related to surface water during the renewal term is discussed 

in the following text.

Surface Water Use Conflicts

This section presents the NRC staff’s review of the plant-specific (Category 2) surface water use 

conflict issue listed in Table 4–4.

For nuclear power plants using cooling towers or cooling ponds supplied with makeup water 

from a river, the potential impact on the flow of the river and water availability to meet the 

demands of other users is a Category 2 issue. This designation requires a plant-specific 

assessment.

In evaluating the potential impacts resulting from surface water use conflicts associated with 

license renewal, the NRC staff uses as its baseline the surface water resource conditions as 

described in Sections 3.1.3 and 3.5.1. These baseline conditions encompass the defined 

hydrologic (flow) regime of the surface water(s) that is potentially affected by continued 

operations, as well as the magnitude of surface water withdrawals for cooling and other 

purposes (as compared to relevant appropriation and permitting standards). The baseline also 

considers other downstream uses and users of surface water.

The mean annual discharge of the Illinois River (described in Section 3.5.1.1) measured at the 

U.S. Geological Survey (USGS) gage at Marseilles, Illinois, is 10,750 cubic feet per second (cfs) 

(304 cubic meters per second (m3

/s)). This gaging station is approximately 3 mi (4.8 km) 
Environmental Consequences and Mitigating Actions

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downstream from the LSCS river screen house and associated river intake structure and 

blowdown discharge canal. Flows measured at this gaging station are also inclusive of surface 

water withdrawals that other entities make in the same general vicinity as LSCS and that 

withdraw surface water from the same portion of the Marseilles Pool as LSCS. These include 

Agrium U.S., Inc., and PCS Phosphate, Marseilles Operation. These facilities are discussed in 

Section 3.5.1.2 and shown in Figure 3–11.

As described in Section 3.5.1.2, LSCS’s average surface water withdrawal rate from the 

Marseilles Pool of the Illinois River is approximately 105 cfs (2.96 m3

/s or 67.8 million gallons 

per day (mgd)), with consumptive use averaging about 49.7 cfs (1.4 m3

/s or 32.1 mgd). This 

consumptive use is equivalent to about 0.5 percent of the Illinois River’s average annual flow.

The NRC staff also evaluated the impacts of continued LSCS operations on low-flow conditions 

in the Illinois River. The lowest annual mean flow recorded for the Illinois River at Marseilles is 

5,583 cfs (157.7 m3

/s), and the mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the 

period of record (USGS 2015). The 90-percent exceedance flow is an indicator value of 

hydrologic drought. It signifies the flow rate that is equaled or exceeded 90 percent of the time 

as compared to the average flow for the period of record. Compared to these measures of 

reduced river flow, LSCS’s current consumptive water use (i.e., 49.7 cfs (1.4 m3

/s or 32.1 mgd)) 

represents a 0.9- and a 1.1-percent reduction, respectively, in the flow of the river downstream 

of the LSCS site. LSCS’s consumptive water use is not expected to increase during the license 

renewal term (Exelon 2015b).

As Exelon noted in its ER (Exelon 2014a), drought conditions could cause the flows in the main 

stem of the Illinois River and surface water elevations to fall below levels that could impact 

LSCS operations. As previously discussed in Section 3.5.1.2 of this SEIS, Exelon maintains an 

Extreme Heat Implementation Plan that is part of an overall Summer Readiness Plan. The 

Extreme Heat Implementation Plan provides procedural guidance to plant personnel for 

responding to worst-case summer weather and hydrologic conditions to ensure compliance with 

LSCS’s National Pollutant Discharge Elimination System (NPDES) permit for thermal discharge

limits and to safeguard plant equipment. As necessary, plant personnel run thermal models and 

will adjust makeup pumping rates to the cooling pond or the rate of blowdown to the river to 

maintain permit compliance. Under extreme cases, it may be necessary for Exelon to reduce 

LSCS’s power output or to shut down the plant (e.g., under conditions of extremely low water 

levels). 

In conclusion, the NRC staff’s review of available data indicates that consumptive water use 

associated with LSCS operations combined with other surface water withdrawals within the 

Marseilles Pool have no substantial impact on downstream water availability. LSCS’s surface 

water withdrawals and low rate of consumptive use of flow in the Illinois River are very unlikely 

to substantially impact downstream water availability or instream uses of surface water within 

the Marseilles Pool during the license renewal term. Thus, operation of LSCS during the license 

renewal term is not expected to result in a water use conflict on the Illinois River.

In addition, in the event of worst-case summer weather and hydrologic conditions affecting 

LSCS, Exelon has operational procedures in place to minimize hydrologic and thermal impacts 

on the river. In total, the NRC staff concludes that the potential impacts on surface water

resources and downstream water availability from LSCS’s continued withdrawals and 

consumptive water use during the license renewal term would be SMALL.

4.5.1.2 Groundwater Resources

Section 3.5.2 describes groundwater resources at LSCS. Table 4–5 identifies issues related to 

groundwater that are applicable to LSCS during the license renewal term.
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Table 4–5. Groundwater Issues

Issue GEIS Section Category

Groundwater contamination and use (non-cooling system impacts) 4.5.1.2 1

Groundwater use conflicts (plants that withdraw less than 100 gpm) 4.5.1.2 1

Groundwater use conflicts (plants with closed-cycle cooling systems that 

withdraw makeup water from a river)

4.5.1.2 2

Groundwater quality degradation (plants with cooling ponds at inland sites) 4.5.1.2 2

Radionuclides released to groundwater 4.5.1.2 2

Source: Table B–1 in Appendix B, Subpart A to 10 CFR Part 51

Generic Groundwater Resources Issues

The NRC staff did not identify any new and significant information associated with the 

Category 1 groundwater issues identified in Table 4–5 during the review of the applicant’s ER, 

the site audit, the scoping process, or the evaluation of other available information. As a result, 

no information or impacts related to these issues were identified that would change the 

conclusions presented in the GEIS (NRC 2013d). For these issues, the GEIS concludes that 

the impacts are SMALL. It is expected that there would be no incremental impacts related to 

these Category 1 issues during the renewal term beyond those discussed in the GEIS; 

therefore, the impacts associated with these issues are SMALL.

The three Category 2 issues (see also Table 4–5) related to groundwater during the renewal 

term are discussed below.

Groundwater Use Conflicts (Plants with Closed-Cycle Cooling Systems That Withdraw Makeup 

Water from a River)

This issue looks at the potential impact of the consumption of river water on the availability of 

groundwater supplies. LSCS uses a cooling pond and withdraws water from a small river. In 

turn, the cooling pond loses water to the atmosphere by evaporation. As a result, less water is 

returned to the Illinois River than that withdrawn. This issue evaluates the impact of river water 

consumption and lowered river water levels on groundwater supplies.

The Illinois River alluvium is hydrologically connected to the Alluvial Aquifer. The Alluvial 

Aquifer is found below and on each side of the Illinois River. It is underlain by the 

Pennsylvanian Aquitard (see Figure 3–8 in Section 3.4.1 of this document). Because the 

Pennsylvanian Aquitard is not a significant source of groundwater, the Alluvial Aquifer is the 

aquifer that would be most impacted by changes in Illinois River water levels.

The average flow in the Illinois River at the Marseilles stream gage (5 mi (8 km) downstream 

from the intake and discharge structures) is 10,750 cfs (304 m3

/s) (Exelon 2014a; 

USGS 1979, 2015). LSCS’s normal peak withdrawal rate from the river at the intake structure is 

134 cfs (3.8 m3

/s), and 67 cfs (1.89 m3/s) of blowdown is discharged to the river from the cooling 

pond. This means that 67 cfs (1.89 m3

/s) is not returned to the river. This rate of consumption 

is 0.6 percent of the normal river flow in the area of the intake and discharge structures. From 

1920 through 2014, the lowest annual river flow recorded at the Marseilles stream gage was 

5,583 cfs (158 m3

/s) in 1964 (USGS 2015). During this period of low flow, the average rate of 

consumption by the plant would be 1.2 percent of the flow in the river. This rate of consumption 

is also unlikely to have much impact on river levels and little or no impact on water levels in the 

Alluvial Aquifer. Therefore, the NRC staff concludes that impacts to groundwater use would be 

SMALL.
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4-25

Groundwater Quality Degradation (Plants with Cooling Ponds at Inland Sites)

This issue looks at the potential for the use of closed-cycle inland unlined cooling ponds to 

degrade the surrounding groundwater quality and the water quality of offsite wells. The total 

dissolved solids concentration in the cooling pond is limited by LSCS operational procedures to 

a concentration below the applicable State of Illinois water quality standard for receiving waters 

as set forth in 35 IAC 302. The water quality of the cooling pond is good enough to support a 

highly successful recreational fishery. With the exception of a few tritium samples that were 

near background values, between 2009 and 2014, radionuclide concentrations in the cooling 

pond have not been detected above background values 

(Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015).

The cooling pond is enclosed on the north, east, and south by dikes. On the west side of the 

cooling pond, the natural topography serves as the shoreline. Seepage from the cooling pond is 

negligible because the pond was built on the Glacial Drift Aquitard (Wedron Silty-Clay Till), 

which has a very low permeability and is 120- to 140-ft (37- to 43-m) thick in the area of the 

cooling pond. Seepage modeling, using data from test boring and pits in the reservoir area, 

indicates that any seepage rates would be very low (Exelon 2014a). As previously discussed in 

Section 3.5.2.1, this aquitard contains only small volumes of extractable groundwater

(Exelon 2014a). Therefore, the impact of the cooling pond on groundwater quality would be 

SMALL.

Radionuclides Released to Groundwater

This issue looks at the potential contamination of groundwater from the inadvertent release of 

radioactive liquids from plant systems into the environment. Section 3.5.2.3 of this SEIS

characterizes the groundwater quality at the LSCS site and vicinity, including historical releases 

of tritium to groundwater. In evaluating the potential impacts on groundwater quality associated 

with license renewal, the NRC staff uses, as its baseline, the existing groundwater conditions as 

described in Section 3.5.2.3 of this SEIS. These baseline conditions encompass the existing 

quality of groundwater potentially affected by continued operations (as compared to relevant 

State or EPA primary drinking water standards), as well as the current and potential onsite and 

offsite uses and users of groundwater for drinking and other purposes. The baseline also 

considers other down-gradient or in-aquifer uses and users of groundwater. 

Historical releases of liquids containing tritium have not impacted groundwater quality in 

aquifers within or beyond the LSCS site boundary. With the exception of the 2010 leak from the 

recycled condensate tank, all radiological leaks into groundwater have been successfully 

remediated. The 2010 leak from the recycled condensate tank contaminated groundwater in 

engineered granular fill but did not contaminate groundwater in an aquifer. The groundwater 

contaminated by this leak into the engineered fill has undergone significant cleanup, and 

because of the low permeability, thickness, and lateral extent of the surrounding Wedron 

Silty-Clay Till, it is very unlikely that the leak will impact offsite groundwater.

The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitard and is too 

deep to be impacted by site activities. A search of Illinois State Geological Survey water well 

files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant buildings 

(ISGS 2015). With the exception of one well completed in the Pennsylvanian Aquitard, all the 

wells have been completed in the Cambrian-Ordovician Aquifer.

Given the low permeability, thickness, and lateral extent of the Wedron Silty-Clay Till, there is 

little chance of significant impact to the groundwater quality of onsite and offsite aquifers. 

Present and future LSCS operations are not expected to impact the quality of groundwater in 

any aquifers that are a current or potential future source of water for offsite users. Therefore, 
Environmental Consequences and Mitigating Actions

4-26

the NRC staff concludes that the impacts on groundwater use and quality during the license 

renewal term would be SMALL.

4.5.2 No-Action Alternative

4.5.2.1 Surface Water Resources

Surface water withdrawals and the rate of consumptive water use would greatly decrease and 

eventually cease after LSCS is shut down. Wastewater discharges would be reduced 

considerably. Therefore, shutdown would reduce the overall impacts on surface water use and 

quality. Stormwater would continue to be discharged from the plant site. Overall, the impact of 

this alternative on surface water resources would be SMALL.

4.5.2.2 Groundwater Resources 

With the cessation of operations, there should be little or no impacts on groundwater quality,

and the consumption of groundwater would be much less. The Glacial Drift Aquitard (Wedron 

Silty-Clay Till) and surrounding dikes would continue to limit groundwater movement either into 

or out of the cooling pond. Therefore, the impact of this alternative on groundwater resources 

would be SMALL.

4.5.3 New Nuclear Alternative

4.5.3.1 Surface Water Resources

Impacts from construction activities on surface water resources associated with the new nuclear 

alternative would be considerable in scale by virtue of the land area required for new nuclear 

units (i.e., 556 ac (225 ha). Deep excavation work for the nuclear island, extensive site clearing,

and a large laydown area for facility construction would have the potential for direct and indirect 

impacts on water resources, which would vary based on site-specific conditions.

Construction activities would alter any onsite surface water drainage features. Some temporary 

impacts to surface water quality may result from increased sediment loading and from any 

pollutants in stormwater runoff from disturbed areas, from excavation, and from any 

dredge-and-fill activities. Stormwater runoff from construction areas and spills and leaks from 

construction equipment could potentially affect downstream surface water quality. 

Nevertheless, application of BMPs in accordance with a State-issued NPDES general permit, 

including appropriate waste management, water discharge, stormwater pollution prevention, 

and spill prevention practices, would prevent or minimize surface water or groundwater quality 

impacts during construction.

The NRC staff assumes that any existing intake and discharge infrastructure at an alternative 

site location would be refurbished and used to reduce construction-related impacts on surface 

water quality. Dredge-and-fill operations would be conducted under a permit from the 

U.S. Army Corps of Engineers (USACE) and State-equivalent permits requiring the 

implementation of applicable BMPs to minimize associated impacts.

The staff assumes that there would be no direct use of surface water during construction and

that water would be obtained from onsite groundwater or from a local water utility or trucked to 

the point of use. During construction, the dewatering of excavations would not be expected to 

affect offsite surface water bodies.

The operation of the two new nuclear units using closed-cycle cooling with natural draft cooling 

towers would require an estimated 86.6 cfs (2.45 m3

/s or 56 mgd) of surface water for cooling 

makeup and related processes. Consumptive water use would be approximately 
Environmental Consequences and Mitigating Actions

4-27

65 cfs (1.84 m3

/s or 42 mgd). The projected consumptive water use under this alternative 

represents about a 31-percent increase as compared to current LSCS operations, which 

consume approximately 49.7 cfs (1.4 m3

/s or 32.1 mgd) of surface water (see Sections 3.5.1.2 

and 4.5.1.1). However, permitting agencies within the ROI could impose limits on surface water 

withdrawals and consumption, which would potentially reduce the cited makeup water and 

consumptive use demands for this alternative on an annualized basis, particularly during 

periods of drought. 

The NRC staff further expects that water treatment additives for new nuclear plant operations 

and effluent discharges would be relatively similar in quality and volume to LSCS. Effluent 

discharges and stormwater discharges would be subject to a State-issued NPDES permit, and 

surface water withdrawals would be subject to applicable State water appropriation and 

registration requirements. To prevent and respond to accidental non-nuclear releases to 

surface water, facility operations would be conducted in accordance with a spill prevention, 

control, and countermeasures plan; storm water pollution prevention plan; or equivalent plans 

and associated BMPs and procedures.

Based on the above, the overall impacts on surface water use and quality from construction and 

operations under the new nuclear alternative would be SMALL to MODERATE.

4.5.3.2 Groundwater Resources

For the new nuclear alternative, the staff assumed that construction water would be obtained 

from onsite groundwater or from a local water utility. During construction and throughout the life 

of this alternative, groundwater withdrawals would be subject to applicable State water 

appropriation and registration requirements. The application of BMPs in accordance with a 

State-issued NPDES general permit, including appropriate waste management, water 

discharge, stormwater pollution prevention plan, and spill prevention practices, would prevent or 

minimize groundwater quality impacts during construction. During operations, the consumptive 

use of groundwater for potable water and water for fire protection would be similar to the 

proposed action. Therefore, the impact of this alternative on groundwater resources would be 

SMALL.

4.5.4 IGCC Alternative

4.5.4.1 Surface Water Resources

Impacts from construction activities associated with the IGCC alternative on surface water

resources would be expected to be similar to, but somewhat greater than, those under the new 

nuclear alternative (see Section 4.5.3.1). The potential for greater impacts is attributable to the 

additional land required for construction of the power blocks for four IGCC units and for 

excavation and construction of other onsite facilities for coal handling and storage and for coal 

ash and scrubber waste management. The same assumptions for construction and operations 

also apply to this alternative, except as noted.

Some temporary impacts to surface water quality may result from increased sediment loading 

and from pollutants in stormwater runoff from disturbed areas and from excavation and 

dredge-and-fill activities. In addition, hydrologic and water-quality impacts could occur from the 

extension or refurbishment of rail spurs to transport coal and other materials to potential site 

locations and to transfer coal ash from those sites. Using an existing power plant site would 

allow the use of the existing cooling water intake, effluent discharge, and rail infrastructure. If 

the IGCC plant is located at the LSCS site, portions of the cooling pond and other plant areas 

may be repurposed to construct IGCC facilities, including closed-cycle mechanical draft cooling 

towers. Regardless, as described in Section 4.5.3.1 for the new nuclear alternative, 
Environmental Consequences and Mitigating Actions

4-28

water-quality impacts from construction activities would be minimized by the application of 

BMPs and through compliance with State-issued NPDES permits. Any dredge-and-fill 

operations would be conducted under a permit from the USACE and State-equivalent permits 

requiring the implementation of BMPs to minimize impacts.

Operation of an IGCC plant would require less makeup water and would have lower 

consumptive use than that of either the new nuclear alternative or current LSCS operations. 

The projected cooling water makeup requirement for an IGCC plant under this alternative is 

approximately 39 cfs (1.09 m3

/s or 25 mgd), with consumptive use of about 31 cfs (0.87 m3/s or 

20 mgd). This alternative would consume about 38 percent less surface water than that under 

current LSCS operations, which consumes approximately 49.7 cfs (1.4 m3

/s or 32.1 mgd).

As summarized in Section 4.5.3.1 for the new nuclear alternative, surface water withdrawals 

and effluent discharges would be subject to applicable regulatory requirements under this 

alternative. However, management of runoff and leachate from coal and ash storage facilities 

would require additional regulatory oversight and would present an additional risk to surface 

water resources near site locations.

For this alternative, based on the projected magnitude of ground disturbance and hydrologic 

alteration and potential water quality impacts from coal and ash handling and management, 

impacts on surface water resources would range from SMALL to MODERATE.

4.5.4.2 Groundwater Resources

The impact significance level on groundwater resources for the IGCC alternative is less than the 

new nuclear alternative described in Section 4.5.3.2. Approximately the same amount of 

groundwater would be consumed during the operation of the facility, but less groundwater would 

be consumed in the construction of the facility than for the new nuclear alternative. Therefore, 

impacts of the IGCC alternative on groundwater resources would be SMALL.

4.5.5 NGCC Alternative

4.5.5.1 Surface Water Resources

Direct impacts from construction activities associated with the NGCC alternative on surface 

water resources would be expected to be much smaller than those under either the new nuclear 

or IGCC alternative. A new NGCC plant and associated pipelines would occupy a much smaller 

footprint (i.e., about 94 ac (38 ha)) than that of the current LSCS facility or the proposed new 

nuclear or IGCC facilities. This smaller footprint would result in less extensive excavation and 

earthwork. Otherwise, the same assumptions for construction and operations also apply to this 

alternative, except as noted. 

Some temporary impacts to surface water quality may result from increased sediment loading, 

any pollutants in stormwater runoff from disturbed areas, excavation, and dredge-and-fill 

activities. Depending on the path of any required new gas pipelines and transmission lines to 

service the NGCC plant, some stream crossings could be necessary. However, because of the 

short-term nature of any required dredge-and-fill operations and stream-crossing activities, the 

hydrologic alterations and sedimentation would be localized, and water-quality impacts would be 

temporary and would cease after construction has been completed and the site has been 

stabilized. The use of modern pipeline construction techniques, such as horizontal directional 

drilling, would further minimize the potential for water-quality impacts in the affected streams. In 

addition, as described in Section 4.5.3.1 for the new nuclear alternative, water-quality impacts 

would be minimized by the application of BMPs and through compliance with State-issued 

NPDES permits for construction. Any dredge-and-fill operations would be conducted under a 
Environmental Consequences and Mitigating Actions

4-29

permit from the USACE and State-equivalent permits requiring the implementation of BMPs to 

minimize impacts.

For onsite facility operations, a five-unit NGCC plant would have a smaller cooling water 

demand and lower consumptive water use as compared to that under current LSCS operations 

and for the new nuclear and IGCC alternatives. It is projected that an NGCC plant would 

require approximately 26.3 cfs (0.74 m3

/s or 17 mgd) of surface water for cooling and related 

processes, with consumptive use totaling about 20.1 cfs (0.57 m3

/s or 13 mgd). Thus, this 

alternative would consume about 60 percent less surface water than that under current LSCS 

operations, which consumes approximately 49.7 cfs (1.4 m3

/s or 32.1 mgd).

Based on this analysis, the overall impacts on surface water resources from construction and 

operations under the NGCC alternative would be SMALL.

4.5.5.2 Groundwater Resources

The impact significance level on groundwater resources for the NGCC alternative are less than 

the new nuclear alternative described in Section 4.5.3.2. Approximately the same amount of 

groundwater would be consumed during the operation of the facility, but less groundwater would 

be consumed in the construction of the facility. Therefore, impacts of the NGCC alternative on 

groundwater resources would be SMALL.

4.5.6 Combination Alternative (NGCC, Wind, Solar)

4.5.6.1 Surface Water Resources

For the NGCC component of this alternative, the impacts on surface water resources from 

facility construction and operations at either the LSCS site or another existing power plant site 

would be a fraction of those described in Section 4.5.5.1 because the NGCC plant would be 

scaled back to a single 360-megawatt (MW) unit. As a result, operational cooling water 

demands would be reduced by roughly 90 percent.

Impacts on surface water resources from constructing land-based wind turbines would primarily 

be limited to the relatively small amounts of water needed at each installation site for dust 

suppression and soil compaction during site clearing, turbine pad preparation, and concrete 

production. Construction of utility-scale solar PV farms would require relatively larger volumes 

of water per site due to the larger land area required per megawatt of replacement power

produced. For both components under this alternative, the NRC assumes that required 

construction water would be procured from offsite sources and trucked to the point of use on an 

as-needed basis. Water could also be supplied via a local water utility. The likely use of 

ready-mix concrete would also reduce the need for onsite use of nearby water sources for 

construction.

Installation of land-based wind turbines and utility-scale solar PV farms would also require 

construction of access roads and possibly transmission lines (especially for sites that are not 

already proximal to transmission line corridors). Access road construction would also require 

some water for dust suppression and roadbed compaction and would have the potential to 

result in soil erosion and stormwater runoff from cleared areas. For such activities, construction 

water would likely be trucked to the point of use from offsite locations, along with road 

construction materials. In all cases, it is expected that construction activities would be 

conducted in accordance with State-issued NPDES or equivalent permits for stormwater 

discharges associated with construction activity, which would require the implementation of 

appropriate BMPs to prevent or mitigate water-quality impacts. In contrast to land-based wind 

turbine sites and utility-scale solar PV farms, installation of small solar PV units on rooftops and 
Environmental Consequences and Mitigating Actions

4-30

at already-developed sites within the electric service ROI (see Section 2.2.2) would have little or 

no impact on surface water resources.

To support the operation of wind turbine and PV installations, no direct use of surface water

would be expected. Water would likely be obtained from groundwater or purchased from a 

water utility. Regardless, only very small amounts of water would be needed to periodically 

clean turbine blades and motors, and water could be trucked to the point of use as part of 

routine servicing. Water also would be required to clean panels at solar PV farms or those 

situated in rooftop arrays. Adherence to appropriate waste management and minimization 

plans, spill prevention practices, and pollution prevention plans during servicing of wind turbine 

and solar PV installations and operation of vehicles connected with site operations would 

minimize the risks to soils and surface water resources from spills of petroleum, oil, and 

lubricant products and stormwater runoff.

Given the information presented above, the impacts on surface water resources from 

construction and operations under the combination alternative would be SMALL.

4.5.6.2 Groundwater Resources

Construction dewatering would be minimal because of the small footprint of foundation 

structures, pad sites, and piling emplacements. Little or no impacts on groundwater use or 

water quality would be expected from routine operations. Consequently, the impacts on 

groundwater use and quality under this combination alternative would be SMALL.

4.5.7 Purchased Power Alternative

4.5.7.1 Surface Water Resources

The impacts of this alternative on surface water resources are likely to be bounded by the 

impact descriptions for the other alternatives, although new transmission lines may be required. 

Specifically, new and continued operation of nuclear, coal-fired, and natural gas-fired plants and 

renewable energy projects would not be expected to result in incremental impacts on surface 

water use and quality that are greater than those described in Sections 4.5.3, 4.5.4, 4.5.5, 

and 4.5.6, as long as all energy-generating facilities operate within the bounds of applicable 

water use and NPDES permits. Therefore, the impact of this alternative on surface water 

resources would be expected to range from SMALL to MODERATE.

4.5.7.2 Groundwater Resources

The impacts of the purchased power alternative on groundwater resources are likely to be 

bounded by the impact descriptions for the other alternatives. Purchased power is likely to 

come from existing facilities, or if new facilities are constructed, it would likely be from one of the 

previously discussed alternatives. These alternatives have SMALL impacts. Therefore, the 

impact of this alternative on groundwater resources would be SMALL.

4.6 Terrestrial Resources 

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on terrestrial resources.

4.6.1 Proposed Action

Section 3.6 describes terrestrial resources on and in the vicinity of the LSCS site. Table 4–6

identifies the generic (Category 1) and site-specific (Category 2) issues that apply to terrestrial 

resources during the proposed license renewal period.
Environmental Consequences and Mitigating Actions

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Table 4–6. Terrestrial Resource Issues

Issue GEIS Section Category

Effects on terrestrial resources (non-cooling system impacts) 4.6.1.1 2

Exposure of terrestrial organisms to radionuclides 4.6.1.1 1

Cooling system impacts on terrestrial resources (plants with

once-through cooling systems or cooling ponds)

4.6.1.1 1

Cooling tower impacts on vegetation (plants with cooling towers) 4.6.1.1 N/A(a)

Bird collisions with plant structures and transmission lines(b) 4.6.1.1 1

Water use conflicts with terrestrial resources (plants with cooling ponds 

or cooling towers using makeup water from a river)

4.6.1.1 2

Transmission line right-of-way (ROW) management impacts on 

terrestrial resources(b)

4.6.1.1 1

Electromagnetic fields on flora and fauna (plants, agricultural crops, 

honeybees, wildlife, livestock)(b)

4.6.1.1 1

(a) This issue does not apply because LSCS does not have cooling towers.

(b) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

4.6.1.1 Generic GEIS Issues

The NRC staff did not identify any new and significant information associated with the generic 

(Category 1) terrestrial resource issues listed in Table 4–6 during the review of the applicant’s 

ER (Exelon 2014a), the site audit, or the scoping process. As a result, the NRC staff expects no 

impacts associated with these issues beyond those discussed in the GEIS. The GEIS 

concludes that the impact level for each of these issues is SMALL. It is expected that there 

would be no incremental impacts related to these Category 1 issues during the renewal term 

beyond those discussed in the GEIS; therefore, the impacts associated with these issues are 

SMALL.

4.6.1.2 Effects on Terrestrial Resources (Non-Cooling System Impacts)

In the GEIS (NRC 2013d), the NRC staff determined that non-cooling system effects on 

terrestrial resources is a Category 2 issue (see Table 4–6) that requires site-specific evaluation 

during each license renewal review. According to the GEIS, non-cooling system impacts can 

include those impacts that result from landscape maintenance activities, stormwater

management, elevated noise levels, and other ongoing operations and maintenance activities 

that would occur during the renewal period and that could affect terrestrial resources on and 

near a plant site.

Landscape Maintenance Activities 

Approximately 25 percent (379 ha (936 ac)) of the LSCS site remains as undeveloped, 

uncultivated natural areas (see Table 3–1, in Section 3.2.1 of this document). The majority of 

site landscape maintenance is performed within the protected area and not within natural areas 

on the site (Exelon 2015f). Typically, only grassy areas within the developed, industrial portion 

of the site are mown to keep vegetation short. Small trees or brush that might pose a safety 

concern may also be removed from these areas as needed. Leased agricultural land is 
Environmental Consequences and Mitigating Actions

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maintained by the leasee and in accordance with the standing lease. Exelon (2014a) has no 

plans to disturb undeveloped areas of the site as part of the proposed license renewal.

Several ongoing restoration projects would result in positive impacts to terrestrial resources 

during the license renewal term. These projects are discussed in Section 3.6 and include 

ongoing management of a small area of native prairie, native vegetation plantings, removal of 

the invasive common reed (Phragmites australis) around the cooling pond, and various bird 

habitat enhancements.

Stormwater Management

Natural drainage of the LSCS site is generally toward the cooling pond. Two stormwater ponds 

on the west side of the LSCS site receive stormwater runoff from the site’s protected area, 

which is divided into two zones (I and II) for purposes of stormwater management. A system of 

surface ditches and underground piping drain the two zones. Zone I discharges to the north 

stormwater pond, and Zone II discharges to the south stormwater water pond. Each stormwater 

pond discharges to the cooling pond discharge canal via NPDES-permitted Outfalls G01 (north 

stormwater pond) and H01 (south stormwater pond). Some storm drains on the site are routed 

through oil separators before entering the stormwater ponds. Areas to the northwest and south 

of the protected area are drained away by existing creeks and gullies (Exelon 2014a).

Exelon maintains a stormwater pollution prevention (SWPP) plan in accordance with Special 

Condition 8 of the site’s NPDES permit (Permit No. IL0048151; IEPA 2013). The SWPP plan 

identifies potential sources of pollutants that could affect stormwater discharges at Outfalls G01, 

H01, and 002 and practices that Exelon uses to reduce pollutants in stormwater discharges and 

ensure compliance with applicable conditions of the NPDES permit (Exelon 2014c). The 

NPDES permit also requires that the SWPP plan identify areas with a high potential for 

significant soil erosion due to topography, activities, or other factors, and that the SWPP plan 

contain measures to limit erosion in these areas (IEPA 2013). Exelon further monitors areas 

with potential for spills of oil or other regulated substances under the LSCS Spill Prevention 

Control and Countermeasure Plan (Exelon 2014c). Collectively, these measures ensure that 

the effects to terrestrial resources from pollutants carried by stormwater would be small during 

the proposed license renewal term.

Noise

The GEIS (NRC 2013d) indicates that elevated noise levels could be a non-cooling system

impact to terrestrial resources. However, the GEIS also concludes that generic noise impacts 

would be small because noise levels would remain well below regulatory guidelines for offsite 

receptors during continued operations and refurbishment associated with license renewal. The 

NRC staff did not identify any information during its review that would indicate that noise 

impacts to terrestrial resources at LSCS would be unique or require separate analysis.

Other Operations and Maintenance Activities

Exelon (2014a) anticipates no refurbishment or other operations or maintenance activities 

during the license renewal term that would disturb terrestrial habitats or result in changes to 

existing land uses.

Exelon (2015e) states that it would continue to comply with all applicable environmental laws

and regulations and would adhere to its company policy of regularly evaluating and 

implementing options that move beyond compliance. Such options may include maintaining 

Exelon’s Wildlife Management Plan and Wildlife Habitat Council certification for LSCS

throughout the proposed license renewal term.
Environmental Consequences and Mitigating Actions

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When new activities that could impact the environment occur at LSCS, Exelon states that it 

follows several procedures to ensure that potential environmental effects are considered and 

appropriately addressed. Exelon (2015g) maintains an Environmental Review procedure 

(EN-AA-103) that provides a process for screening proposed activities to determine if an activity 

requires further evaluation for environmental impacts and risks. Such activities include 

engineering configuration changes, maintenance activities, and operational changes. If further 

environmental evaluation is warranted, Exelon’s (2015g) Environmental Evaluations procedure 

(EN-AA-103-0001) provides guidance on identifying the environmental and regulatory impacts 

of an activity. If Exelon personnel determine that implementation of a proposed activity would 

result in an unacceptable environmental condition or risk, the proposed activity is not 

implemented until the environmental impact is appropriately addressed. These procedures 

would continue to be implemented during the proposed license renewal term and would ensure 

that environmental impacts to terrestrial resources would be addressed or mitigated prior to site 

operational or maintenance activities.

Conclusion

Based on the NRC staff’s independent review, the staff concludes that the landscape 

maintenance, stormwater management, elevated noise levels, and other ongoing operations 

and maintenance activities that Exelon might undertake during the renewal term would primarily 

be confined to disturbed areas of the LSCS site. These activities would not have noticeable 

effects on terrestrial resources, nor would they destabilize any important attribute of the 

terrestrial resources on or in the vicinity of the LSCS site. Therefore, the staff expects 

non-cooling system impacts on terrestrial resources during the license renewal term to be 

SMALL.

4.6.1.3 Water Use Conflicts with Terrestrial Resources

In the GEIS (NRC 2013d), the NRC staff determined that effects of water use conflicts on 

terrestrial resources is a Category 2 issue (see Table 4–6) that requires site-specific evaluation 

during each license renewal review. Water use conflicts occur when the amount of water 

needed to support terrestrial riparian communities is diminished as a result of demand for 

agricultural, municipal, or industrial use; decreased water availability due to droughts; or a 

combination of these factors.

As indicated in Section 4.5.1.1, the amount of Illinois River water LSCS consumes is minor in 

comparison to the flow of water past the plant. In Section 4.5.1.1, the NRC staff found that 

water use conflicts with surface water resources would be SMALL during the proposed license 

renewal term because the surface flows in the Illinois River are able to meet the consumptive 

demand and because regulatory mechanisms are in place that limit LSCS’s consumptive use. 

These regulatory mechanisms ensure that LSCS does not consume an amount that would be 

harmful to riparian communities during low river flow conditions. The terrestrial resources near 

the plant (described in Section 3.6) do not appear to be affected by the consumption of water 

from the river. The NRC staff concludes that water use conflicts would not occur from the 

proposed license renewal or would be so minor that the effects on terrestrial resources would be 

undetectable. Thus, the NRC staff concludes that the impacts of water use conflicts on 

terrestrial resources during the proposed license renewal term would be SMALL.

4.6.2 No-Action Alternative

If LSCS were to shut down, the impacts to terrestrial ecology would remain similar to those 

during operations until the plant is fully decommissioned. Temporary buildings and staging or 

laydown areas may be required during large component and structure dismantling. LSCS is 

likely to have sufficient space within previously disturbed areas for these needs, and therefore, 
Environmental Consequences and Mitigating Actions

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no additional land disturbances would occur on previously undisturbed land. Adjacent lands 

may experience temporary increases in erosional runoff, dust, or noise, but these impacts could 

be minimized with the implementation of standard BMPs (NRC 2002). The NRC staff concludes 

that the no-action alternative is unlikely to noticeably alter or have more than minor effects on 

terrestrial resources. Thus, the NRC staff concludes that the impacts of the no-action

alternative on terrestrial resources during the proposed license renewal term would be SMALL.

4.6.3 New Nuclear Alternative

The new nuclear alternative assumes that Exelon would build a new nuclear facility in Indiana, 

Iowa, Michigan, Missouri, Kentucky, or Wisconsin at an existing power plant site. Construction 

of the facility would require an estimated 324 ac (131 ha) for permanent buildings and facilities 

and an additional 232 ac (94 ha) for temporary facilities, laydown areas, and other temporary 

land disturbances. Additional offsite land would be required for uranium mining, although this 

impact would result in no net change in land use impacts from those that would be associated 

with the proposed license renewal of LSCS.

During construction, terrestrial species could experience habitat loss or fragmentation, loss of 

food resources, and altered behavior due to noise and other construction-related disturbances. 

Erosion and sedimentation from clearing, leveling, and excavating land could affect adjacent 

riparian and wetland habitats, if present. Implementation of appropriate BMPs would minimize 

these effects. This alternative could also require construction of new transmission lines or 

upgrades to existing lines. Because the new nuclear facility would be located on an existing 

energy-producing site, transmission lines could likely be collocated within existing transmission 

line corridors to minimize land disturbance. Although construction activities could noticeably 

alter terrestrial resources through habitat loss or fragmentation, construction is unlikely to 

destabilize any important attributes of the terrestrial environment. The exact magnitude of 

impacts would vary based on the chosen location of the facility and the amount and types of 

undisturbed habitat that would be affected by construction of the alternative, and thus, impacts 

of construction could range from SMALL to MODERATE.

During operation, impacts would be similar in type and magnitude to those assessed in

Section 4.6.1 for continued operation of LSCS under the proposed renewal term and would, 

therefore, be SMALL.

The NRC staff concludes that the impacts of the new nuclear alternative on terrestrial resources 

would be SMALL to MODERATE during construction and SMALL during operation. The range 

in construction impacts is primarily the result of the uncertainty in the amount and types of 

undisturbed habitat that construction would affect.

4.6.4 IGCC Alternative

The IGCC alternative assumes that the new facility would be built at an existing power plant site 

in Illinois, including the LSCS site, or at another power plant site in Indiana, Iowa, Michigan, 

Missouri, Kentucky, or Wisconsin. The facility would require 2,000 ac (800 ha) of land to 

construct the facility. If the facility were to be sited on the LSCS site, the area currently 

occupied by the LSCS facilities, the undeveloped areas immediately surrounding the facility, 

and the area occupied by the Illinois fish hatchery would be affected. Exelon would also need to 

acquire adjacent parcels of land to provide the full complement of acreage required for the 

IGCC facility. Additional offsite land would be required for coal mining, although this impact 

would be partially offset by the elimination of land used for uranium mining to supply fuel to 

LSCS.
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During construction, impacts to terrestrial habitats and species are likely to be similar to the 

types of impacts described for the new nuclear alternative in Section 4.6.3 but would likely be 

larger in magnitude due to the larger footprint of the IGCC facility. If the facility were to be sited 

on the LSCS site, the purchase of additional parcels of land could affect sensitive habitats, 

including wetlands and riparian areas. Accordingly, construction would likely noticeably alter 

terrestrial resources and could destabilize important attributes of the terrestrial environment. 

The exact magnitude of impacts would vary, based on the chosen location of the facility and the 

amount and types of undisturbed habitat that would be disturbed for construction of the 

alternative. Thus, impacts of construction could range from MODERATE, if some disturbances 

to terrestrial habitats occur, to LARGE, if significant disturbances to terrestrial habitats occur, 

especially if disturbed habitats are wetlands or other sensitive habitat types.

The GEIS (NRC 2013d) concludes that impacts on terrestrial resources from the operation of 

fossil energy alternatives would essentially be similar to those from continued operations of a 

nuclear facility. Unique impacts would include periodic maintenance dredging if coal is 

delivered by barge, which could create noise, dust, and sedimentation. Dredging and delivery 

of coal to the site could introduce minerals and trace elements to water resources on which 

terrestrial biota rely. Elements from these minerals could also bioaccumulate in nearby riparian 

or wetland habitats. Air emissions during operation would include sulfur oxides and nitrogen 

oxides, which can combine with water vapor and create sulfuric and nitric acids. These acids 

would then be released back into the environment through precipitation, which could affect the 

acidity levels of water resources and have detrimental effects to plant foliage. Acid precipitation 

has the potential to destabilize the terrestrial environment by creating conditions that are too 

acidic for certain plants or animals and by mobilizing certain metals. The IGCC facility would 

also emit various GHGs during operation, which is an effect that can have far-reaching 

consequences because GHGs contribute to climate change. The effects of climate change on 

terrestrial resources are discussed in Section 4.15.3.2. The various air emissions during 

operation of the IGCC facility could create noticeable impacts on the terrestrial environment, 

and therefore, the operational impacts would be MODERATE.

The NRC staff concludes that the impacts of the IGCC alternative on terrestrial resources would 

be MODERATE to LARGE during construction and MODERATE during operation. The range in 

construction impacts is primarily the result of the uncertainty in the amount and types of 

undisturbed habitat that construction would affect.

4.6.5 NGCC Alternative

The NGCC alternative assumes that a new NGCC facility would be built at the LSCS site. The 

facility would require 94 ac (38 ha) of land and would be sited on the undeveloped land 

immediately surrounding the LSCS. Some infrastructure upgrades could be required, as well as 

a new or upgraded pipeline, which would affect additional land. Additional offsite land would be 

required for gas extraction and collection, although this impact would be partially offset by the 

elimination of land used for uranium mining to supply fuel to LSCS.

During construction, impacts to terrestrial habitats and species are likely to be similar to the 

types of impacts described for the new nuclear alternative in Section 4.6.3 but would likely be 

smaller in magnitude, due to the smaller footprint of the NGCC facility. Because the NGCC 

facility would be built outside of the existing industrial footprint of LSCS, construction would 

require the conversion of natural areas to industrial use, which would result in the direct 

destruction of some existing terrestrial habitats. Although construction would noticeably alter 

terrestrial resources, it would be unlikely to destabilize important attributes of the terrestrial 

environment due to the small footprint size and the pre-disturbed nature of much of the existing 

land on the LSCS site. Thus, impacts of construction would likely be MODERATE.
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The GEIS (NRC 2013d) concludes that impacts to terrestrial resources from the operation of 

fossil energy alternatives would essentially be similar to those from continued operations of a 

nuclear facility. Unique impacts would include air emissions of GHGs such as nitrogen oxides, 

carbon dioxide, and methane, all of which can have far-reaching consequences because they 

contribute to climate change. The effects of climate change on terrestrial resources are 

discussed in Section 4.15.3.2. Although the impacts of operating the NGCC alternative may be 

noticeable, they are unlikely to destabilize any important attribute of the terrestrial environment 

and would, therefore, be SMALL.

The NRC staff concludes that the impacts of the NGCC alternative on terrestrial resources 

would be MODERATE during construction and SMALL during operation.

4.6.6 Combination Alternative (NGCC, Wind, Solar)

The NGCC component of the combination alternative would have the same land requirements 

as discussed for the NGCC alternative in Section 4.6.5. Accordingly, the impacts to terrestrial 

resources would be similar to those concluded for the NGCC alternative and, therefore, would 

be MODERATE during construction and SMALL during operation.

The wind component of this alternative would require an estimated 3,376 to 10,127 ac (1,366 to 

4,098 ha) of land at onshore wind farm sites and agricultural cropland across the ROI. 

Permanently disturbed land would hold the wind turbines, access roads, and transmission lines. 

Land used for equipment laydown and turbine component assembly and erection could be 

returned to its original state. Use of BMPs would ensure that disturbed lands were appropriately 

restored to reduce long-term impacts to the terrestrial environment. Operation of wind turbines 

could uniquely affect terrestrial species through mechanical noise, collision with turbines and 

meteorological towers, and interference with migratory behavior. Bat and bird mortality from 

turbine collisions is an ongoing concern for operating wind farms; however, recent 

developments in turbine design have reduced the potential for bird and bat strikes. The NRC 

staff expects that this component has the potential to noticeably alter terrestrial resources, 

primarily through the loss of habitat and bird and bat mortalities associated with wind turbine 

operation. However, it is unlikely that the wind component would destabilize any important 

attribute of the terrestrial environment, and thus, impacts would be MODERATE.

The solar component of this alternative would require an estimated 7,397 ac (2,993 ha) of land 

across the ROI. The majority of solar installations could be installed on building roofs at existing 

residential, commercial, or industrial sites or at larger standalone solar facilities, and thus, it is 

possible that little terrestrial habitat would be disturbed during construction. However, the exact 

magnitude of impacts on terrestrial resources would depend on the amount of terrestrial habitat 

that is lost or fragmented during construction of solar installations. Operation would have no 

measurable effects on the terrestrial environment. Overall impacts from construction and 

operation of this component of the alternative would range from SMALL to MODERATE,

depending on the locations of solar installations and the amount of terrestrial habitat affected.

Overall, the NRC staff concludes that the impacts of the combination alternative on terrestrial 

resources would be SMALL to MODERATE. This range is primarily the result of the variability 

in land required for the wind and solar components and the types of terrestrial habitats that 

would be disturbed by construction of these components.

4.6.7 Purchased Power Alternative

The purchased power alternative would have wide-ranging impacts that are hard to specifically 

assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind 
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across many different sites in the ROI. This alternative would likely have little to no construction 

impacts because it would include power from already existing power generating facilities. The 

construction of additional transmission lines would require implementation of BMPs to minimize 

erosion and sedimentation in nearby streams, ponds, or rivers. The types of operational 

impacts would be similar to the effects discussed in the preceding alternative sections. This 

alternative would be more likely to intensify already existing effects at power generating facilities 

than create wholly new effects on terrestrial species and habitats. Existing facilities would likely 

have BMPs and other procedures in place to ensure that effects to the environment during 

operations are minimized. The NRC staff concludes that the impacts on terrestrial resources 

from the purchased power alternative would be SMALL.

4.7 Aquatic Resources

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on aquatic resources.

4.7.1 Proposed Action

Section 3.1.3 describes the LSCS cooling and auxiliary water systems, and Section 3.7 

describes the aquatic resources of interest. Table 4–7 identifies the generic (Category 1) and 

site-specific (Category 2) issues that apply to aquatic resources at LSCS during the proposed 

license renewal period.

Table 4–7. Aquatic Resource Issues

Issue GEIS Section Category

All plants

Entrainment of phytoplankton and zooplankton 4.6.1.2 1

Infrequently reported thermal impacts 4.6.1.2 1

Effects of cooling water discharge on dissolved oxygen, gas 

supersaturation, and eutrophication

4.6.1.2 1

Effects of non-radiological contaminants on aquatic organisms 4.6.1.2 1

Exposure of aquatic organisms to radionuclides 4.6.1.2 1

Effects of dredging on aquatic organisms 4.6.1.2 1

Effects on aquatic resources (non-cooling system impacts) 4.6.1.2 1

Impacts of transmission line right-of-way (ROW) management on 

aquatic resources (a)

4.6.1.2 1

Losses from predation, parasitism, and disease among organisms 

exposed to sublethal stresses

4.6.1.2 1

Plants with once-through cooling systems or cooling ponds

Impingement and entrainment of aquatic organisms 4.6.1.2 2

Thermal impacts on aquatic organisms 4.6.1.2 2

Plants with cooling ponds or cooling towers using makeup water 

from a river

Water use conflicts with aquatic resources 4.6.1.2 2
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Issue GEIS Section Category

(a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

4.7.1.1 GEIS Category 1 Issues

The NRC staff did not identify any new and significant information associated with the 

Category 1 aquatic resource issues identified in Table 4–7 during the review of the applicant’s

ER, aquatic surveys and studies performed at LSCS and in the Illinois River, and available 

scientific literature; the site audit; and the Federal and State agency and public comments 

received during the scoping process. As a result, no information or impacts related to these 

issues were identified that would change the conclusions presented in the GEIS (NRC 2013d). 

For these issues, the GEIS concludes that the impacts are SMALL. It is expected that there 

would be no incremental impacts related to these Category 1 issues during the renewal term 

beyond those discussed in the GEIS; therefore, the impacts associated with these issues are 

SMALL.

4.7.1.2 Impingement and Entrainment of Aquatic Organisms

In the GEIS (NRC 2013d), the NRC determined that impingement and entrainment of aquatic 

organisms is a Category 2 issue (see Table 4–7) that requires site-specific evaluation during 

each license renewal review for plants with once-through cooling systems or cooling ponds, 

such as LSCS.

Impingement is the entrapment of all life stages of fish and shellfish on the outer part of an 

intake structure or against a screening device during periods of water withdrawal 

(40 CFR 125.83). Impingement can kill organisms immediately or contribute to a slower death 

resulting from exhaustion, suffocation, injury, and other physical stresses. The potential for 

injury or death is generally related to the amount of time an organism is impinged, its 

susceptibility to injury, and the physical characteristics of the screen washing system and fish 

return (if present) of the plant.

Entrainment is the incorporation of all life stages of fish and shellfish with intake water flow 

entering and passing through a cooling-water intake structure and into a circulating water 

system (CWS) (40 CFR 125.83). Organisms susceptible to entrainment are generally of smaller 

size than those susceptible to impingement and include ichthyoplankton (fish eggs and larvae), 

larval stages of shellfish and other macroinvertebrates, zooplankton, and phytoplankton. 

Entrained organisms may experience physical trauma and stress, pressure changes, excess 

heat, and exposure to chemicals, all of which may result in injury or death (Mayhew et al. 2000).

A particular species can be subject to both impingement and entrainment if some individual fish

are impinged on screens while others pass through the screens and are entrained. For 

instance, adults could be impinged while juveniles could be entrained, if they are small enough 

to pass through the intake screen openings.

At LSCS, aquatic organisms may be impinged or entrained at two locations. Organisms that 

inhabit the Illinois River may be impinged or entrained when makeup water is drawn from the 

river, through the river screen house, and into the cooling pond. Organisms that inhabit the 

cooling pond may be impinged or entrained when water is drawn from the pond, through the 

cooling pond screen house, and into the CWS. Organisms that are entrained by passing 
Environmental Consequences and Mitigating Actions

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through the cooling pond’s screen house and into the LSCS CWS are subject to mechanical, 

thermal, and toxic stresses that make survival unlikely.

This section’s analysis uses a retrospective assessment of the present and past impacts to the 

aquatic ecosystem resulting from LSCS operation in order to provide a prospective assessment 

for the future impacts over the proposed license renewal term (i.e., through 2042 for Unit 1 and 

through 2043 for Unit 2). The timeframe and geographic extent are two components of the 

assessment that bound the analysis. The timeframe defines how far back and how far forward 

the analysis will extend. In assessing the level of impact, the staff looked at the projected 

effects in comparison to a baseline condition. In agreement with National Environmental Policy 

Act (NEPA) guidance (CEQ 1997), the baseline of the assessment is the condition of the 

resource without the action (i.e., under the no-action alternative). Under the no-action 

alternative, the plant would shut down, and the resource would conceptually return to its 

condition without the plant, which is not necessarily the same as the condition before the plant 

was constructed. The timeframe for analyzing ecological resources extends far enough into the 

past to understand trends and to determine whether the resource is stable, which the NRC 

definitions of impact levels require. For assessing direct and indirect impacts, the geographic 

boundaries depend on the biology of the species under consideration.

The NRC staff used a modified weight-of-evidence (WOE) approach to evaluate the effects of 

impingement and entrainment on the aquatic resources in the Illinois River and LSCS cooling 

pond. The NRC chose this approach because EPA recommends a WOE approach for 

ecological risk assessment (EPA 1998). The WOE approach is a useful tool due to the complex 

nature of assessing risk (or impact), and the NRC has used this approach in other evaluations 

of the effects of nuclear power plant cooling systems on aquatic communities 

(e.g., NRC 2010, 2013c, 2015a, 2015b). Menzie et al. (1996) defines WOE as “...the process 

by which multiple measurement endpoints are related to an assessment endpoint to evaluate 

whether significant risk of harm is posed to the environment.” In the present WOE approach, 

the NRC staff examined five lines of evidence (LOE) to determine if operation of LSCS is 

contributing to adverse impacts on aquatic resources in the Illinois River or LSCS cooling pond. 

The lines of evidence are as follows:

LOE Description

1 Results of impingement studies performed at LSCS

2 Results of entrainment studies performed at LSCS

3 Temporal trends in fish populations in the Illinois River

4 Spatial differences in fish populations in the Illinois River

5 Consideration of engineered designs and operational controls that affect 

impingement and entrainment rates

LOE 1: Impingement Studies

Exelon contracted EA Engineering, Science, and Technology, Inc. (EA) to conduct a study to 

determine the impingement rates among the fish and shellfish in the Illinois River. From 

April 2014 through March 2015, EA (2015) collected 20 samples of all fish and shellfish 

impinged at the river screen house within set 24-hour collection periods. EA identified all 

impinged fish and shellfish to species, or the lowest taxonomic level possible. EA (2015) 

extrapolated annual impingement rates for each species by multiplying the number of fish 

collected during a 24-hour collection period by the volume of water that would be withdrawn 

during 1 year and dividing it by the volume of water withdrawn during the 24-hour collection 

period. 
Environmental Consequences and Mitigating Actions

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EA (2015) collected a total of 635 fish representing 41 species, 9 crayfish representing 2 taxa, 

and 9 mussels representing 3 species. The most commonly impinged fish include gizzard shad 

(Dorosoma cepedianum; 29 percent of all samples), round goby (Neogobius melanostomus; 

11 percent), threadfin shad (Dorosoma petenense; 9 percent), bluegill (Lepomis macrochirus; 

6 percent), freshwater drum (Aplodinotus grunniens; 6 percent), and bluntnose minnow 

(Pimephales notatus; 5 percent). Gizzard shad was the most commonly impinged species and 

the most commonly collected species during electrofishing surveys in 2013 (EA 2014 

and 2015). In addition, EA (2014) collected gizzard shad more often downstream of the intake 

as compared to upstream, which would suggest that impingement is not noticeably altering 

populations of gizzard shad near LSCS. 

Bluegill, bluntnose minnow, and freshwater drum each comprised 5 to 6 percent of the impinged 

fish and each comprised 2 to 3 percent of the electrofishing or seining samples in 2013 

(EA 2014, 2015). These results suggest that the impingement rate is similar to the occurrence 

rate in monitoring surveys in the river near LSCS. In addition, EA (2014) reported similar 

numbers of these three fish species directly upstream and downstream of the river intake, which 

would suggest that impingement is not noticeably altering populations of bluegill, bluntnose 

minnow, and freshwater drum near LSCS. The NRC staff notes that EA (2014) may not 

conclusively determine whether impingement affects populations of fish near LSCS due to the 

limited sample size and because some fish may migrate sufficient distances such that a 

noticeable difference would not likely be identified between samples collected immediately 

upstream and downstream of the intake. 

Both round goby and threadfin shad are invasive species. All other impinged species 

comprised less than 5 percent of the impinged fish (EA 2015). 

The nine impinged crayfish included eight Orconectes species, seven of which were northern 

Clearwater crayfish (Orconectes propinquus) and one Procamarus sp. (EA 2015). The nine 

impinged mussels included two fragile papershell (Leptodea fragilis), one pink heelsplitter 

(Potamilus alatus), and six paper pondshell (Utterbackia imbecillis). 

EA (2015) estimated the annual impingement to be 10,673 organisms per year. The estimated 

annual impingement rates at LSCS are approximately 1 to 6 percent of the impingement rate at 

Dresden Nuclear Station, which is located at the confluence of the Kankakee and Illinois Rivers 

(EA 2015; Exelon 2015b). Dresden Nuclear Station operates in either an indirect-open cycle or 

operates its cooling pond in a closed-cycle mode, similar to LSCS. NRC (2004) determined that 

the impacts from impingement would be SMALL on aquatic resources at Dresden Nuclear 

Station. 

LOE 1 Conclusion

Based on the available impingement studies, intake of makeup water from the Illinois River 

appears to have a minor effect on the aquatic community in the vicinity of LSCS, and the NRC 

staff finds that impingement is not likely to noticeably alter or destabilize any important attributes 

of the community.

Although fish and aquatic biota are also impinged at the lake screen house when cooling pond 

water is drawn into LSCS’s cooling system, the impacts of impingement on the aquatic 

community within the cooling pond are unknown because they have not been addressed in 

studies.

LOE 2: Entrainment Studies

Exelon contracted EA to conduct a study to determine the entrainment rates among the fish and 

shellfish taxa in the Illinois River. As part of this study, EA (2015) collected icthyoplankton 
Environmental Consequences and Mitigating Actions

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samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 

samples using 0.5-m (1.6-ft) conical plankton nets with 505 micron mesh suspended from the 

forebay bridge in front of the river intake (see Figure 3.7–1). EA (2015) collected samples 

during the 2014 spawning season, from late April 2014 through August 2014, when 

icthyoplankton densities would likely be highest. EA (2015) extrapolated annual entrainment 

rates for each taxa based on the number of taxa collected during a 24-hour collection period, 

the volume of water that would be withdrawn during 1 year, and the volume of water withdrawn 

during the 24-hour collection period.

EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 

27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 

combined comprised 79 percent of the ichthyoplankton sample. EA (2015) classified 

icthyoplankton by species or taxa, if identification to the species level was not practicable, and 

by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. The most common 

taxa by life stage included lctiobinae yolk-sac larvae (24 percent), cyprinidae yolk-sac larvae 

(23 percent), and common carp yolk-sac larvae (13 percent). All other taxa-life stage categories 

comprised less than 10 percent of the icthyoplankton samples (EA 2015). 

EA (2015) estimated the annual entrainment rate to be about 38 million organisms per year. 

The estimated annual entrainment rates at LSCS are approximately 28 to 38 percent of the 

entrainment rate at Dresden Nuclear Station, which is located at the confluence of the 

Kankakee and Illinois Rivers (EA 2015; Exelon 2015b). Dresden Nuclear Station operates in 

either an indirect-open cycle or operates its cooling pond in a closed-cycle mode, similar to 

LSCS. NRC (2004) determined that the impacts from entrainment would be SMALL on aquatic 

resources at Dresden Nuclear Station. 

LOE 2 Conclusion

Based on the available entrainment studies, intake of makeup water from the Illinois River 

appears to have a minor effect on the aquatic community in the vicinity of LSCS, and the NRC 

staff finds that entrainment is not likely to noticeably alter or destabilize any important attributes 

of the community.

Although fish and aquatic biota are also entrained at the lake screen house when cooling pond 

water is drawn into LSCS’s cooling system, the impacts of entrainment on the aquatic 

community within the cooling pond are unknown because they have not been addressed in 

studies.

LOE 3: Temporal Trends in Fish Populations in the Illinois River

Impingement and entrainment from the withdrawal of makeup water from the Illinois River have

removed individuals from the river ecosystem since LSCS began operating in 1982. Over this 

period of time, the aquatic community has changed in a number of ways, including species 

richness (the number of species present), species composition (the kinds of species present), 

and species evenness (the relative abundance of species). This LOE compares fish 

populations prior to and during operations to determine whether changes have occurred and if 

such changes can be attributed to LSCS operations. If impingement and entrainment were to 

affect fish within the vicinity of LSCS, fish abundances and species richness would likely be 

lower post-operation as compared to before operations. 

In the section below, the NRC staff made general characterizations of fish populations during 

preoperational and operational surveys. However, differences between time periods could 

occur for multiple reasons, including variations in sampling equipment, the frequency and timing 

of sampling events, and sampling locations. Furthermore, the lack of repeated samples over 

time prevented the NRC staff from conducting statistical analyses on the changes in fish 
Environmental Consequences and Mitigating Actions

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populations over time. Therefore, the trends presented below for LSCS studies describe 

general patterns in fish populations that have not been tested for statistical significance. 

As discussed in Section 3.7, fish populations near LSCS have changed over time. The main 

trends have been an increase in species richness and increases in the abundance of species 

that are sensitive to poor water quality. For example, two commonly collected species during 

preoperational surveys, common carp (Cyprinus carpio) and white sucker (Catostomus 

commersonii), were not commonly collected during the 1999 or 2013 study (NRC 1978; 

EA 2000, 2014). OEPA (1987) classifies both of these species as pollution tolerant. On the 

other hand, brook silverside (Labidesthes sicculus), sand shiner (Notropis stramineus), 

smallmouth bass (Micropterus dolomieu), smallmouth buffalo (Ictiobus bubalus), golden 

redhorse (Moxostoma erythrurum), and bluegill (Lepomis macrochirus) were among the six 

most commonly collected species in the 1999 or 2013 study but were not commonly collected in 

the preoperational studies (NRC 1978; EA 2000, 2014). Five of these seven species are native 

species that are sensitive to declines in water quality or habitat degradation (Smith 2002; 

Lerczak 1996). These results suggest that the quality of aquatic habitat within the Illinois River 

near LSCS has improved since the 1970s. Similar trends of improved water quality, increased 

species richness, and increases in the relative abundance of pollution-sensitive species have 

been documented in several studies on the Illinois River (Lerczak 1996; McClelland and 

Pegg 2005; McClelland et al. 2012; Fritts 2013). These results suggest that the major changes 

in fish populations near LSCS are the result of improved water quality, likely from the 

protections provided in the Clean Water Act (CWA), advances in municipal and industrial waste 

treatment, agricultural conservation measures, and other factors.

Conclusion

Given that species richness and populations of pollution-sensitive fish have increased since 

LSCS began operations, and populations of pollution-tolerant fish have decreased, the NRC 

staff concludes that impingement and entrainment are not having a noticeable impact on 

temporal changes in fish population in the Illinois River near LSCS. Other factors, such as 

improved habitat diversity and quality, are having a more noticeable impact on the temporal 

patterns in fish populations (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012). 

LOE 4: Spatial Differences in Fish Populations in the Illinois River

This LOE compares fish populations upstream and downstream of the river intake structure to

determine whether spatial changes have occurred since LSCS began operating and if such 

changes can be attributed to LSCS operations. If impingement and entrainment were to affect 

fish populations within the vicinity of LSCS, fish abundances and species richness would likely 

be lower downstream of the river intake structure as compared to upstream of the river intake 

structure, due to the removal of fish, eggs, and larvae from impingement and entrainment. The 

NRC staff notes that this LOE may not conclusively determine whether LSCS operation affects

populations of fish near LSCS due to the limited sample size and because some fish may 

migrate sufficient distances such that a noticeable difference would not likely be identified 

between samples collected immediately upstream and downstream of the intake. 

In the section below, the NRC staff made general characterizations of the fish populations 

upstream and downstream of the river intake. Neither EA (2014) nor the NRC staff conducted 

statistical analyses on the differences in fish populations among the sample sites. Therefore, 

the trends presented below for LSCS studies describe general patterns in fish populations that 

have not been tested for statistical significance. 

In 2013, EA (2014) conducted fish surveys and compared fish abundances and species 

richness between upstream and downstream of the river intake. During electrofishing surveys, 
Environmental Consequences and Mitigating Actions

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EA (2014) collected more fish downstream of the intake (43 fish) as compared to upstream 

(36 fish). However, species richness was moderately higher upstream of the intake 

(13 species) compared to downstream of the intake (9 species). For seining samples,

EA (2014) collected more fish and species of fish upstream (location 1; 245 fish; 6 species) as 

compared to the closest downstream location (location 2; 65 fish; 3 fish species). EA (2014) 

attributed the higher fish abundances and species richness upstream of the river intake to better 

habitat quality, particularly regarding instream cover for sunfish. The NRC staff is not aware of 

any studies to determine whether the heated effluent has affected the density of aquatic plants 

that may provide cover for fish. Rocks and tree limbs could also provide cover for fish. 

EA (2014) collected the most amount of fish and species of fish at the furthest downstream 

sampling site near South Kickapoo Creek (location 5; 906 fish; 12 species). During seining 

surveys, EA (2014) collected four species exclusively at the furthest downstream sampling site 

(location 5). EA (2014) attributed the high fish abundance and diversity at the furthest 

downstream location to its proximity to South Kickapoo Creek, as well as the habitat diversity at 

the site and the suitability of that location to seining. 

Conclusion

Given that no clear pattern exists regarding the species richness and species abundances 

upstream and downstream of the river intake structure, the NRC staff concludes that 

impingement and entrainment are not having a noticeable impact on spatial patterns in fish 

population in the Illinois River near LSCS. Other factors, such as habitat diversity and quality, 

are likely having a more noticeable impact on temporal fish population trends near LSCS 

(Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012).

LOE 5: Engineered Design and Operational Controls

In August 2014, EPA published a final rule establishing requirements under section 316(b) of 

the CWA for cooling-water intake structures at existing facilities (79 FR 48300). The final rule 

indicates that two basic approaches can reduce impingement and entrainment mortality: 

(1) flow reduction and (2) including technologies into the cooling-water intake design that gently 

exclude organisms or collect and return organisms without harm to the water body. The EPA 

also notes that two additional approaches can reduce impingement and entrainment but that 

these technologies may not be available to all facilities. The two additional approaches are: 

relocating the facility’s intake to a less biologically rich area in a water body and reducing the 

intake velocity. The LSCS CWS on the Illinois River incorporates several of these approaches.

Flow Reduction

Reducing the amount of water that is withdrawn for cooling purposes from a water body reduces 

the number of aquatic organisms that are drawn through the intake structure and subject to 

impingement or entrainment. Because LSCS uses a cooling-pond-based heat-dissipation 

system, the majority of cooling water needed for plant operation is drawn from the cooling pond 

rather than the Illinois River. The cooling pond system is a closed-cycle cooling system as

water in the pond continues to be recirculated through the plant for cooling, and only makeup 

water (water lost to evaporation or discharged as blowdown) is drawn directly from the Illinois 

River. Depending on the quality of the makeup water, closed-cycle cooling systems can 

consume significantly less water than if the same facility were to use a once-through cooling

system. Exelon (2014a) determined that the maximum withdrawal rate, with all three makeup 

pumps operating at capacity, would withdraw approximately 1.8 percent of the river’s 92-year 

annual average mean flow. Similarly, NRC (1978) estimated that the annual average amount of 

water withdrawn from the Illinois River for cooling pond makeup would be about 1 percent of the 

typical flow, or 3 percent of the 7Q10 (e.g., the 7-day, 10-year low flow) flow.
Environmental Consequences and Mitigating Actions

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Technologies That Exclude or Collect and Return Organisms

The LSCS cooling system has several technologies that help exclude organisms from becoming 

impinged or entrained. Water enters the river screen house through an intake bay equipped 

with bar grills and 3/8-in. (9.5-mm) mesh travelling screens to prevent debris and aquatic biota

from entering the system (Exelon 2014a). The EPA indicates that, ideally, traveling screens 

would be used with a fish handling and return system (79 FR 48300). LSCS’s river screen 

house does not contain a fish return system (Exelon 2014a). However, the intake velocity 

(discussed below) should allow some fish to swim away and escape impingement. 

Intake Flow

Water velocity associated with the intake structure greatly influences the rate of impingement

and entrainment. The higher the approach velocity, through-screen velocity, or both, the greater 

the number of organisms that will be impinged or entrained. At an approach velocity of 

0.5 ft/s (0.15 m/s) or less, most fish can swim away and escape from the intake current 

(79 FR 48300). As indicated in Section 3.1.3, water velocity within the intake channel ranges 

from 0.3 to 0.5 ft/s (0.1 to 0.2 m/s) with one pump operating to 0.6 to 1.0 ft/s (0.2 to 0.3 m/s) with 

two pumps operating (EA 2015). The velocity at the face of the travelling screens is 

0.5 ft/s (0.2 m/s) during one-pump full-flow operation and 0.9 ft/s (0.3 m/s) during two-pump 

full-flow operation (EA 2015). Thus, when one pump is operating, the river screen house intake 

velocities are within the 0.5-fps (0.15-m/s) intake velocity recommended by EPA for protection 

of aquatic organisms. However, the through-screen velocity when two or three pumps are 

operating could contribute to impingement and entrainment effects.

Best Technology Available

On July 5, 2013, the Illinois EPA (IEPA) renewed LSCS’s NPDES permit (No. IL0048151). 

Special Condition 15 relates to potential impacts from cooling water intake and whether LSCS 

utilizes the Best Technology Available (BTA) for cooling-water intake structures to prevent or 

minimize impingement mortality in accordance with the Best Professional Judgment (BPJ) 

provisions of 40 CFR 125.3. In the permit, IEPA determined that:

The facility utilizes a closed-cycle recirculating cooling system, a 2058 acre 

cooling pond, for cooling of plant condensers and is determined to be the 

equivalent of BTA for cooling water intake structures to prevent/minimize 

impingement mortality in accordance with the BPJ provisions of 40 CFR 125.3 

because it allows the facility to only withdraw the amount of water necessary to 

maintain the cooling pond level rather than the entire volume used for cooling of 

the plant condensers.

Conclusion

While flow control measures, traveling screens, and low intake velocities reduce the effects of 

impingement and entrainment mortality at LSCS, the lack of a fish return system and the 

through-screen velocity when two or three pumps are operating could contribute to impingement 

and entrainment effects. This LOE does not conclusively indicate whether impingement or 

entrainment at LSCS is creating detectable effects on the Illinois River aquatic community. 

Thus, this LOE, considered alone, is inconclusive.

Overall Impingement and Entrainment Conclusion

The NRC staff reviewed available impingement and entrainment studies, assessed spatial and 

temporal changes in fish populations near LSCS in the Illinois River, and considered engineered 

designs and operational controls that affect impingement and entrainment rates. The NRC staff 

concludes that the impacts to aquatic resources in the Illinois River from impingement and 
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entrainment would be SMALL and would not likely noticeably alter aquatic resources in the 

vicinity of LSCS based on the following:

• relatively low impingement and entrainment rates, 

• increases in species richness and relative abundance of pollution-sensitive species 

since LSCS began operations,

• reduced flow due to operation as a closed-cycle system with the use of the LSCS

cooling pond, 

• bar grills and traveling screens with 3/8 in. (0.95-cm) openings to exclude fish, and

• IEPA’s determination of BTA for use of a closed-cycle recirculating cooling system.

Although fish and aquatic biota are also impinged and entrained at the cooling pond screen 

house when cooling pond water is drawn into LSCS’s cooling system, the impacts of 

impingement on the aquatic community within the cooling pond are unknown because Exelon

has not conducted any impingement or entrainment studies at the cooling pond intake, nor have 

any consistent fish monitoring studies been implemented in the cooling pond. The NRC staff 

notes that the use of bar grills and traveling screens with 3/8-in. (0.95-cm) openings would 

reduce the impacts from impingement and entrainment in the cooling pond. 

4.7.1.3 Thermal Impacts on Aquatic Organisms

In the GEIS (NRC 2013d), the NRC determined that thermal impacts on aquatic organisms is a

Category 2 issue (see Table 4–7) that requires site-specific evaluation during each license 

renewal review for plants with once-through cooling systems or cooling ponds, such as LSCS. 

The NRC’s regulations at 10 CFR Part 51 concerning license renewal reviews and the GEIS 

direct the NRC to consider all aquatic resources that may be affected by plant operations,

regardless of the type of water body in which such resources reside. For instance, 

Section 4.2.2 of the 1996 GEIS specifically notes that aquatic biota of cooling ponds may be 

affected by thermal discharges and that these effects should be considered the same as those 

considered for once-through cooling systems, except that such effects mainly influence aquatic 

communities that did not exist before the creation of the cooling pond. The 2013 GEIS did not 

identify new information that would alter this methodology or alter any conclusions regarding 

impacts to aquatic populations in cooling ponds. Consideration of the impact on aquatic 

resources in cooling ponds is consistent with previous NRC license renewal reviews 

(e.g., NRC 2008b, 2013c, 2015a).

The NRC staff used a modified WOE approach to evaluate thermal impacts on the aquatic 

resources in the Illinois River and LSCS cooling pond. The NRC staff examined the five LOEs

as follows.

LOE Description

1 Results of past NRC reviews on thermal impacts of LSCS operations

2 A review of regulatory and administrative controls on thermal effluents

3 Population trends of indicator species

4 Health of fish populations as an indicator of water quality

5 Fish kills

LOE 1: Past NRC Reviews

The NRC (1978) previously assessed the potential thermal impacts of LSCS operations in the 

Final Environmental Impact Statement for LSCS Operations. The NRC (1978) estimated the 
Environmental Consequences and Mitigating Actions

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size of the thermal plume under two scenarios, one in March and one in July, using relatively 

conservative assumptions (e.g., the 7Q10 low-flow estimate, maximum blowdown rate, 

100 percent load factor). For the March scenario, the NRC (1978) determined that the 5 °F 

(3 °C) isotherm would range from 2,500 m2 (27,000 ft2

) in March to 400 m2 (4,300 ft2) in July. 

The thermal plume would cover approximately 9 percent of the river in March and 8 percent in 

July (NRC 1978). The zone of passage for fish would be 91 to 92 percent, which would be 

greater than the minimum 75 percent required by Illinois water quality standards. Thus, the 

NRC (1978) concluded that juvenile and adult fish would either be able to avoid the thermal 

plume, or a small number of organisms may be exposed to the thermal plume for a short period 

of time. The NRC staff concluded that the discharge impacts would likely be minimal and of 

little influence on the natural biotic populations in the Illinois River. 

LOE 1 Conclusion

The NRC’s past review of the thermal impacts from LSCS discharges to the Illinois River 

indicated that the thermal impacts on the aquatic community would be minor. 

LOE 2: Regulatory and Administrative Controls

The Illinois Administrative Code (IAC) and the LSCS NPDES permit (IEPA 2013) impose 

regulatory controls on LSCS’s thermal effluent that ensure that impacts on the aquatic 

environment are reduced or mitigated.

Title 35, Environmental Protection, Section 302, “Water Quality Standards,” of the IAC contains 

stipulations pertaining to effluent temperature as well as mixing zones and zones of initial 

dilution. The following limitations and requirements included in Section 302 pertain to effluent 

temperature and serve to protect aquatic biota from the effects of such effluents.

The maximum temperature rise shall not exceed 2.8 °C (5 °F) above natural 

receiving water body temperatures. [35 IAC 302.211(d)]

Water temperature at representative locations in the main river shall at no time 

exceed 33.7 °C (93 °F) from April through November and 17.7 °C (63 °F) in other 

months. [35 IAC 302.211(e)]

Several IAC stipulations pertaining to mixing zones also protect aquatic biota from thermal

effluents.

Mixing is not allowed in waters which include a tributary stream entrance. 

[35 IAC 302.102(b)(2)]

Mixing is not allowed in waters containing mussel beds, endangered species

habitat, fish spawning areas, areas of important aquatic life habitat, or any other 

natural features vital to the well-being of aquatic life. [35 IAC 302.102(b)(4)]

Mixing must allow for a zone of passage for aquatic life. [35 IAC 302.102(b)(6)]

The area and volume of mixing must not contain more than 25 percent of the 

cross-sectional area or volume of a stream and must not intersect any body of 

water in such a manner that the maintenance of aquatic life in the body of water 

as a whole would be adversely affected. [35 IAC 302.102(b)(7) and (8)]

The area and volume in which mixing occurs must be as small as is practicable, 

and in no circumstances larger than 26 ac (11 ha). [35 IAC 302.102(b)(12)]

The LSCS NPDES permit (IEPA 2013) also contains requirements related to thermal effluents. 

Special Condition 3 of the permit, which limits the maximum temperature rise above ambient 

conditions and maximum water temperatures during various times of the year, mirrors the 

temperature requirements at 35 IAC 302.211 listed above. 
Environmental Consequences and Mitigating Actions

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The NRC staff reviewed the results of recorded maximum cooling pond blowdown temperatures 

to the Illinois River and associated calculations of river mixing zone temperatures as reported in 

the discharge monitoring reports (DMR) for the past 5 years (2010 through 2014) and as 

compiled by Exelon (Exelon 2015b). Based on the NRC’s staff review and Exelon’s responses 

to the NRC’s RAIs, LSCS has received no notices of violation associated with NPDES permitted 

discharges during the 2010 through 2014 time period (see Section 3.5.1). Nonetheless, Exelon 

requested three variances with respect to LSCS’s effluent discharges to the Illinois River and 

associated river mixing zone temperature limits. Specifically, these variances 

(IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 

March, July, and August 2012, respectively, due to unusual weather conditions and associated 

high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 

meet the requirements of Special Condition 3 of LSCS’s NPDES permit. This limits the number 

of temperature excursion hours to 1 percent (87.6 hours) of the hours in a 12-month period, 

ending with any month (see footnote d in Table 3–7 of this document). During the variance 

period(s), Exelon was required, in part, to continuously monitor both the discharge and receiving 

water temperatures and visually inspect all discharge areas at least three times each day to 

assess the impact on aquatic life. These thermal discharge excursions were not found to have 

any impact on aquatic life (Exelon 2015b).

Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 

cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 

Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 

and associated procedures to mitigate the impacts of summer drought and/or high river 

temperature and river low-flow conditions. Depending on predefined conditions set forth in the 

plan and implementing procedures, such actions may include a combination of monitoring and 

modeling of river intake and mixing zone temperatures; manipulation of the water level of the 

cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 

cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the 

technical specification limits on the condenser inlet temperature from the cooling pond 

(Exelon 2014a; 2015a).

LOE 2 Conclusion

The LSCS thermal effluent is limited by the IAC and the LSCS NPDES permit to ensure that it 

does not create adverse effects on the aquatic communities in the Illinois River. In the past 

5 years, Exelon received no notices of violations and IEPA granted three provisional variances

to allow higher-than-permitted temperatures. Exelon reported no fish kills or other events to the 

IEPA or the NRC that would indicate adverse environmental effects resulting from the 

provisional variances. The NRC depends on the State to enforce the regulatory controls in 

place at LSCS and effectively ensure that any environmental effects to Illinois River aquatic 

communities are not detectable or are so minor as to neither destabilize nor noticeably alter the 

community. 

LOE 3: Spatial and Temporal Trends for Indicator Species

Heat shock has the potential to kill or injure individual fish and other organisms in the Illinois 

River ecosystem. This LOE compares the population trends of indicator species prior to and 

during operations and upstream and downstream of the discharge structure to determine 

whether changes have occurred and if such changes can be attributed to LSCS operations. If 

heat shock were to affect aquatic resources within the vicinity of LSCS, the NRC staff would 

expect the following:
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• Fish and macroinvertebrate abundances and species richness would likely be lower 

after operations began as compared to prior to operations, and lower downstream as 

compared to upstream of the discharge, and 

• Populations of pollution-sensitive fish and macroinvertebrates would likely be lower 

after operations began as compared to prior to operations, and lower downstream of 

the discharge as compared to upstream of the discharge. 

As described in LOE 3 and 4 in Section 4.7.1.2, the NRC staff reviewed fish population trends in 

the Illinois River near LSCS from the 1970s through 2013 (NRC 1978; EA 2000, 2014). The 

NRC staff determined that species richness and populations of pollution-sensitive fish have 

increased since LSCS began operations, and populations of pollution-tolerant fish have 

decreased. In addition, the NRC staff did not identify any clear patterns regarding the species 

richness and species abundances upstream and downstream of the river intake and discharge

structures. Therefore, the thermal effluent is not likely having a noticeable impact on the 

temporal patterns of fish populations in the Illinois River near LSCS. Other factors, such as 

habitat diversity and improved water quality, are likely having a more noticeable impact on the 

spatial patterns in fish populations.

As described in Section 3.7.1.1.2, EA (2000, 2014) compared the macroinvertebrate 

communities upstream and downstream of the LSCS discharge. During 1999 surveys, 

EA (2000) determined that the dominate macroinvertebrate taxa at sites both upstream and 

downstream of the discharge structure were tolerant to poor water quality. EA (2000) also 

determined that both total species richness and the number of Ephemeroptera, Plecoptera, and 

Trichoptera (EPT) species, which are considered intolerant of environmental stress, were 

slightly higher downstream (locations 2 and 4) compared to upstream (location 1) of the 

discharge structure.

During 2013 surveys, EA (2014) observed dominant taxa that were relatively tolerant to poor 

water quality as well as dominant taxa that were relatively intolerant or facultative to poor water 

quality, both upstream and downstream of the discharge. Similarly, species richness among 

pollution-sensitive EPT was similar among all locations, ranging from three to five taxa 

(EA 2014). Given that the NRC staff did not identify any clear patterns regarding the species 

richness and species abundances upstream and downstream of the river discharge structures, 

the thermal effluent is not likely having a noticeable impact on fish populations near LSCS. 

Other factors, such as habitat diversity and quality, are having a more noticeable impact on the 

spatial patterns in fish populations.

LOE 3 Conclusion

Given that species richness and populations of pollution-sensitive fish have increased since 

LSCS began operations and no clear pattern exists regarding the species richness and species 

abundances upstream and downstream of the discharge, the NRC staff concludes that heat 

shock is not having a noticeable impact on aquatic resources in the Illinois River near LSCS. 

Other factors, such as habitat diversity and quality, are likely having a more noticeable impact 

on the temporal and spatial patterns in fish populations. 

LOE 4: Health of Fish Populations as an Indicator of Water Quality

Fish parasites and anomalies generally occur most often in fish that inhabit waterbodies with 

poor water quality (OEPA 1989). Therefore, if the LSCS thermal effluent were to result in heat 

stress for fish near LSCS, one would expect an increase in the occurrence of parasites and 

anomalies since operations began. 
Environmental Consequences and Mitigating Actions

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During preoperational studies, the NRC (1978) noted a high level of external parasitism, 

disease, and physical abnormalities associated with fish near LSCS. The NRC (1978) did not 

provide any quantitative estimates of the amount of fish that had external parasitism, diseases, 

or physical abnormalities. 

In 1999, EA (2000) observed a total of 63 fish (6.6 percent of the catch) with DELT (deformities, 

erosions, lesions, or tumors) anomalies. Channel catfish (Ictalurus punctatus), freshwater drum 

(Aplodinotus grunniens), and common carp exhibited the highest DELT affliction rates (greater 

than 20 percent). The most common DELT anomalies included fin erosion (52 percent) and 

deformities (38 percent). 

In 2013, EA (2014) observed a 0.2-percent DELT rate of all the 1,295 fish collected during

electrofishing and seining studies in the Illinois River. Both fish were freshwater drum that 

exhibited eroded fins. One fish was collected upstream of the discharge structure (location 1) 

and the other fish was collected downstream of the discharge structure (location 2). EA (2014) 

did not observe any fish with parasites. 

These results suggest that the quality of aquatic habitat within the Illinois River near LSCS has 

improved since the 1970s. Similar trends of improved water quality and decreased rates of fish 

parasites and DELT anomalies have been documented in other studies on the Illinois River. For 

example, McClelland and Pegg (2005) reviewed trends in fish parasites and anomalies from 

Illinois Natural History Survey (INHS) data and found a decrease in anomalies over time, with 

no anomalies in 2004. These results suggest that the major changes in fish parasites and 

physical anomalies on fish near LSCS are the result of improved water quality, likely from the 

protections provided in the CWA, advances in municipal and industrial waste treatment, 

implementation of agricultural conservation measures, and other factors.

LOE 4 Conclusion

Given the decreasing rate of fish parasites and DELT anomalies observed on fish in the Illinois 

River near LSCS, the NRC staff concludes that heat shock from LSCS’s thermal effluent is not 

having a noticeable impact on fish health in the Illinois River near LSCS. Other factors, such as 

water quality, are likely having a more noticeable impact on the rate of fish parasites and DELT 

anomalies (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012). 

LOE 5: Fish Kills

Since 2001, Exelon has reported four fish kill events in the LSCS cooling pond; Section 3.7.2.2 

describes these events. Exelon attributes these fish kills to high cooling pond temperatures as 

a result of high summer temperatures combined with low winds and high humidity 

(Exelon 2001, 2009, 2010). Each event resulted in the mortality of several hundred to several 

thousand fish. The largest of these events occurred in July 2001 and included approximately 

94,500 dead fish (Exelon 2001). The majority of dead fish (96 percent) were gizzard shad 

(90,800). The majority of the fish in kills since 2001 were either gizzard shad or threadfin shad 

(Exelon 2001, 2009, and 2010). Fish kills have had a noticeable impact on shad populations in 

the cooling pond. For example, during Illinois Department of Natural Resources (IDNR) surveys 

in the cooling pond, the gizzard shad catch per hour was 451 in 2000 and in 2001, after the 

largest fish kill, it was 108 (Exelon 2002). Exelon (2002) attributed this decline to the large fish 

kill that included 90,800 gizzard shad during the previous summer. Similarly, in a status review 

of the cooling pond in 2011, 2012, and 2014, IDNR noted the decline in the shad populations 

and attributed this decline to a fish kill during the summer (Exelon 2015b). Shad populations 

generally recovered within about 1 year after a kill occurred (Exelon 2002, 2015b) and loss of 

shad did not substantially affect the community dynamics within the cooling pond 
Environmental Consequences and Mitigating Actions

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(Exelon 2010, 2015b). The NRC staff also did not identify any long-term or destabilizing 

changes from previous fish kills. 

Shad are main prey items for recreationally fished species within the LSCS cooling pond. 

Species with important trophic links, such as predators or prey, are considered important 

aquatic species based on the definition in the NRC’s standard review plan (NRC 2013f). As 

such, the NRC staff considers shad an important attribute of the aquatic community in the LSCS

cooling pond because it is prey for many of the recreationally fished species. 

Stocked species are generally a small percentage of fish affected by fish kills in the LSCS

cooling pond (Exelon 2001, 2009, 2010). IDNR generally stocks the pond with fish that are 

tolerant to high temperatures. In addition, if a fish kill or other environmental conditions have 

negatively impacted a stocked species, IDNR can increase the stocking level during the 

following spring (Exelon 2014a, 2015b). Further, IDNR has often reported abundant, growing 

populations of various stocked fish, such as striped bass hybrids and channel catfish 

(IDNR 2007, 2009; Exelon 2015b). 

The NRC expects that fish kills would continue during the proposed license renewal period 

because fish kills in the LSCS cooling pond can occur when temperatures rise above 

95 °F (35 °C), the temperature at which most fish in the cooling pond are thermally stressed 

(Exelon 2014a, 2015a). Past temperature records indicate that the cooling pond regularly 

exceeded 95 °F (35 °C) during the past 10 summers (Exelon 2015b). Further, the LSCS cooling 

pond has reached a point where fish kills could be expected every summer (Exelon 2002). On 

August 3, 2015, the NRC staff published an Environmental Assessment in the Federal Register 

(80 FR 46062) as part of the NRC staff’s review of Exelon’s application to amend LSCS

Technical Specification 3.7.3, “Ultimate Heat Sink,” by increasing the maximum cooling water 

temperature supplied to the plant from the ultimate heat sink (UHS) from 101.25 degrees 

Fahrenheit (°F) (38.47 degrees Celsius (°C)) to a variable limit between 101.25 and 104 °F 

(38.47 and 40 °C), depending on the time of day. On November 19, 2015, the NRC approved 

the amendment (NRC 2015g). In its Environmental Assessment, the NRC staff determined that 

raising the maximum allowable temperature of the UHS would increase cooling pond water 

temperatures, especially during extreme warm weather conditions. Fish kills would be more 

likely to occur, especially when cooling pond temperatures rise above 95 °F (35 °C), the 

temperature at which most fish in the cooling pond are thermally stressed. The NRC staff 

concluded that there would likely be an increase in the number or intensity of fish kills, and that 

the majority of fish killed would be shad. The increase in intensity and number of fish kills would 

not result in a significant impact, however, because the cooling pond is a managed ecosystem 

where fish populations affected by fish kills generally recover in about a year and do not 

significantly alter the fish community structure. Lastly, any impacts from the increased 

temperatures would be confined to the cooling pond and would not affect aquatic resources in 

the Illinois River.

Exelon leases the cooling pond to the IDNR for the IDNR to manage and stock a portion of the 

cooling pond. However, Exelon retains the authority to terminate the lease. If the lease were to 

be terminated during the license renewal period, the NRC staff assumes that the fish community 

would continue to exist in the cooling pond without stocking, although the distribution of species 

and population sizes may change without artificial replenishment and with the elimination of 

recreational fishing pressure. The NRC staff made this determination based on observations of 

other cooling ponds at nuclear power plants that are not stocked with fish but contain a growing 

fish community based on the withdrawal of water from a river (e.g., NRC 2013c). 
Environmental Consequences and Mitigating Actions

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Exelon has not reported any fish kills on the Illinois River since LSCS began operating. 

Furthermore, discharge to the Illinois River remained within the NPDES-allowed limits during 

each of the reportable fish kills (Exelon 2015b).

LOE 5 Conclusion

No fish kills have occurred on the Illinois River. Thus, this LOE indicates that the effects of the 

thermal discharge on Illinois River aquatic biota are not detectable.

Fish kills in the LSCS cooling pond are expected to occur during the license renewal term 

(Exelon 2002, NRC 2015g). The NRC staff determined that such fish kills would have 

noticeable impacts on shad based on the following: 

• Exelon and IDNR documented decreased or noticeable reductions in shad 

population sizes following fish kills in the cooling pond (Exelon 2002, 2015b).

• Exelon and IDNR attributed the declines in shad populations to the fish kills 

(Exelon 2002, 2015b).

Fish kills are not destabilizing to shad populations, however, because they tend to recover in 

about a year. 

Stocked species are a minor portion of affected fish during most fish kills, and therefore, the 

NRC staff concludes that fish kills do not noticeably alter populations of stocked species. In 

addition, if a fish kill negatively impacts a stocked species, IDNR can increase the stocking level 

during the following spring.

Summary of Thermal Impacts Conclusion

The NRC staff reviewed past NRC studies of thermal impacts, regulatory and administrative 

controls to limit the temperature in the LSCS discharge, spatial and temporal patterns of species 

richness and pollution-sensitive species, the health of fish prior to and during LSCS operations, 

and the occurrence of fish kills. The NRC staff concluded that the impacts to aquatic resources 

from heat shock would be SMALL for all fish within the Illinois River and for stock fish within the 

LSCS cooling pond, based on the following:

• fish could avoid the thermal plume, which would cover up to 9 percent of the Illinois 

River, 

• the LSCS thermal effluent is limited by the IAC and the LSCS NPDES permit,

• species richness and the relative abundance of pollution-sensitive species have

increased since LSCS began operations,

• the occurrence of fish parasites and physical abnormalities, which are indicative of 

poor water quality, has decreased since LSCS began operations, and

• stocked species are a minor portion of affected fish during most fish kills in the LSCS

cooling pond.

The NRC staff determined that fish kills in the LSCS cooling pond would have MODERATE 

impacts on shad. A MODERATE impact is defined as environmental effects that are sufficient 

to alter noticeably, but not destabilize, important attributes of the resource (NRC 2013f). The 

NRC staff determined that fish kills would have noticeable impacts on important attributes of the 

aquatic environment within the cooling pond (i.e., shad) based on the following: 

• Exelon and IDNR noted reductions in shad population sizes following fish kills in the 

cooling pond (Exelon 2002, 2015b).
Environmental Consequences and Mitigating Actions

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• Exelon and IDNR attributed the decline in shad populations to the fish kills

(Exelon 2002, 2015b).

• Based on the definition of important species in the NRC’s standard review plan 

(NRC 2013f), shad is an important aquatic attribute to the cooling pond ecosystem 

because it is prey for many recreationally fished species.

• Fish kills would not be destabilizing to shad populations because they tend to 

recover in about a year.

• Fish kills are expected to occur in the LSCS cooling pond during the license renewal 

term (Exelon 2002; NRC 2015g). 

Therefore, the NRC staff concluded that thermal impacts would be MODERATE to shad in the 

LSCS cooling pond. The applicant has proposed no mitigation to reduce the MODERATE 

environmental impacts associated with thermal impacts to gizzard shad and threadfin shad in 

the cooling pond (Exelon 2015b). However, because the cooling pond is a highly managed 

system, any cascading effects resulting from the loss of shad (such as a reduction in prey for 

stocked species, which in turn could affect a stocked species’ population) could be mitigated

through IDNR’s annual stocking and continual management of the pond.

4.7.1.4 Water Use Conflicts with Aquatic Resources

In the GEIS (NRC 2013d), the NRC determined that effects of water use conflicts on aquatic 

resources is a Category 2 issue (see Table 4–7) that requires site-specific evaluation during 

each license renewal review. Water use conflicts occur when the amount of water needed to 

support aquatic resources is diminished as a result of demand for agricultural, municipal, or 

industrial use or decreased water availability due to droughts, or a combination of these factors.

The mean annual discharge of the Illinois River (described in Section 3.5.1.1) measured at the 

USGS gage at Marseilles, Illinois, is 10,750 cfs (304 m3

/s). As described in Section 3.5.1.2, 

LSCS’s average surface water withdrawal rate from the Marseilles Pool of the Illinois River is 

105 cfs (2.96 m3

/s or 67.8 mgd), with consumptive use averaging about 49.7 cfs (1.4 m3/s or 

32.1 mgd). This consumptive use is equivalent to about 0.5 percent of the Illinois River’s 

average annual flow. During periods of low flow, LSCS’s current consumptive water use 

(i.e., 49.7 cfs (1.4 m3

/s or 32.1 mgd)) represents a 0.9- and a 1.1-percent reduction, 

respectively, in the flow of the river downstream of the LSCS site. 

As previously discussed in Section 3.5.1.2 of this SEIS, Exelon maintains an Extreme Heat 

Implementation Plan that is part of an overall Summer Readiness Plan. The Extreme Heat 

Implementation Plan provides procedural guidance to plant personnel for responding to 

worst-case summer weather and hydrologic conditions to ensure compliance with LSCS’s 

NPDES permit for thermal discharge limits and to safeguard plant equipment. As necessary, 

plant personnel run thermal models and will adjust makeup pumping rates to the cooling pond 

or the rate of blowdown to the river to maintain permit compliance. Under extreme cases, it may 

be necessary for Exelon to reduce LSCS’s power output or to shut down the plant (e.g., under 

conditions of extremely low water levels). 

The amount of Illinois River water LSCS consumes is minor in comparison to the flow of water 

past the plant, and administrative mechanisms are in place so LSCS does not consume an 

amount that would be harmful to aquatic biota during low-flow conditions. The NRC staff did not 

identify any information that indicates that the Illinois River biota are affected by the loss of river 

water consumed by LSCS’s makeup water withdrawals. The NRC staff concludes that water 

use conflicts would not occur from the proposed license renewal or would be so minor that the 

effects on aquatic resources would be undetectable. Thus, the NRC staff concludes that the 
Environmental Consequences and Mitigating Actions

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impacts of water use conflicts on aquatic resources during the proposed license renewal term 

would be SMALL.

4.7.2 No-Action Alternative

If LSCS were to cease operating, impacts to aquatic ecology would decrease or stop following 

reactor shutdown. Some withdrawal of water from the Illinois River would continue during the 

shutdown period as the fuel is cooled, although the amount of water withdrawn would decrease 

over time. The reduced demand for cooling water would substantially decrease the effects of 

impingement, entrainment, and thermal effluents. These effects would likely stop following the 

removal of fuel from the reactor cores and shutdown of the spent fuel pool. Given the small 

area of the thermal plume in the Illinois River under normal operating conditions (less than 

9 percent), effects from cold shock are unlikely. The cooling pond, however, would likely 

experience shifts in the relative abundances of fish populations because less heat-tolerant 

species would no longer be stressed by thermal additions to the pond. Some fish populations, 

such as stocked recreational species that thrive in warmer waters, may experience population 

declines in the cooling pond. These alterations in community structure would likely be 

noticeably for some species within the cooling pond. 

Thus, the NRC staff concludes that the impacts of the no-action alternative on aquatic resources 

during the proposed license renewal term would be SMALL within the Illinois River and SMALL 

to MODERATE within the cooling pond.

4.7.3 New Nuclear Alternative

Construction of a new nuclear alternative would occur at an existing nuclear power plant site 

(other than the LSCS site) or a retired coal plant site. Construction activities could degrade 

water quality of nearby streams, ponds, or rivers through erosion and sedimentation; result in 

loss of habitat through pond or wetland filling; or result in direct mortality of aquatic organisms 

from dredging or other in-water work. Due to the relatively short-term nature of construction 

activities, these effects would likely be relatively localized and temporary. Siting the plant on an 

existing site could make use of existing transmission lines, roads, parking areas, and other 

infrastructure, which would limit the amount of habitat disturbance that would be required. Less 

habitat disturbance would create less erosion and sedimentation. The construction of intake 

and discharge structures could result in direct mortality of individuals as well as water quality 

degradation. Appropriate permits would ensure that water quality impacts would be addressed 

through mitigation or BMPs, as stipulated in the permits. The EPA, USACE, or the State would 

oversee applicable permitting, including a CWA Section 404 permit, Section 401 certification, 

and Section 402(p) NPDES general stormwater permit. The NRC (2013a) has completed the 

review of one combined license application to build and operate a new nuclear plant in the ROI 

(Fermi 3 in Michigan) and concluded that construction would have SMALL impacts on aquatic 

resources. Without more specific details on the location of the new nuclear alternative, the NRC 

staff finds it reasonable to adopt its previous construction conclusions regarding Fermi 3 for the 

construction portion of this alternative.

Operational impacts would include those listed in Table 4–7, and the GEIS (NRC 2013d) 

conclusions of SMALL for Category 1 issues in the table would apply during the operational 

phase of the new nuclear alternative. Because this alternative would use a closed-cycle

system, impingement, entrainment, and thermal effects would also be SMALL. Water use 

conflicts with aquatic resources would depend on the site location, water body, and specific 

aquatic community present and cannot be determined without more specific details on the 

location of this alternative.
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The NRC staff concludes that the impacts to aquatic resources from construction and operation 

of a new nuclear alternative would be SMALL.

4.7.4 IGCC Alternative

Construction of an IGCC alternative would occur at the LSCS site or another existing power 

plant site in the ROI. The GEIS (NRC 2013d) indicates that the impacts of new power plant 

construction on ecological resources would be qualitatively similar. Thus, those impacts 

discussed under the new nuclear alternative would apply during the construction phase. Thus, 

construction impacts would be SMALL.

Operation of the IGCC alternative would require less cooling water than LSCS because the 

plant would operate with a closed-cycle system. Accordingly, impingement, entrainment, and 

thermal effects on aquatic resources would likely be smaller than for continued operation of 

LSCS, though the exact magnitude would depend upon the water body and specific aquatic 

communities present. Chemical discharges from the cooling system would be similar to those 

at LSCS. Operation would require coal deliveries, cleaning, and storage, which would require 

periodic dredging (if coal is delivered by barge); create dust, sedimentation, and turbidity; and 

introduce trace elements and minerals into the water. Air emissions from the IGCC units would 

include small amounts of sulfur dioxide, particulates, and mercury that would settle on water 

bodies or be introduced into the water from soil erosion. If the IGCC plant were located on the 

same water body (the Illinois River) in the vicinity of the LSCS site, overall operational impacts 

would be less than for the continued operation of LSCS because of the reduced impingement, 

entrainment, and thermal effects. However, without knowing the location of the IGCC plant, the 

associated water body, aquatic species, and their interactions within the ecosystem, the NRC 

staff cannot assume that overall impacts of operation of an IGCC plant would be less than those 

for the continued operation of LSCS. Thus, impacts could range from SMALL to MODERATE.

The NRC staff concludes that the impacts to aquatic resources from construction of an IGCC 

plant would be SMALL and the impacts from operation would be SMALL to MODERATE.

4.7.5 NGCC Alternative

Construction of an NGCC alternative would occur at the LSCS site. The GEIS (NRC 2013d) 

indicates that the impacts of new power plant construction on ecological resources would be 

qualitatively similar. Thus, those impacts discussed under the new nuclear alternative would 

apply during the construction phase. Construction of new pipelines, if necessary, could impact 

previously undisturbed habitats. This impact would vary depending on the location of the plant 

and would be more likely to impact terrestrial resources than aquatic resources. Because the 

NGCC alternative would be built at the LSCS site, new pipelines could be collocated in existing 

corridors to reduce impacts. Overall, construction impacts would be SMALL.

Operation of the NGCC alternative cooling system would be qualitatively similar to the IGCC 

alternative but would result in smaller impacts because the NGCC alternative would consume 

about half as much cooling water. Air emissions from the NGCC units would include nitrogen 

oxide, carbon dioxide, and particulates that would settle on water bodies or be introduced into 

the water from soil erosion. Given that the NGCC plant would be located on the same water 

body (the Illinois River) as LSCS, overall operational impacts would be less than for the 

continued operation of LSCS, due to the reduced impingement, entrainment, and thermal 

effects, which were determined to be SMALL for aquatic resources in the Illinois River.

The NRC staff concludes that the impacts to aquatic resources from construction and operation 

of an NGCC plant would be SMALL.
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4.7.6 Combination Alternative (NGCC, Wind, Solar)

The NGCC portion of this alternative would be located at the LSCS site. Construction and 

operation impacts would be qualitatively similar to those discussed for the NGCC alternative but 

would be much less in magnitude because of the smaller footprint of the plant, reduced cooling 

water consumption, and lowered air emissions. The wind and solar portions of the alternative, 

which account for 85 percent of the alternative’s power generation, would not require cooling or 

consumptive water use during operation and thus, would not affect aquatic resources. The 

NRC staff concludes that the impacts on aquatic resources from the combination alternative 

would be SMALL.

4.7.7 Purchased Power Alternative

The purchased power alternative would have wide-ranging impacts that are hard to specifically 

assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind 

across many different sites in the ROI. This alternative would likely have little to no construction 

impacts because it would include power from already-existing power generating facilities, and 

the types of operational impacts would be similar to the effects discussed in the preceding 

alternative sections. This alternative would be more likely to intensify already existing effects at 

power generating facilities than create wholly new effects on aquatic species and habitats. 

Existing facilities would likely have permits with appropriate mitigation, BMPs, or other 

procedures in place to ensure that effects to the environment during operations are minimized. 

The NRC staff concludes that the impacts on aquatic resources from the purchased power 

alternative would be SMALL.

4.8 Special Status Species and Habitats

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on special status species and habitats.

4.8.1 Proposed Action

Section 3.8 describes the special status species and habitats that have the potential to be 

affected by the proposed action. The discussion of species and habitats protected under the 

Endangered Species Act of 1973, as amended (ESA), includes a description of the action area 

as defined by the ESA section 7 regulations at 50 CFR 402.02. The action area encompasses 

all areas that would be directly or indirectly affected by the proposed LSCS license renewal.

Table 4–8 lists the one site-specific (Category 2) issue related to special status species and 

habitats applicable to LSCS. Appendix C contains information on the NRC staff’s consultation 

with the U.S. Fish and Wildlife Service (FWS) for the proposed action pursuant to section 7 of 

the ESA. No listed species under the National Marine Fisheries Service’s (NMFS) jurisdiction 

occur in the action area, therefore, the NRC staff did not consult with NMFS.

Table 4–8. Special Status Species and Habitat Issues

Issue GEIS Section Category

Threatened, endangered, and protected species, critical habitat and 

essential fish habitat

4.6.1.3 2

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51
Environmental Consequences and Mitigating Actions

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Correspondence

In late February 2015, the NRC staff filled in an online form to obtain an updated protected 

species list for LSCS on the FWS’s Environmental Conservation Online System, Information for 

Planning and Conservation. The FWS (2015b) responded with a list of threatened and 

endangered species that may occur in the project location and may be affected by the Federal 

action. In October 2015, the NRC staff checked the FWS (2015a) online Illinois County 

distribution of listed species for updates.

Analysis and Determination of Effects

Exelon (2014a) reports that no Federally listed species identified in Section 3.8, have been 

reported in the action area and no designated or proposed critical habitat under the ESA occurs 

in the action area. Thus, the NRC staff concludes that the proposed action would have no effect 

on the Federally listed species identified in Section 3.8. The FWS (2014) does not typically 

provide its concurrence with “no effect” determinations by Federal agencies. Thus, the ESA 

does not require further informal consultation or the initiation of formal consultation with the 

FWS for the proposed license renewal. 

ESA regulations at 50 CFR 402.12(f)(4) direct Federal agencies to consider cumulative effects 

as part of the proposed action effects analysis. Under the ESA, cumulative effects are defined 

as “those effects of future State or private activities, not involving Federal activities, that are 

reasonably certain to occur within the action area of the Federal action subject to consultation”

(50 CFR 402.02). Unlike the NEPA definition of cumulative impacts (see Section 4.16), 

cumulative effects under the ESA do not include past actions or other Federal actions requiring 

separate ESA section 7 consultation. When formulating biological opinions under formal 

section 7 consultation, the FWS and the National Marine Fisheries Service (NMFS) (FWS and 

NMFS 1998) consider cumulative effects when determining the likelihood of jeopardy or adverse 

modification. Therefore, consideration of cumulative effects under the ESA is necessary only if 

listed species will be adversely affected by the proposed action (FWS 2014). Since the NRC 

staff concludes that no species would be adversely affected by license renewal, the NRC staff 

did not assess cumulative effects.

Reporting Requirements

If in the future, a Federally listed species is observed on the LSCS site, the NRC has measures 

in place to ensure that NRC staff would be appropriately notified so that the NRC staff could 

determine the appropriate course of action. If the renewed licenses have not yet been issued, 

the NRC’s response could include the initiation of consultation pursuant to section 7 of the ESA.

LSCS’s Unit 1 and Unit 2 operating licenses, Appendix B, “Environmental Protection Plan”

(see NRC 2001), require Exelon to report to the NRC within 24 hours any “unusual or important 

event” that indicates or could result in significant environmental impact causally related to plant 

operation. The licenses give the specific example of “mortality or unusual occurrence of any 

species protected by the Endangered Species Act of 1973.” Additionally, the NRC’s regulations 

containing notification requirements require that operating nuclear power reactors report to the 

NRC within 4 hours “any event or situation, related to...protection of the environment, for which 

a news release is planned or notification to other government agencies has been or will be 

made” (10 CFR 50.72(b)(2)(xi)). Such notifications include reports regarding Federally listed 

species, as described in Section 3.2.12 of NUREG–1022, “Event Reporting Guidelines for 

10 CFR 50.72 and 50.73” (NRC 2013b). 

Special Status Species and Habitats Impacts Summary

Table 4–9 summarizes the NRC staff’s findings. 
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Table 4–9. Federally Listed Species and Designated Habitat in LaSalle County, Illinois, 

and NRC Effect Determinations for Proposed LSCS License Renewal

Group

Federally Listed 

Species Common Name

Federal 

Status(a) Determination

Clams and Mussels Plethobasus cyphyus sheepnose mussel E no effect

Flowering Plants Boltonia decurrens decurrent false aster T no effect

Platanthera leucophaea eastern prairie fringed 

orchid

T no effect

Delea foliosa leafy prairie clover E no effect

Mammals Myotis sodalis Indiana bat E no effect

Myotis septentrionalis northern long-eared bat T no effect

Critical Habitat

Myotis sodalis Indiana bat no effect

(a) E=endangered; T=threatened

Sources: FWS 2015a, 2015b

4.8.2 No-Action Alternative

Under the no-action alternative, the plant would shut down. Federally listed species and 

designated critical habitat can be affected not only by operation of nuclear power plants but also 

by activities during shutdown. The ESA action area for the no-action alternative would most 

likely be the same as discussed in Section 3.8. The plant would require substantially less 

cooling water, so potential impacts to aquatic species and habitats discussed in Section 4.8.1 

would be reduced, although the plant would still require some cooling water for some time. 

Changes in land use and other shutdown activities might affect terrestrial species differently 

than under continued operation.

Typically, the effects on ESA-listed aquatic species would be smaller than the effects under 

continued operation but would depend on the listed species and habitats present if shutdown 

were to occur. The types and magnitudes of adverse impacts to terrestrial ESA-listed species 

would depend on the shutdown activities and the listed species and habitats present when the 

alternative is implemented. Therefore, the NRC cannot forecast a particular level of impact for 

this alternative.

4.8.3 New Nuclear Alternative

This alternative entails shutdown and decommissioning of LSCS and construction of a new 

nuclear unit at an alternative industrial location, possibly in Indiana, Iowa, Michigan, Missouri, 

Kentucky, or Wisconsin. Section 4.8.2 discusses ESA considerations for the shutdown of 

LSCS.

Because the new nuclear alternative would be built on an existing power plant site outside of 

Illinois, which has restrictions on new nuclear power plant construction, the special status 

species and habitats affected by the action would be different than those considered under the 

proposed action. Because the NRC would be the licensing agency under this alternative, the 

ESA would require the NRC to initiate consultation with FWS and NMFS, as applicable, prior to 

construction to ensure that the construction and operation of the new nuclear plant would not be 
Environmental Consequences and Mitigating Actions

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likely to jeopardize the continued existence of any Federally listed species or result in the 

destruction of designated critical habitat. Section 4.8.2 discusses general ESA considerations.

In the unlikely event that the new nuclear plant is sited in an area that could affect water bodies 

with designated essential fish habitat (EFH), which applies only to certain commercially 

harvested marine and anadromous fish species, consultation with NMFS under the MSA would 

be required to assess potential impacts to that habitat. 

Because the types and magnitudes of adverse impacts to listed species would depend on the 

proposed site, plant design, operation, and species and habitats listed when the alternative is 

implemented, the NRC cannot forecast a particular level of impact for this alternative.

4.8.4 IGCC Alternative

This alternative entails shutdown and decommissioning of LSCS and construction of a new 

IGCC facility at either the LSCS site or an alternative industrial location. Section 4.8.2 

discusses ESA considerations for the shutdown of LSCS.

Unlike the new nuclear alternative, the NRC does not license IGCC facilities, and the NRC 

would not be responsible for initiating ESA section 7 consultation if listed species or habitats 

might be adversely affected under this alternative. If no other federal agency was involved in 

licensing the facilities, the facilities themselves would be responsible for protecting listed 

species because the ESA forbids the “take” of a listed species, where “take” means “harass, 

harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such 

conduct.”

If the IGCC alternative were to be built on the LSCS site, the ESA action area might still be 

different because the activities and structures associated with the construction and operations of 

an IGCC plant would be different than those described under the continued operation of LSCS. 

If the IGCC alternative were to be built at a site other than the LSCS site, the listed species and 

habitats affected by the action would be different than those identified for LSCS. 

Because the types and magnitudes of adverse impacts to -listed species would depend on the 

proposed site, plant design, operation, and species and habitats listed when the alternative is 

implemented, the NRC cannot forecast a particular level of impact for this alternative.

4.8.5 NGCC Alternative

This alternative entails the shutdown and decommissioning of LSCS and construction of a new 

NGCC facility at either the LSCS site or an alternative industrial location. Section 4.8.2 

discusses ESA considerations for the shutdown of LSCS.

Unlike the new nuclear alternative, the NRC does not license NGCC facilities, and the NRC 

would not be responsible for initiating ESA section 7 consultation if listed species or habitats 

might be adversely affected under this alternative. If no other federal agency was involved in 

licensing the facilities, the facilities themselves would be responsible for protecting listed 

species because the ESA forbids the “take” of a listed species, where “take” means “harass, 

harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such 

conduct.”

If the NGCC alternative were to be built on the LSCS site, the ESA action area might still be 

different because the activities and structures associated with the construction and operations of 

an NGCC plant would be different than those described under the continued operation of LSCS. 

If the NGCC alternative were to be built at a site other than the LSCS site, the listed species and 

habitats affected by the action would be different than those identified for LSCS. 
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Because the types and magnitudes of adverse impacts to listed species would depend on the 

proposed site, plant design, operation, and species and habitats listed when the alternative is 

implemented, the NRC cannot forecast a particular level of impact for this alternative.

4.8.6 Combination Alternative (NGCC, Wind, Solar)

This alternative entails the shutdown and decommissioning of LSCS and construction of new 

non-nuclear facilities at the LSCS site and alternative industrial locations. Section 4.8.2 

discusses ESA considerations for the shutdown of LSCS.

The combination alternative would involve construction and operation of wind turbines and solar 

PV systems throughout the ROI, as well as an NGCC plant at the LSCS site. Unlike the new 

nuclear alternative, the NRC does not license NGCC, wind, or solar facilities, and the NRC 

would not be responsible for initiating ESA section 7 consultation if listed species or habitats 

might be adversely affected under this alternative. If no other federal agency was involved in 

licensing the facilities, the facilities themselves would be responsible for protecting listed 

species because the ESA forbids the “take” of a listed species, where “take” means “harass, 

harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such 

conduct.”

Even though the NGCC portion of the combination alternative would be located on the LSCS

site, the ESA action area might be different because the activities and structures associated 

with the construction and operations of the NGCC portion of the combination alternative would 

be different than those described under the continued operation of LSCS. Since the wind and 

solar parts of the combination alternative would be located on a site or sites other than the 

LSCS site, the listed species and habitats affected by the action would be different than those 

identified for LSCS. 

Because the types and magnitudes of adverse impacts to listed species would depend on the 

proposed site, wind and solar component designs, operation, and species and habitats listed 

when the alternative is implemented, the NRC cannot forecast a particular level of impact for 

this alternative.

4.8.7 Purchased Power Alternative

Because the purchased power alternative might include a mixture of coal, natural gas, nuclear, 

and wind across many different sites in the ROI, the special status species and habitats affected 

by the action would be different than those considered under continued operation. Because the 

types and magnitudes of adverse impacts to listed species would depend on the proposed sites, 

plant designs, operation, and species and habitats listed at the various sites when the 

alternative is implemented, the NRC cannot forecast a particular level of impact for this 

alternative. As with the other alternatives discussed previously, the facilities themselves, or a 

different federal regulator, but not the NRC, would be responsible for initiating ESA section 7 

consultation if listed species or habitats might be adversely affected under this alternative.

4.9 Historic and Cultural Resources

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on historic and cultural resources.
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4.9.1 Proposed Action

Section 3.9 describes the historic and cultural resources that have the potential to be affected 

by the proposed action. Table 4–10 identifies the historic and cultural resource issue applicable 

to LSCS during the license renewal term. 

Table 4–10. Historic and Cultural Resources Issue

Issue GEIS Section Category

Historic and cultural resources 4.7.1 2

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

The National Historic Preservation Act of 1966, as amended (54 USC 300101 et seq. (NHPA)) 

requires Federal agencies to consider the effects of their undertakings on historic properties, 

and renewing the operating license of a nuclear power plant is an undertaking that could 

potentially affect historic properties. Historic properties are defined as resources eligible for 

listing in the National Register of Historic Places (NRHP). The criteria for eligibility are listed in 

36 CFR 60.4, and include: (1) association with significant events in history, (2) association with 

the lives of persons significant in the past, (3) embodiment of distinctive characteristics of a 

type, period, or method of construction, and (4) sites or places that have yielded, or are likely to 

yield, important information.

The historic preservation review process (Section 106 of the NHPA) is outlined in regulations 

issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800.

In accordance with the provisions of the NHPA, the NRC is required to make a reasonable effort 

to identify historic properties included in or eligible for inclusion in the NRHP in the Area of 

Potential Effect (APE). The APE for a license renewal action is the area at the power plant site, 

the transmission lines up to the first substation and immediate environs that may be affected by 

the license renewal decision, and land-disturbing activities associated with continued reactor

operations. For LSCS, the first substation is located on site at the 345-kV LSCS Station 

switchyard. Additionally, LSCS property containing the makeup and blowdown piping from the 

cooling lake to the Illinois River are included in the APE (Exelon 2014a).

If historic properties are present within the APE, the NRC is required to contact the State 

Historic Preservation Office (SHPO), assess the potential impact, and resolve any possible 

adverse effects of the undertaking (license renewal) on historic properties. In addition, the NRC 

is required to notify the SHPO if historic properties would not be affected by license renewal or if 

no historic properties are present. The SHPO is part of the Illinois Historic Preservation Agency 

(IHPA).

Consultation

In accordance with 36 CFR 800.8(c), on February 9, 2015, the NRC initiated consultations on 

the proposed action by writing to the ACHP and IHPA (NRC 2015c, 2015d). Also on 

February 9, 2015, the NRC initiated consultation with the following 14 Federally recognized 

Tribes (NRC 2015e) (see Appendix C for a list of these letters):

• Ho-Chunk Nation,

• Miami Tribe of Oklahoma,

• Peoria Tribe of Indians of Oklahoma,
Environmental Consequences and Mitigating Actions

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• Citizen Potawatomi Nation,

• Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki,

• Sac and Fox Nation of Missouri in Kansas and Nebraska,

• Sac and Fox Nation,

• Pokagon Band of Potawatomi,

• Forest County Potawatomi,

• Hannahville Indian Community, Band of Potawatomi,

• Prairie Band of Potawatomi Nation,

• Winnebago Tribe of Nebraska,

• Kickapoo Tribe in Kansas, and

• Kickapoo Tribe of Oklahoma.

By letter, the NRC provided information about the proposed action, defined the APE, and 

indicated that the NHPA review would be integrated with the NEPA process, according to 

36 CFR 800.8(c). The NRC invited participation in the identification and possible decisions 

concerning historic properties and also invited participation in the scoping process. The NRC 

received no scoping comments from any of the tribes contacted. In April 2015, the NRC 

received a determination from the IHPA stating no objection to the undertaking and that no 

historic properties would be affected (Leibowitz 2015) (see Appendix C). The NRC met with the 

Illinois SHPO in May 2015. The Illinois SHPO did not express any concerns about the proposed 

LSCS license renewal during the meeting (NRC 2015f).

Exelon currently has no planned physical changes or license-renewal-related refurbishment

activities at the LSCS site. Any future ground-disturbing activities at the LSCS site will be done 

in accordance with established LSCS procedures to determine whether the proposed activities 

will impact known or potential cultural and historic resources (Exelon 2015b). Exelon would 

consult with the SHPO, if necessary, to determine what measures would be needed to minimize 

and mitigate the impacts (Exelon 2014a). Supplemental cultural resource surveys may be 

performed of the affected areas based on consultation with the SHPO. As described in 

Section 3.9, there are no historic properties or known NRHP-eligible historic or cultural 

resources located within the LSCS APE. Exelon has established a draft Cultural Resource 

Management Plan (CRMP) to help ensure historic and cultural resources are considered prior to 

ground-disturbing activities. The CRMP instructs Exelon’s staff on how to evaluate land 

disturbing activity for possible impacts to historic and cultural resources and identifies previously 

disturbed areas of the LSCS property and any areas with the potential to contain undiscovered 

resources (Exelon 2015b). Additionally, Exelon has established procedures in the event that 

historic or cultural resources are inadvertently discovered during operational activities. These 

procedures direct the Exelon staff to stop work, protect exposed resources, and contact Exelon 

environmental personnel to take appropriate action (Exelon 2015b). Cultural resource training 

is not currently required for LSCS staff members (Exelon 2015b).

The NRC staff concludes that license renewal would not affect any known historic properties 

(36 CFR Section 800.4(d)(1)) based on (1) no current NRHP-eligible historic properties in the 

APE, (2) tribal input, (3) Exelon’s draft CRMP, (4) no current plan for license-renewal-related 

physical changes or ground-disturbing activities, (5) IHPA input, and (6) cultural resource

assessment. The NRC staff notes that Exelon could reduce the risk of potential impacts to 

historic and cultural resources located on or near the LSCS site by finalizing its draft CRMP, 
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with input from the SHPO, and by providing training on cultural resources for Exelon’s staff 

engaged in planning and executing ground-disturbing activities.

4.9.2 No-Action Alternative

Not renewing the operating licenses and terminating reactor operations would have no effect on 

historic properties and cultural resources within the site boundaries of LSCS. Therefore, the 

NRC staff concludes that the impacts on historic and cultural resources from the no-action

alternative would be SMALL.

4.9.3 New Nuclear Alternative

Any land areas potentially affected by the construction of the new nuclear alternative power 

plant would need to be surveyed to identify and record historic and archaeological cultural 

resources. An inventory of a previously disturbed former plant industrial site may still be 

necessary if the site has not been previously surveyed or to verify the level of previous 

disturbance and to evaluate the potential for intact subsurface cultural resources to be present. 

Power plant developers would need to survey all potentially affected land areas associated with 

operation of the alternative (e.g., land required for new roads, transmission corridors, other 

ROWs). Any cultural resources found during these surveys would need to be recorded and 

evaluated for eligibility for listing on the NRHP. Mitigation of adverse effects would need to be 

considered if eligible resources properties were encountered. Areas with the greatest sensitivity 

and most significant cultural resources should be avoided. Visual impacts on significant cultural 

resources, such as the historic property viewsheds near the proposed power plant site, should 

also be assessed and evaluated.

The potential for impacts to historic and cultural resources from the new nuclear alternative 

would vary greatly, depending on the location of the site selected for the proposed new nuclear 

power plant site. Cooling towers could impact historic property viewsheds. However, given the 

preference to use a previously disturbed former power plant site, avoidance of undisturbed land 

could further reduce potential impacts to historic and cultural resources. The NRC staff 

concludes that the impacts on historic and cultural resources from the construction and 

operation of a new nuclear alternative power plant would be SMALL.

4.9.4 IGCC Alternative

Any areas potentially affected by the construction of the IGCC alternative may need to be 

surveyed to identify and record historic and cultural resources if a Federal undertaking under 

NHPA is present. If the IGCC alternative is located on the existing LSCS site, previously 

disturbed areas known to not contain historic and cultural resources could be used. If the 

alternative is sited on the approximately 350 ac (142 ha) of undeveloped land on the LSCS site, 

a survey and inventory for potential historic and cultural resources may need to be performed. If 

the IGCC power plant is sited at an existing power plant site other than LSCS and a Federal 

undertaking under NHPA is present, a cultural resource survey may still be necessary if the site 

has not been previously surveyed or to verify the level of disturbance and evaluate the potential 

for intact subsurface resources. Any resources found in these surveys would need to be 

evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be 

addressed if eligible resources were encountered. Areas with the greatest sensitivity should be 

avoided. Visual impacts on significant cultural resources, such as the historic property 

viewshed of historic properties near the proposed power plant site, should also be assessed 

and evaluated.
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The potential for impacts on historic and cultural resources from the IGCC alternative would 

vary greatly depending on the location of the proposed site. Given that the preference is to use 

a previously disturbed former plant site and no major infrastructure upgrades are necessary, 

avoidance of significant historic and cultural resources should be possible and effectively 

managed under current laws and regulations. The NRC staff concludes that the impacts on 

historic and archaeological resources from the IGCC alternative would be SMALL.

4.9.5 NGCC Alternative

Any areas potentially affected by the construction and operation of an NGCC power plant may 

need to be surveyed to identify and record historic and cultural resources if a Federal 

undertaking under NHPA is present. If the NGCC power plant is constructed at the existing 

LSCS site, previously disturbed areas known to not contain historic and cultural resources could 

be used. If the power plant is sited on the approximately 350 ac (142 ha) of undeveloped land 

on the LSCS site and a Federal undertaking under NHPA is present, a survey and inventory of 

potential historic and cultural resources would need to be performed. Additionally, plant 

operators would need to survey all areas associated with the alternative (e.g., a new pipeline, 

roads, transmission corridors, other ROWs). Any resources found in these surveys would need 

to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be 

addressed if eligible resources were encountered. Areas with the greatest sensitivity should be 

avoided. Visual impacts on significant cultural resources, such as the viewsheds of historic 

properties near the proposed power plant site, should also be assessed and evaluated.

Given that the NGCC alternative is assumed to be sited at LSCS, avoidance of significant 

historic and cultural resources should be possible. However, historic and archaeological

resources could potentially be affected, depending on the resource richness of the land required 

for a new gas pipeline; but, as with the plant site itself, avoidance of significant historic and 

cultural resources should be possible and effectively managed under current laws and 

regulations. The NRC staff concludes that the impacts on historic and cultural resources from 

the NGCC alternative would be SMALL.

4.9.6 Combination Alternative (NGCC, Wind, Solar)

Areas potentially affected by the construction of the NGCC, wind, and solar alternative may 

need to be surveyed to identify and record historic and archaeological resources if a Federal 

undertaking under NHPA is present. Any resources found in these surveys would need to be 

evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be 

addressed if eligible resources were encountered. 

Impacts to historic and cultural resources from the NGCC portion of this alternative are similar to 

the NGCC alternative in Section 4.9.5. The potential for impacts on historic and cultural 

resources from the wind portion of this alternative would vary greatly, depending on the location 

of the proposed sites. Areas with the greatest sensitivity could be avoided or effectively 

managed under current laws and regulations. However, construction of wind farms and their 

support infrastructure have the potential to notably impact historic and archaeological resources

because of earthmoving activities (e.g., grading and digging) and the aesthetic changes they 

may bring to the viewshed of historic properties located nearby. The impacts of the construction 

of a new solar alternative on historic and cultural resources will vary, depending on the form of 

the solar capacity installed. Rooftop installations minimize land disturbance and the 

modifications necessary to the transmission system, thereby minimizing impacts to historic and 

cultural resources. Land-based installations are larger than rooftop installations and will require 

some degree of land disturbance for installation purposes, potentially causing greater impacts to 
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historic and archaeological resources. Aesthetic changes caused by the installation of both 

forms could have a noticeable effect on the viewshed of nearby historic properties. Using 

previously disturbed sites for land-based installations and collocating any new transmission 

lines with existing ROWs could minimize impacts to historic and archaeological resources. 

Areas with the greatest sensitivity could be avoided or effectively managed under current laws 

and regulations. The NRC staff concludes that, depending on the resource richness of the sites 

chosen for the NGCC, wind, and solar alternative, the impacts could range from SMALL to 

LARGE.

4.9.7 Purchased Power Alternative

No direct impacts on historic and cultural resources are expected from purchased power. If new 

transmission lines were needed to convey power to the PJM Interconnection area, surveys 

similar to those discussed in Section 4.9.3 may need to be performed if a Federal undertaking 

under NHPA is present. However, transmission lines would likely be collocated with existing 

ROWs, minimizing any impacts to historic and cultural resources.

Indirectly, construction of new nuclear, coal-fired, and natural-gas-fired plants, or wind energy 

projects, and any new transmission lines to support increased demand in the purchased power 

alternative could affect historic and cultural resources. If the amount of purchased power 

exceeds the available supply, new electrical power generating facilities may be needed. Any 

areas potentially affected by construction may need to be surveyed to identify and record 

historic and cultural resources if a Federal undertaking under NHPA is present. Resources 

found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of 

adverse effects would need to be addressed if eligible resources were encountered. Plant 

operators would need to survey all areas associated with operation of the alternative 

(e.g., roads, transmission corridors, other ROWs). The potential for impacts on historic and 

cultural resources would vary greatly, depending on the location of the proposed sites; however, 

using previously disturbed sites could greatly minimize impacts to historic and cultural 

resources. Areas with the greatest sensitivity could be avoided or effectively managed under 

current laws and regulations. The NRC staff concludes that, depending on the resource 

richness of the sites chosen, the impacts on historic and cultural resources could range from 

SMALL to LARGE.

4.10 Socioeconomics

This section describes the potential socioeconomic impacts of the proposed action (license 

renewal) and alternatives to the proposed action.

4.10.1 Proposed Action

Socioeconomic effects of ongoing reactor operations at LSCS have become well established as 

regional socioeconomic conditions have adjusted to the presence of the nuclear power plant. 

These conditions are described in Section 3.10. Any changes in employment and tax payments 

caused by license renewal and any associated refurbishment activities could have a direct and 

indirect impact on community services and housing demand, as well as traffic volumes in the 

communities around a nuclear power plant.

Table 4–11 identifies the socioeconomic NEPA issues from Table B–1 in Appendix B to 

Subpart A of 10 CFR Part 51, applicable to LSCS during the license renewal term.
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Table 4–11. Socioeconomic NEPA Issues Affected by License Renewal

Issue GEIS Sections Category

Employment and income, recreation and tourism 4.8.1.1 1

Tax revenues 4.8.1.2 1

Community services and education 4.8.1.3 1

Population and housing 4.8.1.4 1

Transportation 4.8.1.5 1

Source: Table B–1 in Appendix B, Subpart A of 10 CFR Part 51

The supplemental site-specific socioeconomic impact analysis for the license renewal of LSCS

included a review of Exelon’s ER, scoping comments, other information records, and a 

data-gathering site visit to LSCS. The NRC staff did not identify any new and significant 

information during the review that would result in impacts that would exceed the predicted 

socioeconomic impacts evaluated in the GEIS, and no additional socioeconomic NEPA issues 

were identified beyond those listed in Table B–1.

In addition, Exelon indicated in its ER that it has no plans to add non-outage workers during the 

license renewal term and that increased maintenance and inspection activities could be 

managed using the current workforce. Consequently, people living in the vicinity of LSCS are 

not likely to experience any changes in socioeconomic conditions during the license renewal 

term beyond what is currently being experienced. Therefore, the impact of continued reactor

operations during the license renewal term would not exceed the socioeconomic impacts 

predicted in the GEIS. For these issues, the GEIS predicted that the impacts would be SMALL 

for all nuclear plants.

4.10.2 No-Action Alternative

4.10.2.1 Socioeconomics

Not renewing the operating license and terminating reactor operations would have a noticeable 

impact on socioeconomic conditions in the communities located near LSCS. The loss of jobs 

and income would have an immediate socioeconomic impact. Some, but not all, of the 

approximately 890 employees would begin to leave after reactor operations are terminated, and 

overall tax revenue generated by plant operations would be reduced (Exelon 2014a). Exelon 

pays annual property taxes to various entities to partially fund their respective operating 

budgets. The property tax revenue is used to fund public schools, libraries, county and local 

township operations, and other services. The loss of tax revenue could reduce or eliminate 

some public and educational services. Indirect employment and income generated by power 

plant operations would also be reduced.

Former LSCS workers and their families could leave in search of employment elsewhere. The 

increase in available housing along with decreased demand could cause housing prices to fall. 

Since the majority of employees reside in LaSalle and Grundy Counties, socioeconomic impacts 

from the termination of reactor operations would be concentrated in these counties, with a 

corresponding reduction in purchasing activity and tax revenue in the regional economy. 

Income and revenue losses from the termination of reactor operations at LSCS would directly 

affect LaSalle County and nearby communities most reliant on income from power plant 

operations. The impact of the job loss, however, may not be as noticeable in local communities,

given the amount of time required for decommissioning. The socioeconomic impacts from the 
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termination of nuclear plant operations (which would not entirely cease until after 

decommissioning) would, depending on the jurisdiction, range from SMALL to LARGE.

4.10.2.2 Transportation 

Traffic congestion caused by commuting workers and truck deliveries on roads in the vicinity of 

LSCS would be reduced after power plant shutdown. Most of the reduction in traffic volume 

would be associated with the loss of jobs. The number of truck deliveries to LSCS would be 

reduced until decommissioning. Traffic-related transportation impacts would be SMALL as a 

result of the shutdown of the nuclear power plant.

4.10.3 New Nuclear Alternative

4.10.3.1 Socioeconomics 

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 power plant could affect regional employment, income, and 

expenditures.

Two types of jobs would be created by this alternative: (1) construction jobs, which are 

transient, short in duration, and less likely to have a long-term socioeconomic impact, and 

(2) power plant operations jobs, which have the greater potential for permanent, long-term 

socioeconomic impacts. Workforce requirements for the construction and operation of a new 

nuclear power plant were evaluated to measure their possible effects on current socioeconomic 

conditions.

The construction workforce could peak at 3,500 workers (NRC 2008a). The relative economic 

effect of this many workers on the local economy and tax base would vary, with the greatest 

impacts occurring in the communities where the majority of construction workers would reside 

and spend their income. As a result, local communities could experience a short-term economic 

“boom” from increased tax revenue and income generated by construction expenditures and the 

increased demand for temporary (rental) housing and public as well as commercial services.

After construction, local communities could experience a return to preconstruction economic 

conditions. Based on this information and given the number of workers, socioeconomic impacts 

during construction in communities near an existing nuclear power plant or retired coal site 

could range from MODERATE to LARGE.

Approximately 800 workers would be required during nuclear power plant operations 

(NRC 2008a). Some LSCS operations workers could transfer to the new nuclear power plant. 

Local communities near the new nuclear power plant would experience the economic benefits 

from increased tax revenue and income generated by operational expenditures and demand for 

housing and public as well as commercial services. The amount of property tax payments 

under the new nuclear alternative may also increase if additional land is required to support this 

alternative.

This alternative would also result in a loss of approximately 890 relatively high-paying jobs at 

LSCS and a corresponding reduction in purchasing activity and revenue contributions to the 

regional economy. Should LSCS cease operations, there would be an immediate 

socioeconomic impact to local communities and businesses from the loss of jobs (some, but not 

all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, 

the housing market could experience increased vacancies and decreased prices if operations 

workers and their families move out of the region. The impact of the job loss, however, may not 

be noticeable in local communities, given the amount of time required for decommissioning of 
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the existing LSCS facilities. Based on this information and given the number of operations 

workers, socioeconomic impacts during nuclear power plant operations on local communities 

could range from SMALL to MODERATE.

4.10.3.2 Transportation

Transportation impacts associated with construction and operation of a new nuclear power plant 

would consist of commuting workers and truck deliveries of construction materials to the power 

plant site. During periods of peak construction activity, up to 3,500 workers could be commuting 

daily to the construction site (NRC 2008a). Workers commuting to the construction site would 

arrive via site access roads and the volume of traffic on nearby roads could increase 

substantially during shift changes. In addition to commuting workers, trucks would be 

transporting construction materials and equipment to the work site, thereby increasing the 

amount of traffic on local roads. The increase in vehicular traffic would peak during shift 

changes, resulting in temporary levels of service impacts and delays at intersections. Materials 

could also be delivered by rail or barge, depending on the location. Traffic-related 

transportation impacts during construction would likely range from MODERATE to LARGE.

Traffic-related transportation impacts on local roads would be greatly reduced after the 

completion of the power plant. Approximately 800 operations workers would be commuting 

daily to the new nuclear power plant site (NRC 2008a). Transportation impacts would include 

daily commuting by the operating workforce, material deliveries, and the removal of commercial 

waste material to offsite disposal or recycling facilities by truck. Traffic on roadways would peak 

during shift changes and refueling outages, resulting in temporary levels of service impacts and 

delays at intersections. Overall, at the new nuclear power plant site, transportation impacts 

would be SMALL to MODERATE during operations.

4.10.4 IGCC Alternative 

4.10.4.1 Socioeconomics

As explained in Section 4.10.3, two types of jobs would be created by this alternative: 

(1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for 

permanent, long-term socioeconomic impacts. Workforce requirements for the construction and 

operation of a new IGCC power plant were evaluated to measure their possible effects on 

current socioeconomic conditions.

The construction workforce could peak at 4,600 workers (DOE 2010a). The relative economic 

effect of this many workers on the local economy and tax base would vary, with the greatest 

impacts occurring in the communities where the majority of construction workers would reside 

and spend their income. As a result, local communities could experience a short-term economic 

“boom” from increased tax revenue and income generated by construction expenditures and the 

increased demand for temporary (rental) housing and public as well as commercial services.

After construction, local communities could experience a return to preconstruction economic 

conditions. Based on this information and given the number of workers, socioeconomic impacts 

during construction in communities near an existing power plant site could range from 

MODERATE to LARGE.

An estimated 420 workers would be required during power plant operations (DOE 2010a). 

Local communities would experience the economic benefits from increased tax revenue and 

income generated by operational expenditures and demand for housing and public as well as 

commercial services. The amount of property tax payments under the IGCC alternative may 

also increase if additional land is required to support this alternative.
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This alternative would also result in a loss of approximately 890 relatively high-paying jobs at 

LSCS and a corresponding reduction in purchasing activity and revenue contributions to the 

regional economy. Should LSCS cease operations, there would be an immediate 

socioeconomic impact to local communities and businesses from the loss of jobs (some, but not 

all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, 

the housing market could experience increased vacancies and decreased prices if operations 

workers and their families move out of the region. The impact of the job loss, however, may not 

be noticeable in local communities, given the amount of time required for decommissioning the 

existing LSCS facilities. Based on this information and given the number of operations workers, 

socioeconomic impacts during IGCC power plant operations on local communities could range 

from SMALL to MODERATE.

4.10.4.2 Transportation

Transportation impacts associated with construction and operation of the two-unit, IGCC power 

plant would consist of commuting workers and truck deliveries of construction materials to the 

power plant site. During periods of peak construction activity, up to 4,600 workers could be 

commuting daily to the construction site. Workers commuting to the construction site would 

arrive via site access roads, and the volume of traffic on nearby roads could increase 

substantially during shift changes. In addition to commuting workers, trucks would be 

transporting construction materials and equipment to the work site, thereby increasing the 

amount of traffic on local roads. The increase in vehicular traffic would peak during shift 

changes, resulting in temporary levels of service impacts and delays at intersections. Materials 

could also be delivered by rail or barge, depending on location. Traffic-related transportation 

impacts during construction would likely range from MODERATE to LARGE.

Traffic-related transportation impacts on local roads would be greatly reduced after the 

completion of the power plant. The estimated maximum number of operations workers 

commuting daily to the power plant site could be 420 (DOE 2010a). Fewer workers would be 

required if multiple units are operated at the same site. Frequent coal and limestone deliveries 

and ash removal by rail would add to the overall transportation impact. The increase in traffic 

on roadways would peak during shift changes, resulting in temporary levels of service impacts 

and delays at intersections. Onsite coal storage would make it possible to receive several trains 

per day at a site with rail access. If the IGCC power plant is located on navigable waters, coal 

and other materials could be delivered by barge. Coal and limestone delivery and ash removal 

via rail would cause levels of service impacts due to delays at railroad crossings. Overall, 

transportation impacts would be SMALL to MODERATE during IGCC power plant operations.

4.10.5 NGCC Alternative

4.10.5.1 Socioeconomics

As explained in Section 4.10.3, two types of jobs would be created by this alternative: 

(1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for 

permanent, long-term socioeconomic impacts. Workforce requirements for the construction and 

operation of a new NGCC power plant were evaluated to measure their possible effects on 

current socioeconomic conditions.

The construction workforce could peak at 1,783 workers (Exelon 2014a). The relative economic 

effect of this many workers on the local economy and tax base would vary, with the greatest 

impacts occurring in the communities where the majority of construction workers would reside 

and spend their income. As a result, local communities could experience a short-term economic 
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“boom” from increased tax revenue and income generated by construction expenditures and the 

increased demand for temporary (rental) housing and public as well as commercial services.

After construction, local communities could experience a return to preconstruction economic 

conditions. Based on this information and given the number of workers, socioeconomic impacts 

during construction in communities near an existing power plant site could range from 

MODERATE to LARGE.

An estimated 94 workers would be required during power plant operations (Exelon 2014a). 

Local communities would experience the economic benefits from increased tax revenue and 

income generated by operational expenditures and demand for housing and public as well as 

commercial services. The amount of property tax payments under the NGCC alternative may 

also increase if additional land is required to support this alternative.

This alternative would also result in a loss of approximately 890 relatively high-paying jobs at 

LSCS and a corresponding reduction in purchasing activity and revenue contributions to the 

regional economy. Should LSCS cease operations, there would be an immediate 

socioeconomic impact to local communities and businesses from the loss of jobs (some, but not 

all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, 

the housing market could experience increased vacancies and decreased prices if operations 

workers and their families move out of the region. The impact of the job loss, however, may not 

be noticeable in local communities given the amount of time required for decommissioning the 

existing LSCS facilities. Based on this information and given the number of operations workers, 

socioeconomic impacts during NGCC power plant operations on local communities could range 

from SMALL to MODERATE.

4.10.5.2 Transportation 

Transportation impacts associated with construction and operation of a five-unit, NGCC power 

plant would consist of commuting workers and truck deliveries of construction materials to the 

power plant site. During periods of peak construction activity, up to 1,783 workers could be 

commuting daily to the construction site. Workers commuting to the construction site would 

arrive via site access roads, and the volume of traffic on nearby roads could increase 

substantially during shift changes. In addition to commuting workers, trucks would be 

transporting construction materials and equipment to the work site, thus increasing the amount 

of traffic on local roads. 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 of existing natural gas pipeline systems could also have a 

temporary impact. Materials also could be delivered by barge or rail, depending on location. 

Traffic-related transportation impacts during construction would likely range from MODERATE 

to LARGE.

Traffic-related transportation impacts would be greatly reduced after completing the installation 

of the NGCC alternative. Transportation impacts would include daily commuting by the 

operating workforce, equipment and materials deliveries, and the removal of commercial waste 

material to offsite disposal or recycling facilities by truck. The operations workforce of 

94 workers would likely not be noticeable relative to total traffic volumes on local roadways. 

Since fuel is transported by pipeline, the transportation infrastructure would experience little to 

no increased traffic from plant operations. Overall, given the relatively small operations 

workforce estimate of 94 workers, transportation impacts would be SMALL during power plant 

operations.
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4.10.6 Combination Alternative (NGCC, Wind, Solar)

4.10.6.1 Socioeconomics 

As explained in Section 4.10.3, two types of jobs would be created by this alternative: 

(1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

socioeconomic impact, and (2) operations jobs, which have the greater potential for permanent, 

long-term socioeconomic impacts. Workforce requirements for the construction and operation 

of the NGCC, wind, and solar generation components of this combination alternative were 

evaluated to estimate their possible effects on current socioeconomic conditions.

Fewer workers would be required to construct the single NGCC unit at the LSCS site than the 

full-power NGCC alternative. Installation of an estimated 3,376 wind turbines would likely be 

done in stages and could require up to 931 construction workers (NREL 2013). Additional 

workers would be required to install solar PV systems on existing buildings or structures at 

already-developed residential, commercial, or industrial sites. Similar to the wind farms, 

installation would likely be done in stages and could require up to 600 construction workers 

(DOE 2010b).

Conversely, a small number of operations workers would be needed to operate the single 

NGCC unit and additional small numbers of workers would be required to maintain the wind 

farms and PV systems. Local communities could experience the economic benefits from 

increased tax revenue and income generated by operational expenditures and demand for 

housing and public as well as commercial services. The amount of property tax payments 

under the wind and solar PV components may also increase if additional land is required to 

support this combination alternative.

This combination alternative would also result in a loss of approximately 890 relatively 

high-paying jobs at LSCS, and a corresponding reduction in purchasing activity, tax payments, 

and revenue contributions would occur in the surrounding regional economy. Should LSCS 

cease operations, there would be an immediate socioeconomic impact to local communities and 

businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), 

and tax payments may be reduced. In addition, the housing market could experience increased 

vacancies and decreased prices if operations workers and their families move out of the region. 

The impact of the job loss, however, may not be noticeable in local communities, given the 

amount of time required for decommissioning of the existing LSCS facilities. Based on this 

information and given the relatively small numbers of construction and operations workers, 

socioeconomic impacts during construction and operations on local communities would be 

SMALL.

4.10.6.2 Transportation 

Transportation impacts during the construction and operation of the NGCC unit as well as the 

wind and solar components of this combination alternative would be less than the impacts for 

any of the previous alternatives discussed. This is because the construction workforce for each 

component and the volume of materials and equipment needing to be transported to the

respective construction site would be smaller than for any one of the individual replacement 

power alternatives. In other words, the transportation impacts would not be concentrated as in 

the other alternatives but spread out over a wider area.

Workers commuting to the construction site would arrive via site access roads, and the volume 

of traffic on nearby roads could increase during shift changes. In addition to commuting 

workers, trucks would be transporting construction materials and equipment to the work site, 

thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would 

peak during shift changes, resulting in temporary levels of service impacts and delays at 
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intersections. Transporting heavy and oversized components on local roads could have a 

noticeable impact over a large area. Some components and materials could also be delivered 

by rail or barge, depending on location. Traffic-related transportation impacts during 

construction could range from SMALL at the LSCS site and SMALL to MODERATE at the wind 

farms and solar installations; depending on current road capacities and average daily traffic 

volumes.

During operations, transportation impacts would be less noticeable during shift changes and 

maintenance activities. Given the small numbers of operations workers, the levels of service 

traffic impacts on local roads from NGCC, wind farm, and solar PV operations would be SMALL.

4.10.7 Purchased Power Alternative

4.10.7.1 Socioeconomics 

This alternative would result in a loss of approximately 890 relatively high-paying jobs at LSCS, 

and a corresponding reduction in purchasing activity, tax payments, and revenue contributions 

would occur in the surrounding regional economy. Should LSCS cease operations, there would 

be an immediate socioeconomic impact to local communities and businesses from the loss of 

jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be 

reduced. In addition, the housing market could experience increased vacancies and decreased 

prices if operations workers and their families move out of the region. The impact of the job 

loss, however, may not be noticeable in local communities, given the amount of time required 

for decommissioning of the existing LSCS facilities. Purchased power from existing power 

generating facilities would not have any socioeconomic impact, because there would be no 

change in power plant operations or workforce. If the amount of purchased power exceeds the 

available supply, new electrical power generating facilities would be needed. Construction and 

operation of a new electrical power generating facility to supply purchased power could cause 

noticeable socioeconomic impacts in the communities located near the new facility. The 

intensity of the impact would depend on the number of workers required to build and operate the 

new electrical power generating facility and the amount of increased demand for housing and 

public services.

This alternative would also result in a loss of approximately 890 relatively high-paying jobs at 

LSCS, and a corresponding reduction in purchasing activity, tax payments, and revenue 

contributions would occur in the surrounding regional economy. Should LSCS cease 

operations, there would be an immediate socioeconomic impact to local communities and 

businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), 

and tax payments may be reduced. In addition, the housing market could experience increased 

vacancies and decreased prices if operations workers and their families move out of the region. 

The impact of the job loss, however, may not be noticeable in local communities, given the 

amount of time required for decommissioning of the existing LSCS facilities.

Therefore, the extent of the socioeconomic impact would depend on whether a new electrical 

power generating facility was needed to supply purchased power. If a new power generating 

facility is needed, socioeconomic impacts would range anywhere from SMALL to LARGE.

4.10.7.2 Transportation 

Purchased power from existing power generating facilities would not have any transportation 

impact, because there would be no change in power plant operations or workforce. If 

necessary, construction and operation of a new electrical power generating facility could cause 

noticeable transportation impacts, depending on the number of workers and truck deliveries 

required to build and operate the new electrical power generating facility. Consequently, traffic 
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volumes could increase noticeably on local roads near the new power plant site during shift 

changes.

The extent of the transportation impact would depend on whether a new electrical power 

generating facility were needed to supply purchased power. If a new power generating facility is 

needed, transportation impacts would range anywhere from SMALL to LARGE.

4.11 Human Health

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on human health resources. 

4.11.1 Proposed Action

Section 3.11 describes the human health resources associated with LSCS. Table 4–12

identifies the human health resource issues applicable to LSCS during the license renewal term. 

Table 4–12. Human Health Issues

Issue GEIS Section Category

Radiation exposures to the public 4.9.1.1.1 1

Radiation exposures to plant workers 4.9.1.1.1 1

Human health impact from chemicals 4.9.1.1.2 1

Microbiological hazards to the public (plants with cooling ponds or 

canals or cooling towers that discharge to a river)

4.9.1.1.3 2

Microbiological hazards to plant workers 4.9.1.1.3 1

Chronic effects of electromagnetic fields (EMFs)(a) 4.9.1.1.4 N/A(b)

Physical occupational hazards 4.9.1.1.5 1

Electric shock hazards(a) 4.9.1.1.5 2

(a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

(b) N/A (not applicable) The categorization and impact finding definition does not apply to this issue.

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

4.11.1.1 Normal Operating Conditions

Generic Human Health Issues (Category 1)

The NRC staff did not identify any new and significant information during its review of Exelon’s 

ER (Exelon 2014a), the site audit, or the scoping process for the Category 1 issues listed in 

Table 4–12. Therefore, there are no impacts related to these issues beyond those discussed in 

the GEIS. For these Category 1 issues, the GEIS concluded that the impacts are SMALL and, 

thus, the impacts associated with these issues for the LSCS license renewal are SMALL.

Chronic Effects of Electromagnetic Fields (EMFs)

In the GEIS (NRC 2013d), the chronic effects of 60-Hz electromagnetic fields (EMFs) from 

power lines were not designated as Category 1 or 2 and will not be until a scientific consensus 

is reached on the health implications of these fields.
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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 DOE.

The report by NIEHS (NIEHS 1999) contains the following conclusion:

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 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 EMFs. The NRC staff considers the GEIS finding of “UNCERTAIN” still 

appropriate and will continue to follow developments on this issue.

Site-Specific Human Health Issues (Category 2)

Microbiological Hazards to the Public

In the GEIS (NRC 2013d), the NRC staff determined that effects of thermophilic microorganisms 

on the public for plants using cooling ponds, lakes, or canals or cooling towers that discharge to 

a river is a Category 2 issue (see Table 4–12) that requires site-specific evaluation during each 

license renewal review.

In order to determine whether the continued operations of LSCS could promote increased 

growth of thermophilic microorganisms and thus have an adverse effect on the public, the NRC 

staff considered several factors: the thermophilic microorganisms of concern, LSCS’s thermal 

effluent characteristics, Exelon’s chlorination procedures, recreational use of the LSCS cooling 

pond and the Illinois River, and input from the Illinois Environmental Protection Agency (IEPA) 

and Illinois Department of Public Health (IDPH).

Section 3.11.3 describes the thermophilic microorganisms that the GEIS identified to be of 

potential concern at nuclear power plants and summarizes data from the Centers for Disease 

Control and Prevention (CDC) on the prevalence of waterborne diseases associated with these 

microorganisms that have been linked to recreational water from 2002 through 2011. CDC data 

indicate that no outbreaks or cases of waterborne Salmonella or Pseudomonas aeruginosa

infection from recreational waters have occurred in the United States during this time frame. 

Shigella and Naegleria fowleri infections linked to exposure in recreational waters were rarely 

reported, and none of the reported cases occurred in Illinois. Public exposure to aerosolized 

Legionella from nuclear plant operations is generally not a concern because such exposure 

would be confined to a small area of the site to which the public would not have access. In the 

case of LSCS, which does not have cooling towers, exposure of workers to Legionella is 

unlikely. Based on the information presented in Section 3.11.3, the thermophilic organisms 

most likely to be of potential concern at Illinois are Shigella and N. fowleri.

LSCS’s circulating water system and two service water systems discharge heated water to the 

site’s artificial cooling pond through a discharge canal. LSCS also continuously discharges

blowdown to the Illinois River, and this discharge is subject to the limitations set forth in the 

site’s NPDES permit (IEPA 2013). The permit requires monitoring and reporting of the average 

monthly and daily maximum rates of blowdown discharges to the river (Outfall 001), as further 
Environmental Consequences and Mitigating Actions

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described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Sections 3.1.3 and 3.5.1 describe the 

cooling system and surface water characteristics, respectively.

The temperature in the cooling pond is generally below the optimal growth temperature of both 

Shigella and N. fowleri (95 to 106 °F (35 to 41 °C)). From 2001 through 2014, there have been 

a few periods during summer months that the temperatures in the cooling pond exceeded 

95 °F (35 °C) (Exelon 2015b). Although these temperatures could reasonably enhance survival 

or growth of Shigella and N. fowleri, the short duration and periodicity of these temperatures are 

unlikely to have produced a measurable effect on the Shigella and N. fowleri population, if 

present in the pond.

For blowdown to the Illinois River, Special Condition 3 of the NPDES permit limits the maximum 

temperature rise above ambient conditions and maximum water temperatures at Outfall 001. 

This condition stipulates that, at the edge of the thermal mixing zone, discharges from 

Outfall 001 shall not cause the Illinois River water to rise above natural temperatures by more 

than 2.8 °C (5 °F). The temperature beyond the mixing zone cannot exceed specified monthly 

limits for longer than 1 percent (i.e., 87.6 hours) of any 12-month period and cannot at any time 

exceed the specified monthly limit by more than 1.7 °C (3 °F). During the months of April 

through November, the calculated temperature outside the mixing zone cannot exceed 93 °F 

(34 °C). These limits are consistent with Title 35, Environmental Protection, Section 302, 

“Water Quality Standards,” of the IAC, which stipulates that, for thermal effluents, the maximum 

temperature rise shall not exceed 2.8 °C (5 °F) above natural receiving water body 

temperatures and that the water temperature at representative locations in the main river shall 

at no time exceed 33.7 °C (93 °F) from April through November and 17.7 °C (63 °F) in other 

months (35 IAC 302.211). These temperature limits in the NPDES permits are below the 

optimal growth temperature for both Shigella and N. fowleri, and thus, would not enhance the 

growth or survival of these thermophilic organisms, if present in Illinois River water.

In addition to temperature limitations, the IAC prohibits the area and volume of thermal mixing 

from being more than 25 percent of the cross-sectional area or volume of stream flow 

(35 IAC 302.102). The NRC (1978) determined that LSCS’s thermal mixing zone meets the 

IAC’s criteria: the surface area of the thermal mixing zone was estimated to be 2,500 m2

(27,000 ft2

) in March to 400 m2 (4,300 ft2) in July, which would cover approximately 8 to 

9 percent of the river. Thus, the IAC’s thermal mixing limitations effectively minimize the area 

and volume over which microorganisms could experience enhanced growth or survival in the 

Illinois River near the LSCS discharge.

Chlorine is an effective disinfectant for water containing the microorganisms of concern. The 

EPA (1999a) reports that chlorination at concentrations of 1 to 2 milligrams per liter (mg/L) in 

water at a pH of 6.0 to 8.0 can effectively eliminate health hazards caused by bacteria, including

Shigella. The CDC (CDC 2013) reports that chlorine at a concentration of 1 part per 

million ((ppm) (1 mg/L)) added to 77 °F (25 °C) clear water at a pH of 7.5 will reduce the number 

of viable N. fowleri trophozoites by 99.99 percent in 12 minutes.

Exelon treats water entering the circulating water system and service water systems with 

sodium hypochlorite to control biofouling (Exelon 2014a). Water discharged to the Illinois River 

may not contain more than an instantaneous maximum concentration of 0.2 mg/L of residual 

chlorine or 0.05 mg/L of residual oxides, as measured at Outfall 001, per Special Condition 4 of 

the NPDES permit (IEPA 2013). Chlorination of the system is likely to prevent some increased 

growth and survival of microorganisms that might otherwise result from operation of LSCS.

Both the cooling pond and the Illinois River are used for recreational purposes. The cooling 

pond is part of the LaSalle Lake State Fish and Wildlife Area, which Exelon and the IDNR jointly 

manage. It is generally open to the public from mid-March until mid-October (Exelon 2014a). 
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Portions of the cooling pond within the exclusion zone, which includes the essential cooling 

pond, are off limits to the public (Exelon 2014a). Swimming, wading, water skiing, and use of 

non-motorized boats are prohibited at LaSalle Lake (IDNR 2015b), which further reduces the 

potential for human exposure to the microorganisms of concern, if present in the cooling pond.

As discussed above, LSCS’s thermal mixing zone in the Illinois River is relatively small 

(0.1 ha (0.22 ac)), and the temperature limitations set forth in the NPDES permit are lower than 

those that would promote increased growth or survival of thermophilic microorganisms. In 

accordance with the IAC, the discharge is not located near any public access areas because 

thermal mixing is prohibited “in water adjacent to bathing beaches, bank fishing areas, boat 

ramps or dockages or any other public access area” (35 IAC 302.102(b)(3)). Given the small 

area of thermally altered waters and the unlikelihood of the water to create conditions favorable 

to thermophilic microorganisms, exposure of recreational Illinois River users to elevated 

concentrations of the microorganisms of concern is unlikely.

The environmental standard review plan for license renewal directs the NRC staff to consult with 

the State public health department regarding concerns about the potential for waterborne 

disease outbreaks associated with license renewal. In response to RAIs, Exelon (2015b) 

included copies of correspondence between Exelon and IDPH and IEPA regarding this issue. 

Exelon requested information from IEPA and IDPH on the potential increase in adverse effects 

on public health from exposure to N. fowleri or any other thermophilic pathogen in the Illinois 

River. In response, IEPA and IDPH each indicated that its staff does not have the expertise 

necessary to adequately evaluate Exelon’s assessment (IEPA 2014a; IDPH 2014). 

Accordingly, the NRC staff did not separately contact the IDPH or IEPA during its license 

renewal review.

Conclusion

The thermophilic microorganisms Shigella and N. fowleri have been linked to waterborne 

outbreaks in recreational waters within the United States. However, based on these 

microorganisms’ temperature tolerances, Shigella and N. fowleri are unlikely to be present in the

vicinity of LSCS. Additionally, Exelon’s chlorination procedures and the small thermal mixing 

zones in the cooling pond and Illinois River make exposure of recreational water users to 

elevated levels of these microorganisms unlikely. The NRC staff concludes that the impacts of 

thermophilic microorganisms on the public are SMALL for LSCS license renewal.

Electric Shock Hazards

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 found to be a 

problem at most operating plants and generally is not expected to be a problem during the 

license renewal term. However, a site-specific review is required to determine the significance 

of the electric shock potential along the portions of the transmission lines that are within the 

scope of this SEIS.

As discussed in Section 3.11.4, there are no offsite transmission lines that are in scope for this 

SEIS. Therefore, there are no potential impacts to members of the public.

As discussed in Section 3.11.5, LSCS maintains an occupational safety program in accordance 

with the Occupational Safety and Health Administration regulations for its workers, which 

includes protection from acute electric shock. Therefore, the NRC staff concludes that the 

potential impacts from acute electric shock during the license renewal term would be SMALL.
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4.11.1.2 Environmental Impacts of Postulated Accidents

This section describes the environmental impacts from postulated accidents that LSCS might 

experience 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. The two classes of 

postulated accidents listed in Table 4–13 are contained in Table B–1 of Appendix B to 

Subpart A of 10 CFR Part 51 and are evaluated in detail in the GEIS. These two classes of 

accidents are design-basis accidents (DBAs) and severe accidents.

Table 4–13. Issues Related to Postulated Accidents

Issue GEIS Section Category

DBAs 4.9.1.2 1

Severe accidents 4.9.1.2 2

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

Design-Basis Accidents

In order to receive 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.

Design-basis accidents are those accidents that both the applicant 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. Many 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 preventive and mitigative safety systems of the 

nuclear power plant. Parts 50 and 100 of 10 CFR describe the acceptance criteria for DBAs.

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, the safety evaluation 

report, the final environmental statement (FES), and Section 4.11 of this 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; as such, 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 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.
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The Commission has generically 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.

No new and significant information related to DBAs was identified during the review of the LSCS

ER (Exelon 2014a), the site audit, the scoping process, or evaluation of other available 

information. Therefore, there are no impacts related to these issues beyond those discussed in 

the GEIS.

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 NRC staff assessed the effects of severe accidents during the 

period of extended operation, using the results of existing analyses and site-specific information 

to conservatively predict the environmental impacts of severe accidents for each plant during 

the period of extended operation.

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 LSCS site in the GEIS (NRC 1996). However, the GEIS 

did evaluate existing impact assessments performed by the NRC and by 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 terrorist 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 and beyond-design-basis earthquakes 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, 2013a).

Based on information in the GEIS, the staff found the following to be true:

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 staff identified no new and significant information related to postulated accidents

during the review of Exelon’s ER for LSCS (Exelon 2014a), the site audit, the scoping process, 

or 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), the staff has reviewed severe accident mitigation alternatives

(SAMAs) for LSCS.

Severe Accident Mitigation Alternatives

If the NRC staff has not previously considered SAMAs for the applicant’s plant in an 

environmental impact statement or related supplement or in an environmental assessment, 

10 CFR 51.53(c)(3)(ii)(L) requires license renewal applicants to consider alternatives to mitigate 
Environmental Consequences and Mitigating Actions

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severe accidents. 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. If a SAMA determined to be potentially cost

beneficial is not related to adequately managing the effects of aging during the period of 

extended operation, then it is not required to be implemented as part of the license renewal 

process pursuant to 10 CFR Part 54. The NRC staff has not previously considered SAMAs for 

LSCS; therefore, the following addresses alternatives to mitigate severe accidents.

Overview of SAMA Process

This section presents a summary of the SAMA evaluation for LSCS, as described in the ER 

(Exelon 2014a) and responses to requests for additional information (RAIs) (Exelon 2015h), and 

the NRC staff’s review of this information. The NRC staff performed its review with contract 

assistance from the Center for Nuclear Waste Regulatory Analyses. Appendix F to this SEIS 

provides the NRC staff’s detailed review, and Appendix F to Exelon’s ER provides Exelon’s 

LSCS SAMA evaluation.

The SAMA evaluation for LSCS conducted by Exelon contained the following main components:

(1) Exelon quantified the level of risk associated with potential reactor accidents using 

the plant-specific probabilistic risk assessment (PRA) and other risk models. 

(2) Exelon 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. 

(3) Exelon screened out SAMA candidates that are not applicable to the LSCS plant 

design or are of low benefit in boiling water reactors (BWRs) such as LSCS, as 

well as candidates that have already been implemented at LSCS or whose benefits 

have been achieved at LSCS using other means.

(4) Exelon estimated the costs of implementing the unscreened SAMA candidates, 

and those whose estimated implementation cost exceeded the maximum possible 

averted cost risk were also screened out.

(5) Exelon estimated how much each remaining unscreened SAMA could reduce risk. 

Referred to as potential benefits of implementing each SAMA, those estimates 

were developed in terms of dollars in accordance with NRC guidance for 

performing regulatory analyses. Exelon compared the implementation cost with 

the benefit of each remaining unscreened SAMA candidate to determine whether it 

was potentially cost beneficial (the benefits of the SAMA exceeded its cost).

Sensitivity analyses were then performed by Exelon to quantify effects on the 

cost-benefit evaluation.

Estimate of Risk

Exelon submitted an assessment of SAMAs for LSCS in Appendix F of the ER (Exelon 2014a). 

The assessment was based on the most recent LSCS PRA available at that time, a 

plant-specific offsite consequence analysis performed using the MELCOR Accident 

Consequence Code System 2 (MACCS2) Version 1.13.1 computer code, and insights from the 

combined individual plant examination (IPE) and individual plant examination of external events 

(IPEEE) for LSCS (Commonwealth Edison Company (CECO) 1994). 

Exelon combined two distinct analyses to form the basis for estimating risk in the SAMA

analysis: (1) LSCS Level 1 and Level 2 PRA models and (2) a supplemental analysis of offsite 

consequences and economic impacts (essentially a Level 3 PRA model) developed specifically 

for the SAMA analysis. The Level 1 model is a significant upgrade and revision to the IPE 
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Level 1 model, whereas the Level 2 model is an update of the prior large early release 

frequency (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 

and 2 PRA models available at the time of the ER, referred to as the LSCS PRA 2013A 

(or LS213A) model. This LSCS PRA includes internal floods but does not include external 

events.

The LSCS core damage frequency (CDF) is approximately 2.6x10−6 per year (Exelon 2014a). 

Exelon did not explicitly include the contribution from external events within the LSCS SAMA

risk estimates; however, it did account for the potential risk reduction benefits associated with 

external events by multiplying the estimated benefits for internal events by a factor of 5.2. 

Section F.2.2.2 of Appendix F discusses this issue further. Using the calculated risk reduction 

as a quantitative measure of the potential benefit from SAMA implementation, Exelon performed 

a cost-benefit comparison with estimated implementation costs for each SAMA.

The breakdown of CDF by initiating event is provided in Table 4–14. As shown in this table, 

events initiated by a turbine trip with bypass, a dual unit loss of offsite power, a loss of 

instrument air, and a loss of condenser vacuum are the dominant contributors to the CDF. 

Exelon found that station blackout contributes 6.4x10−7 per year, or 25 percent of the total CDF 

for internal events, whereas anticipated transients without scram (ATWS) contribute 

4.9x10−7 per year, or approximately 19 percent of the total CDF for each unit (Exelon 2015h).

Exelon stated the following:

The expansion of the LERF model to a full Level 2 model involved a 

reassessment of the timing and release categorization of each containment event 

tree (CET) endstate. To perform this reassessment, MAAP [Modular Accident 

Analysis Program] calculations for each accident class were performed and used 

to assess the CET endstates. Each CET node was evaluated and updated to 

reflect the current state of knowledge regarding Level 2 accident 

phenomenology. The endstate timing was also updated to reflect the current 

emergency plan and evacuation time estimates.

The Level 2 model uses three general CET types to assess the accident progression during a 

core damage event. CETs contain both phenomenological and containment system status 

events. Level 1 core damage sequences are binned into plant damage states or accident 

classes, which provide the interface between the Level 1 and Level 2 CET analysis. Each 

accident class bin is entered into the CET, resulting in 15 LSCS-specific CETs. The CET is 

linked directly to the Level 1 event trees, and CET nodes are evaluated using supporting fault 

trees (Exelon 2015h).

Table 4–14. LSCS CDF for Internal Events

Initiating Event CDF(a) (per year) Percent CDF Contribution

Turbine Trip with Bypass 5.6x10−7 22

Dual Unit Loss of Offsite Power 3.1x10−7 12

Loss of Instrument Air 2.8x10−7 11

Loss of Condenser Vacuum 2.7x10−7 10

Fire Protection System Pipe Rupture in Reactor 

Building

1.9x10−7 7

Main Steam Isolation Valve Closure 1.4x10−7 5

Loss of Turbine Building Component Cooling Water 1.2x10−7 5

Loss of Feedwater 1.2x10−7 4

Loss of Offsite Power 7.2x10−8 3
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Initiating Event CDF(a) (per year) Percent CDF Contribution

Manual Shutdown 5.9x10−8 2

Inadvertently Open Relief Valve 5.9x10−8 2

Loss of 125-V Direct-Current Bus 2A 5.1x10−8 2

Loss of 125-V Direct-Current Buses 2A and 2B 3.9x10−8 2

Other Initiating Events(b) 3.3x10−7 13

Total (Internal Events)(c) 2.58x10−6 100

(a) CDF is based on Fussell-Vesely importance and total CDF.

(b) For “Other Initiating Events,” each event would contribute less than 2 percent to the total CDF.

(c) Column totals may be different because of rounding.

Key: CDF = core damage frequency, and V = volt(s).

Source: Exelon 2014a

The result of the Level 2 PRA is a set of 13 release bins or categories with their respective 

frequency and release characteristics. The results of this analysis for LSCS are provided in 

Tables F.2–5, F.2–6, F.3–15, F.3–16, and F.3–19 of the ER (Exelon 2014a). The categories 

were defined based on the timing of release (three release time ranges) and the magnitude of 

release (four release magnitude ranges). One additional release category was included for an 

intact containment.

For use in the SAMA analysis, the release category for high magnitude and early timing was 

divided into two bins (one with containment isolation and one without such isolation). Due to the 

small release category contributions from six categories, the number of release category bins 

was reduced to eight cases. The frequency of each release category was obtained by summing 

the frequency of the individual accident progression CET endpoints binned into the release 

category. Source terms were developed for each of the 13 release categories using the results 

of MAAP Version 4.0.5 computer code calculations (Exelon 2014a).

Exelon computed offsite consequences for potential releases of radiological material using the 

MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its 

determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 

site-specific input values for core radionuclide inventory, source term and release 

characteristics, site meteorological data, projected population distribution and growth within a 

50-mi (80-km) radius, emergency response evacuation modeling, and economic data. The 

estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and 

occupational dose) is based on guidance in NUREG/BR–0184, Regulatory Analysis Technical 

Evaluation Handbook (NRC 1997). In its calculation for replacement power costs, Exelon 

accounted for the increased electric power output of LSCS compared to the generic reactor

power output presented in NUREG/BR–0184 (NRC 1997).

In the ER, as updated by Exelon’s response to RAIs from the NRC staff (Exelon 2015h), Exelon 

estimated the dose risk to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to 

the population within 50 mi (80 km) of the LSCS site. The offsite economic cost risk was 

calculated to be $57,700 per year. Table 4–15 summarizes the breakdown of the population 

dose risk by containment release mode. The medium-magnitude intermediate release category 

accounted for 52 and 62 percent of the population dose risk and offsite economic cost risk, 

respectively. Additionally, two categories (1) medium-magnitude early release and 

(2) high-magnitude early release for breaks outside containment) together accounted for 
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approximately 41 and 31 percent of the population dose risk and offsite economic cost risk, 

respectively.

The NRC staff has reviewed Exelon’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 Exelon.

Potential Plant Improvements

Exelon considered potential plant improvements (SAMAs) that addressed the major contributors 

to CDF and release frequency at LSCS and considered SAMA candidates from six other boiling

water reactor (BWR) plants, as follows:

(1) Susquehanna Steam Electric Station;

(2) Cooper Nuclear Station;

(3) Duane Arnold Energy Center;

(4) Nine Mile Point, Unit 2;

(5) Columbia Generating Station; and

(6) Grand Gulf Nuclear Station.

Exelon identified potential plant improvements by reviewing the following:

• LSCS PRA results and PRA group insights;

• Potentially cost-effective Phase 2 SAMAs from the following:

− Susquehanna Steam Electric Station SAMA analysis;

− Cooper Nuclear Station SAMA analysis;

− Duane Arnold Energy Center SAMA analysis;

− Nine Mile Point, Unit 2, SAMA analysis;

− Columbia Generating Station SAMA analysis; and

− Grand Gulf Nuclear Station SAMA analysis;

• LSCS IPE; and

• LSCS IPEEE.

Table 4–15. Base Case Mean Population Dose Risk and

Offsite Economic Cost Risk for Internal Events

Release Mode Population Dose Risk(a) Offsite Economic Cost Risk

ID(b)

Frequency 

(per year) person-rem/yr % Contribution $/yr % Contribution

H/E–BOC(c) 8.3x10‒8 1.3x100 18 7.2x103 13

H/E 6.0x10‒8 3.2x10‒1 4 2.8x103 5

H/I(d) 1.9x10‒8 1.1x10‒1 1 9.7x102 2

M/E 2.4x10‒7 1.7x100 23 1.0x104 18

M/I(d) 1.0x10‒6 3.9x100 52 3.6x104 62
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Release Mode Population Dose Risk(a) Offsite Economic Cost Risk

L/E 3.9x10‒7 8.7x10‒2 1 1.3x102 0.2

L/I(d) 1.5x10‒7 1.1x10‒1 1 1.8x102 0.3

CI 6.2x10‒7 1.4x10‒3 <0.1 1x100 <0.1

Total 2.6x10−6 7.6x100 100 5.8x104 100

(a) Unit Conversion Factor: 1 Sv = 100 rem.

(b) Release Mode Nomenclature (Magnitude/Timing) 

Magnitude:

High (H)—greater than 10-percent release fraction for cesium iodide

Medium (M)—1- to 10-percent release fraction for cesium iodide

Low (L)—0.1- to 1-percent release fraction for cesium iodide

Low-Low (LL)—less than 0.1-percent release fraction for cesium iodide

Containment intact (CI)—much less than 0.1-percent release fraction for cesium iodide

Timing:

Early (/E)—less than 5 hours

Intermediate (/I)—5 to 24 hours

Late (/L)—greater than 24 hours

(c) These are contributions from initiators with breaks outside containment (BOC). 

(d) The release categories for late timing were negligible and subsumed into the intermediate release categories for 

H, M, and L releases. Categories for LL magnitude releases were negligible and subsumed into the L release 

category with intermediate timing.

Sources: Exelon 2014a, 2015h

Exelon indicated that, in addition to the “Industry Phase 2 SAMA” review identified above, an 

industry-based SAMA list in Nuclear Energy Institute (NEI) 05-01, “Severe Accident Mitigation 

Alternative (SAMA) Analysis Guidance Document,” issued November 2005 (NEI 2005), was 

used to help identify the types of changes that could be used to address the areas of concern 

identified through the LSCS importance list review.

Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as 

Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the 

initial list of SAMAs and eliminated SAMAs from further consideration using the following 

criteria:

Applicability to the Plant. If a proposed SAMA does not apply to the LSCS

design or has already been implemented, it is not retained.

Implementation Cost Greater Than the Screening Cost. If the estimated cost of 

implementation is greater than the maximum averted cost risk, the SAMA is 

screened out from further analysis.

Through this process, two SAMA candidates were initially screened out based on the excessive 

cost criterion. Subsequently, following modeling corrections, one of these two SAMA

candidates was determined to not be screened out (Exelon 2015h). Table F.6–1 of the ER 

(Exelon 2014a), as amended (Exelon 2015h), provides a description of each of the 25 Phase II 

SAMA candidates.

In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as 

discussed in Sections F.4 and F.6 of Appendix F. To account for the potential impact of 
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external events, the estimated benefits based on internal events were multiplied by a factor of 

5.2, as discussed in Section F.2.2.2 of Appendix F.

Evaluation of Risk Reduction and Costs of Improvements

Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II 

evaluation in a revised analysis (Exelon 2015h). The SAMA evaluations were generally 

performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit 

of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be 

optimistically low, thereby overestimating the benefit of the SAMA. Other cases assumed that 

the SAMA eliminated all the risk associated with the proposed enhancement. The NRC staff 

notes that this bounding approach overestimates the benefit and is conservative.

Exelon used model requantification to determine the potential benefits for each of the SAMAs. 

The CDFs, population dose reductions, and offsite economic cost reductions were estimated 

using the LSCS PRA model. The changes made to the model to quantify the impact of each 

SAMA are described in Section F.6 of the ER. Table 4–16 summarizes the assumptions used 

to estimate the risk reduction for each potentially cost-beneficial SAMA, the estimated risk 

reduction in terms of CDF percent reduction, population dose, offsite economic cost, and the 

estimated total benefit (present value) of the averted risk. The determination of the benefits for 

the various SAMAs is further discussed in Section F.6 of Appendix F.

The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction 

estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that 

resulted from this review is discussed in Section F.4 of Appendix F. The determination of the 

benefits for the various SAMAs is further discussed in Section F.6 of Appendix F.

Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other 

licensees’ estimates for similar improvements and the development of site-specific cost 

estimates, where appropriate. SAMA cost estimates were based on initial hardware, 

installation, and implementation costs. In response to an NRC staff RAI to provide further 

information as to what was included in the LSCS cost estimates, Exelon explained that 

maintenance and testing costs during the license renewal period were conservatively not 

included in the estimate (Exelon 2015h).

The NRC staff reviewed the applicant’s cost estimates presented in Section F.6 of the ER 

(Exelon 2014a). For certain improvements, the NRC 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.

The NRC staff noted that a few SAMAs (e.g., SAMAs 8, 14, and 27) involve use of equipment 

that may be available as a result of the B.5.b program. In response to an NRC staff RAI to 

discuss this further, Exelon responded that the B.5.b program at LSCS includes a small 

generator that is used to support two individual safety relief valve (SRV) solenoids to hold the 

SRVs open after 125-V direct-current (DC) battery depletion, but the generator does not power 

the station battery chargers, and it is not designed to support the reactor core isolation cooling 

(RCIC) system through DC feeds. Because of these limitations, the B.5.b generator is not a 

viable substitute for the generators that have been proposed for SAMAs 8, 14, and 27; 

therefore, the availability of the B.5.b generator would not reduce the implementation costs for 

these SAMAs. With the above clarifications, the NRC staff concludes that the cost estimates 

provided by Exelon are sufficient and appropriate for use in the SAMA evaluation.
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Table 4–16. LSCS Potentially Cost-Beneficial SAMAs(a)

Individual SAMA and Assumptions

% Risk Reduction(b) Total Benefi

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

Per

2—AUTOMATE SUPPRESSION POOL COOLING 14 20 25 1.4M 

SAMA 2 Modeling: The fault tree incorporated the automation of suppression pool cooling alignment by changing the inde

IDs for suppression pool cooling initiation to alternate IDs. This accomplishes two functions: (1) assignment of alternate f

are representative of an automated function and (2) prevention of the recovery logic from identifying suppression pool coo

human actions and preclusion of the suppression pool cooling initiation failures from dependent human error combinations

3—INSTALL PASSIVE VENT PATH 36 51 61 1.0M 

SAMA 3 Modeling: The basic event for the operator action for venting was replaced with a new placeholder event with a v

prevents the creation of dependent operator actions, including the vent action. The hardware failures associated with the 

been retained to approximate the potential failures of the rupture disk (with the support system dependencies removed).

4—INSTALL A KEYLOCK MSIV LOW-LEVEL ISOLATION 

BYPASS SWITCH 16 12 10 674K 

SAMA 4 Modeling: The independent human error probability to bypass the main steam isolation valve low-level isolation i

1x10‒5, and the joint human error probabilities that include this action have been eliminated.

5—AUTOMATE SBLC INITIATION 8 7 6 386K 

SAMA 5 Modeling: The automatic SBLC initiation capability is modeled by manipulation of associated basic events. Early 

event ID (2SLOP-LVLCTRLH--) was changed to “SAMA5” and set to a probability of 1x10‒6 to reduce the independent fail

small value and to prevent the inclusion of dependent operator action combinations with SBLC initiation failures, consisten

action.

8—OBTAIN A 480-V AC PORTABLE GENERATOR TO SUPPLY 

THE 125-V DC BATTERY CHARGERS AND DEVELOP 

PROCEDURES FOR ITS USE

4 4 4 259K 

SAMA 8 Modeling: The 480-V AC generator capability has been approximated by adding the diesel fire pump as a low-pr

for station blackout scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added t

480-V AC power source that feeds the Division 1 battery chargers.

9—DEVELOP FLOOD ZONE-SPECIFIC PROCEDURES 9 3 3 224K 

SAMA 9 Modeling: Initiating event frequencies for flooding events were set to zero in the cutsets.
4-85

Individual SAMA and Assumptions

% Risk Reduction(b) Total Benefi

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

Per

10—CHANGE THE LOGIC TO CLOSE THE TURBINE DRIVEN 

FEEDWATER PUMP DISCHARGE VALVES WHEN THE PUMPS 

ARE NOT RUNNING

9 21 23 1.3M 

SAMA 10 Modeling: The human failure event associated with closing the turbine-driven feedwater pump discharge valves 

event with a failure probability of 1x10‒4. This treatment reduces the independent contribution of the isolation failure and p

generation of dependent human error combination, including the operator action to isolate the valves.

14—PROVIDE A PORTABLE DC SOURCE TO SUPPORT RCIC 

AND SRV OPERATION 9 7 7 444K 

SAMA 14 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low-pressur

station blackout scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to r

power source that feeds the Division 1 battery chargers.

15—TIE RHRSW TO THE LPCS SYSTEM FOR ISLOCA 

MITIGATION 37 57 57 3.4M 

SAMA 15 Modeling: Changes were made to both the main fault tree and the recovery fault tree. The cross-tie was assum

injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHR

ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the c

logic was added at the sequence level for BOC and ISLOCA sequences for which credit was not previously taken for any l

systems, and was added to the existing fault tree structure in scenarios for which venting or containment failure resulted in 

injection systems.

16—PROVIDE PORTABLE FANS FOR ALTERNATE ROOM 

COOLING IN THE CSCS VAULTS 14 12 15 866K 

SAMA 16 Modeling: The alternate CSCS room cooling capability was approximated by deleting the gates associated with 

(excluding the automatic initiation failures, which are already addressed in the model).

18—IMPROVE THE CONNECTION BETWEEN THE FIRE 

PROTECTION AND FEEDWATER SYSTEMS 9 9 10 609K 

SAMA 18 Modeling: The fault tree was updated to credit the FPS in places for which LPCI and LPCS are credited, but the 

LOCA and IORV initiating event and for water hammer scenarios. In addition, the logic was changed to include the FPS in

early station blackout scenarios in which the ADS is available for those sequences not impacted by the LPCS-LPCI gate.
4-86

Individual SAMA and Assumptions

% Risk Reduction(b) Total Benefi

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

Per

19—PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 

TO THE LPCS SYSTEM FOR LOCA MITIGATION 38 58 58 3.4M 

SAMA 19 Modeling: The inclusion of the RHRSW-LPCS cross-tie required changes to both the main fault tree and the rec

cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the 

(existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an e

the cross-tie. Cross-tie logic was added at the sequence level for BOC and ISLOCA sequences for which credit was not p

low-pressure injection systems and was added to the existing fault tree structure in scenarios in which venting or containm

the loss of injection systems.

21—INSTALL AUTOMATIC ATWS LEVEL CONTROL SYSTEM 14 14 12 754K 

SAMA 21 Modeling: The SAMA is modeled by setting the early and late level control actions to zero in the fault tree.

23—ENHANCE THE FUEL POOL EMERGENCY MAKEUP PUMP 

AND CONNECTION 27 46 52 3.0M 

SAMA 23 Modeling: The inclusion of the fuel pool emergency makeup pump cross-tie required changes to both the main 

recovery fault tree. The cross-tie was assumed to require the residual heat removal B injection path (existing logic from th

logic was added to the existing fault tree structure in scenarios in which venting or containment failure resulted in the loss 

(a) Potentially cost-beneficial SAMAs relate to LSCS, Unit 1 and Unit 2.

(b) Risk reduction percentages displayed in this table were obtained from the ER (Exelon, 2014) before Exelon’s revised results (Exelon 

percentages for the revised benefit results were not provided.

(c) Exelon identified potentially cost-beneficial SAMAs by comparing the total benefit with uncertainty at the 95th percentile to the estima

Total benefit and cost values presented in this table were obtained from Exelon’s revised results (Exelon 2015h).

Key: AC = alternating current, ADS = automatic depressurization system, ATWS = anticipated transients without scram, BOC = break o

CDF = core damage frequency, CSCS = core standby cooling system, DC = direct current, ECCS = emergency core cooling system, 

system, ID = identification, IORV = inadvertent/stuck open relief valve, ISLOCA = interfacing-systems loss-of-coolant accident, LPCI = 

injection, LPCS = low-pressure core spray, LOCA = loss-of-coolant accident, MSIV = main steam isolation valve, OECR = offsite econ

RCIC = reactor core isolation cooling, RHRSW = residual heat removal service water, SAMA = severe accident mitigation alternative, 

control, and SRV = safety relief valve.

Sources: Exelon 2014a, 2015h
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Cost-Benefit Comparison

If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 

was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 

SAMA candidate was considered to be potentially cost beneficial. Table 4–16 presents the 

results of the cost-benefit evaluation. Exelon’s cost-benefit analysis identified 14 SAMA 

candidates determined to be potentially cost beneficial at the 95th percentile on an individual 

basis, as follows:

• SAMA 2: Automate suppression pool cooling.

• SAMA 3: Install passive vent path.

• SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation 

bypass switch.

• SAMA 5: Automate SBLC initiation.

• SAMA 8: Obtain a 480-V AC portable generator to supply the 125-V DC battery 

chargers and develop procedures for its use.

• SAMA 9: Develop flood zone-specific procedures.

• SAMA 10: Change the logic to close the turbine-driven feedwater pump discharge

valves when the pumps are not running.

• SAMA 14: Provide a portable DC source to support RCIC and SRV operation.

• SAMA 15: Tie RHRSW to the LPCS system for ISLOCA mitigation.

• SAMA 16: Provide portable fans for alternate room cooling in the core standby 

cooling system vaults.

• SAMA 18: Improve the connection between the fire protection and 

feedwater systems.

• SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for 

LOCA mitigation.

• SAMA 21: Install automatic ATWS level control system.

• SAMA 23: Enhance the fuel pool emergency makeup pump and connection.

When the planned installation of a hardened vent pipe is considered as the base case, the 

number of SAMA candidates considered to be potentially cost beneficial at the 95th percentile 

may be reduced. Because a new baseline is established following the implementation of a 

SAMA, which further influences the benefits provided by the remaining SAMA candidates, 

Exelon defined an optimal set to containing SAMAs that, if implemented, would render the 

remaining SAMAs to be not cost beneficial. Acknowledging Exelon’s commitment to install the 

hardened vent pipe (SAMA 1), additional modifications included in the optimal set are 

SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). Assessment of the optimal set 

was performed before Exelon generated revised results in response to the NRC staff’s RAIs 

(Exelon 2015h). Exelon is referring the 14 potentially cost-beneficial SAMAs from its revised 

analysis (Exelon 2015h) to the LSCS Plant Health Committee for further implementation 

considerations within the established plant procedural process, as indicated in Section 4.15 of 

the ER (Exelon 2014a).
Environmental Consequences and Mitigating Actions

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Conclusions

Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 

updated probabilistic safety assessment models, SAMA-related industry documentation, 

plant-specific enhancements, and its review of SAMA candidates from potential improvements 

primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 

SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 

been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 

costs and benefits associated with each of the 25 potential SAMAs. Exelon concluded that 

14 of these SAMA candidates were potentially cost beneficial at the 95th percentile (shown in 

Table 4–16). Exelon has decided to proceed with the modification to install a hardened vent 

pipe regardless of cost even though it is not cost beneficial. From a sensitivity analysis, no 

additional SAMA candidates were identified as potentially cost beneficial. Pursuant to 

10 CFR 54.30, a licensee’s compliance with its current licensing basis is not within the scope of 

the license renewal review. Therefore, because the potentially cost-beneficial SAMAs have to 

do with the licensee’s current licensing basis and do not relate to aging management during the 

period of extended operation, their implementation is not required as part of license renewal. 

Instead, as stated in Section 4.15 of the ER (Exelon 2014a), Exelon indicated that the 

potentially cost-beneficial SAMAs are being referred to the LSCS Plant Health Committee for 

further implementation considerations within the established plant procedural process.

The NRC staff reviewed Exelon’s SAMA analysis and concludes that, based on the discussion 

in Appendix F of this document, the methods used and implementation of those methods were 

sound. On the basis of the applicant’s treatment of SAMA benefits and costs, the NRC staff 

finds that the SAMA evaluations performed by Exelon are reasonable and are sufficient for the 

license renewal submittal. The NRC staff concurs with Exelon’s conclusion that 14 SAMA 

candidates are potentially cost beneficial for LSCS and notes that Exelon’s assessment was 

based on generally conservative treatment of costs, benefits, and uncertainties. Based on the 

NRC staff’s review of Exelon’s SAMA evaluations, including Exelon’s response to the NRC 

staff’s RAIs, the NRC staff concludes that Exelon has adequately identified 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 

NRC staff agrees that further evaluation by Exelon of the 14 SAMA candidates identified by 

Exelon as being potentially cost beneficial is warranted.

The NRC staff also evaluated whether the identified potentially cost-beneficial SAMAs are 

subject to aging management. The evaluation considered any structures, systems, and 

components associated with these SAMAs that perform intended functions without moving parts 

or without a change in configuration or properties and that would not be subject to replacement 

based on a qualified life or specified time period. The NRC staff determined that the potentially 

cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the 

period of extended operation. Therefore, they do not need to be implemented as part of license 

renewal in accordance with 10 CFR Part 54.

4.11.2 No-Action Alternative

Human health risks would be smaller following plant shutdown. The two reactor units, which are 

currently operating within regulatory limits, would emit less gaseous, liquid, and solid radioactive 

material to the environment. In addition, following 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 Section 4.11.1, the NRC staff concluded that the 

impacts of continued plant operation on human health would be SMALL, except for “chronic 

effects of electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. In 
Environmental Consequences and Mitigating Actions

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Section 4.11.1.2, 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 types of accidents decrease following shutdown, the NRC staff concludes that the risk to 

human health following plant shutdown would be SMALL.

4.11.3 New Nuclear Alternative

Impacts on human health from construction of two new nuclear units would be similar to impacts 

associated with the construction of any major industrial facility. Compliance with worker 

protection rules would control those impacts on workers at acceptable levels. Impacts from 

construction on the general public would be minimal, since limiting active construction area 

access to authorized individuals is expected. Impacts on human health from the construction of 

two new nuclear units would be SMALL.

The human health effects from the operation of two new nuclear units would be similar to those 

of operating the two existing LSCS units. As presented in Section 4.11.1, impacts on human 

health from the operation of LSCS would be SMALL, except for “chronic effects of 

electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. Therefore, the impacts 

on human health from the operation of two new nuclear units would be SMALL.

4.11.4 IGCC Alternative

Impacts from construction on workers are expected to be similar to those experienced during 

construction of any major industrial facility. Impacts from construction of an IGCC facility are 

expected to be the same as those for construction of fossil fuel facilities. Construction would 

increase traffic on local roads, which could affect the health of the general public. Human health 

impacts would be the same for all facilities, whether located on greenfield sites or at an existing 

power plant. Personal protective equipment, training, and engineered barriers would protect the 

workforce (NRC 2013d). Therefore, the impacts on human health from the construction of an 

IGCC facility would be SMALL.

The IGCC alternative introduces worker risks from coal and limestone mining, worker and public 

risk from coal and lime/limestone transportation, worker and public risk from disposal of 

coal-combustion waste, and public risk from inhalation of stack emissions. In addition, human 

health risks are associated with the management and disposal of coal combustion waste. Coal 

combustion generates waste in the form of ash, and equipment for controlling air pollution 

captures additional ash and produces scrubber sludge, which must be managed as coal 

combustion waste. Human health risks may extend beyond the facility workforce to the public, 

depending on their proximity to the coal combustion waste storage and/or disposal facility. The 

character and the constituents of coal combustion waste depend on both the chemical 

composition of the source coal and the technology used to combust it. Generally, the primary 

sources of adverse consequences from coal combustion waste are from exposure to sulfur 

oxide and nitrogen oxide in air emissions and radioactive elements, such as uranium and 

thorium, as well as the heavy metals and hydrocarbon compounds contained in fly ash and 

bottom ash, and scrubber sludge (NRC 2013d).

Regulatory agencies, including EPA and state agencies, base air emission standards and 

requirements on human health impacts. These agencies also impose site-specific emission 

limits as needed to protect human health. Given the regulatory oversight exercised by EPA and 

state agencies, the NRC staff concludes that the human health impacts from radiological doses 

and inhaled toxins and particulates generated from the IGCC alternative would be SMALL 

(NRC 2013d).
Environmental Consequences and Mitigating Actions

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4.11.5 NGCC Alternative

Impacts on human health from construction of the NGCC alternative would be similar to effects 

associated with the construction of any major industrial facility. Compliance with worker 

protection rules would control those impacts on workers at acceptable levels. Impacts from 

construction on the general public would be minimal, since crews would limit active construction 

area access to authorized individuals. Based on the above, the NRC staff concludes that the 

impacts on human health from the construction of the NGCC alternative would be SMALL.

Impacts from the operation of an NGCC facility include public risk from inhalation of gaseous 

emissions. The risk may be attributable to nitrogen oxide emissions that contribute to ozone 

formation, which in turn contribute to health risk. Regulatory agencies, including the EPA and 

state agencies, base air emission standards and requirements on human health impacts. 

These agencies also impose site-specific emission limits as needed to protect human health. 

Given the regulatory oversight exercised by EPA and state agencies, the NRC staff concludes 

that the human health impacts from the NGCC alternative would be SMALL.

4.11.6 Combination Alternative (NGCC, Wind, Solar)

Impacts on human health from construction of a combination of NGCC, wind, and solar 

alternative would be similar to effects associated with the construction of any major industrial 

facility. Compliance with worker protection rules and personal protective equipment, training, 

and engineered barriers would protect the workforce (NRC 2013d). Impacts from construction 

on the general public would be minimal, since crews would limit active construction area access 

to authorized individuals. Based on the above, the NRC staff concludes that the Impacts on 

human health from the construction of the NGCC, wind, and solar alternative would be SMALL.

Operational hazards at an NGCC facility are discussed in Section 4.11.5.

Operational hazards at a wind facility for the workforce include working at heights, near rotating 

mechanical or electrically energized equipment, and in extreme weather. Potential impacts to 

workers and the public include ice thrown from rotor blades and broken blades thrown as a 

result of mechanical failure. Potential impacts also include EMF exposure, aviation safety 

(hazards), and exposure to noise and vibration from the rotating blades.

Operational hazards at a solar PV facility may involve exposure to airborne toxic metals 

(e.g., cadmium) and silicon if the PV cell loses its integrity from a fire. Workers could also inhale 

silicon dust if a PV cell were smashed by an object or from a fall to the ground. However, based 

on worker and environmental protection rules, it is expected that remediation of toxic material 

would occur. Such remediation would minimize the impact to workers and the environment.

Therefore, given the expected compliance with worker and environmental protection rules and 

the use of personal protective equipment, training, and engineered barriers, the NRC staff 

concludes that the potential human health impacts would be SMALL.

4.11.7 Purchased Power Alternative

Purchased power is expected to come from the types of electricity generation available within 

the ROI: coal, natural gas, nuclear, and wind. The human health impacts from the operation of 

these types of power plants are discussed in Sections 4.11.3, 4.11.4, 4.11.5, and 4.11.6. Based 

on the information in those sections, the NRC staff concludes that the human health impacts of 

the purchased power alternative using nuclear, coal, natural gas, wind, and solar would be 

SMALL.
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4.12 Environmental Justice

This section describes the potential human health and environmental effects of the proposed 

action (license renewal) and alternatives to the proposed action on minority and low-income

populations. 

4.12.1 Proposed Action

Section 3.12 identifies minority and low-income populations living in the vicinity of LSCS. 

Table 4–17 identifies the environmental justice issue applicable to LSCS during the license 

renewal term. 

Table 4–17. Environmental Justice NEPA Issue

Issue GEIS Section Category

Minority and low-income populations 4.10.1 2

Source: Table B–1 in Appendix B, Subpart A of 10 CFR Part 51

The NRC addresses environmental justice matters for license renewal by (1) identifying the 

location of minority and low-income populations that may be affected by the continued operation 

of the nuclear power plant during the license renewal term, (2) determining whether there would 

be any potential human health or environmental effects to these populations and special 

pathway receptors, and (3) determining if any of the effects may be disproportionately high and 

adverse. 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 risks of impacts on the natural or physical environment in a minority or low-income 

community that are significant and appreciably exceed the environmental impact on the larger 

community. Such effects may include biological, cultural, economic, or social impacts.

Figures 3–17 and 3–18 show the location of predominantly minority and low-income population 

block groups residing within a 50-mi (80-km) radius of LSCS. This area of impact is consistent 

with the impact analysis for public and occupational health and safety, which also focuses on 

populations within a 50-mi (80-km) radius of the plant. Chapter 4 presents the assessment of 

environmental and human health impacts for each resource area. The analyses of impacts for 

all environmental resource areas indicated that the impact from license renewal would be 

SMALL.

Potential impacts on minority and low-income populations (including migrant workers or Native 

Americans) would mostly consist of socioeconomic and radiological effects; however, radiation 

doses from continued operations during the license renewal term are expected to continue at 

current levels, and they would remain within regulatory limits. Section 4.11.1.2 of this SEIS 

discusses the environmental impacts from postulated accidents that might occur during the 

license renewal term, which include both design basis and severe accidents. In both cases, the 

Commission has generically determined that impacts associated with DBAs are small because 

nuclear plants are designed and operated to successfully withstand such accidents, and the 

probability-weighted consequences of severe accidents are small.
Environmental Consequences and Mitigating Actions

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Therefore, based on this information and the analysis of human health and environmental 

impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 

adverse human health and environmental effects on minority and low-income populations from 

the continued operation of LSCS during the license renewal term.

As part of addressing environmental justice concerns associated with license renewal, the NRC 

staff also assessed the potential radiological risk to special population groups (such as migrant 

workers or Native Americans) from exposure to radioactive material received through their 

unique consumption practices and interaction with the environment, including subsistence 

consumption of fish and wildlife, native vegetation, surface waters, sediments, and local 

produce; absorption of contaminants in sediments through the skin; and inhalation of airborne 

radioactive material released from the plant during routine operation. This analysis is presented 

below.

Subsistence Consumption of Fish and Wildlife

The special pathway receptors analysis is an important part of the environmental justice

analysis because consumption patterns may reflect the traditional or cultural practices of 

minority and low-income populations in the area, such as migrant workers or Native Americans.

Section 4–4 of Executive Order 12898 (1994) directs Federal agencies, whenever practical and 

appropriate, to collect and analyze information about 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, the NRC considered whether there were any 

means for minority or low-income populations to be disproportionately affected by examining 

impacts on American Indian, Hispanics, migrant workers, and other traditional lifestyle special 

pathway receptors. The assessment of special pathways considered the levels of radiological 

and nonradiological contaminants in vegetation, crops, soils and sediments, groundwater, 

surface water, fish, and game animals on or near LSCS.

Radionuclides released to the atmosphere may deposit on soil and vegetation and, therefore, 

may eventually be incorporated into the human food chain. To assess the impact of LSCS

operations to humans from the ingestion pathway, samples of fish, milk, green leafy vegetables, 

surface water, sediment, and groundwater are collected and analyzed for radioactivity. The 

following describes Exelon’s radiological environmental monitoring program (REMP).

Exelon has an ongoing comprehensive REMP to assess the impact of LSCS operations on the 

environment. To assess the impact of nuclear power plant operations, samples are collected 

annually from the environment and analyzed for radioactivity. A plant effect would be indicated 

if the radioactive material detected in a sample were larger or higher than background levels. 

Two types of samples are collected. The first type, a control sample, is collected from areas 

that are beyond the influence of the nuclear power plant or any other nuclear facility. These 

samples are used as reference data to determine normal background levels of radiation in the 

environment. These samples are then compared with the second type of samples, indicator 

samples, collected near the nuclear power plant. Indicator samples are collected from areas 

where any contribution from the nuclear power plant will be at its highest concentration. These 

samples are then used to evaluate the contribution of nuclear power plant operations to 

radiation or radioactivity levels in the environment. An effect would be indicated if the 

radioactivity levels detected in an indicator sample were larger or higher than the control sample 

or background levels.

Samples were collected from the aquatic and terrestrial environment in the vicinity of LSCS in 

2014. The aquatic environment includes groundwater, surface water, fish, and river sediment. 

Aquatic monitoring results for 2014 of water, sediment, and fish showed only naturally occurring 
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radioactivity and radioactivity associated with fallout from past atmospheric nuclear weapons 

testing and were consistent with levels measured prior to the operation of LSCS. No 

radioactivity was detected greater than the minimum detectable activity in any aquatic sample 

during 2014, and no adverse long-term trends were identified in aquatic monitoring data 

(Exelon 2015a).

The terrestrial environment includes airborne particulates, milk, and food products (i.e., beets, 

kohlrabi, potatoes, Swiss chard, and kale). However, cow milk samples were not analyzed in 

2014, as the dairy herd was sold prior to the first sample in 2014 (Exelon 2015a). Terrestrial 

monitoring results for 2014 of groundwater and leafy garden vegetable samples, showed only 

naturally occurring radioactivity. The radioactivity levels detected were consistent with levels 

measured prior to the operation of LSCS. No radioactivity was detected greater than the 

minimum detectable activity in any terrestrial samples during 2014. The terrestrial monitoring 

data also showed no adverse trends in the terrestrial environment (Exelon 2015a).

Analyses performed on 1,393 samples collected from the environment at LSCS in 2014 showed 

no significant measurable radiological constituent above background levels. Overall, 

radioactivity levels detected in 2014 were consistent with previous levels, as well as radioactivity 

levels measured prior to the operation of LSCS. REMP sampling in 2014 did not identify any 

radioactivity above the minimum detectable activity (Exelon 2015a).

Based on the radiological environmental monitoring data from LSCS, the NRC staff finds that 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 water, 

local food, fish, and wildlife. Continued operation of LSCS would not have disproportionately 

high and adverse human health and environmental effects on these populations.

4.12.2 No-Action Alternative

This section evaluates the potential for disproportionately high and adverse human health and 

environmental effects on minority and low-income populations that could result from the 

no-action alternative. Impacts on minority and low-income populations would depend on the 

number of jobs and the amount of tax revenues lost by communities in the immediate vicinity of 

the power plant after LSCS ceases operations. Not renewing the operating licenses and 

terminating reactor operations would have a noticeable impact on socioeconomic conditions in 

the communities located near LSCS. The loss of jobs and income would have an immediate 

socioeconomic impact. Some, but not all, of the approximately 890 employees would begin to 

leave after reactor operations are terminated; and overall tax revenue generated by plant 

operations would be reduced. The reduction in tax revenue would decrease the availability of 

public services in LaSalle County. This could disproportionately affect minority and low-income 

populations that may have become dependent on these services. See also Appendix J of 

NUREG–0586, Supplement 1 (NRC 2002), for additional discussion of these impacts.

4.12.3 New Nuclear Alternative

This section 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 nuclear power plant. Some of these potential effects have 

been identified in resource areas discussed in this SEIS. For example, increased demand for 

rental housing during replacement power plant construction could disproportionately affect 

low-income populations. Everyone living near the proposed power plant site could be affected 

by the construction and operation of a new nuclear power plant, including minority and 

low-income populations.
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Potential impacts to minority and low-income populations from the construction and operation of 

a new nuclear power plant at an existing nuclear power plant or retired coal plant site would 

mostly consist of environmental and socioeconomic effects (e.g., noise, dust, traffic, 

employment, and housing impacts). Noise and dust impacts from construction would be short

term and primarily limited to onsite activities. Minority and low-income populations residing 

along site access roads would be affected by increased commuter vehicle traffic during shift 

changes and truck traffic. However, these effects would be temporary during certain hours of 

the day and would not likely be high and adverse. Increased demand for rental housing during 

construction could affect low-income populations. However, given the proximity of some 

existing nuclear power plant or retired coal plant sites to metropolitan areas, construction 

workers could commute to the site, thereby reducing the potential demand for rental housing.

Potential impacts to minority and low-income populations from new nuclear power plant 

operations would mostly consist of radiological effects; however, radiation doses are expected 

to be well below regulatory limits. All people living near the new nuclear power plant would be 

exposed to the same potential effects from power plant operations, and permitted air emissions 

are expected to remain within regulatory standards.

Based on this information and the analysis of human health and environmental impacts 

presented in this SEIS, it is not likely that the construction and operation of a new nuclear power 

plant would have disproportionately high and adverse human health and environmental effects 

on minority and low-income populations. However, this determination would depend on the 

location, plant design, and operational characteristics of the new power plant. Therefore, the 

NRC staff cannot determine whether this alternative would result in disproportionately high and 

adverse human health and environmental effects on minority and low-income populations.

4.12.4 IGCC Alternative

This section 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 IGCC power plant. Some of these potential effects have 

been identified in resource areas discussed in this SEIS. For example, increased demand for 

rental housing during replacement power plant construction could disproportionately affect 

low-income populations. Everyone living near the proposed power plant site could be affected 

by the construction and operation of a new IGCC power plant, including minority and 

low-income populations.

Potential impacts to minority and low-income populations from the construction and operation of 

a new IGCC plant at the LSCS site or at another existing power plant site would consist of 

environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

impacts). Noise and dust impacts from construction would be short term and primarily limited to 

onsite activities. Minority and low-income populations residing along site access roads would 

be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

However, these effects would be temporary during certain hours of the day and would not likely 

be high and adverse. Increased demand for rental housing during construction could affect 

low-income populations. However, given the proximity of some existing power plant sites to 

Chicago (LSCS site) and other metropolitan areas (at another existing power plant site), 

construction workers could commute to the site, thereby reducing the potential demand for 

rental housing.

Emissions from the IGCC plant during power plant operations could disproportionately affect 

minority and low-income populations. However, permitted air emissions are expected to remain 

within regulatory standards.
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Based on this information and the analysis of human health and environmental impacts 

presented in this SEIS, it is not likely that the construction and operation of a new IGCC plant 

would have disproportionately high and adverse human health and environmental effects on 

minority and low-income populations. However, this determination would depend on the 

location, plant design, and operational characteristics of the new power plant at the LSCS site or 

at another existing power plant site. Therefore, the NRC staff cannot determine whether this 

alternative would result in disproportionately high and adverse human health and environmental 

effects on minority and low-income populations.

4.12.5 NGCC Alternative 

This section 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 NGCC plant. Some of these potential effects have been 

identified in resource areas discussed in this SEIS. For example, increased demand for rental 

housing during replacement power plant construction could disproportionately affect low-income 

populations. Everyone living near the proposed power plant site could be affected by the 

construction and operation of a new NGCC power plant, including minority and low-income 

populations.

Potential impacts to minority and low-income populations from the construction and operation of 

a new NGCC plant at the LSCS site would mostly consist of environmental and socioeconomic 

effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise and dust impacts 

from construction would be short term and primarily limited to onsite activities. Minority and 

low-income populations residing along site access roads would be affected by increased 

commuter vehicle traffic during shift changes and truck traffic. However, these effects would be 

temporary during certain hours of the day and would not likely be high and adverse. Increased 

demand for rental housing during construction could affect low-income populations in the vicinity 

of the LSCS site. However, given the proximity of LSCS to the Chicago metropolitan area, 

many construction workers could commute to the site, thereby reducing the potential demand 

for rental housing.

Emissions from the NGCC plant during power plant operations could disproportionately affect 

minority and low-income populations living in the vicinity of the new power plant. However, 

permitted air emissions are expected to remain within regulatory standards.

Based on this information and the analysis of human health and environmental impacts 

presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant 

would have disproportionately high and adverse human health and environmental effects on 

minority and low-income populations. However, this determination would depend on the 

location, plant design, and operational characteristics of the new power plant at LSCS. 

Therefore, the NRC staff cannot determine whether this alternative would result in 

disproportionately high and adverse human health and environmental effects on minority and 

low-income populations.

4.12.6 Combination Alternative (NGCC, Wind, Solar)

This section 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 of NGCC, wind, and solar PV electrical power 

generating activities. Some of these potential effects have been identified in resource areas 

discussed in this SEIS. For example, increased demand for rental housing during construction 

could disproportionately affect low-income populations. Everyone living near the new NGCC, 
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wind farms, and solar PV installations could be affected by construction activities and facility 

operations, including minority and low-income populations.

Potential impacts to minority and low-income populations from the construction and operation of 

a new NGCC plant, wind turbines, and solar PV installations would mostly consist of 

environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

impacts). Noise and dust impacts from construction would be short term and primarily limited to 

onsite activities. Minority and low-income populations residing along site access roads would 

be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

However, these effects would be temporary during certain hours of the day and would not likely 

be high and adverse. Increased demand for rental housing during construction could affect 

low-income populations. However, given the small number of construction workers and the 

possibility that many workers could commute to these construction sites, the potential need for 

rental housing would not be significant.

Minority and low-income populations living in close proximity to wind farm and solar PV power 

generating installations could be disproportionately affected by maintenance and operations 

activities. However, operational impacts from the wind turbines and solar PV installations would 

mostly be limited to noise and aesthetic effects.

Based on this information and the analysis of human health and environmental impacts 

presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant, 

wind farms, and solar PV installations would have disproportionately high and adverse human 

health and environmental effects on minority and low-income populations. However, this 

determination would depend on the location, plant design, and operational characteristics of 

these new power generating facilities. Therefore, the NRC staff cannot determine whether this 

alternative would result in disproportionately high and adverse human health and environmental 

effects on minority and low-income populations.

4.12.7 Purchased Power Alternative

This section evaluates the potential for disproportionately high and adverse human health and 

environmental effects on minority and low-income populations that could result from purchasing 

electric power. As previously discussed, such effects may include human health, biological, 

cultural, economic, or social impacts.

Purchased power from existing power generating facilities would not likely have any 

disproportionately high and adverse effects on minority populations, because there would be no 

change in power plant operations or workforce. However, low-income populations could be 

disproportionately affected by increased utility bills, due to the cost of purchased power, 

although programs are available to assist low-income families in paying for increased electrical 

costs.

If the amount of purchased power needed exceeds the available supply, new electric power 

generating facilities would be needed. Construction and operation of a new electrical power 

generating facility to supply purchased power could create new human health and 

environmental effects in communities located near the new facility. Everyone living near the 

new electric power generating facility could be affected by construction activities and facility 

operations, including minority and low-income populations.

Potential human health and environmental effects from constructing and operating a new power 

generating facility have been described in the previous sections. Operational impacts for all 

new power generating facilities would mostly be limited to noise, air emissions, and aesthetic

effects. Minority and low income populations could experience disproportionate human health 
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and environmental effects from the emissions from fossil-fueled power plants (e.g., increased 

asthma). However, any human health or environmental effects would depend on the location of 

the new power plant in relation to minority and low-income communities and the magnitude of 

the change in ambient air quality conditions. Also, permitted air emissions would be expected to 

remain within regulatory standards.

Based on this information and the analysis of human health and environmental impacts 

presented in this SEIS, it is not likely that purchasing electrical power from existing power 

generating facilities would have disproportionately high and adverse human health and 

environmental effects on minority and low-income populations. In addition, this determination 

would depend on whether a new electrical power generating facility were needed to supply 

purchased power. If a new power generating facility is needed, impacts to minority and 

low-income populations would depend on the location, plant design, and operational 

characteristics of these new power generating facilities. Therefore, the NRC staff cannot 

determine whether this alternative would result in disproportionately high and adverse human 

health and environmental effects on minority and low-income populations.

4.13 Waste Management

This section describes the potential impacts of the proposed action (license renewal) and 

alternatives to the proposed action on waste management and pollution prevention.

4.13.1 Proposed Action

Section 3.12 describes LSCS waste management and pollution prevention. Table 4–18 

identifies the waste management issues applicable to LSCS during the license renewal term. 

Table 4–18. Waste Management Issues

Issue GEIS Section Category

Low-level waste storage and disposal 4.11.1.1 1

Onsite storage of spent nuclear fuel 4.11.1.2(a) 1

Offsite radiological impacts of spent nuclear fuel and high-level waste

disposal

4.11.1.3(b) 1

Mixed-waste storage and disposal 4.11.1.4 1

Nonradioactive waste storage 4.11.1.4 1

(a) The environmental impact of this issue for the time frame beyond the licensed life for reactor operations is 

contained in NUREG–2157 (NRC 2014).

(b) The environmental impact of this issue is contained in NUREG–2157 (NRC 2014).

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

The NRC staff’s evaluation of the environmental impacts associated with spent nuclear fuel is 

addressed in two issues in Table 4–18, “Onsite storage of spent nuclear fuel” and “Offsite 

radiological impacts of spent nuclear fuel and high-level waste disposal.” The issue of onsite 

storage of spent nuclear fuel now incorporates the generic environmental impact determinations 

codified in Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51 and in the revised 

10 CFR 51.23, pursuant to the Continued Storage Rule (79 FR 56238).

4

 The issue of offsite 

 4 79 FR 56238. U.S. Nuclear Regulatory Commission. “Continued Storage of Spent Nuclear Fuel.”

Federal Register 79 (182): 56238–56263. September 19, 2014.
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radiological impacts of spent nuclear fuel and high-level waste disposal are codified in 

Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51, and the technical feasibility of disposal 

in a geologic repository is discussed in NUREG–2157, Generic Environmental Impact 

Statement for Continued Storage of Spent Nuclear Fuel, Volumes 1 and 2 (NRC 2014). 

The NRC staff did not identify any new and significant information related to waste management 

issues listed in Table 4–18 during its review of the applicant’s ER (Exelon 2014a), the site visit, 

or the scoping process. Therefore, there are no impacts related to these issues beyond those 

discussed in the GEIS (NRC 2013d) and NUREG–2157 (NRC 2014). During the license 

renewal term, for these Category 1 issues discussed in the GEIS, the NRC staff concludes that 

the impacts are SMALL.

4.13.2 No-Action Alternative

If the no-action alternative were implemented, LSCS would cease operation at the end of the 

term of the initial operating licenses, or sooner, and enter decommissioning. The plants, which 

are currently operating within regulatory limits, would generate less spent nuclear fuel and emit 

less gaseous and liquid radioactive effluents into the environment. In addition, following 

shutdown, the variety of potential accidents at the plants (radiological and industrial) would be 

reduced to a limited set associated with shutdown events and fuel handling and storage. 

Therefore, as radioactive emissions to the environment decrease, and the likelihood and variety 

of accidents decrease following shutdown and decommissioning, the NRC staff concludes that 

impacts from implementation of the no-action alternative would be SMALL.

4.13.3 New Nuclear Alternative

Construction-related debris would be generated during construction activities and would be 

recycled or disposed of in approved landfills.

During normal plant operations, routine plant maintenance, and cleaning activities would 

generate radioactive low-level waste, spent nuclear fuel, and high-level waste, as well as 

nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 

management at LSCS. Quantities of radioactive and nonradioactive waste generated by LSCS 

would be comparable to that generated by the two new nuclear plants.

According to the GEIS (NRC 2013d), the generation and management of solid radioactive and 

nonradioactive waste during the license renewal term are not expected to result in significant 

environmental impacts.

Based on this information, the waste impacts would be SMALL for the new nuclear alternative.

4.13.4 IGCC Alternative

Construction-related debris would be generated during plant construction activities and would 

be recycled or disposed of in approved landfills.

Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 

for controlling air pollution generates additional ash, spent selective catalytic reduction (SCR) 

catalyst, and scrubber sludge. The management and disposal of the large amounts of coal 

combustion waste is a significant part of the operation of a coal-fired power generating facility.

Although an IGCC facility is likely to use offsite disposal of coal combustion waste, some 

short-term storage of coal combustion waste (either in open piles or in surface impoundments) 

is likely to take place on site, thus establishing the potential for leaching of toxic chemicals into 

the local environment.
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The impacts of managing the substantial amounts of solid waste, especially fly ash and 

scrubber sludge, generated during operation of this alternative would be MODERATE 

(NRC 1996). The amount of the construction waste would be small compared to the amount of 

waste generated during the operational stage and much of it could be recycled (i.e., marketed 

for beneficial use). Therefore, the NRC staff concludes that the overall waste management 

impacts from construction of this alternative would be SMALL and from operation of this 

alternative would be MODERATE.

4.13.5 NGCC Alternative

Construction-related debris would be generated during plant construction activities, and would 

be recycled or disposed of in approved landfills.

Waste generation from NGCC technology would be minimal. The only significant waste 

generated at an NGCC power plant would be spent SCR catalyst, which is used to control 

nitrogen oxide emissions.

The spent catalyst would be regenerated or disposed of offsite. Other than the spent SCR 

catalyst, waste generation at an operating natural-gas-fired plant would be limited largely to 

typical operations and maintenance of nonhazardous waste. Overall, the NRC staff concludes 

that waste impacts from the NGCC alternative would be SMALL.

4.13.6 Combination Alternative (NGCC, Wind, Solar)

Construction-related debris would be generated during construction activities and would be 

recycled or disposed of in approved landfills.

Waste generation from NGCC technology is discussed in Section 4.13.5.

Waste generation from a combination of wind and solar PV alternatives would be minimal, 

consisting of debris from routine maintenance and the disposal of worn or broken parts. Based 

on this information, the NRC staff concludes that waste impacts from the construction and 

operation of a combination wind and solar PV alternative would be SMALL.

4.13.7 Purchased Power Alternative

The types of waste generated by the alternative electricity generation sources (i.e., coal, natural 

gas, nuclear, and wind) used in the purchased power alternative are discussed in 

Sections 4.13.3, 4.13.4, 4.13.5, and 4.13.6. Depending on types of power generation plants 

used to provide the electricity for the purchased power alternative, the NRC staff concludes that 

the waste management impacts would range from SMALL to MODERATE.

4.14 Evaluation of New and Potentially Significant Information

New and significant information must be new based on a review of the GEIS (NRC 2013d) as 

codified in Table B–1 of Appendix B to Subpart A of 10 CFR Part 51, and must bear on the 

proposed action or its impacts, presenting a seriously different picture of the impacts from those 

envisioned in the GEIS (i.e., impacts of greater severity than impacts considered in the GEIS, 

considering their intensity and context).

In accordance with 10 CFR 51.53(c), the ER that the applicant submits must provide an analysis 

of the Category 2 issues in Table B–1 of 10 CFR Part 51, Subpart A, Appendix B. Additionally, 

it must discuss actions to mitigate any adverse impacts associated with the proposed action and 

environmental impacts of alternatives to the proposed action. In accordance with 
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10 CFR 51.53(c)(3), the ER does not need to contain an analysis of any Category 1 issue 

unless there is new and significant information on a specific issue.

The NRC process for identifying new and significant information is described in NUREG–1555, 

Supplement 1, Standard Review Plans for Environmental Reviews for Nuclear Power Plants, 

Supplement 1: Operating License Renewal (NRC 2013f). The search for new information 

includes: 

• review of an applicant’s ER and the process for discovering and evaluating the 

significance of new information;

• review of public comments;

• review of environmental quality standards and regulations;

• coordination with Federal, state, and local environmental protection and resource 

agencies; and 

• review of technical literature. 

New information that the staff discovers is evaluated for significance using the criteria set forth 

in the GEIS. For Category 1 issues in which new and significant information is identified, 

reconsideration of the conclusions for those issues is limited in scope to assessment of the 

relevant new and significant information; the scope of the assessment does not include other 

facets of an issue that the new information does not affect.

The NRC staff reviewed the discussion of environmental impacts associated with operation 

during the renewal term in the GElS and has conducted its own independent review, including a 

public involvement process (e.g., public meetings) to identify new and significant issues for the 

LSCS license renewal application environmental review. The NRC staff has not identified new 

and significant information on environmental issues related to operation of LSCS during the 

renewal term. The NRC staff also determined that information provided during the public 

comment period did not identify any new issue that requires site-specific assessment.

The NRC staff did, however, find new, but not significant, information regarding the uranium fuel 

cycle issue, and this information is discussed in Section 4.15.1 and Appendix G of this SEIS.

4.15 Impacts Common to All Alternatives

This section describes the impacts that are considered common to all alternatives discussed in 

this SEIS, including the proposed action and replacement power alternatives. The continued 

operation of a nuclear power plant and replacement fossil fuel power plants both involve the 

mining, processing, and consumption of fuel, which results in comparative impacts 

(NRC 2013d). In addition, the termination of operations and the decommissioning of both a 

nuclear power plant and replacement fossil-fueled power plants, as well as GHG emissions, are 

discussed in the following sections.

4.15.1 Fuel Cycles

This section describes the environmental impacts associated with the fuel cycles of the 

proposed action and replacement power alternatives. Most replacement power alternatives 

employ a set of steps in the utilization of their fuel sources, which can include extraction, 

transformation, transportation, and combustion. Emissions generally occur at each stage of the 

fuel cycle (NRC 2013d).
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4.15.1.1 Uranium Fuel Cycle

The uranium fuel cycle issues applicable to LSCS are discussed below and listed in Table 4–19 

for Category 1 issues. Table B–1 of Appendix B to Subpart A of 10 CFR Part 51 contains more 

information on these issues.

Table 4–19. Issues Related to the Uranium Fuel Cycle

Issue GEIS Section Category

Offsite radiological impacts—individual impacts from other than the 

disposal of spent fuel and high-level waste

4.12.1.1 1

Offsite radiological impacts—collective impacts from other than the 

disposal of spent fuel and high-level waste

4.12.1.1 1

Nonradiological impacts of the uranium fuel cycle 4.12.1.1 1

Transportation 4.12.1.1 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

The uranium fuel cycle includes uranium mining and milling, 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 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 NUREG–1437 (NRC 2013d).

The NRC staff did not identify any new and significant information related to the uranium fuel 

cycle issues “Offsite radiological impacts—individual impacts from other than the disposal of 

spent fuel and high level waste,” “Offsite radiological impacts—collective impacts from other 

than the disposal of spent fuel and high-level waste,” and “Nonradiological impacts of the 

uranium fuel cycle,” listed above in Table 4–19, during its review of the applicant’s ER 

(Exelon 2014a), the site visit, and 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 issue, “Offsite radiological impacts—

collective impacts,” to which the NRC has not assigned an impact level. This issue assesses 

the 100-year radiation dose to the U.S. population (i.e., collective effects or collective dose) from 

radioactive effluent released as part of the uranium fuel cycle for a nuclear power plant during 

the license renewal term compared to the radiation dose from natural background exposure. It 

is a comparative assessment for which there is no regulatory standard to base an impact level.

The NRC staff did, however, find new information regarding the uranium fuel cycle issue 

“Transportation,” listed above in Table 4–19, in its review of the applicant’s ER. The NRC has 

generically determined, in its license renewal application reviews, that the environmental 

impacts of the transportation of fuel and radioactive wastes to and from nuclear power facilities 

are small for all reactors as long as certain specific conditions are met. The application for 

license renewal of LSCS stated that the specific conditions that allow the transportation impacts 

of spent fuel to be generically determined to be small may not be met for LSCS. Therefore, the 

NRC staff analyzed the environmental impacts of transporting spent fuel from LSCS in 

Appendix G of this SEIS. From this analysis, the NRC staff concludes that the environmental 

impacts of the transportation of spent fuel from LSCS would be consistent with the 

environmental impacts associated with the transportation of fuel and radioactive wastes to and 

from current-generation reactors presented in Table S–4 of 10 CFR 51.52, and thus would be 

SMALL.
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4.15.1.2 Replacement Power Plant Fuel Cycles

Fossil Fuel Energy Alternatives

Fuel cycle impacts for a fossil-fuel-fired plant result from the initial extraction of fuel, cleaning 

and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 

solid wastes from fuel combustion. These impacts are discussed in more detail in 

Section 4.12.1.2 of the GEIS (NRC 2013d) and can generally include:

• significant changes to land use and visual resources;

• impacts to air quality, including release of criteria pollutants, fugitive dust, VOCs, and 

coalbed methane in the atmosphere;

• noise impacts;

• geology and soil impacts due to land disturbances and mining;

• water resource impacts, including degradation of surface water and groundwater

quality;

• ecological impacts, including loss of habitat and wildlife disturbances;

• historic and cultural resources impacts within the mine footprint;

• socioeconomic impacts from employment of both the mining workforce and service 

and support industries;

• environmental justice impacts;

• health impacts to workers from exposure to airborne dust and methane gases; and

• generation of coal and industrial wastes.

New Nuclear Energy Alternatives

Uranium fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport 

of fuel to the facility, and management and ultimate disposal of spent fuel. The environmental 

impacts of the uranium fuel cycle are discussed above in Section 4.15.1.1.

Renewable Energy Alternatives

The “fuel cycle” for renewable energy facilities is difficult to define for technologies such as wind 

and solar because these natural resources exist regardless of any effort to harvest them for 

electricity production. Impacts from the presence or absence of these renewable energy 

technologies are often difficult to determine (NRC 2013d).

4.15.2 Terminating Power Plant Operations and Decommissioning

This section describes the environmental impacts associated with the termination of operations 

and the decommissioning of a nuclear power plant and replacement power alternatives. All 

operating power plants will terminate operations and be decommissioned at some point after the 

end of their operating life or after a decision is made to cease operations. For the proposed 

action, license renewal would delay this eventuality for an additional 20 years beyond the 

current license period, which ends in 2022 and 2023 for LSCS Units 1 and 2, respectively.

4.15.2.1 Existing Nuclear Power Plant

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 Supplement 1 of 
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NUREG–0586 (NRC 2002). Additionally, the incremental environmental impacts associated 

with decommissioning activities resulting from continued plant operation during the renewal term 

are discussed in the GEIS.

Table 4–20 lists the Category 1 issue in Table B–1 of Title 10 of the CFR Part 51, Subpart A, 

Appendix B, that is applicable to LSCS decommissioning following the license renewal term.

Table 4–20. Issues Related to Decommissioning

Issue GEIS Section Category

Termination of plant operations and decommissioning 4.12.2.1 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

Decommissioning would occur whether LSCS were shut down at the end of its current operating 

license or at the end of the period of the license renewal term. Exelon stated in its ER 

(Exelon 2014a) that it is not aware of any new and significant information on the environmental 

impacts of LSCS during the license renewal term. The NRC staff has not found any new and 

significant information during its independent review of Exelon’s ER, the site visit, or the scoping

process. Therefore, the NRC staff concludes that there are no impacts related to 

decommissioning, beyond those discussed in the GEIS, which concluded that the impacts are 

SMALL.

4.15.2.2 Replacement Power Plants

Fossil Fuel Energy Alternatives

The environmental impacts from the termination of power plant operations and 

decommissioning of a fossil-fuel-fired plant are dependent on the facility’s decommissioning 

plan. General elements and requirements for a fossil fuel plant decommissioning plan are 

discussed in Section 4.12.2 of the GEIS and can include the removal of structures to at least 

3 ft (1 m) below grade; removal of all coal, combustion waste, and accumulated sludge; removal 

of intake and discharge structures; and the cleanup and remediation of incidental spills and 

leaks at the facility. The decommissioning plan outlines the actions necessary to restore the 

site to a condition equivalent in character and value to the greenfield or brownfield site on which 

the facility was first constructed (NRC 2013d).

The environmental consequences of decommissioning are discussed in Section 4.12.2 of the 

GEIS and can generally include:

• short-term impacts on air quality and noise from the deconstruction of facility 

structures,

• short-term impacts on land use and visual resources,

• long-term reestablishment of vegetation and wildlife communities,

• socioeconomic impacts due to the decommissioning workforce and the long-term 

loss of jobs, and
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• elimination of health and safety impacts on operating personnel and the general 

public.

New Nuclear Alternative

Termination of operations and decommissioning impacts for a nuclear plant include all activities 

related to the safe removal of the facility from service and the reduction of residual radioactivity 

to a level that permits release of the property under restricted conditions or unrestricted use and 

termination of a license (NRC 2013d). The environmental impacts of the uranium fuel cycle are 

discussed above in Section 4.15.1.1.

Renewable Alternative

Termination of power plant operation and decommissioning for renewable energy facilities 

would be similar to the impacts discussed for fossil-fuel-fired plants above. Decommissioning 

would involve the removal of facility components and operational wastes and residues in order 

to restore the site to a condition equivalent in character and value to the greenfield or brownfield 

site on which the facility was first constructed (NRC 2013d).

4.15.3 Greenhouse Gas Emissions and Climate Change

The following sections discuss GHG emissions and climate change impacts. Section 4.15.3.1 

evaluates GHG emissions associated with operation of LSCS and replacement power

alternatives. Section 4.15.3.2 discusses the observed changes in climate, the potential future 

climate change during the license renewal term based on climate model simulations under 

future global GHG emission scenarios, and the impacts of climate change on affected 

resources. The cumulative impacts of global GHG emissions on climate are discussed in 

Section 4.16.11, “Global Climate Change.”

4.15.3.1 Greenhouse Gas Emissions from the Proposed Project and Alternatives

Gases found in the Earth’s atmosphere that trap heat and play a role in the Earth’s climate are 

collectively termed GHG. GHGs include carbon dioxide (CO2); methane (CH4); nitrous 

oxide (N2O); water vapor (H2O); and fluorinated gases, such as hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The Earth’s climate responds to 

changes in concentrations of GHGs in the atmosphere because GHGs affect the amount of 

energy absorbed and heat trapped by the atmosphere. Increasing GHG concentrations in the 

atmosphere generally increases Earth’s surface temperature. Atmospheric concentrations of 

carbon dioxide, methane, and nitrous oxide have significantly increased since 1750 

(IPCC 2007c, 2013). Carbon dioxide, methane, nitrous oxide, water vapor, and fluorinated 

gases (termed long-lived GHGs) are well mixed throughout the Earth’s atmosphere, and their 

impact on climate is long lasting as a result of their long atmospheric lifetime (EPA 2009a). 

Carbon dioxide is of primary concern for global climate change, due to its long atmospheric 

lifetime, and it is the primary gas emitted as a result of human activities. Climate change 

research indicates that the cause of the Earth’s warming over the last 50 years is due to the 

buildup of GHGs in the atmosphere resulting from human activities (USGCRP 2014; 

IPCC 2013). The EPA has determined that GHGs “may reasonably be anticipated both to 

endanger public health and to endanger public welfare” (74 FR 66496).

Proposed Action

Operation of LSCS emits GHGs directly and indirectly. LSCS’s direct GHG emissions result 

from stationary combustion sources (i.e., diesel generators on site), refrigerant appliances that 

contain fluorinated gases, LSCS’s carbon dioxide injection system and fire protection system, 

and use of sulfur hexafluoride to locate leaks in condensers (Exelon 2015d). Indirect GHG 
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emissions originate from mobile combustion sources (employee vehicle GHG emissions and 

nonroad equipment) and purchased electricity generated off site. 

Annual direct GHG emissions at LSCS and indirect GHG emissions attributable to purchased 

electricity generated off site are presented in Table 4–21 for the 2010 to 2014 timeframe. 

Employee vehicle GHG emissions are not provided in Table 4–21 because Exelon does not 

compile or report GHG data for mobile sources. The NRC staff estimates annual GHG 

emissions resulting from employee vehicles to be approximately 9,400 metric tons (MT) per 

year of carbon dioxide equivalent emissions.

Table 4–21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)

Year

Stationary Combustion 

Sources(a)

Fugitive 

Emissions(b)

Purchased 

Electricity(c)

Refrigerant-Related 

Sources(d) Total

2010 1,022 1,355 34,260 1,104 37,741

2011 322 2,980 33,493 629 37,424

2012 350 1,792 36,066 360 38,568

2013 245 2,508 30,520 955 34,228

2014 605 4,566 32,978 474 38,623

(a) Stationary combustion sources include emissions from large (greater than 600 horsepower) and small (less than 

600 horsepower) diesel engines. These emissions were calculated based on fuel-use data and EPA AP-42 

emission factors.

(b) Fugitive emissions account for LSCS’s (1) CO2 injection system used to adjust pH in the cooling pond, (2) the CO2

fire protection system, and (3) SF6 used to locate leaks in the condensers. These emissions assume that all 

purchased CO2 and SF6 were released.

(c) Purchased electricity emissions were calculated based on monthly billings from the offsite electricity supplier for 

LSCS.

(d) Refrigerant-related sources include emissions from direct HFC/PFC refrigerants and ozone-depleting refrigerants. 

The emissions assume all purchased refrigerants were released.

Key: MT/yr of CO2e = metric ton(s) per year of carbon dioxide equivalent (emissions).

Source: Exelon 2015d

No-Action Alternative

As discussed in previous no-action alternative sections, the no-action alternative represents a 

decision by the NRC not to renew the operating license of a nuclear power plant beyond the 

current operating license term. At some point, all nuclear plants will terminate operations and 

undergo decommissioning. Under the no-action alternative, plant operations for LSCS would 

terminate at or before the end of the current license term. When the plant stops operating, a 

reduction in GHG emissions from activities related to plant operation, such as use of diesel 

generators and employee vehicles, will occur. The GHG emissions are anticipated to be less 

than those presented in Table 4–21.

New Nuclear Alternative

As discussed in Section 2.2.2.1, the NRC staff evaluated the new nuclear power plant 

alternative that would consist of two units with an approximate generating capacity of

1,120 megawatt electric (MWe) each. The GEIS (NRC 2013d) presents life-cycle GHG 

emissions associated with nuclear power generation. As presented in Tables 4.12–4 
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through 4.12–6 of the GEIS, life-cycle5 GHG emissions from nuclear power generation can 

range from 1 to 288 grams of carbon equivalent per kilowatt hour (g Ce/kWh). Operation of 

nuclear power plants does not burn fossil fuels to generate electricity and, therefore, does not 

emit GHG emissions. Sources of GHG emissions include stationary combustion sources 

(e.g., emergency diesel generators and diesel-driven pumps) and mobile sources (e.g., worker 

vehicles, onsite heavy equipment, support vehicles, delivery of materials, and disposal of 

wastes). It is anticipated that air emissions from a new nuclear power plant would be similar to 

those from LSCS.

IGCC Generation Alternative

As discussed in Section 2.2.2.2, the NRC staff evaluated the IGCC plant alternative that would 

consist of four 618-MWe units for a total 2,472 MW. The GEIS presents life-cycle GHG 

emissions associated with coal power generation. As presented in Table 4.12–4 of the GEIS, 

life-cycle GHG emissions from coal power generation can range from 264 to 1,689 g Ceq/kWh. 

However, these life-cycle emission factors are for conventional coal power plants; recent studies 

estimate life-cycle GHG emissions for an IGCC plant to be 937 kilograms of carbon dioxide 

equivalent per megawatt-hour (kg CO2e/MWh) (NETL 2012). The NRC staff estimates that 

operation of the IGCC alternative directly will emit about 14.3 million tons per year 

(13.0 million MT per year) of carbon dioxide equivalent emissions. 

NGCC Generation Alternative

As discussed in Section 2.2.2.3, the NRC staff evaluated an NGCC alternative that consists of 

five NGCC 560-MWe units (total 2,800 MWe). The GEIS presents life-cycle GHG emissions 

associated with natural gas power generation. As presented in Table 4.12–5 of the GEIS, 

life-cycle GHG emissions from natural gas can range from 120 to 930 g Ceq/kWh. The NRC 

staff estimates that operation of the NGCC alternative directly will emit about 9.8 million tons 

(8.2 million MT) per year of carbon dioxide equivalent emissions.

Combination Alternative (NGCC, Wind, and Solar)

As discussed in Section 2.2.2.4, the NRC staff evaluated an alternative that relies on NGCC 

(15 percent), wind (75 percent), and solar (10 percent) capacity to replace LSCS. The 

combination alternative would consist of a 360-MWe NGCC unit, a 227-MWe solar PV facility, 

and a 1,813-MWe windfarm. For this combination alternative, it is assumed that the majority of 

the GHG emissions result from the NGCC portion only because renewable portions (wind and 

solar PV) do not burn fossil fuels to generate electricity. As discussed in Section 4.3.5., GHG 

emissions associated with the operation of the NGCC portion are reduced proportionally

because its electricity output is approximately 13 percent that of the NGCC alternative. The 

NRC staff estimates that operation of the combination alternative will directly result in about 

1.3 million tons (1.2 million MT) per year of carbon dioxide equivalent emissions.

Purchased Power Alternative

Purchased power would come from common types of existing technology (coal, natural gas, 

nuclear, and renewable sources) within the ROI. GHG emissions from purchased power will 

vary and will depend on the type and combination of technology from which purchased power 

originates. In 2014, coal, natural gas, and nuclear power accounted for 39-, 27-, and 19-percent 

shares, respectively, of total U.S. electricity generation (EIA 2015b). Using these percentage 

shares for the purchased power alternative, the NRC staff estimates 8.0 million ton 

(7.3 million MT) per year of carbon dioxide equivalent emissions. However, GHG emissions 

 5 Life-cycle carbon emissions analyses consider construction, operation, decommissioning, and 

associated processing of fuel (e.g., gas and coal).
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may be greater or less than this estimate and will depend on the technology from which the 

purchased power originates.

Summary of GHG Emissions from the Proposed Action and Alternatives

Table 4–22 presents the direct GHG emissions from operation of the proposed action and 

alternatives. GHG emissions from the proposed action (license renewal) and the new nuclear 

alternative would be the lowest. GHG emissions for IGCC, NGCC, combination, and purchased 

power alternatives are higher than those for the proposed action and a new nuclear alternative 

by several orders of magnitude. GHG emissions from the purchased power alternative are 

expected to be greater than those from the NGCC alternative but less than those from the IGCC 

alternative.

Table 4–22. Direct(a) GHG Emissions from Operation

of the Proposed Action and Alternatives

Technology CO2e (MT/yr)

LSCS license renewal(a) 5.7x103

New Nuclear(b) 5.7x103

IGCC(c) 13.0x106

NGCC(c) 8.2x106

Combination(d) 1.2x106

Purchased Power(e) 7.3x106

(a) Emissions rounded up from the stationary combustion sources, fugitive, and refrigerant 

related sources emissions (i.e., direct emissions) for the year 2014 from Table 4–21. 

Purchased electricity-related GHG emissions presented in Table 4–21 are indirect emissions

from the offsite electricity supplier for LSCS. Therefore, in order to provide a commensurate 

comparison of direct GHG emissions of the proposed action (LSCS license renewal) and the 

alternatives (i.e., the combustion of natural gas or coal) only the direct emissions from LSCS 

are presented in this table. 

(b) Emissions assumed similar to LSCS operation.

(c) The GHG emissions for the NGCC and IGCC alternatives presented include emissions 

resulting from direct combustion of gas and coal, respectively. 

(d) This is only the NGCC portion of GHG emissions.

(e) Air emissions were estimated by assuming that purchased-power coal accounted for a

39-percent share, natural gas accounted for a 27-percent share, nuclear accounted for a 

19-percent share, and renewables accounted for a 15-percent share of electricity generation.

4.15.3.2 Climate Change Impacts to Resource Areas

Climate change is the decades or longer change in climate measurements (e.g., temperature

and precipitation) that has been observed on a global, national, and regional level (IPCC 2007c; 

EPA 2014; USGCRP 2014). Climate change can vary regionally, spatially, and seasonally,

depending on local, regional, and global factors. Just as regional climate differs throughout the 

world, the impacts of climate change can vary between locations.

On a global level, from 1901 to 2013, average surface temperatures rose at a rate of 0.15  ̊F 

(0.08  ̊C) per decade, and total annual precipitation increased at an average rate of 0.2 percent 

per decade (EPA 2014). The observed global change in average surface temperature and 

precipitation has been accompanied by an increase in sea surface temperatures, a decrease in 

global glacier ice, an increase in sea level, and changes in extreme weather events. Such 
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extreme events include an increase in the frequency of heat waves, heavy precipitation, and 

recorded maximum daily high temperatures (IPCC 2007c; USGCRP 2009, 2014; EPA 2014).

In the United States, the U.S. Global Change Research Program (USGCRP) reports that, from 

1895 to 2012, average surface temperature increased by 1.3 °F to 1.9 °F (0.72 to 1.06 °C) and,

since 1900, average annual precipitation has increased by 5 percent. On a seasonal basis, 

warming has been the greatest in winter and spring. Since the 1980s, an increase in the length 

of the frost-free season, the period between the last occurrence of 32  ̊F (0 °C) in the spring and 

first occurrence of 32  ̊F (0 °C) in the fall, has been observed for the contiguous United States; 

between 1991 and 2011, the average frost-free season was 10 days longer than between 1901 

and 1960 (USGCRP 2014). Since the 1970s, the United States has warmed at a faster rate as 

the average surface temperature rose at an average rate of 0.31 to 0.45  ̊F (0.17 to 0.25 °C) per 

decade (EPA 2014). The year 2014 was the warmest on record (AMS 2015). Observed 

climate-related changes in the United States include increases in the frequency and intensity of 

heavy precipitation, earlier onset of spring snowmelt and runoff, rise of sea level in coastal 

areas, increase in occurrence of heat waves, and a decrease in occurrence of cold waves 

(USGCRP 2014).

Temperature data indicate that the Midwest region, where LSCS is located, experienced a 

0.06  ̊C (0.11  ̊F) per decade increase in annual mean temperature during the 1900 to 

2010 period (NOAA 2013). Temperature data for the recent past indicate an increased rate of 

warming for the Midwest region of 0.12 °C (0.22 °F) per decade for the 1950-to-2010 time 

period and a 0.26  ̊C (0.47  ̊F) temperature increase for the 1979-to-2010 time period. Average 

annual precipitation data for the Midwest region exhibit an increasing trend of 0.31 in. (0.79 cm) 

per decade for the long-term period (1895 to 2011) (NOAA 2013). The NRC staff analyzed 

temperature and precipitation trends for the period of 1865 to 2014 in the northeast region 

(Climate Division No. 2) of Illinois (NCDC 2015). Average annual temperatures during this time 

period show large year-to-year variations; however, since 1865, temperatures have increased 

0.1 °F (0.05 °C) per decade. Average annual precipitation also displays year-to-year variations, 

although precipitation has increased at a rate of 0.48 in. (1.2 cm) per decade.

Future global GHG emission concentrations (emission scenarios) and climate models are 

commonly used to project possible climate change. Climate models indicate that over the next 

few decades, temperature increases will continue due to current GHG emission concentrations 

in the atmosphere (USGCRP 2014). Over the longer term, the magnitude of temperature 

increases and climate change effects will depend on both past and future global GHG emissions 

(IPCC 2007c; USGCRP 2009, 2014).

For the license renewal period of LSCS, Units 1 and Unit 2 (2022 to 2042 and 2023 to 2043, 

respectively), climate model simulations (between 2021 and 2050 relative to the reference 

period (1971 to 1999)) indicate an increase in annual mean temperature in the Midwest region 

of 2.5 to 3.5  ̊F (4.5 to 6.3 °C) for both a low- and high-emission-modeled scenario 

(NOAA 2013). The predicted increase in temperature during this time period occurs for all 

seasons, with the largest increase occurring in the summertime (June, July, and August). 

Climate model simulations (for the time period 2021 to 2050) suggest spatial differences in 

annual mean precipitation changes for the Midwest, with northern areas experiencing an 

increase in precipitation and with the southern areas experiencing a decrease in precipitation. 

For Illinois, the models indicate a 0- to 3-percent increase in annual mean precipitation, with fall, 

winter, and spring seasons experiencing precipitation change increases and with the summer 

season experiencing a decrease in precipitation. However, these changes in precipitation were 

only statistically significant under a high-emission-modeled scenario (NOAA 2013).
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The implications of climate change on LSCS operations are outside the scope of the NRC’s 

license renewal environmental review, which documents the potential environmental impacts 

from continued reactor operations. Site-specific environmental conditions are considered when 

siting nuclear power plants, including consideration of meteorological and hydrologic siting 

criteria in 10 CFR Part 100. LSCS was designed and constructed in accordance with the 

General Design Criteria of Appendix A to 10 CFR Part 50. NRC regulations require that plant 

structures, systems, and components important to safety be designed to withstand the effects of 

natural phenomena, such as flooding, without loss of capability to perform safety functions. 

Furthermore, nuclear power plants are required to operate within technical safety specifications

in accordance with the NRC operating license, including coping with natural phenomena 

hazards. The NRC conducts safety reviews before allowing licensees to make operational 

changes due to changing environmental conditions. Additionally, the NRC evaluates nuclear 

power plant operating conditions and physical infrastructure to ensure ongoing safe operations 

through its Reactor Oversight Process. If new information about changing environmental 

conditions becomes available, the NRC will evaluate the new information to determine whether

any safety-related changes are needed at existing nuclear power plants. This process is 

separate and distinct from the NRC’s license renewal environmental review that is conducted in 

accordance with NEPA (42 U.S.C. 4321 et seq.).

Changes in climate have broader implications for public health, water resources, land use and 

development, and ecosystems. For instance, changes in precipitation patterns and an increase 

in air temperature can affect water availability and quality, distribution of plant and animal 

species, land-use patterns, and land cover; these impacts can, in turn, affect terrestrial and 

aquatic habitats. The sections below discuss how future climate change may impact air quality,

land use, water resources, aquatic resources, terrestrial resources, human health, and minority 

and low-income populations in the ROI for LSCS. Although the future effects of climate change 

are uncertain, the following discussions describe the potential implications of climate change in 

affected environmental resource areas.

Air Quality

As discussed above, an increase in average temperatures in Illinois has been observed. 

Despite the strong year-to-year variations, climate models project continued warming in the 

Midwest region during the license renewal period. Air pollutant concentrations result from 

complex interactions between physical and dynamic properties of the atmosphere, land, and 

ocean. The formation, transport, dispersion, and deposition of air pollutants depend, in part, on 

weather conditions (IPCC 2007a). Air pollutant concentrations are sensitive to winds, 

temperature, humidity, and precipitation (EPA 2009a). Hence, climate change can impact air 

quality as a result of the changes in meteorological conditions.

Ozone has been found to be particularly sensitive to climate change (IPCC 2007a; EPA 2009b). 

Ozone is formed, in part, as a result of the chemical reaction of nitrogen oxides and VOCs in the 

presence of heat and sunlight. Nitrogen oxides and VOC sources include both natural 

emissions (e.g., biogenic emissions from vegetation or soils) and human-activity-related 

emissions (e.g., motor vehicles and power plants). Sunshine, high temperatures, and air 

stagnation are favorable meteorological conditions to produce higher levels of ozone 

(IPCC 2007a; EPA 2009a). The emission of ozone precursors also depends on temperature, 

wind, and solar radiation (IPCC 2007a); both nitrogen oxide and biogenic VOC emissions are 

expected to be higher in a warmer climate (EPA 2009b). Although surface temperatures are 

expected to increase in the Midwest, this may not necessarily result in an increase in ozone 

concentrations. The observed correlation between increased ozone concentrations and 

temperature has been found to occur in polluted and urban regions (i.e., those areas where 

ozone concentration are greater than 60 parts per billion). Additionally, increases in ozone 
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concentrations correlated with temperature increases occur in combination with cloud-free 

regions and air stagnation episodes (Jacob and Winner 2009; IPCC 2013). Furthermore, 

climate models do not agree on the sign of ozone response to climate change. Some models 

indicate increases in ozone concentrations with climate change for the Midwest and Northeast 

(e.g., Wu et al. 2008), and others project decreases in ozone concentrations with climates for 

the northern regions of the United States (e.g., Tagaris et al. 2009).

Land Use

Anthropogenic land use is both a contributor to climate change and a receptor of climate change 

impacts (Dale 1997). As described previously in this section, the Midwest will likely experience 

rising temperatures and heavier precipitation events during the proposed license renewal 

period. Agriculture (the major land use in the vicinity of LSCS) and growing urban areas will 

further exacerbate these changes by continuing to inhibit natural ecosystem functions that could 

moderate climate change effects. For instance, air temperatures and near-surface moisture 

levels change in areas where natural vegetation is converted to agricultural use, and higher 

temperatures have been observed in the Midwest as a result of converting land to agricultural 

use (USGCRP 2014). The USGCRP (2014) indicates that land use changes, such as the 

continued expansion of urban areas, paired with climate change effects, such as heavier 

precipitation events, can exacerbate climate change effects, including reduced water filtration 

into the soil and increased surface runoff. Although anthropogenic land uses will contribute to 

climate change in these and other ways, land uses will also be affected by climate change in 

several ways. For instance, plant winter hardiness zones are likely to shift one-half to one full 

zone by the end of the proposed license renewal period (USGCRP 2014). This shift will affect 

the ability to grow certain crops as the Midwest will likely contain plants now associated with the 

Southeast by the end of the century (USGCRP 2014). Additionally, the USGCRP (2014) 

projects that the Midwest will experience a loss in cropland cover and an expansion in exurban 

and suburban areas. Changes in cropland cover and expansion of exurban and suburban 

areas could then reduce the quality and availability of land resources and agricultural 

productivity.

Water Resources

Predicted changes in the timing, intensity, and distribution of precipitation will likely result in 

changes in surface water runoff affecting water availability across the Midwest. As discussed 

above, the Midwest may experience an increase in mean precipitation during the fall, winter, 

and spring and an increase in the frequency and intensity of extreme (heavy) precipitation 

(USGCRP 2014). As cited by the USGCRP, in spite of increased annual average precipitation, 

the loss of moisture from soils because of higher temperatures, along with increased 

evapotranspiration from vegetation and the increased average number of days without 

precipitation, is likely to intensify short-term (seasonal or shorter) droughts across the region 

into the future (USGCRP 2009, 2014). Such conditions can potentially reduce the amount of 

water available for surface runoff and streamflow on a seasonal timeframe. Runoff and 

streamflow at a regional scale for the Midwest region indicate no clear trend during the last half 

century; however, annual runoff and river flow are projected to increase in the upper Midwest.

Climate change impacts on groundwater availability depend on basin geology, frequency and 

intensity of high-rainfall periods, recharge, soil moisture, and groundwater and surface water

interactions (USGCRP 2014). Precipitation and evapotranspiration are key drivers in aquifer 

recharge. Increased precipitation in the fall, winter, and spring is likely to result in increased 

groundwater recharge. More precipitation during these seasons (as opposed to summer) would 

percolate into the groundwater because it would experience lower evaporation and transpiration 

rates. Furthermore, a portion of the winter precipitation would fall as snow. Instead of running 
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off the land, much of the snow is likely to slowly melt in place and contribute to groundwater 

recharge.

Terrestrial Resources

As described above, the Midwest will likely experience rising temperatures and heavier 

precipitation events during the proposed license renewal period. As the climate changes, 

terrestrial resources will either need to be able to tolerate the new physical conditions or shift 

their population range to new areas with a more suitable climate. Scientists currently estimate 

that species are shifting their ranges at a rate of 20 to 36 ft (6.1 to 11 m) in elevation per decade 

and 3.8 to 10.5 mi (6.1 to 16.9 km) in latitude per decade (Chen et al. 2011; Thuiller 2007). 

Although some species may readily adapt to a changing climate, others may be more prone to 

experience adverse effects. For example, species whose ranges are already limited by habitat 

loss or fragmentation or who require very specific environmental conditions may not be able to 

successfully shift their ranges over time. Migratory birds that travel long distances may also be 

disproportionately affected because they may not be able to pick up on environmental clues that 

a warmer, earlier spring is occurring in the United States while overwintering in tropical areas. 

Fraser et al. (2013) found that songbirds overwintering in the Amazon did not leave their winter 

sites earlier, even when spring sites in the eastern United States experienced a warmer spring. 

As a result, the song birds missed periods of peak food availability. For many Midwest species, 

migration to changed habitats is projected to be slow due to flat topography, high latitudes, and 

fragmented habitats (USGCRP 2014). For instance, in its final rule to list the red knot (Calidris 

canutus rufa), a shorebird that uses the Great Lakes during spring and fall migration, FWS cites 

several effects resulting from climate change as factors contributing to the species’ decline 

(79 FR 73705). These effects include habitat loss from sea level rise, asynchronies in the 

timing of annual cycles, and increased frequency of severe storm events. Special status 

species and habitats, such as those that are Federally protected by the ESA, would likely be 

more sensitive to climate changes because these species’ populations are already experiencing 

threats that are endangering their continued existence throughout all, or a significant portion of 

their ranges. Habitat ranges for forest systems in the Midwest, such as paper birch 

(Betula papyrifera), balsam fir (Abies balsamea), and black spruce (Picea mariana), are 

projected to decline across the Midwest as they shift northward, and species that are common 

farther south, such as oaks (Quercus spp.) and pines (Pinus spp.), will expand their range north 

into the Midwest region (USGCRP 2014). Climate changes could also favor non-native, 

invasive species and promote population increases of insect pests and plant pathogens, which 

may be more tolerant to a wider range of climate conditions.

Aquatic Resources

The potential effects of climate change, whether from natural cycles or manmade activities,

could result in changes that could affect aquatic resources in the Illinois River. Raised air 

temperatures could result in higher water temperatures in the cooling pond and in the Illinois 

River and its tributaries. Higher water temperatures would increase the potential for thermal 

effects on aquatic biota, such as fish kills within the cooling pond, and could exacerbate existing 

environmental stressors, such as excess nutrients, sedimentation, and lowered dissolved 

oxygen associated with eutrophication (USGCRP 2014). The Midwest will likely experience an 

increased frequency of extreme rainfall events, which will cause erosion and could lead to a 

decline in water quality (USGCRP 2014). Species that require cleaner waters, such as 

freshwater mussels, could experience further population declines. The USGCRP (2014) 

predicts habitat loss and local extinctions of fish and other aquatic species throughout the 

United States from the combined effects of water withdrawal and climate change. Shifts in 

species assemblages and distributions are also likely as climate change continues 

(USGCRP 2014), which could alter the balance of the aquatic community in the Illinois River. 
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As discussed below under the section entitled, “Terrestrial Resources,” special status species, 

such as those that are Federally protected under the ESA (16 U.S.C. 1531 et seq.), would be 

more sensitive to climate changes. Invasions of non-native species that thrive under a wide 

range of environmental conditions and warmer waters could further disrupt the current 

composition of aquatic communities (NRC 2013d).

Historic and Cultural Resources 

Increases in river levels because of changes in meteorological conditions due to climate change

could result in the loss of historic and cultural resources from flooding, erosion, or inundation. 

Due to water-level changes, some resources could be lost before they could be documented or 

otherwise studied. However, the limited extent of climate change that may occur during the 

20-year license renewal term would not likely result in any significant loss of historic and cultural 

resources at LSCS.

Socioeconomics

Rapid changes in climate conditions could have an impact on the availability of jobs in certain 

industries. For example, tourism and recreation are major job creators in some regions, 

bringing billions of dollars to regional economies. Across the Nation, fishing, hunting, and other 

outdoor activities make important economic contributions to rural economies and are also a part 

of the cultural tradition. A changing climate would mean reduced opportunities for some 

activities in some locations and expanded opportunities for others. Hunting and fishing 

opportunities could also change as animals’ habitats shift and as relationships among species 

are disrupted by their different responses to climate change (USGCRP 2014).

Water-dependent recreation could also be affected (USGCRP 2009). The USGCRP reports 

that increasing heat and humidity associated with climate change in parts of the Midwest region 

by the year 2050 could create unfavorable conditions for summertime outdoor recreation and 

tourism activity (USGCRP 2014). However, the limited extent of climate change that may occur 

during the 20-year license renewal term would not likely cause any significant changes in 

socioeconomic conditions in the vicinity of LSCS.

Human Health

Increasing temperatures due to changes in climate conditions could have an impact on human 

health. However, changes in climate conditions that may occur during the license renewal term 

will not result in any significant change to the impacts discussed in Section 4.11.1 from LSCS’s

radioactive and nonradioactive effluents.

Environmental Justice

Rapid changes in climate conditions could disproportionately affect minority and low-income 

populations. The USGCRP (2009) indicates that “infants and children, pregnant women, the 

elderly, people with chronic medical conditions, outdoor workers, and people living in poverty 

are especially at risk from a variety of climate-related health effects.” Examples of these effects 

include increased heat stress; air pollution; extreme weather events; and diseases carried by 

food, water, and insects. The greatest health burdens related to climate change are likely to fall 

on the poor, especially those lacking adequate shelter and access to other resources, such as 

air conditioning. Elderly people on fixed incomes, who are more likely to be poor, are more 

likely to have debilitating chronic diseases or limited mobility. In addition, the elderly have a 

reduced ability to regulate their own body temperature or the ability to sense when they are too 

hot. According to the USGCRP (2009), the elderly “are at greater risk of heart failure, which is 

further exacerbated when cardiac demand increases in order to cool the body during a heat 

wave.” The USGCRP (2009) also found that people taking medications, such as diuretics for 
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high blood pressure, have a higher risk of dehydration. The USGCRP (2014) reconfirmed the 

previous report findings regarding the risks of climate change on low-income populations and 

also warns that climate change could affect the availability and access to local plant and animal 

species, thus impacting the people who have historically depended on them for food or 

medicine. However, minority and low-income populations at LaSalle are not likely to experience 

disproportionately high and adverse impacts from climate change, based on the expected small 

or slow change, effectively, in the environment during the 20-year license renewal term.

4.16 Cumulative Impacts of the Proposed Action

The NRC staff considered potential cumulative impacts in the environmental analysis of 

continued operation of LSCS during the 20-year license renewal period. Cumulative impacts 

may result when the environmental effects associated with the proposed action are overlaid or 

added to temporary or permanent effects associated with other past, present, and reasonably 

foreseeable actions. Cumulative impacts can result from individually minor, but collectively 

significant, actions taking place over a period of time. An impact that may be SMALL by itself 

possibly could result in a MODERATE or LARGE cumulative impact when it is considered in 

combination with the impacts of other actions on the affected resource. Likewise, if a resource 

is regionally declining or imperiled, even a SMALL individual impact could be important if it 

contributes to, or accelerates, the overall resource decline. 

For the purposes of this cumulative analysis, past actions are those before the receipt of the 

license renewal application; present actions are those related to the resources at the time of 

current operation of the power plant; and future actions are 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 license renewal term. The geographic area over which past, present, 

and reasonably foreseeable actions would occur depends on the type of action considered and 

is described below for each resource area.

To evaluate cumulative impacts, the incremental impacts of the proposed action, as described 

in Sections 4.2 to 4.15, are combined with other past, present, and reasonably foreseeable 

future actions, regardless of which agency (Federal or non-Federal) or person undertakes such 

actions. The NRC staff used the information provided in Exelon’s ER; responses to RAIs; 

information from other Federal, State, and local agencies; scoping comments; and information 

gathered during visits to the LSCS site to identify other past, present, and reasonably 

foreseeable actions. For a project to be considered in the cumulative analysis, the NRC staff 

determined whether it would occur within the noted geographic areas of interest and within the 

period of extended operation, whether it was reasonably foreseeable, and whether there would 

be a potential overlapping effect with the proposed project. For past actions, consideration 

within the cumulative impacts assessment is resource and project specific. In general, the 

effects of past actions are included in the description of the affected environment in Chapter 3, 

which serves as the baseline for the cumulative impacts analysis. However, past actions that 

continue to have an overlapping effect on a resource that potentially could be affected by the 

proposed action are considered in the cumulative analysis. 

Appendix E describes other actions and projects identified during this review and considered in 

the NRC staff’s analysis of the potential cumulative effects. Not all actions or projects listed in 

Appendix E are considered in each resource area because of the uniqueness of the resource 

and its geographic area of consideration.
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4.16.1 Air Quality and Noise 

This section addresses the direct and indirect effects of license renewal on air quality and noise 

when added to the aggregate effects of other past, present, and reasonably foreseeable future 

actions. As described in Section 4.3.1, the incremental impacts on air quality and noise levels 

from the proposed license renewal would be SMALL.

4.16.1.1 Air Quality

The geographic area considered in the cumulative air quality analysis is the county where the 

proposed action is located, as air quality designations for criteria air pollutants are generally 

made at the county level. Counties are further grouped together based on a common airshed—

known as an Air Quality Control Region (AQCR)—to provide for the attainment and 

maintenance of the NAAQS. LSCS is located in LaSalle County, Illinois, which is part of the 

North Central Illinois Intrastate AQCR (40 CFR 81.262). 

With regard to NAAQS criteria pollutants, LaSalle County and the entire North Central Illinois 

Intrastate AQCR are designated as attainment for all NAAQS (40 CFR 81.314). According to 

EPA’s Enforcement and Compliance History Online, there are 20 facilities designated as major6

air emission sources, 9 synthetic minor air emissions sources, and 160 facilities designated as 

minor air emission sources located in LaSalle County (EPA 2015b). LSCS, as discussed in 

Section 3.3.2 of this SEIS, is a synthetic minor air source. Air emissions from permitted sources 

at LSCS are presented in Chapter 3, Table 3–4. There will be no refurbishment-related 

activities during the license renewal period. Additionally, Exelon does not anticipate equipment 

or operational upgrades or replacement activities that would increase air emissions during the 

license renewal term (Exelon 2015c). As a result, the NRC staff expects emissions from LSCS 

during the license renewal period to be similar to those emissions presented in Section 3.3.2. 

Appendix E provides a list of current projects and reasonably foreseeable future actions that 

could contribute to cumulative impacts to air quality. Air emissions sources that contribute to air 

quality identified in Appendix E are currently operating and, given the designated attainment 

status for all NAAQS in LaSalle County, these emissions have not contributed to a violation of 

the NAAQS. Consequently, cumulative impacts to air quality in LaSalle County would be the 

result of changes to present-day emissions and future actions within the county. Development 

and construction activities associated with regional growth of housing, business, and industry, 

as well as associated vehicular traffic, can increase air emissions. Regional air quality 

conditions could deteriorate from the effects of the growth of the county as construction 

activities give rise to dust, exhaust, and emissions that can degrade air quality. Population 

growth is estimated to increase by 4 percent per decade in LaSalle County (LaSalle 

County 2014). Air quality effects of development are monitored through the statewide ambient 

air quality monitoring network. If degradation in air quality is observed, the IEPA can develop air 

quality control programs to mitigate the effects of development. Furthermore, any new 

stationary sources of emissions that would be established in the region would be required to 

apply for an air permit from the IEPA and be operated in accordance with regulatory 

requirements. IEPA will examine the potential air quality impacts using various modeling tools 

to assess any potential changes to compliance with the NAAQS prior to issuing an air permit to 

a new source (or to an existing source that proposes to undergo significant modification).

 6 Major sources emit or have the potential to emit 10 tons per year of any one hazardous air pollutant 

(HAP), 25 tons per year of any combination of HAPs, or 100 tons per year of any other regulated air 

contaminant. A minor source has a potential to emit that is less than the major source thresholds. A 

minor synthetic source is an air pollution source that has a Federally Enforceable State Operating 

Permit (FESOP) with conditions that legally restrict its potential to emit to below threshold levels.
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Climate change can impact air quality as a result of changes in meteorological conditions. Air 

pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 

(EPA 2009a). As discussed in Section 4.15.3.2, ozone levels have been found to be particularly 

sensitive to climate change influences (EPA 2009b; IPCC 2007c). Climate change may make it 

difficult for regions to meet ozone NAAQS (USGCRP 2009). However, as discussed in 

Section 4.15.3, while surface temperatures are expected to increase in the Midwest, this may 

not necessarily result in an increase in ozone concentrations. Changes in air emission 

concentrations will depend on the combination of higher temperatures, current levels of ozone 

(increases in ozone concentrations and temperature correlations have been observed in urban 

regions), stagnant air masses, sunlight, and emissions of pollutant precursors. Furthermore, 

climate models do not agree on the direction of ozone changes (increase or decrease) in 

response to climate change for the Midwest (Wu et al. 2008; Tagaris et al. 2009).

Because of the small quantity of emissions from LSCS and that no emissions increase 

associated with license renewal is expected, the potential for LSCS to contribute to a cumulative 

impact with other air pollutant sources is SMALL. Given the current designated attainment 

status of LaSalle County and few reasonably foreseeable projects that may increase air 

emissions in the region of interest, the NRC staff concludes that, combined with the emissions 

from other past, present, and reasonably foreseeable future actions, cumulative impacts on air 

quality would be SMALL.

4.16.1.2 Noise

Section 3.3.3 presents a summary of noise sources at LSCS and in the vicinity of the site.

Noise levels in the vicinity of a nuclear power plant could increase from planned activities 

associated with urban, industrial, and commercial development. The magnitude of cumulative 

impacts depends on the nuclear plant’s proximity to other noise sources. A 3-A-weighted 

decibels (-dBA) change in sound level is considered barely discernable (FHWA 2011), as 

discussed in Section 3.3.3 of this SEIS. A 3-dBA increase would occur with the placement of 

another identical source over an existing source (e.g., a doubling of the traffic volume). 

Ongoing or foreseeable future projects in and around LSCS, as identified in Appendix E, would 

increase noise levels only in the vicinity of the noise sources. Therefore, contributions to noise 

levels from future actions are limited to projects in the vicinity of LSCS (within a 2 mi (3.3 km) 

radius). 

For example, wind farm projects in the immediate vicinity of LSCS may contribute to noise 

impacts, particularly the Grand Ridge Wind Farm. As discussed in Section 4.3.6, noise impacts 

from wind generation operations would include aerodynamic noise from the turbine rotors and 

mechanical noise from the turbine drivetrain components. Wind-turbine-generated noise will 

vary depending on the speed of the turbine, environmental conditions, and the distance of the 

receptor from the turbine. Exelon stated that any additional noise from installation and 

operation of the wind turbine in the vicinity has been imperceptible (Exelon 2015j). The NRC 

staff identified noise concerns raised by the public regarding wind farm installations in counties 

surrounding LaSalle (News-Gazette 2013, Daily Herald 2010, FarmProgress 2010; 

FairWindEnergy undated). However, the NRC staff did not identify noise concerns raised 

specifically in LaSalle County or the immediate area surrounding LSCS. Furthermore, windturbine-generated noise, and other projects, must comply with noise regulations found in IAC 

Title 35, Subtitle H. Accordingly, the NRC staff concludes that the cumulative impact to the 

noise environment from past, present, and reasonably foreseeable actions is SMALL.
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4.16.2 Geology and Soils

This section addresses the direct and indirect effects of license renewal on geology and soils 

when added to the aggregate effects of other past, present, and reasonably foreseeable future 

actions. As noted in Section 4.4.1, the NRC staff concludes that the impacts of the proposed 

action (license renewal) on geology and soils would be SMALL. The cumulative impacts on the 

geologic environment primarily relate to land disturbance and the potential for soil erosion and 

loss, as well as the projected consumption of geologic resources. Exelon has no plans to 

conduct refurbishment or replacement actions. Ongoing operation and maintenance activities at 

LSCS are expected to be confined to previously disturbed areas. Any use of geologic materials 

such as aggregates to support operation and maintenance activities would be procured from 

local and regional sources. Thus, activities associated with continued operations are not 

expected to affect the geologic environment.

The NRC staff assumes that any construction activities would use material from local and 

regional sources, as these materials are abundant in the region. These identified projects are of 

such a scale as to not be likely to impact regional sources and supplies of the identified 

resources. Furthermore, construction activities would need to be conducted in accordance with 

State and local requirements and development activities would be subject to BMPs for soil 

erosion and sediment control, which would serve to minimize soil erosion and loss. Considering 

ongoing activities and reasonably foreseeable actions, the NRC staff concludes that the 

cumulative impacts on geology and soils during the license renewal term would be SMALL.

4.16.3 Water Resources

This section addresses the direct and indirect effects of the proposed action (license renewal) 

on water resources when added to the aggregate effects of other past, present, and reasonably 

foreseeable future actions. 

4.16.3.1 Surface Water Resources

As described in Section 4.5.1.1, the incremental impacts on surface water resources from 

continued operations of LSCS during the license renewal term would be SMALL. The NRC staff 

has also evaluated other projects and actions for consideration in determining their contribution 

to cumulative impacts on surface water resources (see Appendix E). 

The description of the affected environment under Section 3.5.1 of this SEIS serves as the 

baseline for the cumulative impacts assessment for surface water resources. The geographic 

area of analysis for the surface water resources component of the cumulative impacts analysis 

includes the lowermost portion of the Upper Illinois River Basin, as described in Section 3.5.1.1, 

with a detailed focus on the Marseilles Pool of the Illinois River and its tributaries. As such, this 

review focused on those projects and activities that would withdraw water from or discharge

effluent to the Marseilles Pool. The cumulative impacts on surface water use and quality, along 

with associated climate change considerations, are presented below.

Water Use Considerations

The Upper Illinois River Basin is composed of a 10,949 square mile (mi2) (28,369 square 

kilometer (km2

)) drainage area upstream from Ottawa, Illinois. LSCS is located on the 

Marseilles Pool of the main stem of the Illinois River. This pool is one of eight such navigation 

pools along the Illinois River and major tributaries that includes an associated lock and dam. 

Each pool includes a navigation channel that is at least 9 ft (2.7 m) deep and 300 ft (91 m) wide. 

Together, the navigation pools are part of the Illinois Waterway, which enables commercial river 
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traffic to travel from Lake Michigan to the Mississippi River and from there to the Gulf of Mexico 

(Arnold et al. 1999; Talkington 1991; USGS 1998). 

Operation of the navigation pools using the locks and dams has the effect of decreasing overall 

river flow velocity and stabilizing river water levels, particularly during low flows. As a result of 

this extensive management, some 60 percent of the State of Illinois’ commodities travel the 

waterway annually. This includes grain, petroleum products, coal, chemicals, sand and gravel, 

pulp, paper, and others (Talkington 1991).

In support of this cumulative impacts analysis, the NRC staff obtained and evaluated the best 

available data on water consumption and projected trends in water use, as compiled by 

responsible water resources management agencies. The USGS published a comprehensive 

investigation of hydrologic and water quality conditions in the Upper Illinois River Basin in 1999

that also considered water use (Arnold et al. 1999). 

Excluding surface water diversions from Lake Michigan in the Chicago area, nearly five times as 

much groundwater as surface water is used in the Upper Illinois River Basin for public water 

supply. Within the basin, surface water is primarily used for cooling and associated 

thermoelectric power generation, followed by public water supply and industrial and commercial 

use. In total, more than 90 percent of all reported water use in the basin is for the cooling and 

thermoelectric power generation sector, with nearly all of the water from surface water sources. 

This percentage reflects total water demands and does not account for water that is withdrawn 

and not consumptively used (i.e., water that is returned to the water source rather than being 

lost) (Arnold et al. 1999). Thermoelectric power generating plants that use once-through cooling

systems return most of the water they withdraw back to the source. In contrast, those using 

closed-cycle cooling systems, which are now the standard for new facilities, withdraw much less 

water (i.e., about 90 percent less than those with once-through cooling systems) but their 

operation entails consumptive loses (i.e., primarily due to evaporation) of greater than 

50 percent, resulting in the return of less water (NRC 2013d). 

The rankings by water use sector cited above in Arnold et al. (1999) are mirrored in the 

county-level forecasts of water use prepared by Southern Illinois University for the Illinois State 

Water Survey (Dziegielewski et al. 2005). As part of its analysis, the NRC staff considered the 

counties in the lowermost Upper Illinois River Basin, including counties that border LaSalle 

County, where LSCS is located, and the immediately upstream portion of the Marseilles Pool in 

Grundy County. Total water demand (both groundwater and surface water) overall in the Illinois 

counties within the lowermost part of the Upper Illinois River Basin is projected to increase by 

about 30 percent by 2025, as compared to water use in the year 2000. This is a 1,148 mgd 

(4.35 million m3

/d) (equivalent to 1,776 cfs (50.2 m3/s)) increase over water use in 2000

(Dziegielewski et al. 2005).

By 2025, the demand for public water use within the lowermost Upper Illinois River Basin is 

projected to increase by about 36 percent. This reflects an increase of approximately 

69 mgd (261,000 m3

/d) as compared to public water use in the year 2000. For self-supplied 

commercial and industrial water use, an increase of approximately 16 mgd (60,600 m3

/d) by 

2025 is forecast (Dziegielewski et al. 2005).

The NRC staff believes that the county-level total water demand projections likely overestimate 

future demand, as they are heavily influenced by large forecasted increases in water demand 

for thermoelectric power generation, which have not been realized to date. In addition, the 

thermoelectric power generation component of these projections includes the Collins 

Generating Station, a fossil-fuel fired power plant in Morris (Grundy County), Illinois, which 

withdrew water from the Illinois River. This facility was permanently decommissioned in 2004 
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and, as a result, the county-level projections, particularly for Grundy County, probably 

overestimate future total water demand. 

In LaSalle County, total water demands are projected to increase by approximately 

3.8 mgd (14,400 m3

) to 89.8 mgd (340,000 m3/d) by 2025 as compared to the county’s total 

water use in 2000. This is a rate of increase of about 0.15 mgd (570 m3

/d) per year, or an 

increase of about 4 percent as compared to water use in 2000. This total county demand 

includes 62.9 mgd (238,100 m3

/d) attributable to LSCS operations. This total projected increase 

by 2025 includes 0.3 mgd (1,140 m3

/d) for public water supply (3 percent increase) and 2.5 mgd 

(9,500 m3

/d) increase for self-supplied commercial and industrial uses (a nearly 70 percent 

increase), with the remainder attributable to use for thermoelectric power generation 

(Dziegielewski et al. 2005). The projected increase in public water supply demand is in line with 

the historical trend in LaSalle County’s population growth, which has averaged about 2 percent 

per decade. Most recently, the Illinois Department of Commerce and Economic Opportunity has 

projected county population to grow at a rate of about 4 percent between 2020 and 2030, or 

about 0.4 percent per year (LaSalle County 2014). 

Based on the discussion above, the NRC staff estimates that by the end of the period of 

extended operations for LSCS in 2043, LaSalle County’s total water demands could increase to 

96.5 mgd (365,000 m3

/d). This conservative projection assumes water demand will increase by 

about 0.4 percent per year equally across all water use sectors and that LSCS’s river makeup 

water withdrawals, which dominate water withdrawals in the county and across the lowermost 

Upper Illinois River Basin, will also increase proportionally.

However, even if the entire projected water demand for LaSalle County (96.5 mgd, equivalent to 

149 cfs (4.2 m3

/s)) which includes water needs by LSCS were to be withdrawn from the 

Marseille Pool of the Illinois River and not returned, this would be equivalent to approximately 

1.4 percent of the mean annual flow of the Illinois River through the Marseilles Pool. This small 

percentage increase would be less because some of the water withdrawn from the pool would 

be returned, as more than 50 percent of the water withdrawn by LSCS at present (i.e., about 

55 cfs (1.6 m3

/s)) is returned directly to the Marseilles Pool. It is extremely likely that future 

demands for public water supply will continue to be met by groundwater and not surface water. 

There are no municipalities that use the Marseilles Pool of the Illinois River as a public water 

supply source. All identified public water supplies within 10 mi (16 km) of LSCS rely on 

groundwater (Exelon 2014a, 2014b). Given the abundant groundwater supplies in the county 

and also the higher cost of surface water treatment, the NRC staff does not anticipate public 

water supplies to switch to surface water as a water source during the license renewal term. 

Thus, it is extremely unlikely that continued LSCS operations withdrawing surface water from 

the Marseilles Pool of the Illinois River, combined with those of other users in the county, would 

substantially impact the downstream availability of surface water. 

Water Quality Considerations

Water quality within the whole of the Illinois River Basin has historically suffered from rapid 

population growth, urbanization, and industrial development. This resulted in the discharge of 

poorly treated sewage, the discharge of industrial pollutants and refuse, runoff of agricultural 

chemicals and sediments, and the alteration of the natural hydrology of the river (Exelon 2014a; 

Talkington 1991).

Nonetheless, over the last 50 years, substantial improvements in water quality have occurred,

due to municipal and industrial waste treatment and management efforts to address both point 

and nonpoint pollutant sources. Ongoing water quality concerns within the Upper Illinois River 

Basin remain and include the atmospheric deposition of pesticides and trace metals; endocrine 

disrupting compounds in surface and groundwater; nutrient enrichment of surface and 
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groundwater; the transport and fate of pesticides, trace elements, and volatile organic 

compounds in surface and groundwater; and the effects of urbanization on biodiversity, habitat, 

and water quality (USGS 1998; Groschen 2004).

As discussed in Section 3.5.1.3 of this SEIS, a segment of the Illinois River that encompasses 

the Marseilles Pool does not meet designated uses and associated water-quality standards and 

is listed as an impaired waterway. The segment is listed as impaired for not meeting designated 

uses for fish consumption due to polychlorinated biphenyls (PCBs) and mercury as well as for 

primary contact recreation use, due to fecal coliform bacteria. However, the segment is 

classified as fully supporting its designated use for aquatic life. IEPA has assigned a medium 

priority for the development of Total Maximum Daily Load (TMDL) limits to improve water quality 

in this river segment pursuant to Section 303(d) of the Federal Water Pollution Control Act 

(i.e., Clean Water Act (CWA)) (33 U.S.C. 1251). 

As noted previously, development in the lowermost Upper Illinois River Basin, including 

associated population growth and industrial development, is expected. Upstream development 

could lead to increased discharges and pollutant loading to the Marseilles Pool of the Illinois 

River with impacts on ambient water quality. The magnitude of cumulative impacts would 

depend on the nature and location of the actions relative to receiving surface water bodies, the 

number of actions (facilities or projects), and the extent of municipal, county, and state 

regulatory agency development planning and environmental regulatory controls. At a minimum, 

new and modified industrial and large commercial facilities would be subject to regulation under 

the Federal CWA (33 U.S.C. 1251) (i.e., Section 402). This would include IEPA-administered 

NPDES permit limits on stormwater and point source discharges designed to be protective of 

surface water resources. Likewise, it is this regulatory framework that presently governs 

industrial effluent and thermal discharges from LSCS and other major industrial facilities in the 

lowermost Upper Illinois River Basin.

Climate Change Considerations

The NRC staff also considered the USGCRP’s most recent compilations of the state of 

knowledge relative to global climate change effects (USGCRP 2014). Climate change can 

impact surface water as a result of changes in temperature and precipitation. As discussed in 

Section 4.15.3.2, climate model simulations for the Midwest region indicate an increase in 

annual mean temperature as well as precipitation. More especially, the frequency and intensity 

of heavy precipitation events is forecast to increase. Increased precipitation results in greater

runoff and streamflow. The USGCRP (USGCRP 2014) predicts that runoff and streamflow for 

the upper Midwest will increase overall. 

In its ER, Exelon (2014a) cites an analysis prepared by the Illinois State Water Survey 

(Knapp 2009) that assesses trends in stream flows encompassing the Illinois River Basin and 

their implications for flood frequency. For stream gaging sites with a long period of record 

(90 years), the analysis indicates a consistent trend of increasing stream flows in the upper 

Midwest, attributed to a 7- to 10-percent increase in precipitation over the past 30 years

(through 2008). Results from an earlier study prepared by USGS (Arnold et al. 1999) and 

specific to the Upper Illinois River Basin also indicate a statistically significant increase in mean 

annual stream flow (over the period 1950–1997) at all seven stations selected for analysis, 

including as measured at the USGS gage at Marseilles, Illinois. In contrast to Knapp (2009), the 

USGS study was not able to correlate any trends in precipitation with the apparent increases in 

streamflow. Rather, the authors concluded that the observed trends were more likely 

attributable to land-use changes in the affected watersheds, causing more rapid runoff of 

precipitation, and to increases in groundwater usage and associated increased return effluent to 

receiving waters from wastewater treatment plants in the basin. These two studies serve to 
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point to the uncertainty over whether there has been an observable trend in precipitation and/or 

streamflow in the upper Midwest, as forecast by the USGCRP. 

Despite any observable trends to date, rapid runoff events occurring due to more frequent and 

intensive precipitation events associated with climate change, especially over cleared or 

urbanized areas, will result in increases in erosion and transport of sediment and other 

pollutants to receiving waters. This can negatively affect ambient water quality.

Further, higher air temperatures and increased runoff associated with heavy precipitation events 

could impact the thermal regime of the Marseilles Pool of the Illinois River, along with increases 

in runoff laden with nutrients, sediment, and other contaminants. Higher surface water

temperatures decrease the cooling efficiency of thermoelectric power generating facilities as 

well as plant capacity, due to the need to reduce the discharge of thermal effluent (USGCRP 

2014). As intake water temperatures warm, cooling water makeup requirements increase. 

Degradation in ambient surface water quality increases the costs of water treatment for both 

industrial cooling water and potable water, due to the need for increased filtration and higher 

additions of chemical treatments for such uses as antiscaling and disinfection. With respect to 

LSCS operations, these potential climate-induced changes can lead to higher cooling pond 

temperatures and an increase in evaporative losses from LSCS’s cooling pond. This can 

conceivably result in additional makeup water withdrawals from the Marseilles Pool and an 

increased need for blowdown discharges from the cooling pond to the Illinois River. At present, 

the data available to the NRC staff is not sufficient to indicate whether or not a warming trend is 

evident in the waters of the Illinois River, including the Marseilles Pool. Exelon (2015b) has not 

identified any increasing trend in cooling pond temperatures to date, although this observation is 

based on limited data. Regardless, as detailed in Section 3.5.1.3 of this SEIS, the chemical and 

thermal quality of LSCS’s discharges to the Illinois River are subject to the effluent limitations 

and monitoring requirements prescribed by its NPDES permit (IEPA 2013). Additionally, 

thermal mixing zone limits set by LSCS’s NPDES permit indirectly limit surface water 

withdrawals and consumptive water use during low river flow and extreme summer weather 

events.

Future thermal and pollutant discharges from new and modified industrial and large commercial 

facilities in the lowermost Upper Illinois River Basin would be required to comply with applicable 

NPDES permit requirements under the Federal CWA, local and regional health standards, and 

TMDLs imposed by the State of Illinois.

Conclusion

Surface water availability is expected to continue to be sufficient through the license renewal 

term, based on the projections and associated assumptions cited above. Surface water from 

the Marseilles Pool of the Illinois River has been able to support ongoing demands for uses 

ranging from navigation to cooling and thermoelectric power generation to commercial and 

industrial water supply. Flows within the Upper Illinois River Basin and through the Marseilles 

Pool are not likely to decrease and may trend higher during the LSCS license renewal term, in 

part due to climate-induced hydrologic changes. No increase in LSCS consumptive water use 

is expected during the license renewal term. Surface water withdrawals and associated 

consumptive water use for LSCS operations are expected to remain a small percentage of the 

mean annual and 90-percent exceedance flow through the Marseilles Pool of the Illinois River.

It is reasonable to anticipate that water-quality-based limits imposed by the IEPA through 

NPDES permits and other measures on cooling water, wastewater, and stormwater discharges

and similar limits on sources of development, agricultural, and urban runoff will continue to 

maintain or improve ambient surface water quality in the Illinois River. LSCS’s combined 

cooling pond blowdown, wastewater, and stormwater discharges to the Illinois River are 
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regulated under an IEPA-administered NPDES permit. Available data indicate that LSCS 

operations are a very small contributor to the pollutant and thermal loading to the Illinois River. 

Based on the foregoing, the NRC staff concludes that the cumulative impacts from past, 

present, and reasonably foreseeable future actions and trends on surface water resources 

during the license renewal term would be SMALL. 

4.16.3.2 Groundwater Resources

This section addresses the direct and indirect effects of license renewal on groundwater use 

and quality when added to the aggregate effects of other past, present, and reasonably 

foreseeable future actions. As noted in Section 4.5.1.2, the NRC staff concludes the impacts of 

the proposed action (license renewal) on groundwater consumption and quality would be 

SMALL. All groundwater consumed at LSCS is obtained from two wells completed in the 

Cambrian-Ordovician Aquifer (see Section 3.5.2.2).

LaSalle County has an adequate supply of groundwater for industrial, municipal, and domestic 

purposes (LaSalle County 2014). The Cambrian-Ordovician Aquifer System is a major source 

of water in LaSalle County. Groundwater levels in the Cambrian-Ordovician Aquifer System of 

LaSalle County and the plant area have shown little change from 1995 to 2007 

(Burch 2002, 2008). Even if this trend does not continue, the plant is unlikely to have a 

significant impact on the Cambrian-Ordovician Aquifer System. 

Ongoing operations have not impacted the groundwater quality of aquifers on or off the site. 

The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitards, which 

prevent the groundwater quality from being impacted by site activities. Whether an aquifer is 

located on site or off site, the low permeability, thickness, and lateral extent of the Wedron 

Silty-Clay Till means there is little chance of significant impact to groundwater quality from site 

activities.

Considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes 

that the cumulative impacts on groundwater use and quality during the LSCS license renewal 

term would be SMALL.

4.16.4 Terrestrial Resources

This section addresses the direct and indirect effects of license renewal on terrestrial resources 

when added to the aggregate effects of other past, present, and reasonably foreseeable future 

actions. Section 4.6 of this SEIS finds that the direct and indirect impacts on terrestrial 

resources from the proposed license renewal, when considered in the absence of the aggregate 

effects, would be SMALL. The cumulative impact is the total effect on terrestrial resources of all 

actions taken, no matter who has taken the actions (the second principle of cumulative effects 

analysis in CEQ 1997).

Two related concepts bound the analysis of cumulative impacts: (1) the timeframe and 

(2) geographic extent. The timeframe for cumulative analyses for ecological resources extends 

far enough into the past to understand the processes that affect the present resource conditions 

and to examine whether and why terrestrial resources are stable or unstable, which the NRC’s 

definitions of impact levels require. The timeframe for cumulative impact analysis is more 

extensive than that for the direct and indirect impact analysis.

The geographic extent considered in this cumulative terrestrial resource analysis depends on 

the particular cumulative impacts being discussed. Direct and indirect impacts from LSCS

operation are largely limited to the LSCS site and immediate vicinity. However, projects or 

actions located beyond this geographic area could directly or indirectly affect terrestrial 

resources in this area. This section focuses on the cumulative effects of such actions.
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The level of cumulative impacts is measured against a baseline. Consistent with other Federal 

agencies’ and the Council on Environmental Quality’s (CEQ 1997) NEPA guidance, the term 

“baseline” pertains to the condition of the resource without the action (i.e., under the no-action

alternative). Under the no-action alternative, the plant would shut down, and the resource would 

conceptually return to its condition without the plant (which is not necessarily the same as the 

condition before the plant was constructed). The baseline, or benchmark, for assessing 

cumulative impacts on terrestrial resources takes into account the preoperational environment,

as recommended by EPA (1999b) for its review of NEPA documents.

Past Development and Habitat Alteration

The LSCS site was partially disturbed during the construction of the facility to develop site 

buildings and infrastructure and to create the cooling pond. Of the site’s 1,528 ha (3,776 ac), 

65 ha (160 ac) were permanently converted for industrial use to support buildings and 

infrastructure, and approximately 800 ha (1,976 ac) are occupied by the cooling pond. During 

construction, some additional land may have been temporarily disturbed to allow for laydown 

areas for construction supplies or storage of construction equipment.

In the broader area—the Illinois/Indiana Prairies Level IV Ecoregion—native tallgrass prairies, 

wetlands, and floodplain forests have been converted to agricultural and urban land, which now 

account for the major land-use types. Habitat loss, in general, can negatively affect breeding 

success, dispersal success, predation rate, and other animal behaviors (Fahrig 2003). Habitat 

fragmentation (the breaking up of a larger area of habitat into smaller patches of smaller total 

area) can also negatively affect terrestrial biota. In a study of breeding bird communities in 

24 Illinois grassland fragments, Herkert (1994) found that fragmentation was likely a factor in 

Midwestern grassland bird population declines. A study conducted in 2012 on the partridge pea 

(Chamaecrista fasciculata) concludes that native prairie plant species that occur in smaller, 

isolated prairie fragments are likely to suffer a reduction in genetic fitness (Mannouris and 

Byers 2013). IDNR (2005) reports that remaining prairie remnants within the State lack many 

natural ecosystem functions, due to their small size, and areas of prairie restoration often lack 

forbs or are overly dominated by big bluestem (Andropogon gerardii) or Indiangrass 

(Sorghastrum nutans). Accordingly, remaining native populations in these habitats are likely to 

suffer from reduced genetic fitness, which is further exacerbated by fragmentation. 

Energy Production and Development

Two nuclear power plant sites with four operating reactors (Braidwood Station, Units 1 and 2, 

and Dresden Nuclear Power Station, Units 2 and 3) lie within 50 mi (80 km) of the LSCS site. 

Because the effects of these facilities would primarily be limited to the terrestrial resources on 

each plant’s site and the immediate vicinity, the operation of these two facilities during the 

proposed LSCS license renewal term would not result in cumulative effects to the terrestrial 

resources affected by LSCS operation.

Four fossil-fuel-fired energy facilities occur in the region (Table E–1 in Appendix E) and each is 

about 20 mi (30 km) from LSCS. Although no coal or gas energy projects are under 

construction in the region at this time, other energy development may arise over the proposed 

license renewal term. Air emissions from these facilities include GHGs, such as nitrogen 

oxides, carbon dioxide, and methane, all of which can have far-reaching consequences 

because they cumulatively contribute to climate change. The effects of climate change on 

terrestrial resources are discussed in Section 4.15.3.2.

Four wind energy facilities exist in the region (Table E–1 in Appendix E). Grand Ridge Wind 

Farm is a 140-unit wind facility located immediately west of the LSCS property, and it extends 

southwest for approximately 8 mi (13 km). The other three wind facilities are located between 
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6 mi (10 km) and 27 mi (43 km) from the LSCS site and consist of a total of 450 wind units. 

Operation of wind farms can result in direct mortality of birds and bats through collision with 

turbine blades as well as indirect effects, such as wildlife avoidance, habitat disruption, reduced 

nesting or breeding density, habitat abandonment, and behavioral effects 

(Stewart et al. 2005, 2007). Given that the majority of bird and bat species are migratory, 

effects of wind farms on bird and bat populations can be far reaching.

Development, Urbanization, and Habitat Fragmentation

As the region surrounding the LSCS site becomes more developed, habitat fragmentation will 

increase, and the amount of forested, prairie, and wetland habitat is likely to decline further. 

Transmission lines, pipelines, and associated corridors established to connect new buildings to 

the regional electric grid and to utilities could further fragment habitats if the corridors split 

otherwise continuous tracts of habitat. Edge species that prefer open or partially open habitats 

will likely benefit from the fragmentation, whereas species that require interior forest or wetland

habitat will likely suffer. 

Continued urbanization in the future will likely include construction of additional housing units 

and associated commercial buildings; roads, bridges, and rail; and water or wastewater

treatment and distribution facilities and associated pipelines. Increased development will likely 

decrease the overall availability and quality of terrestrial habitats. Species that require larger 

ranges, especially larger predators, will likely suffer reductions in their populations. Similarly, 

species with threatened or endangered Federal or State status or otherwise declining 

populations would be more sensitive to declines in habitat availability and quality. Native prairie 

plants will likely continue to experience reductions in genetic fitness, as previously discussed.

Wildlife Refuges, State Parks, and Recreational Areas

A number of State parks, State Fish and Wildlife Areas, and State Natural Areas and 

recreational areas are located near LSCS (Table E–1 in Appendix E) that provide valuable 

habitat to native wildlife, migratory birds, and protected terrestrial species and habitats. Illini 

State Park, which comprises 510 ac (206 ha) and lies 6 mi (10 km) north-northwest of the LSCS 

site, provides habitat for a number deciduous trees, including hickory (Carya spp.), ash 

(Fraxinus spp.), walnut (Juglans spp.), elm (Ulmus spp.), cottonwood (Populus deltoids), oak 

(Quercus spp.), and maple (Acer spp.), as well as white-tailed deer (Odocoileus virginianus), 

eastern gray squirrels (Sciurus carolinensis), opossums (Didelphis virginiana), beavers (Castor 

canadensis), raccoon (Procyon lotor), groundhogs (Marmota monax), and a variety of waterfowl 

and songbirds (IDNR 2015a). Starved Rock State Park, which comprises 2,700 ac (1,090 ha) 

and lies 15 mi (24 km) northwest of the LSCS site along the Illinois River, contains a variety of 

habitats, including canyons, sandstone bluffs, rolling plains, forest, upland prairies, waterfalls, 

rivers, and streams, and provides particularly high-quality habitat to many species of native 

wildlife and migrating birds. As fragmentation and land-use changes continue, these protected 

areas will become ecologically more important because they provide large, uninterrupted areas 

of minimally disturbed habitat.

Conclusion

The NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity of 

the LSCS site are MODERATE to LARGE, based on past, present, and reasonably foreseeable 

future actions. This level of impact is primarily the result of past habitat alteration and loss on 

the LSCS site and within the larger Illinois/Indiana Prairies Level IV Ecoregion. The 

environmental effects of these actions are clearly noticeable and have destabilized important 

attributes of certain terrestrial communities. The loss of genetic fitness of native prairie species 

and the loss of tallgrass prairies, wetlands, and floodplains are demonstrative of such effects. 
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The incremental, site-specific impact from the continued operation of LSCS during the license 

renewal period would be an unnoticeable or minor contributor to cumulative impacts on 

terrestrial resources.

4.16.5 Aquatic Resources

This section addresses the direct and indirect effects of license renewal on aquatic resources 

when added to the aggregate effects of other past, present, and reasonably foreseeable future 

actions. Section 4.7 finds that the direct and indirect impacts on aquatic resources from the 

proposed license renewal would be SMALL for all aquatic ecology issues, with the exception of 

MODERATE impacts to gizzard shad and threadfin shad from heat shock in the cooling pond. 

The geographic area considered in the cumulative aquatic resources analysis includes the 

LSCS cooling pond and the vicinity of the intake and discharge structures on the Illinois River 

affected by LSCS water withdrawal and discharge. The baseline, or benchmark, for assessing 

cumulative impacts on aquatic resources takes into account the preoperational environment as 

recommended by EPA (1999b) for its review of NEPA documents.

Section 3.7 presents an overview of the current condition of the LSCS cooling pond and Illinois 

River and the history and factors that led to current conditions. In summary, the direct and 

indirect impacts from draining wetlands, construction of locks and dams, maintenance of 

navigation channels, industrial effluent, and sewage discharge are some of the most influential 

human activities on the Illinois River Basin (Parker 2014). By the 1960s, biodiversity of fish 

within the upper Illinois River was low and freshwater mussels were nearly absent from the 

upper Illinois River (Sietman et al. 2001). Pollution-tolerant non-native common carp (Cyprinus 

carpio) and goldfish (Carassius auratus) dominated fish populations (Parker 2014). Since the 

passage of the CWA in 1974, water quality within the Illinois River has improved, and more 

diverse fish assemblages have inhabited the upper Illinois River (Parker 2014). Similarly, 

freshwater mussels have recolonized portions of the upper Illinois River since the 1980s 

(Sietman et al. 2001). 

Many natural and anthropogenic activities can influence the current and future aquatic biota in 

the area surrounding the LSCS site and the Illinois River Basin. Potential biological stressors 

include operational impacts from LSCS (as described in Section 4.7), energy development, and 

urbanization. 

4.16.5.1 Energy Development

Several other power plants withdraw water from and discharge water to the Illinois River (see 

Appendix E). The largest nuclear power plant near LSCS and located on the Illinois River is the 

Dresden Nuclear Station, located on River Mile 272.3 of the Illinois River. Dresden Nuclear 

Station withdraws water from the Kankakee River and discharges to the Illinois River (EA 2015). 

For 3.5 months of the year, Dresden operates in an indirect-open-cycle mode, and during the 

remainder of the year (8.5 months), Dresden operates its cooling pond in a closed-cycle mode, 

similar to LSCS. Operating in a closed-cycle mode reduces the impacts to aquatic resources 

because less water is withdrawn and discharged, and therefore, less thermal effluent is 

discharged to the Illinois River. The NRC (2004) determined that the impacts from 

impingement, entrainment, and heat shock from Dresden Nuclear Station would be SMALL on 

aquatic resources. Furthermore, it is unlikely that the thermal effluent from Dresden Nuclear 

Station and LSCS overlap, given that both thermal plumes dissipate within the vicinity of each 

respective discharge structure and the distance between the two plants (NRC 2004; 

Exelon 2014a). Impingement and entrainment at both plants could affect similar fish 

populations; however, operating in the closed-cycle mode would reduce impacts to fish 

(NRC 2004; EA 2015). 
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Kendall County Generation is a natural-gas-fueled plant with 1,140 MW generating capacity that 

withdraws water from and discharges water to the Illinois River. This plant is approximately 

27 mi (43 km) northeast of LSCS. Given that the discharge plumes are limited to the vicinity of 

the discharge structures, the heated effluent from the two plants would not likely overlap. 

However, many of the same fish populations could be affected by impingement and entrainment

at LSCS and Kendall County Generation. 

The other power plants located on the Illinois River have a much smaller generating capacity—

less than 180 MW (see Appendix E)—and therefore require less cooling water. Given the lower 

withdraw and discharge rates, effects to aquatic resources from impingement, entrainment, and 

thermal effluents would also be lower at these facilities. 

Several wind and solar farms operate within 50 mi (80 km) of LSCS (see Appendix E). These 

facilities would not have detectable impacts on aquatic resources in the Illinois River because, in 

general, they do not require water during operation.

4.16.5.2 Future Urbanization and Transportation Development

Future urbanization in the vicinity of LSCS would likely include construction of new housing units 

and associated commercial buildings; roads, bridges, and rail; and water or wastewater

treatment (or both), distribution facilities, and associated pipelines. Continued development of 

the area has the potential to increase the rate and volume of stormwater runoff and reduce 

groundwater recharge. If not managed appropriately, such development could result in 

increased flooding, higher and more frequent storm-related flows, and low flows of longer 

duration in streams. The increased runoff rates and high channel velocities from inappropriately 

managed sites could result in excessive bank erosion and associated sedimentation and stream 

degradation in the Illinois River and its tributaries. As a result, aquatic biota populations may 

experience habitat degradation or loss, reduced food or prey availability, and increased 

susceptibility to exotic species invasions. Such potential impacts can be mitigated through 

implementation of BMPs that address stormwater quality, quantity, and discharge. Stormwater 

BMPs are often required by state and local regulations, which would ensure that impacts to 

aquatic resources resulting from future development would be appropriately mitigated.

4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas

Several wildlife preserves, parks, and recreation sites lie within the vicinity of LSCS (see 

Appendix E), including the Marseilles State Fish and Wildlife Area, which lies 1.5 mi (2.4 km) 

north of the LSCS site. The continued preservation of these areas will protect aquatic habitats 

and, as land development continues, these areas will become ecologically more important 

because they will provide large areas of unfragmented natural habitat.

4.16.5.4 Illinois Wildlife Conservation Plan

The State of Illinois maintains a Comprehensive Wildlife Conservation Plan and Strategy 

(IDNR 2005), which is implemented by the IDNR and numerous Federal, State, local, and 

private partners. The plan addresses long-range landscape-level planning initiatives, which 

include projects to address declining wildlife populations and conservation and restoration of 

ecologically important, sensitive, and rare habitats. Part of the plan includes the Conservation 

Reserve Enhancement Program, which is a voluntary program to assist landowners in

protecting environmentally sensitive land, decreasing erosion, restoring wildlife habitat, 

increasing populations of threatened and endangered species, and safeguarding groundwater

and surface water in the Illinois River Basin (IDNR 2005). Commitment to this plan will help 

protect or restore aquatic habitats and continue to support a diversity of aquatic life in the future.
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4.16.5.5 Conclusion

The stresses from past river flow alterations, increasing urbanization, and demand for water 

resources across the geographic area of interest depend on many factors that the NRC staff 

cannot quantify but that are likely to noticeably alter aquatic resources when all stresses on the 

aquatic communities are assessed cumulatively. Continued protection of aquatic habitats 

through wildlife preserves, parks, and recreational areas, as well as the implementation of the 

Illinois Wildlife Conservation Plan, will likely mitigate some of these effects, and, therefore, the 

NRC staff finds it reasonable to assume that these activities will ensure that future actions do 

not destabilize important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, 

the NRC staff concludes that the cumulative impacts on aquatic resources from the proposed 

license renewal and other past, present, and reasonably foreseeable projects would be

MODERATE. 

4.16.6 Historic and Cultural Resources

This section addresses the direct and indirect effects of license renewal on historic and cultural 

resources when added to the aggregate effects of other past, present, and reasonably 

foreseeable future actions. The geographic area considered in this analysis is the APE 

associated with the proposed undertaking, as described in Section 3.9.

The archaeological record for the region indicates prehistoric and historic occupation of the 

LSCS site and its immediate vicinity. Given the location of identified cultural resources, the 

construction of LSCS may have resulted in destruction of cultural resources within the LSCS 

site and its immediate vicinity.

Other land uses in the vicinity of LSCS may have resulted in impacts on and the loss of, cultural 

resources on the LSCS site and its immediate vicinity. However, there remains the possibility 

for additional historic or cultural resources to be located within the LSCS site. The present and 

reasonably foreseeable projects that could affect these resources, reviewed in conjunction with 

license renewal, are noted in Appendix E of this document. Direct impacts would occur if 

historic and cultural resources in the APE were physically removed or disturbed. It is unlikely 

that the projects discussed in Appendix E would impact historic and cultural resources on the 

LSCS site because those resources are not in areas that would be subject to foreseeable future 

development.

As described in Section 4.9 of this document, no known cultural resources would be adversely 

affected by LSCS license renewal activities, as no associated changes or ground-disturbing 

activities will occur (Exelon 2014a). Moreover, as discussed in Section 4.9, Exelon has 

established draft procedures to ensure cultural resources are considered in project planning 

during operation of LSCS.

The NRC staff concludes that the cumulative impacts of the proposed license renewal on 

historic and cultural resources, when combined with other past, present, and reasonably 

foreseeable future activities, would be SMALL.

4.16.7 Socioeconomics

This section addresses socioeconomic factors that have the potential to be directly or indirectly 

affected by changes in operations at LSCS, 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 includes LaSalle, Grundy, and Will Counties, where 

approximately 83 percent of LSCS employees reside (see Table 3–15). This is where the 

economy, tax base, and infrastructure would most likely be affected because the majority of 
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LSCS workers and their families reside, spend their incomes, and use their benefits within these 

counties.

As discussed in Section 4.10, continued operation of LSCS during the license renewal term 

would have no impact on socioeconomic conditions in the region beyond what is already being 

experienced. Since Exelon has no plans to hire additional workers during the license renewal 

term, overall expenditures and employment levels at LSCS would remain relatively unchanged 

with no new or increased demand for housing and public services. Based on this and other 

information presented in Chapter 4, there would be no contributory effect on socioeconomic 

conditions in the region during the license renewal term from the continued operation of LSCS 

beyond what is currently being experienced. Therefore, the only contributory effects would 

come from reasonably foreseeable future planned activities at LSCS, unrelated to the proposed 

action (license renewal), and other reasonably foreseeable planned offsite activities. For 

example, offsite residential development is planned throughout the LSCS region. The 

availability of new housing could attract individuals and families from outside the region, 

increasing the local population and causing increased traffic on local roads, as well as increased 

demand for public services. 

When combined with other past, present, and reasonably foreseeable future activities, the 

contributory effects of continued reactor operations at LSCS would have no new or increased 

impact on socioeconomic conditions in the region beyond what is currently being experienced.

4.16.8 Human Health

The NRC and EPA established radiological dose limits for protection of the public and workers 

from both acute and long-term exposure to radiation and radioactive materials. These dose 

limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.11.1, the 

NRC staff concluded that impacts to human health from continued plant operations are SMALL. 

For the purposes of this analysis, the geographical area considered is the area included within 

an 80-km (50-mi) radius of the LSCS plant site. There are four other nuclear power plants 

within the applicable geographical area: Braidwood Station, Units 1 and 2, and Dresden 

Nuclear Power Station, Units 2 and 3. Also, LSCS’s 80-km (50-mi) radius overlaps with the 

80-km (50-mi) radii of Byron Station, Units 1 and 2; Quad Cities Nuclear Power Station, Units 1 

and 2; and Clinton Power Station, Unit 1. As discussed in Section 3.1.4.4, in addition to storing 

its spent nuclear fuel in a storage pool, LSCS stores some of its spent nuclear fuel in an onsite 

independent spent fuel storage installation (ISFSI).

EPA regulations in 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, and transportation of fuel and waste. As discussed in Section 3.1.4.5, LSCS has a 

REMP that measures radiation and radioactive materials in the environment from LSCS, its 

ISFSI, and all other sources. The NRC staff reviewed the radiological environmental monitoring 

results for the 5-year period from 2010 to 2014 as part of the cumulative impacts assessment. 

The NRC staff’s review of Exelon’s data showed no indication of an adverse trend in 

radioactivity levels in the environment from LSCS or its ISFSI. The data showed that there was 

no measurable impact to the environment from operations at LSCS.

The NRC staff concludes that the cumulative radiological impacts of the proposed license 

renewal, when combined with other past, present, and reasonably foreseeable future activities, 

would be SMALL. This is based on the NRC staff’s review of REMP data, radioactive effluent 

release data, worker dose, and LSCS’s expected continued compliance with Federal radiation 

protection standards during continued operation, and regulation of any future development or 

actions in the vicinity of the LSCS site by the NRC and the State of Illinois.
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4.16.9 Environmental Justice

The environmental justice cumulative impact analysis evaluates 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 the continued operational effects of LSCS during the renewal term. Everyone 

living near LSCS currently experiences its operational effects, including minority and low-income 

populations. The NRC addresses environmental justice matters for license renewal by 

identifying the location of minority and low-income populations, determining whether there would 

be any potential human health or environmental effects to these populations, and determining if 

any of the effects may be disproportionately high and adverse.

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 risks of impacts on the natural or physical environment in a minority or low-income 

community that are significant and appreciably exceed 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 preceding sections of 

Chapter 4 in this SEIS. As previously discussed in this chapter, the impact from license renewal 

for all resource areas (e.g., land, air, water, ecology, and human health) would be SMALL.

As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 

adverse impacts on minority and low-income populations from the continued operation of LSCS

during the license renewal term. Since Exelon has no plans to hire additional workers during 

the license renewal term, employment levels at LSCS would remain relatively constant, and 

there would be no additional demand for housing or increased traffic. Based on this information 

and the analysis of human health and environmental impacts presented in the preceding 

sections, it is not likely there would be any disproportionately high and adverse contributory 

effect on minority and low-income populations from the continued operation of LSCS during the 

license renewal term. Therefore, the only contributory effects would come from the other 

reasonably foreseeable future planned activities at LSCS, unrelated to the proposed action 

(license renewal), and other reasonably foreseeable planned offsite activities.

Exelon has no reasonably foreseeable future planned activities at LSCS beyond continued 

reactor operations. When combined with other past, present, and reasonably foreseeable future 

activities, the ongoing contributory effects of continued reactor operations at LSCS would not 

likely cause disproportionately high and adverse human health and environmental effects on 

minority and low-income populations residing in the vicinity of LSCS beyond what is currently 

being experienced.

4.16.10 Waste Management

This section describes waste management impacts during the license renewal term when added 

to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 

the purpose of this cumulative impacts analysis, the area within a 50-mi (80-km) radius of LSCS

was considered. The NRC staff concluded, in Section 4.11, that the potential human health 

impacts from LSCS’s waste during the license renewal term would be SMALL.

As discussed in Sections 3.1.4 and 3.1.5, Exelon maintains waste management programs for 

radioactive and nonradioactive waste generated at LSCS and is required to comply with Federal 
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and State permits and other regulatory requirements for the management of waste material. 

The nuclear power plants and other facilities within a 50-mi (80-km) radius of LSCS are also 

required to comply with appropriate NRC, EPA, and state requirements for the management of 

radioactive and nonradioactive waste. Current waste management activities at LSCS would 

likely remain unchanged during the license renewal term, and continued compliance with 

Federal and State requirements for radioactive and nonradioactive waste is expected.

Based on the above, the NRC staff concludes that the potential cumulative impacts from 

radioactive and nonradioactive waste during the license renewal term would be SMALL. 

Continued compliance with Federal and State requirements for radioactive and nonradioactive 

waste management by Exelon is expected.

4.16.11 Global Climate Change

This section addresses the impact of GHG emissions resulting from continued operation of 

LSCS on global climate change when added to the aggregate effects of other past, present, and 

reasonably foreseeable future actions.

The impacts of climate change on air, water, and ecological resources are discussed in 

Section 4.15.3. Climate is influenced by both natural and human-induced factors; the observed 

global warming (increase in Earth’s surface temperature) in the 21st century has been attributed 

to the increase in GHG emissions resulting from human activities (USGCRP 2009). Climate 

model projections indicate that future climate change is dependent on current and future GHG 

emissions (IPCC 2007b; USGCRP 2009, 2014). As described in Section 4.15.3.1, operations at 

LSCS emit GHG emissions. 

The cumulative impact of a GHG emission source on climate is global. GHG emissions are 

transported by wind and become well mixed in the atmosphere as a result of their long 

atmospheric residence time. Therefore, the extent and nature of climate change is not specific 

to where GHGs are emitted. In April 2015, EPA published the official U.S. inventory of GHG 

emissions, which identifies and quantifies the primary anthropogenic sources and sinks of 

GHGs. The EPA GHG inventory is an essential tool for addressing climate change and 

participating with the United Nations Framework Convention on Climate Change to compare the 

relative global contribution of different emission sources and GHGs to climate change. In 2013, 

the United States emitted 6,673 teragrams (Tg) (6,673 million metric tons (MMT)) of carbon 

dioxide equivalents (CO2e), and from 1990 to 2013, emissions increased by 5.9 percent 

(EPA 2015d). In 2012 and 2013, the total amount of CO2e emissions related to electricity 

generation was 2,022 Tg (2,022 MMT) and 2,039 Tg (2,039 MMT), respectively (EPA 2015d). 

The Energy Information Administration (EIA) reported that, in 2013, electricity production alone 

in Illinois was responsible for 94.1 MMT CO2e (EIA 2015a). Facilities that emit 25,000 MT CO2e

or more per year are required to annually report their GHG emissions to EPA. These facilities 

are known as direct emitters, and the data are publicly available in EPA’s facility-level 

information on GHGs tool (FLIGHT). In 2013, FLIGHT identified 11 facilities in LaSalle County, 

Illinois, where LSCS is located, that emitted a total of 0.89 MT CO2e (EPA 2015c). In 2012, 

FLIGHT identified 290 facilities in Illinois that emitted a total of 134 MMT CO2e (EPA 2015c).

Appendix E provides a list of current and reasonably foreseeable future projects and actions 

that could contribute to GHG emissions. Permitting and licensing requirements and other 

mitigative measures can minimize the impacts of GHG emissions. For instance, in 2012, EPA

issued a final GHG Tailoring Rule (77 FR 41051) to address GHG emissions from stationary 

sources under the CAA permitting requirements; the GHG Tailoring Rule establishes when an 

emission source will be subject to permitting requirements and control technology to reduce 

GHG emissions. On June 25, 2013, President Obama set forward a plan to reduce carbon 
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pollution. The Climate Action Plan will reduce carbon pollution, prepare the United States for 

the impacts of climate change, and lead international efforts to combat global climate change. 

The Clean Power Plan Final Rule7 (80 FR 64661), aimed at reducing carbon pollution from 

power plants, requires carbon emissions from the power sector to be 32 percent below 2005

levels (870 million tons less). The Clean Power Plan sets forth carbon dioxide emission 

performance rate standards for fossil fuel-fired power plants that should be achieved by 2030. 

Future actions and steps taken to reduce GHG emissions can lessen the impacts on climate 

change.

In 2006, Illinois Executive Order (E.O. 06-11) created the Illinois Climate Change Advisory 

Group (ICCAG), which was charged with recommending State-level strategies to meet 

statewide GHG reduction goals. The Illinois GHG reduction goals are as follows: reduction of 

GHG emissions to 1990 levels (231 MT CO2e) by 2020 and 60 percent below 1990 levels 

by 2050. The ICCAG’s 2007 report identified that between1995–1997 nuclear generation 

capacity decreased in Illinois with the decrease replaced with coal generation along with an 

increase in GHG emissions (ICCAG 2007). As presented in Table 4–22, the IGCC, NGCC, 

combination, and purchased power alternatives’ annual GHG emissions are higher by several 

orders of magnitude than those from continued operation of LSCS. Therefore, if LSCS’s 

generating capacity were to be replaced by other non-nuclear power generating alternatives 

assessed in this SEIS, there would be an increase in GHG emissions, as was observed in 

1995–1997 for Illinois. If non-nuclear replacement power alternatives were to be located in 

Illinois, the associated increase in GHGs may result in the implementation of additional 

State-level strategies (ICCAG 2007) to meet Illinois GHG reduction goals. Consequently, 

continued operation of LSCS (the proposed action) results in GHG emissions avoidance. 

EPA’s U.S. inventory of GHG emissions illustrates the diversity of GHG sources, such as 

electricity generation (including fossil fuel combustion and incineration of waste), industrial 

processes, and agriculture. As presented in Section 4.15.3, annual direct GHG emissions from 

combustion sources resulting from ancillary operations at LSCS range from 4,514 to 

7,659 MT CO2e. In comparing LSCS’s GHG emission contribution to different emissions 

sources, whether it be total U.S. GHG emissions, emissions from electricity production in Illinois, 

or emissions on a county level, GHG emissions from LSCS are minor relative to these 

inventories; this is evident, as presented in Table 4–23. Further, total annual LSCS GHG 

emissions are below EPA’s reporting threshold of 25,000 MT CO2e, as codified in 

40 CFR Part 98. 

The emissions impact of a single source on climate change requires that a climate model 

account for that specific emissions source in order to project the magnitude and extent of 

climate change. Climate models indicate that short-term climate change (through the year 

2030) is dependent on past GHG emissions. Therefore, climate change is projected to occur 

with or without present and future GHG emissions from LSCS. The NRC staff concludes that 

the incremental impact from the contribution of GHG emissions from the proposed action of the 

continued operation of LSCS on climate change would be SMALL. 

Due to the global significance of GHG emissions, this global climate change cumulative impacts 

analysis considers the entire Earth’s atmosphere and therefore global emissions (as opposed to 

county, state, or national emissions). As discussed in Section 4.15.3.2, climate change and 

climate-related environmental changes have been observed on a global level, and climate 

models indicate that future climate change will depend on present and future global GHG 

 7 On February 9, 2016, the U.S. Supreme Court issued a stay of implementation of the Clean Power Plan 

pending judicial review in the U.S. Court of Appeals for the District of Columbia. The Clean Power Plan 

requirements are therefore on hold until the U.S. Court of Appeals makes a final ruling on the plan.
Environmental Consequences and Mitigating Actions

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emissions. With continued increases in global GHG emission rates, climate models project that 

Earth’s average surface temperature will continue to increase and climate-related changes will 

persist. Therefore, the cumulative impact of global GHG emissions from past, present, and 

reasonably foreseeable future actions on climate change is noticeable but not destabilizing. 

The NRC staff concludes that the cumulative impacts of global GHG emissions from past, 

present, and reasonably foreseeable future actions are MODERATE. However, as discussed 

above, the incremental addition of GHG emissions from the continued operation of LSCS, when 

compared to global emissions, are negligible and would have a net, beneficial contribution to 

GHG emissions and climate change impacts during the license renewal term compared to other 

baseload replacement power generation sources assessed in this SEIS.

Table 4–23. Comparison of GHG Emission Inventories

Source CO2e MMT/year

Global Fossil Fuel Combustion Emissions (2013) (a) 36,000

U.S. Emissions (2013)(b) 6,673

Illinois (2013)(c) 134

LaSalle County, Illinois (2013)(c) 0.89

LSCS(d) 0..008

(a) Source: GCP 2014

(b) Source: EPA 2015d

(c) GHG emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year (EPA 2015c).

(d) Direct emissions (stationary combustion sources, fugitive emissions, and refrigerant related sources) rounded 

from and obtained from Exelon 2015d. 

4.16.12 Summary of Cumulative Impacts

The NRC staff considered the potential impacts resulting from the operation of LSCS during the 

period of extended operation and other past, present, and reasonably foreseeable future actions 

near LSCS. The preliminary determination is that the potential cumulative impacts would range 

from SMALL to LARGE, depending on the resource. Table 4–24 summarizes the cumulative 

impacts on resource areas.

Table 4–24. Summary of Cumulative Impacts on Resource Areas

Resource Area Cumulative Impact

Air Quality and 

Noise

Past, present, and reasonably foreseeable future activities exist in the geographic 

areas of interest (local for noise; local and regional for criteria pollutants) that could 

affect air quality and noise resources. However, the incremental contribution of 

impacts on air quality and noise resources from plant operations at LSCS would be 

minimal. The NRC staff concludes that cumulative impacts from LSCS related actions 

and other past, present, and reasonably foreseeable future actions on air quality and 

noise resources in the geographic areas of interest would be SMALL.
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Resource Area Cumulative Impact

Geology and 

Soils

Any use of geologic materials, such as aggregates to support operation and 

maintenance activities, would be procured from local and regional sources. These 

materials are abundant in the region, and geologic conditions are not expected to 

change during the license renewal term. Thus, activities associated with continued 

operations are not expected to affect the geologic environment. Considering ongoing 

activities and reasonably foreseeable actions, the NRC staff concludes that the 

cumulative impacts on geology and soils during the LSCS license renewal term would 

be SMALL.

Water 

Resources

No increase in LSCS consumptive water use is expected during the license renewal 

term. Surface water availability is expected to continue to be sufficient through the 

license renewal term, and surface water withdrawals and associated consumptive 

water use for LSCS operations are expected to remain a small percentage of the flow 

through the Marseilles Pool of the Illinois River. LaSalle County has an adequate 

supply of groundwater for industrial, municipal and domestic purposes, and ongoing 

operations at LSCS have not affected groundwater quality. Therefore, considering 

ongoing activities and reasonably foreseeable actions, the NRC staff concludes that 

cumulative impact of the proposed license renewal, combined with other past, 

present, and reasonably foreseeable future activities, would be SMALL on surface 

water and groundwater resources. 

Terrestrial 

Ecology

NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity 

of the LSCS site are MODERATE to LARGE based on past, present, and reasonably 

foreseeable future actions. This level of impact is primarily the result of past habitat 

alteration and loss on the LSCS site and within the larger region. The environmental 

effects of these actions are clearly noticeable and have destabilized important 

attributes of certain terrestrial communities. The incremental, site-specific impact 

from the continued operation of LSCS during the license renewal period would be an 

unnoticeable or minor contributor to cumulative impacts on terrestrial resources.

Aquatic 

Resources

The stresses from past river flow alterations, increasing urbanization, and demand for 

water resources across the geographic area of interest depend on many factors that 

NRC staff cannot quantify, but that are likely to noticeably alter aquatic resources 

when all stresses on the aquatic communities are assessed cumulatively. Continued 

protection of aquatic habitats through wildlife preserves, parks, and recreational 

areas, as well as the implementation of the Illinois Wildlife Conservation Plan will 

likely mitigate some of these effects, and, therefore, the NRC staff finds it reasonable 

to assume that these activities will ensure that future actions do not destabilize 

important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, the 

NRC staff concludes that the cumulative impacts from the proposed license renewal 

and other past, present, and reasonably foreseeable projects would be MODERATE.

Historical 

and Cultural 

Resources

No known cultural resources would be adversely affected by LSCS license renewal 

activities as no associated changes or ground-disturbing activities would occur. 

Exelon has established draft procedures to ensure cultural resources are considered 

in project planning during operation of LSCS. Therefore, the NRC staff concludes that 

the cumulative impact of the proposed license renewal when combined with other 

past, present, and reasonable foreseeable future activities on historic and cultural 

resources would be SMALL.

Socioeconomics When combined with other past, present, and reasonably foreseeable future activities, 

the contributory effects from the continued operation of LSCS during the license 

renewal period would have no new or increased impact on socioeconomic conditions 

beyond what is currently being experienced. 

Human Health The NRC staff concludes that the cumulative radiological impacts of the proposed 

LSCS license renewal, when combined with other past, present, and reasonably 

foreseeable future activities, would be SMALL.
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Resource Area Cumulative Impact

Environmental 

Justice

The NRC staff concludes that the contributory effects of continued reactor operations 

at LSCS, when combined with other past, present, and reasonably foreseeable future 

activities considered, would not likely cause disproportionately high and adverse 

human health and environmental effects on minority and low-income populations 

residing in the vicinity of LSCS.

Waste 

Management 

NRC staff concludes that the potential cumulative impacts from radioactive and 

nonradioactive waste during the license renewal term would be SMALL. Continued 

compliance with Federal and State requirements for radioactive and nonradioactive 

waste management by Exelon is expected. 

Global Climate 

Change

Climate change and climate-related changes have been observed on a global level, 

and climate models indicate that future climate change will depend on present and 

future global GHG emissions. Climate models project that Earth’s average surface 

temperature will continue to increase and climate-related changes will persist. 

Therefore, the cumulative impact of global GHG emissions on climate change during 

the LSCS license renewal timeframe would be noticeable but not destabilizing. The 

NRC staff concludes that the cumulative impacts of global GHG emissions from the 

proposed license renewal and other past, present, and reasonably foreseeable 

projects would be MODERATE. However, the incremental addition of GHG emissions 

from the continued operation of LSCS, when compared to global emissions, are 

negligible and would have a net, beneficial contribution to GHG emissions and climate 

change impacts during the license renewal term compared to other baseload 

replacement power generation sources assessed in this SEIS.

4.17 Resource Commitments

4.17.1 Unavoidable Adverse Environmental Impacts

Unavoidable adverse environmental impacts are impacts that would occur after implementation 

of all workable mitigation measures. Carrying out any of the energy alternatives considered in 

this SEIS, 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 EPA emissions 

standards, although 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 standards or 

administrative control limits. In comparison, the alternatives involving 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 public.

The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 

hazardous waste, and nonhazardous waste, would be unavoidable. Hazardous and 

nonhazardous wastes would be generated at non-nuclear power generating facilities. Wastes 
Environmental Consequences and Mitigating Actions

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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 carry 

out all activities and optimize all operations in a way that generates the smallest amount of 

waste possible.

4.17.2 Short-Term Versus Long-Term Productivity

The operation of power generating facilities would result in short-term uses of the environment, 

as described in Chapter 4. “Short term” is the period of time that continued power generating 

activities take place.

Power plant operations require short-term use of the environment and commitment of resources 

(e.g., land and energy), indefinitely or permanently. Certain short-term resource commitments 

are substantially greater under most energy alternatives, including license renewal, than under 

the no-action alternative because of the continued generation of electrical power and the 

continued use of generating sites and associated infrastructure. During operations, all energy 

alternatives 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 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 they 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 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 requires an increase in energy and consumes 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 are 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.

4.17.3 Irreversible and Irretrievable Commitments of Resources

This section describes the irreversible and irretrievable commitments of resources that have 

been noted in this SEIS. Resources are irreversible 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 commitments of resources for electrical power generation include the commitment 

of land, water, energy, raw materials, and other natural and man-made resources required for 

power plant operations. In general, the commitments of capital, energy, labor, and material 

resources are also irreversible.

The implementation of any of the energy alternatives considered in this SEIS would entail the 

irreversible and irretrievable commitments of energy, water, chemicals, and—in some cases—
Environmental Consequences and Mitigating Actions

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fossil fuels. These resources would be committed during the license renewal term and over the 

entire life cycle of the power plant, and they would 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 fuel would be 

purchased from offsite commercial sources. Water would be obtained from existing water 

supply systems. These resources are readily available, and the amounts required are not 

expected to deplete available supplies or exceed available system capacities.

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5-1

5.0 CONCLUSION

This supplemental environmental impact statement (SEIS) contains the environmental review of 

the application for renewed operating licenses for LaSalle County Station, Units 1 and 2 (LSCS), 

submitted by Exelon Generation Company, LLC (Exelon), as required by the Code of Federal 

Regulations (CFR), Part 51 of Title 10 (10 CFR Part 51), the U.S. Nuclear Regulatory 

Commission’s (NRC’s) regulations that implement the National Environmental Policy Act 

(NEPA). This chapter presents conclusions and recommendations from the site-specific 

environmental review of LSCS. Section 5.1 summarizes the environmental impacts of license 

renewal; Section 5.2 presents a comparison of the environmental impacts of license renewal 

and energy alternatives; and Section 5.3 presents the NRC staff conclusions and 

recommendation.

5.1 Environmental Impacts of License Renewal

The NRC staff’s review of site-specific environmental issues in this SEIS leads to the conclusion 

that issuing renewed licenses at LSCS would have SMALL to MODERATE impacts for the 

Category 2 issues applicable to license renewal at LSCS. The NRC staff considered mitigation

measures for each Category 2 issue, as applicable. The NRC staff concluded that no additional 

mitigation measure is warranted. 

5.2 Comparison of Alternatives

In Chapter 4, the staff considered the following alternatives to LSCS license renewal:

• no-action alternative,

• new nuclear alternative,

• integrated gasification combined-cycle alternative

• natural gas combined-cycle (NGCC) alternative,

• combination alternative (NGCC, wind, solar), and

• purchased power.

Based on the summary of environmental impacts provided in Table 2–2, the NRC staff 

concluded that the environmental impacts of renewal of the operating licenses for LSCS would 

be smaller than those of feasible and commercially viable alternatives. The no-action

alternative, the act of shutting down LSCS on or before its license expiration dates, would have 

SMALL environmental impacts with the exception of socioeconomic impacts which would have 

SMALL to LARGE environmental impacts. Continued operation of LSCS would have SMALL to 

MODERATE environmental impacts for aquatic resources and SMALL environmental impacts in 

all other areas. The NRC staff concluded that continued operation of LSCS is the 

environmentally preferred alternative.

5.3 Recommendation

The NRC’s recommendation is that the adverse environmental impacts of license renewal for 

LSCS are not so great that preserving the option of license renewal for energy-planning 

decisionmakers would be unreasonable. This recommendation is based on the following:
Conclusion

5-2

• the analysis and findings in NUREG–1437, Volumes 1 and 2, Generic 

Environmental Impact Statement for License Renewal of Nuclear Plants,

• the environmental report submitted by Exelon,

• consultation with Federal, State, local, and Tribal government agencies,

• the NRC staff’s environmental review, and

• consideration of public comments received during the scoping process and 

received on the draft SEIS.
6-1

6.0 LIST OF PREPARERS

This supplemental environmental impact statement (SEIS) was prepared by members of the 

Office of Nuclear Reactor Regulation (NRR) with assistance from other U.S. Nuclear Regulatory 

Commission (NRC) organizations and contract support from Pacific Northwest National 

Laboratory (PNNL), the Center for Nuclear Waste Regulatory Analyses (CNWRA), a private 

contractor and Idoneous, Inc. (Idoneous). Table 6–1 lists the NRC staff who contributed to the 

development of the SEIS. PNNL provides contract support for analysis of transportation 

impacts of high burnup fuel. CNWRA provides contract support for severe accident mitigation

alternative (SAMA) reviews. Idoneous provides contract support for technical editing reviews.

Table 6–1. List of Preparers

Name Education/Experience Function or Expertise

NRC-NRR

Jim Danna M.S., Civil Engineering/Geology

29 years of experience in engineering 

and project management including 

16 years at NRC, including as an NRC 

technical and projects branch manager

Management oversight

David Wrona B.S., Electrical Engineering; 27 years of

nuclear plant experience, including as 

an NRC resident inspector, reactor

engineer, project manager, and projects 

and technical branch manager

Management oversight

David Drucker B.S., General Engineering; 

M.S., Engineering Management; 

34 years of project and program 

management experience

Project management

Jeffrey Rikhoff M.R.P., Regional Planning; 

M.S., Economic Development and 

Appropriate Technology; B.A., English; 

35 years of combined industry and 

government experience including 

28 years in NEPA compliance, 

environmental impact analysis, 

socioeconomics and environmental 

justice impact analysis, cultural 

resource impacts, and comprehensive 

land-use and development planning

Socioeconomics and environmental 

justice

Bill Rautzen B.S., Health Physics; B.S., Industrial 

Hygiene; M.S. Health Physics; 5 years 

of experience in environmental impact 

analysis

Human health, radiological, and waste 

management
List of Preparers

6-2

Name Education/Experience Function or Expertise

Kevin Folk B.A., Geoenvironmental Studies; 

M.S., Environmental Biology; 25 years 

of experience in NEPA compliance; 

geologic, hydrologic, and water quality 

impacts analysis; utility infrastructure 

analysis; and environmental regulatory 

compliance and water supply and 

wastewater discharge permitting

Surface water resources

Briana Grange B.S., Conservation Biology; 10 years of 

experience in environmental impact 

analysis, section 7 consultations, and 

essential fish habitat consultations

Terrestrial ecology, land use, and 

visual resources

Nancy Martinez A.M., Earth and Planetary Science; 

B.S., Earth and Environmental Science; 

4 years of experience in environmental 

impact analysis

Air quality, noise, and climate change

Michelle Moser M.S., Biological Sciences; 

B.S., Environmental Sciences; 

13 years of experience in ecological 

studies, environmental impact 

assessment, and protected resource 

management

Aquatic ecology and microbiological 

hazards

Jerry Dozier M.S. Reliability Engineering; M.B.A. 

Business Administration; B.S. 

Mechanical Engineering; 30 years of 

experience including operations, 

reliability engineering, technical 

reviews, and NRC branch management

SAMA

Russell Chazell B.S., Liberal Studies; J.D, Law; 

M.S., Nuclear Engineering; Certificate 

in Project Management; Certificate in 

NEPA; 26 years of combined industry 

and government experience including

analytical and environmental laboratory 

science, laboratory project 

management, technical business 

development, engineering project 

management, and NEPA compliance

Historic and cultural resources

Non-radioactive waste management

Non-radioactive human health

William Ford M.S., Geology; 41 years of combined 

industry and government experience 

working on groundwater, surface water,

and geology projects and associated 

technical and environmental analyses

Geologic environment and groundwater

resources

Robert Hoffman B.S., Environmental Resource 

Management; 29 years of experience in 

NEPA compliance, environmental 

impact assessment, alternatives

identification and development, and 

energy facility siting

Alternatives and cumulative effects
List of Preparers

6-3

Name Education/Experience Function or Expertise

Dennis Logan Ph.D., Marine Studies and Biological 

Oceanography; M.S., Biological 

Sciences, Marine Biology; B.S., 

Zoology; 40 years of experience in 

ecological studies, ecological risk 

assessment, environmental impact 

assessment, protected resource 

management, and project management

Threatened and endangered species

Don Palmrose B.S., Nuclear Engineering; M.S., 

Nuclear Engineering; Ph.D., Nuclear 

Engineering; 30 years of relevant 

experience

High burnup fuel transportation impacts

National Laboratory Personnel

Steve Maheras, 

PNNL(a)

B.A. Zoology;

M.S. Health Physics

Ph.D. Health Physics

27 years of experience in health 

physics and transportation risk 

assessment

High burnup fuel transportation impacts

Commercial Contractors

R. Benke, 

CNWRA (b)

Ph.D., Nuclear Engineering, 

M. Eng., Radiological Health 

B.S., Nuclear Engineering, 

20 years of experience in nuclear 

engineering, radiological health, risk 

analysis, and is a certified health 

physicist

SAMA

D. Speaker, 

CNWRA

B.S., Nuclear Engineering

M.S., Nuclear Engineering

10 years of experience in nuclear 

engineering, radiation detection, 

instrumentation, nondestructive 

evaluation, and nuclear reactor design 

and analysis

SAMA

E.R. Schmidt,

Contractor

B.S., Mechanical Engineering; 

M.S., Nuclear Engineering

50 years of nuclear industry experience 

including 35 year experience in 

performing, managing and reviewing 

Probabilistic Risk Assessments

SAMA

Susan Anastasi, 

Idoneous

Technical Editing

(a) Pacific Northwest National Laboratory (PNNL) is operated by Battelle for the U.S. Department of Energy.

(b) CNWRA is a federally funded research and development center sponsored by the NRC.

7-1

7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM 

COPIES OF THIS SEIS ARE SENT

Name Affiliation

J. Barrett Tribal Nation—Citizen Potawatomi Nation

H. Frank Tribal Nation—Forest County Potawatomi

K. Meshigaud Tribal Nation—Hannahville Indian Community, Band of Potawatomi

J. Greendeer Tribal Nation—Ho-Chunk Nation

S. Cadue Tribal Nation—Kickapoo Tribe in Kansas

G. Salazar Tribal Nation—Kickapoo Tribe of Oklahoma

D. Lankford Tribal Nation—Miami Tribe of Oklahoma

J. Froman Tribal Nation—Peoria Tribe of Indians in Oklahoma

J. Warren Tribal Nation—Pokagon Band of Potawatomi

S. Ortiz Tribal Nation—Prairie Band of Potawatomi Nation

J. Bender Tribal Nation—Sac and Fox Tribe of the Mississippi in lowa/Meskwaki

B. Robidoux Tribal Nation—Sac and Fox Nation of Missouri in Kansas and Nebraska

G. Thurman Tribal Nation—Sac and Fox Nation

J. Blackhawk Tribal Nation—Winnebago Tribe of Nebraska

R. Nelson Advisory Council on Historic Preservation

J. Duyvejonck U.S. Fish & Wildlife Service

R. Leibowitz Illinois Historic Preservation Agency

Alan Keller Illinois Environmental Protection Agency

Nathan Grider Illinois Department of Natural Resources

Patty Smith Mayor, City of Marseilles, Illinois

Bob Eschbach Mayor, City of Ottawa, Illinois

David Spicer Mayor, Village of Seneca, Illinois

Kay Hines Mayor, City of Grand Ridge, Illinois

EIS Scoping Meeting Participants

Reed Wilson Office of U.S. Representative Kinzinger

Elizabeth Poole U.S. EPA Region 5

Jerry Hicks LaSalle County Board Chairman

Rick Zuffa Illinois Emergency Management Agency

Cecil Settles Illinois Emergency Management Agency

Doug O’Brien Illinois Clean Energy Coalition

Jim Carlson Superintendent, Seneca Township High School

Roger Blumquist Argonne National Laboratory

Beth Jung Nuclear Power Illinois

Linda Lewison Nuclear Energy Information Service
List of Agencies, Organizations, and Persons

7-2

EIS Scoping Participant

(continued) Affiliation

Ruth Thomas Environmentalists, Inc.

Marvin Lewis Public

Tom Walsh LaSalle County Board, District 18

Connie Brooks Director, LaSalle County Emergency Management Agency

Wayne Eichelkraut City of Ottawa

Shelli Ocepak United Way of Eastern LaSalle County

Mike Gallagher Exelon Generation Company

Chris Wilson Exelon Generation Company

Krista Lopykinski Exelon Generation Company

John Keenan Exelon Generation Company

Megan Borchers Exelon Generation Company

Bryan Mooney Exelon Generation Company

Pete Karaba Exelon Generation Company

Harold Vinyard Exelon Generation Company

Jay Houston Exelon Generation Company

Nancy Ranek Exelon Generation Company

Commenters on Draft Supplemental Environmental Impact Statement

Gale Snyder Nuclear Energy Information Service

Steve Buck Public

Tom Jackson Illini State Park, Illinois Department of Natural Resources

Dan Boudart Nuclear Energy Information Service

Kenneth Westlake U.S. EPA Region 5

Rachel Leibowitz Illinois Historic Preservation Agency

Valencia Darby U.S. Department of Interior
8-1

8.0 INDEX

A

accident ..................................... xxiv, xxviii, 

xxx, xxxii, 3-8, 3-13, 3-73, 4-75, 4-76, 

4-77, 4-79, 4-80, 4-86, 6-1, A-20, A-21, 

A-22, D-1, F-1, F-2, F-3, F-8, F-9, F-10, 

F-11, F-12, F-15, F-16, F-17, F-18, F-25, 

F-35, F-38, F-40, F-41, F-42, F-47, G-1, 

G-4, G-9, G-11, G-12

accidents ...........................xxiv, 3-102, 4-1, 

4-75, 4-76, 4-77, 4-78, 4-88, 4-91, 4-98, 

F-9, F-11, F-13, F-17, F-20, F-26, F-41, 

G-1, G-3, G-8, G-9, G-11, G-12

Advisory Council on Historic 

Preservation (ACHP) ......xxvii, 1-7, 4-60, 

4-148, 7-1, B-6, C-3

aesthetic .................3-42, 3-103, 4-63, 4-96

alternatives....................... iii, xxiv, 1-5, 2-1, 

2-3, 2-4, 2-5, 2-7, 2-16, 2-20, 2-21, 2-23, 

2-24, 4-1, 4-6, 4-16, 4-17, 4-18, 4-20, 

4-21, 4-29, 4-30, 4-35, 4-36, 4-37, 4-55, 

4-59, 4-64, 4-70, 4-72, 4-77, 4-91, 4-97, 

4-99, 4-100, 4-102, 4-104, 4-107, 4-130, 

4-133, 4-134, 5-1, 6-2, A-2, A-23, A-25, 

A-27, A-29, A-30, A-31, A-33, B-2, C-2, 

F-1, F-30, F-44

archaeological......................1-6, 2-4, 3-82, 

3-84, 4-62, 4-63, 4-126

archaeological resources.............1-6, 2-4, 

3-84, 4-63

B

biocide .................................................3-11

biological assessment................. C-1, C-2

biota.........................3-10, 3-64, 4-35, 4-40, 

4-41, 4-44, 4-45, 4-46, 4-51, 4-52, 4-111, 

4-122, 4-124, 4-125, A-5, A-12, A-16

boiling water reactor...................xxvii, 2-1, 

3-6, 4-78, 4-81, A-39, F-1, G-2

burnup ............................3-6, 6-1, 6-3, D-1, 

D-2, G-2, G-9, G-11

C

chronic effect ...........4-72, 4-73, 4-88, 4-89

chronic effects .........4-72, 4-73, 4-88, 4-89

Clean Air Act (CAA)...................xxvii, 3-25, 

3-26, 3-27, 3-114, 4-11, 4-14, 4-129, 

4-136, 4-138, 4-139, 4-140, A-7, B-3, B-8

closed-cycle.................... 2-8, 2-12, 2-13, 2

-14, 3-6, 3-7, 3-43, 4-24, 4-25, 4-26, 4-27, 

4-40, 4-41, 4-43, 4-44, 4-45, 4-53, 4-54, 

4-117, 4-124, A-12, A-13

closed-cycle cooling................ 2-14, 4-24, 

4-26, 4-43, 4-117, A-13

Coastal Zone Management Act 

(CZMA)................. xxviii, 3-22, 3-114, B-4

cold shock .......................................... 4-53

consumptive use...................... 3-41, 4-23, 

4-27, 4-28, 4-29, 4-33, 4-52

cooling system...................xxii, xxiii, xxviii, 

1-4, 1-6, 2-10, 2-12, 2-13, 2-14, 3-6, 3-7, 

3-8, 3-60, 3-74, 3-76, 3-100, 4-18, 4-22, 

4-24, 4-31, 4-32, 4-33, 4-37, 4-38, 4-39, 

4-40, 4-41, 4-43, 4-44, 4-45, 4-54, 4-73, 

4-86, 4-87, 4-117, A-12, A-13, A-18, F-6, 

F-9, F-26, F-27, F-30, F-38

core damage frequency ............... xviii, xix, 

xxvii, 4-78, 4-79, 4-80, 4-81, 4-83, 4-84, 

4-85, 4-86, A-40, F-1, F-2, F-3, F-5, F-6, 

F-7, F-9, F-10, F-11, F-12, F-13, F-14, 

F-15, F-17, F-20, F-25, F-27, F-28, F-31, 

F-32, F-34, F-38, F-41, F-43

Council on Environmental Quality 

(CEQ) .............................xxvii, 1-3, 3-103, 

3-114, 4-39, 4-121, 4-122, 4-138, A-19, 

A-30, A-31, A-34, A-35, A-92

critical habitat........................... 3-75, 3-77, 

3-78, 3-79, 3-80, 4-55, 4-56, 4-57, 4-58, 

A-34, B-6, C-1, C-2

cultural resource ................xxiii, xxviii, 2-4, 

2-26, 3-24, 3-81, 3-84, 4-59, 4-60, 4-61, 

4-62, 4-63, 4-64, 4-102, 4-112, 4-126, 

4-132, 6-1, 6-2, A-15, A-18, B-1, B-6

cultural resources .............. xxiii, 2-4, 3-24, 

3-81, 3-84, 4-59, 4-60, 4-61, 4-62, 4-63, 

4-64, 4-102, 4-112, 4-126, 4-132, 6-2, 

A-15, A-18, B-1, B-6
Index

8-2

D

decommissioning ................xxxii, 2-2, 2-3, 

4-1, 4-57, 4-58, 4-59, 4-65, 4-66, 4-68, 

4-69, 4-70, 4-71, 4-98, 4-100, 4-102, 

4-103, 4-104, 4-105, 4-106, 4-134, A-18, 

A-22, E-1, E-10

design-basis accident................ xxviii, 4-1, 

4-75

discharge........................... xxviii, 2-8, 2-10, 

2-12, 2-13, 2-14, 3-7, 3-8, 3-10, 3-11, 

3-12, 3-13, 3-14, 3-22, 3-36, 3-37, 3-40, 

3-41, 3-43, 3-44, 3-45, 3-46, 3-49, 3-55, 

3-61, 3-64, 3-65, 3-66, 3-70, 3-76, 3-99, 

3-100, 4-22, 4-23, 4-24, 4-26, 4-27, 4-32, 

4-37, 4-46, 4-47, 4-48, 4-49, 4-51, 4-52, 

4-53, 4-72, 4-73, 4-74, 4-75, 4-85, 4-87, 

4-103, 4-116, 4-118, 4-120, 4-124, 4-125, 

6-1, A-5, A-17, A-19, A-25, A-26, A-32, 

B-3, B-4, E-4, E-8, F-30, F-35, F-42, G-7, 

G-9

discharges............................3-1, 3-6, 3-10, 

3-12, 3-14, 3-36, 3-37, 3-40, 3-41, 3-42, 

3-44, 3-45, 3-46, 3-49, 3-76, 3-101, 

3-108, 4-26, 4-27, 4-28, 4-29, 4-32, 4-45, 

4-46, 4-47, 4-54, 4-73, 4-74, 4-119, 

4-120, 4-124, 4-125, A-16, A-24, E-4

dose ..................................xxxii, 3-13, 3-14, 

3-15, 3-16, 3-98, 3-99, 3-108, 4-80, 4-83, 

4-101, 4-127, 4-148, A-40, B-2, B-5, F-3, 

F-19, F-20, F-21, F-22, F-31, F-32, F-40, 

F-41, F-43, G-1, G-3, G-4, G-5, G-7, G-8, 

G-9, G-10, G-11, G-12

dredge........................................2-10, 4-26, 

4-27, 4-28

dredging ...........................3-46, 3-76, 4-22, 

4-35, 4-37, 4-53, 4-54, A-32, B-7

E

education.........................3-92, 3-123, 4-65

electromagnetic field ........................ xxviii, 

4-72, 4-88, 4-89

electromagnetic fields ......4-72, 4-88, 4-89

endangered and threatened 

species ..................................... 3-57, B-6

endangered species....................1-6, 3-76, 

3-77, 3-79, 3-80, 3-122, 4-46, 4-56, 

4-125, 4-143, 6-2, B-1, C-2, C-5

Endangered Species Act ............ xviii, xxiii, 

xxix, 1-6, 1-7, 1-8, 2-4, 2-30, 3-54, 3-58, 

3-75, 3-78, 3-80, 3-109, 3-115, 4-55, 

4-56, 4-57, 4-58, 4-59, 4-111, 4-112, 

4-135, 4-139, 4-143, A-18, A-34, A-92, 

B-6, B-8, C-1, C-2, C-5

entrainment .......................xxiii, 3-43, 3-62, 

3-72, 3-73, 3-74, 3-76, 3-77, 4-37, 4-38, 

4-39, 4-40, 4-41, 4-42, 4-43, 4-44, 4-45, 

4-53, 4-54, 4-124, 4-125, 4-145, A-12, 

A-13, A-14, A-16, A-17

environmental justice .............. 2-4, 3-103, 

3-110, 4-91, 4-92, 4-102, 4-128, 4-136, 

6-1, A-92

essential fish habitat................. xxiii, xxviii, 

4-55, 4-58, 6-2, B-6, C-3

eutrophication ................ 3-76, 4-37, 4-111

evaporative .....................3-41, 4-120, A-26

evaporative loss ............. 3-41, 4-120, A-26

Exelon ........................................iii, xxi, xxii, 

xxiv, xxv, 1-1, 1-2, 1-5, 1-7, 1-8, 1-9, 2-1, 

2-2, 2-3, 2-4, 2-8, 2-9, 2-10, 2-21, 2-26, 

2-27, 2-28, 2-30, 3-1, 3-2, 3-3, 3-4, 3-5, 

3-6, 3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 3-13, 

3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 3-20, 

3-21, 3-22, 3-23, 3-24, 3-25, 3-27, 3-29, 

3-30, 3-31, 3-33, 3-34, 3-35, 3-36, 3-37, 

3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 

3-46, 3-47, 3-48, 3-49, 3-50, 3-52, 3-55, 

3-56, 3-57, 3-58, 3-59, 3-60, 3-61, 3-64, 

3-65, 3-69, 3-70, 3-71, 3-72, 3-74, 3-75, 

3-76, 3-78, 3-79, 3-80, 3-81, 3-83, 3-84, 

3-85, 3-86, 3-94, 3-95, 3-96, 3-97, 3-98, 

3-99, 3-102, 3-108, 3-115, 3-116, 3-117, 

3-118, 3-119, 3-120, 3-122, 3-123, 3-124, 

3-127, 3-128, 3-129, 3-130, 4-1, 4-2, 4-3, 

4-7, 4-8, 4-22, 4-23, 4-24, 4-25, 4-31, 

4-32, 4-33, 4-34, 4-39, 4-40, 4-41, 4-43, 

4-44, 4-45, 4-47, 4-49, 4-50, 4-51, 4-52, 

4-56, 4-60, 4-61, 4-65, 4-68, 4-69, 4-72, 

4-73, 4-74, 4-75, 4-76, 4-77, 4-78, 4-79, 

4-80, 4-81, 4-82, 4-83, 4-86, 4-87, 4-88, 

4-92, 4-93, 4-98, 4-101, 4-103, 4-104, 

4-105, 4-113, 4-114, 4-115, 4-116, 4-118, 

4-119, 4-120, 4-124, 4-126, 4-127, 4-128, 

4-129, 4-131, 4-132, 4-133, 4-137, 4-138, 

4-139, 4-140, 4-141, 4-142, 4-144, 4-147, 

4-148, 5-1, 5-2, 7-2, A-2, A-4, A-5, A-6, 

A-7, A-8, A-9, A-10, A-12, A-13, A-14, 

A-15, A-16, A-17, A-18, A-19, A-20, A-21, 

A-22, A-23, A-24, A-26, A-28, A-29, A-31, 

A-33, A-36, A-38, A-39, A-41, A-92, A-93, 

B-7, B-8, C-2, D-1, D-2, E-4, E-8, F-1, 

F-2, F-3, F-4, F-5, F-6, F-9, F-10, F-11, 
Index

8-3

F-12, F-13, F-14, F-15, F-16, F-17, F-18, 

F-19, F-20, F-21, F-22, F-23, F-24, F-25, 

F-26, F-27, F-28, F-29, F-30, F-31, F-32, 

F-33, F-38, F-39, F-40, F-41, F-42, F-43, 

F-44, F-45, F-46, F-47, G-2, G-4, G-5, 

G-9, G-11, G-13

Exelon Generation Company .......... iii, xxi, 

1-1, 1-8, 2-2, 2-30, 3-1, 3-115, 3-116, 

3-117, 3-118, 3-119, 3-120, 3-123, 3-124, 

3-127, 3-128, 4-137, 4-138, 4-139, 4-140, 

4-141, 4-142, 4-144, 4-147, 4-148, 5-1, 

7-2, A-2, A-4, A-92, A-93, B-8, D-1, E-8, 

F-1, F-45, F-46, F-47, G-2, G-13

F

Fish and Wildlife Coordination Act 

(FWCA).............................................. B-8

G

Generic Environmental Impact Statement 

(GEIS) ............................................ iii, xxi, 

xxii, xxv, xxix, 1-3, 1-4, 1-6, 1-7, 1-8, 1-9, 

2-1, 2-2, 2-3, 2-4, 2-17, 2-19, 2-32, 3-6, 

3-36, 3-88, 3-101, 3-127, 4-1, 4-2, 4-6, 

4-7, 4-11, 4-20, 4-22, 4-24, 4-31, 4-32, 

4-33, 4-35, 4-36, 4-37, 4-38, 4-45, 4-52, 

4-53, 4-54, 4-55, 4-60, 4-65, 4-72, 4-73, 

4-75, 4-76, 4-77, 4-91, 4-97, 4-98, 4-99, 

4-100, 4-101, 4-102, 4-103, 4-105, 4-106, 

4-146, 4-147, 5-2, A-12, A-13, A-14, A-16, 

A-17, A-22, A-28, A-29, A-30, A-33, A-34, 

A-39, A-93, A-94, G-2, G-14

greenhouse .................................xxiii, xxix,

2-7, 2-13, 3-27, 4-8, 4-136, A-25, A-29

greenhouse gases .....................xxix, 2-13, 

3-27, 4-8, 4-136

groundwater...............................xxiii, 3-13, 

3-18, 3-42, 3-43, 3-44, 3-47, 3-49, 3-52, 

3-93, 3-100, 4-21, 4-23, 4-24, 4-25, 4-26,

4-27, 4-28, 4-29, 4-30, 4-92, 4-93, 4-102, 

4-110, 4-117, 4-118, 4-119, 4-121, 4-125, 

4-132, 6-2, B-1, E-4

H

hazardous waste.....................3-18, 4-133, 

4-134, A-5, B-5, B-7, B-8

heat shock.................................4-47, 4-48, 

4-49, 4-51, 4-124

high heat shock burnup fuel .............. 6-1, 

D-1, D-2

high-level waste ........................... xxii, 1-4, 

4-97, 4-98, 4-101, A-38, G-2

I

Illinois Department of Natural Resources 

(IDNR) ............................... xxx, 3-1, 3-21, 

3-22, 3-23, 3-40, 3-44, 3-53, 3-54, 3-57, 

3-58, 3-59, 3-60, 3-61, 3-69, 3-70, 3-71, 

3-72, 3-73, 3-74, 3-80, 3-115, 3-122, 

3-123, 3-124, 3-128, 4-49, 4-50, 4-51, 

4-52, 4-74, 4-122, 4-123, 4-125, 4-144, 

7-1, 7-2, A-2, A-14, A-15, A-18, A-19, 

A-20, B-7, E-5, E-6, E-8, E-9

impingement............................. 3-43, 3-72, 

3-73, 3-74, 3-76, 3-77, 4-38, 4-39, 4-40, 

4-41, 4-42, 4-43, 4-44, 4-45, 4-53, 4-54, 

4-124, 4-125, A-11, A-12, A-13, A-14, 

A-16, A-17

independent spent fuel storage 

installation (ISFSI) .................... xxx, 3-1, 

3-17, 3-19, 4-127

Indian tribe........................................ 3-103

Indian tribes...................................... 3-103

Indiana bat................................ 3-54, 3-57, 

3-77, 3-80, 3-132, 4-57

invasive species..................... 4-40, 4-111, 

A-12, A-32, A-33

L

LaSalle County Station (LSCS).............. iii, 

xvii, xviii, xix, xxi, xxii, xxiii, xxiv, xxv, xxx, 

1-1, 1-2, 1-5, 1-6, 1-7, 1-8, 1-9, 2-1, 2-2, 

2-3, 2-4, 2-5, 2-8, 2-9, 2-10, 2-11, 2-12, 

2-13, 2-14, 2-16, 2-17, 2-18, 2-19, 2-20, 

2-21, 2-22, 2-23, 2-24, 2-25, 2-26, 2-30, 

3-1, 3-2, 3-3, 3-4, 3-5, 3-6, 3-7, 3-8, 3-9, 

3-10, 3-11, 3-12, 3-13, 3-14, 3-15, 3-16, 

3-17, 3-18, 3-19, 3-20, 3-21, 3-22, 3-23, 

3-24, 3-25, 3-26, 3-27, 3-28, 3-29, 3-30, 

3-31, 3-32, 3-33, 3-34, 3-35, 3-36, 3-37, 

3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 

3-46, 3-47, 3-48, 3-50, 3-51, 3-52, 3-53, 

3-54, 3-55, 3-56, 3-57, 3-58, 3-59, 3-60, 

3-61, 3-62, 3-63, 3-64, 3-65, 3-66, 3-67, 

3-68, 3-69, 3-70, 3-71, 3-72, 3-73, 3-74, 

3-75, 3-76, 3-77, 3-78, 3-79, 3-80, 3-81, 

3-82, 3-83, 3-84, 3-85, 3-86, 3-87, 3-88, 

3-89, 3-90, 3-91, 3-92, 3-93, 3-95, 3-96, 
Index

8-4

3-97, 3-98, 3-99, 3-100, 3-102, 3-103, 

3-104, 3-105, 3-106, 3-107, 3-108, 3-112, 

3-114, 3-115, 3-116, 3-117, 3-118, 3-119, 

3-120, 3-124, 3-127, 3-128, 3-129, 4-1, 

4-2, 4-3, 4-4, 4-6, 4-7, 4-8, 4-9, 4-10, 

4-11, 4-12, 4-13, 4-16, 4-17, 4-19, 4-20, 

4-21, 4-23, 4-24, 4-25, 4-26, 4-27, 4-28, 

4-29, 4-30, 4-31, 4-32, 4-33, 4-34, 4-35, 

4-37, 4-38, 4-39, 4-40, 4-41, 4-42, 4-43, 

4-44, 4-45, 4-46, 4-47, 4-48, 4-49, 4-50, 

4-51, 4-52, 4-53, 4-54, 4-55, 4-56, 4-57, 

4-58, 4-59, 4-60, 4-61, 4-62, 4-63, 4-64, 

4-65, 4-66, 4-68, 4-69, 4-70, 4-71, 4-72, 

4-73, 4-74, 4-75, 4-76, 4-77, 4-78, 4-79, 

4-80, 4-81, 4-82, 4-83, 4-84, 4-86, 4-87, 

4-88, 4-89, 4-91, 4-92, 4-93, 4-94, 4-95, 

4-97, 4-98, 4-100, 4-101, 4-102, 4-103, 

4-104, 4-105, 4-106, 4-107, 4-108, 4-109, 

4-110, 4-112, 4-113, 4-114, 4-115, 4-116, 

4-117, 4-118, 4-119, 4-120, 4-121, 4-122, 

4-123, 4-124, 4-125, 4-126, 4-127, 4-128, 

4-129, 4-130, 4-131, 4-132, 4-133, 4-137, 

4-138, 4-139, 4-140, 4-141, 4-142, 4-144, 

4-145, 4-148, 5-1, 8-1, A-1, A-3, A-5, A-6, 

A-7, A-8, A-9, A-10, A-11, A-12, A-13, 

A-14, A-15, A-16, A-17, A-18, A-19, A-20, 

A-21, A-22, A-23, A-24, A-25, A-26, A-27, 

A-28, A-29, A-30, A-31, A-32, A-33, A-34, 

A-35, A-36, A-37, A-38, A-39, A-40, A-92, 

A-93, B-2, B-6, B-8, C-1, C-2, C-3, C-4, 

D-1, D-2, E-1, E-2, E-5, E-8, F-1, F-2, 

F-3, F-4, F-5, F-6, F-7, F-8, F-9, F-10, 

F-11, F-12, F-13, F-14, F-15, F-16, F-17, 

F-18, F-19, F-20, F-21, F-22, F-23, F-24, 

F-25, F-26, F-27, F-28, F-29, F-30, F-31, 

F-32, F-34, F-38, F-39, F-41, F-42, F-43, 

F-44, F-45, F-46, F-47, G-1, G-2, G-3, 

G-4, G-6, G-7, G-8, G-9, G-10, G-11, 

G-12, G-13

long-term dose................................... F-41

low-level waste........ xxx, 3-17, 4-98, 4-101

M

Magnuson–Stevens Fishery 

Conservation and Management Act 

(MSA)................................. xxxi, 1-6, 1-7, 

1-8, 3-75, 3-125, 4-58, 4-146, B-6, B-9, 

C-3, C-5

Marine Mammal Protection Act 

(MMPA).................. xxxi, 3-75, 3-125, B-9

mitigation.............................xxii, xxiv, xxxii, 

1-3, 1-4, 1-5, 4-16, 4-17, 4-52, 4-53, 4-55, 

4-62, 4-63, 4-64, 4-77, 4-86, 4-87, 4-133, 

4-148, 5-1, 6-1, A-21, A-22, A-23, D-1, 

F-1, F-9, F-38, F-42

mixed waste............................... 3-13, 3-17

Myotis sodalis .......................... 3-54, 3-57, 

3-77, 3-80, 3-121, 3-129, 4-57

N

National Environmental Policy Act 

(NEPA) ...............................xviii, xxii, xxxi, 

1-1, 1-8, 2-1, 2-31, 3-74, 3-103, 3-114, 

3-126, 4-39, 4-56, 4-61, 4-64, 4-65, 4-91, 

4-109, 4-122, 4-124, 4-138, 4-139, 4-146, 

5-1, 6-1, 6-2, A-15, A-16, A-17, A-19, 

A-27, A-29, A-30, A-31, A-32, A-33, A-35, 

A-93, B-2, C-1, C-3, C-5, G-12, G-14

National Marine Fisheries Service 

(NMFS)........................... xxxi, 3-75, 4-55, 

4-56, 4-57, 4-58, 4-143, B-6, C-1, C-2, 

C-3, C-5

National Pollutant Discharge Elimination 

System (NPDES) ...................... xvii, xxxi, 

3-10, 3-11, 3-12, 3-18, 3-40, 3-42, 3-43, 

3-44, 3-45, 3-46, 3-99, 3-108, 3-110, 

3-111, 3-124, 4-23, 4-26, 4-27, 4-28, 

4-29, 4-30, 4-32, 4-44, 4-46, 4-47, 4-51, 

4-52, 4-53, 4-73, 4-74, 4-119, 4-120, 

4-135, 4-137, 4-144, A-9, A-24, B-1, B-4, 

B-7, B-8, E-4, E-7

Native American..................... 3-83, 3-125, 

4-91, 4-92

no-action..................................iii, xxiv, 2-1, 

2-3, 2-4, 2-23, 2-24, 2-26, 4-2, 4-34, 4-39, 

4-53, 4-57, 4-62, 4-93, 4-98, 4-105, 

4-122, 4-134, 5-1

no-action alternative ...................... iii, xxiv, 

2-1, 2-3, 2-4, 2-23, 2-24, 2-26, 4-2, 4-34, 

4-39, 4-53, 4-57, 4-62, 4-93, 4-98, 4-105, 

4-122, 4-134, 5-1

nonattainment .................. 3-26, 3-27, 4-19

O

once-through............................ 4-31, 4-37, 

4-38, 4-43, 4-45, 4-117, A-16, A-18

once-through cooling .............. 4-31, 4-37, 

4-38, 4-43, 4-45, 4-117, A-16, A-18
Index

8-5

P

postulated accidents ..................4-1, 4-75, 

4-76, 4-77, 4-91, G-1

pressurized water reactor...................xxxii

R

radioactive nuclide..............................3-14

radon...................................3-13, 3-18, G-8

reactor .................................xxi, xxvii, xxxii, 

2-1, 2-2, 2-3, 2-9, 2-10, 2-28, 3-1, 3-6, 

3-10, 3-12, 3-15, 3-17, 3-19, 3-21, 3-24, 

3-25, 3-29, 3-35, 3-44, 3-52, 3-81, 3-99, 

3-108, 4-53, 4-60, 4-62, 4-64, 4-65, 4-76, 

4-77, 4-78, 4-80, 4-81, 4-83, 4-86, 4-88, 

4-93, 4-97, 4-102, 4-109, 4-127, 4-128, 

4-133, 4-136, 6-1, 6-3, A-9, A-22, A-23, 

A-25, A-26, A-34, A-39, A-92, E-1, E-10, 

F-1, F-3, F-9, F-10, F-12, F-16, F-18, 

F-20, F-26, F-27, F-32, F-38, F-41, G-1, 

G-2, G-3, G-4, G-7, G-11, G-12

refurbishment..............................2-2, 3-81, 

4-6, 4-27, 4-32, 4-61, 4-64, 4-114, 4-116, 

A-9, A-34

replacement power .....................xxiii, xxiv, 

xxxiv, 2-3, 2-5, 2-7, 2-16, 4-29, 4-70, 

4-80, 4-93, 4-94, 4-95, 4-100, 4-102, 

4-104, 4-130, 4-131, 4-133, A-27, A-37, 

F-3, F-22, F-40, F-41

right-of-way ..........................xxxii, 3-1, 3-7, 

3-21, 3-74, 3-80, 4-2, 4-31, 4-37

runoff ..................................3-7, 3-31, 3-37, 

3-40, 3-43, 3-45, 3-61, 4-26, 4-27, 4-28, 

4-29, 4-30, 4-32, 4-34, 4-108, 4-110, 

4-118, 4-119, 4-120, 4-125, A-26, B-4

S

scoping...............................iii, xxi, xxii, xxv, 

1-1, 1-2, 1-6, 1-8, 4-1, 4-7, 4-20, 4-22, 

4-24, 4-31, 4-38, 4-61, 4-65, 4-72, 4-76, 

4-77, 4-98, 4-101, 4-103, 4-113, 5-2, A-1, 

A-16, A-39, A-92, C-2, C-3, C-4, D-1

seismic...................................... xxxiii, 3-29, 

3-35, F-4, F-9, F-11, F-12, F-15, F-25, 

F-27, F-29

severe accident...................xxiv, xxxii, 4-1, 

4-75, 4-77, 4-86, 4-91, 6-1, A-2, D-1, F-1, 

F-11, F-20, F-38, F-41

severe accident mitigation 

alternative......................... xix, xxiv, xxxii, 

4-77, 4-78, 4-80, 4-81, 4-82, 4-83, 4-84, 

4-85, 4-86, 4-87, 4-88, 4-146, 6-1, 6-2, 

6-3, A-2, A-39, A-40, A-41, D-1, F-1, F-2, 

F-4, F-5, F-6, F-10, F-11, F-13, F-14, 

F-15, F-16, F-17, F-18, F-19, F-20, F-21, 

F-22, F-23, F-24, F-25, F-26, F-27, F-28, 

F-29, F-30, F-31, F-32, F-34, F-35, F-36, 

F-37, F-38, F-39, F-40, F-42, F-43, F-44, 

F-46

severe accidents ......................... xxiv, 4-1, 

4-75, 4-77, 4-91, F-11, F-20, F-41

solid waste........................ xxiv, 2-22, 3-13, 

3-16, 3-17, 3-99, 3-108, 4-13, 4-99, 

4-102, B-1, E-4

spent fuel........................ xxii, xxx, 1-4, 3-1,

3-6, 3-13, 3-17, 3-19, 3-20, 4-53, 4-101, 

4-102, 4-127, 4-136, A-38, A-39, E-1, 

G-1, G-2, G-3, G-4, G-6, G-7, G-8, G-9, 

G-11, G-12

State Historic Preservation Office 

(SHPO)..........................xxxiii, 3-84, 4-60, 

4-61, 4-62, 4-148

State Pollutant Discharge Elimination 

System (SPDES) ...............................B-1

stormwater....................... 3-37, 3-40, 3-44, 

3-45, 3-46, 3-49, 4-26, 4-27, 4-28, 4-29, 

4-30, 4-31, 4-32, 4-33, 4-53, 4-119, 

4-120, 4-125, B-4

surface runoff................................... 4-110

surface water................... 3-10, 3-36, 3-37, 

3-40, 3-41, 3-42, 3-46, 3-60, 3-100, 4-21, 

4-22, 4-23, 4-26, 4-27, 4-28, 4-29, 4-30, 

4-33, 4-47, 4-52, 4-73, 4-92, 4-102, 

4-110, 4-116, 4-117, 4-118, 4-119, 4-120, 

4-125, 4-132, 6-2, A-14, A-26, B-1, B-4

T

taxes.................................. 3-95, 3-97, 4-65

threatened and endangered 

species ....................... 3-76, 3-122, 4-56, 

4-125, 4-143, C-2, C-5

threatened species................... 3-57, 3-78, 

4-137, B-6, C-1

transmission corridor....................... 4-62, 

4-63, 4-64

transmission line corridors ................ 4-6, 

4-29, 4-34
Index

8-6

transmission lines ......................2-4, 2-12, 

2-13, 2-14, 2-16, 3-20, 3-76, 3-81, 3-101, 

3-102, 4-2, 4-5, 4-6, 4-19, 4-28, 4-29, 

4-30, 4-31, 4-34, 4-36, 4-37, 4-38, 4-53, 

4-60, 4-64, 4-72, 4-75

tribe......................................................3-83

tritium ................................3-15, 3-52, 4-25

U

U. S. Army Corps of Engineers 

(USACE) ......................................... xxxiii, 

3-20, 3-36, 3-46, 3-60, 3-130, 4-26, 4-28, 

4-29, 4-53, A-32, B-4, B-7, B-8

U.S. Department of Energy (DOE).... xxviii, 

2-4, 2-8, 2-9, 2-10, 2-11, 2-14, 2-15, 2-16, 

2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-27, 

2-28, 2-29, 2-30, 2-31, 2-33, 3-17, 4-10, 

4-14, 4-17, 4-67, 4-68, 4-70, 4-72, 4-138, 

4-139, 4-146, 6-3, G-3, G-5, G-7, G-13

U.S. Environmental Protection Agency 

(EPA) ................................xxviii, 1-2, 1-8, 

2-4, 2-11, 2-21, 2-22, 2-23, 2-30, 3-8, 

3-10, 3-12, 3-14, 3-15, 3-16, 3-25, 3-26, 

3-27, 3-28, 3-29, 3-42, 3-43, 3-44, 3-46, 

3-52, 3-67, 3-69, 3-95, 3-99, 3-108, 

3-110, 3-112, 3-115, 3-116, 3-132, 4-9, 

4-11, 4-12, 4-14, 4-15, 4-25, 4-39, 4-43, 

4-44, 4-53, 4-74, 4-89, 4-90, 4-104, 

4-105, 4-107, 4-108, 4-109, 4-114, 4-115, 

4-122, 4-124, 4-127, 4-129, 4-130, 4-131, 

4-133, 4-136, 4-137, 4-139, 4-140, 7-1, 

7-2, A-1, A-2, A-8, A-9, A-11, A-25, A-26, 

A-30, A-33, A-36, A-92, B-1, B-3, B-4, 

B-5, B-8, E-3, E-4, E-5, E-8, F-20

U.S. Fish and Wildlife Service 

(FWS)................................. xxix, 1-6, 1-8, 

2-8, 2-9, 2-14, 2-15, 2-33, 3-54, 3-59, 

3-75, 3-76, 3-77, 3-78, 3-79, 3-80, 3-81, 

3-109, 3-110, 3-121, 3-122, 3-129, 4-55, 

4-56, 4-57, 4-111, 4-137, 4-143, B-6, C-1, 

C-2, C-5

uranium................................ xxii, xxxv, 2-8, 

3-6, 3-19, 4-1, 4-3, 4-4, 4-34, 4-35, 4-89, 

4-100, 4-101, 4-102, 4-104, G-1, G-2, 

G-4, G-9

W

wastewater......................... 3-1, 3-18, 3-40, 

3-43, 3-44, 3-46, 3-93, 4-119, 4-120, 

4-123, 4-125, 6-1, A-6, A-12, A-13, A-14, 

E-4, E-7, E-8

Y

Yucca Mountain.................... xix, G-2, G-3, 

G-4, G-6, G-7, G-8, G-9, G-11, G-12, 

G-13
COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW

A-1

A. Comments Received on the LSCS Environmental Review

A.1 Comments Received During the Scoping Period

The scoping process for the environmental review of the license renewal application for LaSalle 

County Station, Units 1 and 2 (LSCS), began on February 3, 2015, with the publication of the 

U.S. Nuclear Regulatory Commission’s (NRC’s) Notice of Intent to conduct scoping in 

Volume 80 of the Federal Register, page 5793 (80 FR 5793). The scoping process included 

two public meetings held in Ottawa, Illinois, on March 10, 2015. Approximately 30 people 

attended the meetings. After the NRC presented its prepared statements on the license 

renewal process, the meetings were open for public comments. Attendees provided oral 

statements that were recorded and transcribed by a certified court reporter. A summary and 

transcripts of the scoping meetings are available through 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.html. The scoping meetings summary is 

available at ADAMS No. ML15091A329. Transcripts for the afternoon and evening meetings 

are available at ADAMS Nos. ML15083A538 and ML15089A580, respectively. In addition to 

receiving comments during the public meetings, the NRC received one comment electronically.

A total of 15 commenters provided comments during the scoping period. Comments from 12 of 

the 15 commenters were in support of license renewal for LSCS or in support of nuclear power 

in general. These comments are not within the scope of this license renewal review; therefore, 

the NRC staff did not respond to them. These commenters, along with the affiliation and the 

source of their comments (i.e., afternoon or evening scoping meeting transcript), are listed in the 

LSCS Scoping Summary Report (ADAMS No. ML15147A380).

Comments received from the other 3 of the 15 commenters (Linda Lewison, Marvin Lewis, and 

Nelson Dewey) do not fall within, or are specifically excluded from, the purview of the NRC’s

environmental review related to license renewal. These comments addressed the disposition of 

spent nuclear fuel and safety concerns associated with fuel enrichment and hydraulic fracturing. 

These comments and the NRC staff’s responses to them are available in the LSCS Scoping 

Summary Report (ADAMS No. ML15147A380).

A.2 Comments Received on the Draft Supplemental Environmental Impact 

Statement

The NRC issued a site-specific draft supplemental environmental impact statement (SEIS) for 

public comment in February 2015 (ADAMS No. ML16033A103). A 45-day comment period 

began on the date the U.S. Environmental Protection Agency (EPA) published a Notice of 

Availability of the filing of the draft SEIS, which allowed members of the public and agencies 

time to comment on the environmental review. On March 22, 2015, the NRC conducted a 

public meeting in Ottawa, Illinois, to describe the results of the environmental review, respond to 

questions, and accept public comments.

Table A–1 lists the commenters and their affiliation and includes the comment source, which 

shows how the comment was received (i.e., through a public meeting, by letter, or through 

Regulations.gov). The table also lists the ADAMS No. for the comment received. This number 

can be used to locate the document in the agency’s electronic document retrieval system 

(ADAMS). However, all of the public comments received are reproduced at the end of this 

appendix. Table A–1 also lists the identifying (ID) numbers that were assigned to the 

comments.
Appendix A

A-2

Table A–1. Commenters on the Draft Supplemental Environmental Impact Statement

Commenter Affiliation ID

Comment 

Source ADAMS No.

Gale Snyder Nuclear Energy 

Information Service

M-001

to

M-002

Meeting 

Transcript

ML16091A441

Doug O’Brien Illinois Clean Energy 

Coalition

M-003 Meeting 

Transcript

ML16091A441

Steve Bach Resident of Ottawa, Illinois M-004 Meeting 

Transcript

ML16091A441

Tom Jackson Illini State Park, IDNR M-005 Meeting 

Transcript

ML16091A441

Dan Boudart Nuclear Energy 

Information Service

M-006 Meeting 

Transcript

ML16091A441

Kenneth Westlake U.S. Environmental 

Protection Agency

E-001

to

E-002

Letter ML16098A330

Anonymous Nuclear Energy 

Information Service

N-001

to

N-002

Letter ML16091A112

Michael Gallager Exelon Generation 

Company, LLC

L-001

to

L-099

Letter ML16095A269

Nancy Ranek Exelon Generation 

Company, LLC

L-100

to

L-173

Letter ML16099A107

Rachel Leibowitz Illinois Historic 

Preservation Agency

H-001 Letter ML16082A274

Valincia Darby U.S. Department of Interior I-001 Regulations.gov ML16098A329

In response to the comments, the NRC staff revised the text of the report as appropriate and 

documented its response to these comments in this appendix. However, the NRC staff did not 

provide a response for all comments, including those that did not require the staff to reevaluate

the report (i.e., Comments M-004, M-005, H-001, and I-001). In addition, the NRC staff did not 

provide responses for Comments L-100 to L-173. Because these comments involved mostly 

small editorial and punctuation changes, the NRC staff revised the text as appropriate but did 

not prepare written responses.

Section A.3 contains the comments and the NRC staff’s responses to them. They have been 

grouped by resource area or by evaluations in the report, such as alternatives, waste 

management, climate change, and severe accident mitigation alternatives (SAMAs). 

Section A.4 contains copies of the original comments along with the identifying number 

assigned to each comment. Section A.5 contains the list of references for this appendix.
Appendix A

A-3

A.3 Comments and Responses Regarding the Draft SEIS

A.3.1 Alternatives

Comment L-028: In Section 2.2.2 on page 2–6, correct the sentence in lines 15 to 17 as 

follows: “The [Illinois] law also includes an energy efficiency standard that requires utilities to 

implement cost-effective energy efficiency measures to meet energy savings of 12 percent by 

calendar year 2016 and thereafter (ILGA 2011).”

SB 1652, Section 5/8–103 (ILGA 2011, page 46) sets the energy savings goal for Illinois utilities 

at 2 percent of energy delivered in the year commencing June 1, 2015 and thereafter.

Response: The commenter requests that the statement regarding state energy efficiency 

requirements be corrected. The NRC staff agrees with the comment and revised the text as 

suggested.

Comment L-029: In Section 2.2.2.1 on page 2–9, correct the sentence in lines 6 to 8 as 

follows: “Twelve nuclear power plants operate in the ROI; eightten applicants have received 

renewed licenses, and threetwo additional applicants have applied for renewed licenses from 

the NRC (including LSCS) (NRC 2015

http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html).

The corrections reflect renewals of the Byron and Braidwood Stations’ operating licenses in 

November 2015 and January 2016, respectively (see 

http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html)

Response: The commenter requests that the statement regarding the status of nuclear plants 

within the region of influence (ROI) be updated to include recent licensing actions concerning 

Byron and Braidwood. The NRC staff has updated the text to reflect the renewed license 

recently issued to Braidwood; however, Byron had already been included in the earlier values 

presented. Of the 12 nuclear power plants in the ROI, 9 have received renewed licenses 

(Braidwood, Byron, Dresden, Quad Cities, Duane Arnold, Callaway, Donald Cook, Palisades, 

and Point Beach). Two (Fermi and LaSalle) have applied for renewed licenses from the NRC, 

and one (Clinton) has yet to submit a license renewal application. Therefore, the NRC staff 

revised the text as appropriate.

Comment L-030: In Section 2.2.2.4 on page 2–16, the sentence in lines 17 to 18 reads as 

follows: “For the solar portion of this combination alternative, approximately 7,397 ac (2,993 ha) 

would be required to support an installed net capacity of 227 MWe.” In the Combination 

Alternative column of Table 2–1 on p. 2–8, the Land Requirements row reads, in part, as follows 

for the 227 MWe installed solar PV facility portion: “[S]olar PV facilities would require 6,749 ac 

(2,731 ha) (Ong et al. 2013).” The inconsistency between Table 2–1 and the sentence in 

lines 17 to 18 on p. 2–16 with respect to land requirements should be corrected or explained.

Response: The commenter has identified an inconsistency in the report regarding the land 

required for the solar portion of the combination alternative. The NRC staff has corrected 

Table 2–1 and related discussions in Sections 4.2.6 and 4.6.6 to conform them with the value of 

7,397 acres (ac) (2,993 hectares (ha)) presented in Section 2.2.2.4.

Comment L-031: In Section 2.4 on page 2–24, the sentence in lines 1 to 2 reads as follows: 

“The environmental impacts of the proposed action ... would be SMALL for all impact 

categories.” However, in the “Proposed Action” column of Table 2–2 on p. 2–25, the “Aquatic 

Resources” row contains the words “SMALL to MODERATE.” The inconsistency between 

Table 2–2 and the sentence in lines 1 to 2 on page 2–24 with respect to impact level 
Appendix A

A-4

characterization should be corrected based on the resolution of Exelon Generation’s comments 

regarding section 4.7.1.2 in the DSEIS, which are presented in comments L-001 through L-009.

Response: The commenter has identified an inconsistency regarding Table 2–2 and the 

associated text in Section 2.4. The NRC staff has revised the text to conform with the impact 

determinations in Table 2–2.

Comment L-032: In Section 2.4 on page 2–26, the “Key” for Table 2–2 on p. 2–26 should be 

corrected as follows: Key: IGCC = coal-integrated gasification combined-cycle (alternative), 

NGCC = natural gas combined-cycle (alternative), NRHP = National Register of Historic Places, 

APE = area of potential effect, CRMP = Cultural ResponseResources Management Plan, and 

IHPA = Illinois Historic Preservation Agency.

Response: The commenter identified that the acronym CRMP is defined incorrectly in the key 

to Table 2–2. The NRC staff has revised the text as appropriate.

A.3.2 Description of Nuclear Power Plant and Facility

Comment L-033: In Section 3.1.1 on page 3–1, correct the text in line 16 as follows:

“ ... Braidwood Generating Station in Braceville, Illinois. Interstate Highway 80 is 8 mi (13 km) 

north...”

Response: The NRC staff agrees with the comment and corrected the text as suggested.

Comment L-034: In Section 3.1.1 on page 3–1, correct the sentence in lines 22 to 24 as 

follows: “The Chicago, Rock Island and PacificCSX Railroad, which runs parallel to, and slightly 

north of, the Illinois River, is the closest railroad line in this area.” Exelon Generation provided 

this updated railroad ownership information in response to RAI LU-03 (ML15185A375). Also, 

DSEIS Section 3.1.6, p. 3–20, reflects the updated railroad information.

Response: The NRC staff agrees with the comment and revised the text as suggested.

Comment L-035: In Section 3.1.3 on page 3–7 in line 20, correct the text as follows:

“ ... thea natural levee of the Illinois Rivercreated by existing topography forms the fourth side.”

Response: The commenter requests that a statement regarding the cooling pond be modified. 

The NRC staff agrees with the comment and revised the text as suggested.

Comment L-36: In Section 3.1.3 on page 3–11 in line 1, correct the text as follows:

“ ... water supplied to the facility from the UHS portion of the cooling pond to 101.25 °F 

(38.5 °C)within diurnal temperature limits based on the time of day, but that are no higher than 

104 oF (40 oC) ...” This correction is needed because Tech Spec 3.7.3 was revised by Letter 

from NRC to Exelon Generation (B. Hanson) dated 11/19/2015, ADAMS Accession 

No. ML15202A578.

Response: The commenter requests that a statement on the technical specification-prescribed 

temperature limit in the ultimate heat sink (UHS) portion of the cooling pond be revised to reflect 

the revised temperature limits approved by the NRC in response to an Exelon Generation 

Company, LLC (Exelon) license amendment request. The NRC staff agrees with the comment 

and revised the text as suggested. In addition, a reference citation to the approved license 

amendment (issued by the NRC in November 2015) has been added.

Comment L-037: In Section 3.1.3 on page 3–11 in line 4, correct the text in the parenthetical 

on as follows: “... (3.36 million m3

/d) ...” 
Appendix A

A-5

Response: The commenter requests that the units of measure given in parentheses for 

condenser circulating water flow be revised. The NRC staff agrees with the comment and 

revised the text as suggested.

Comment L-038: In Section 3.1.3 on page 3–11 in line 11, correct the text as follows:

“... openings. Trash rakes prevent larger debris and aquatic biota from entering the system. 

The ...”. The deleted sentence is incorrect because bar grills, not the trash rake, prevent larger 

debris from entering the system. The trash rake is used to remove such debris from the bar 

grill. The bar grills are sometimes referred to collectively as the trash rack.

Response: The commenter requests that a statement regarding the trash rakes be deleted. 

The NRC staff agrees with the comment and deleted the statement as suggested.

Comment L-039: In Section 3.1.3 on page 3–11 in lines 44 to 46, correct the sentence as 

follows: “Nevertheless, the blowdown lineradwaste discharge line is equipped with a radiation 

monitor that will automatically isolateclose the radwaste discharge linevalve in the event of a 

high-radiation signal ...”. See LSCS UFSAR, subsection 11.2.2.6, p. 11.2–19.

Response: The commenter requests that a statement regarding the monitored discharge of 

radwaste to the blowdown line be revised. The NRC staff agrees with the comment, revised the 

statement as suggested, and further reorganized the paragraph for clarity.

Comment L-040: In Section 3.1.3 on page 3–11 in line 46, the reference “Exelon 2014b” is 

cited. This appears to be an error because Section 3.14 in the Draft SEIS identifies 

“Exelon 2014b” as follows: “[Exelon] Exelon Generation Co. LLC. 2014b. Illinois Water 

Inventory Program [LaSalle County Station report submitted to the Illinois State Water Survey 

for calendar year 2013]. ADAMS No. ML15195A385.” The document identified as 

Exelon 2014b contains no information about the LSCS radwaste processing system.

Response: The commenter indicates that a text reference citing information on the radwaste 

discharge to the blowdown line is not correct. The NRC staff agrees with the comment. As 

noted by the commenter, “Exelon 2014b” erroneously cited the wrong reference document and 

was intended to cite the LSCS updated final safety analysis report (UFSAR) in Section 3.14. 

The reference listings in Section 3.14 and the corresponding text reference citations in 

Chapter 3 have been reviewed and revised, as necessary, and “Exelon 2014b” now accurately 

corresponds to the reference listing for the LSCS UFSAR in Section 3.14.

Comment L-041: In Section 3.1.3 on page 3–12 in lines 2 to 3, correct the text as follows:

“...lined swale that connects with the Illinois River at RM 249.4 (RKm 401) and just 

upstreamdownstream of the LSCS river screen house...” 

Response: The commenter requests that a statement on the location of the discharge

structure relative to that of the river screen house be revised. The NRC staff agrees with the 

comment and revised the statement as suggested.

Comment L-042: In Section 3.1.5 on page 3–18 in line 14, correct the text as follows:

“... nuclear power plants generate both hazardous and nonhazardous wastes that are not 

contaminated with either radionuclides or hazardous chemicals.” This correction is needed 

because contamination with hazardous chemicals is not the only criteria for a nonradioactive 

waste to be classified as hazardous waste and because this section addresses nonradioactive 

wastes that are both hazardous and nonhazardous.

Response: The NRC staff agrees with the comment and revised the text as suggested.
Appendix A

A-6

Comment L-043: In Section 3.1.5 on page 3–18 in lines 34 and 35, correct the text as follows 

because nonradioactive industrial wastewaters are not processed at the sewage treatment 

plant: “... Nonradioactive industrial wastewater is also processed at thea separate onsite 

wastewater treatment plant, and the treated effluent is also discharged into the cooling pond.

Response: The NRC staff agrees with the comment and updated the text as suggested.

Comment L-044: In Section 3.1.6.1 on page 3–19 in lines 12 to 15, correct the text as follows 

because LSCS has five, rather than six, diesel generators to supply standby a-c power: 

“... LSCS has sixfive diesel generators. (three for each nuclear unit) that can each Two 

diesel-generators each are provided for Units 1 and 2. The other diesel-generator is arranged 

to serve essential auxiliaries for either Unit 1 or Unit 2 (Exelon 2014g, Section 1.2.2.6.7). Each 

diesel-generator is designed and installed to provide up to 4.16 kV of power, which is ample 

capacity to supply all power required for the safe shutdown of both units in the event of a total 

loss of offsite power (Exelon 2014g, Section 8.3.1.2).

Response: The commenter requests that statements regarding onsite independent power 

sources be revised to reflect the correct number and function of the diesel generators. The 

NRC staff agrees with the comment and revised the statements as suggested.

Comment L-045: In Section 3.1.6.3 on page 3–19 in line 39, correct the text as follows:

“... for potable water and other uses.”

Response: The commenter requests the NRC staff to make a correction to a statement 

regarding deep well water use. The NRC staff agrees with the comment and revised the 

statement as suggested.

Comment L-046: In Section 3.1.6.4 on page 3–20 in line 11, correct the text as follows: 

“...Lock and Dam at Marseilles, Illinois, and the Dresden Island Lock and Dam south of 

Channahon,...”

Response: The commenter requests that the NRC staff make a correction to the name of a 

lock and dam referenced in the SEIS. The NRC staff agrees with the comment and revised the 

statement as suggested.

Comment L-047: In Section 3.1.6.4 on page 3–20 in lines 12 and 13, correct the sentence as 

follows: “... These lock and dam sites are part of the Illinois Waterway, which flows from 

Chicago, Illinois, to Grafton, Illinois, slightly upstream from St. Louis, Missouri, and is composed 

of seven water systems: ...” See DSEIS Section 3.5.1.1, page 3–35, line 43.

Response: The commenter requests that the NRC clarify the termination point of the Illinois 

Waterway. The NRC staff agrees with the comment and revised the statements as suggested.

A.3.3 Land Use and Visual Resources

Comment L-048: In Section 3.2.1.1 on page 3–21 in line 18, correct the text as follows 

because the cooling pond is located on the eastern side of the LSCS site: “A cooling pond 

occupies the westerneastern side of the site and accounts for about half of the site area.”

Response: The commenter requests that the NRC staff correct a reference to the location of 

the cooling pond on site. The NRC staff agrees with the comment and revised the statement as 

suggested.

Comment L-049: In Section 3.2.2 on page 3–24, correct the sentence in lines 3 to 4 as follows: 

“... The site’s grade elevation is approximately 216 m (710 ft) above MSL, which is one of the 

highest points within a 3-km (5-mi) radius.” This correction is needed because, in line 12 on 
Appendix A

A-7

page 3–24, the DSEIS describes wind turbines located within 5 miles of LSCS and indicates 

them to be at slightly higher elevations (725 to 750 ft) than the LSCS site. Also, the LSCS 

License Renewal Environmental Report (ER) (page 3–9) and the UFSAR on which it is based 

(e.g., Section 2.3.2.3) indicate the plant is one of the highest points, but does not designate it as 

the highest point, within a 5-mile radius. The ER (page 3–9) goes on to describe the slightly 

higher ground west and east of LSCS as the site of several wind turbines.

Response: The commenter requests that the NRC staff clarify that the site is one of several 

areas with high elevation that are within the vicinity of the site. The NRC staff agrees with the 

comment and revised the statement as suggested.

Comment L-075: In Section 4.2.6.1 on page 4–5 in the 2nd line of the 1st paragraph correct 

the text as follows: “... as discussed for the NGCC alternative in Section 4.3.3.14.2.5.1. 

Accordingly, the impacts to land use ...”

Response: The commenter requests that the NRC staff correct a reference to an SEIS section 

number. The NRC staff agrees with the comment and revised the statement as suggested.

Comment L-076: In Section 4.2.6.1 on page 4–5 in the 2nd line of the 1st paragraph correct 

the text as follows: “... than those described in Section 4.3.3.24.2.5.2 for the NGCC alternative 

and, therefore, would be ...”

Response: The commenter requests that the NRC staff correct a reference to an SEIS section 

number. The NRC staff agrees with the comment and revised the statement as suggested.

A.3.4 Meteorology, Air Quality, and Noise

Comment L-050: In Section 3.3.1 on page 3–24 in line 25, correct the sentence as follows:

“LSCS is located in LaSalle County in northeastern Illinois, approximately 7075 mi (113120 km) 

southwest of downtown Chicago and 35 mi (56 km) southwest of Joliet, Illinois...”

This correction is needed for consistency with the estimated distance to Chicago provided on 

p. 3–21 in the DSEIS, and to provide an approximate point of reference within the Chicago city 

limits for the measurement.

Response: The commenter requests that the distance between LSCS and downtown Chicago 

be revised. The NRC staff agrees with the comment and revised the statement as suggested.

Comment L-051: In Section 3.3.2 correct the paragraph that begins in line 22 on page 3–26 

and ends in line 9 on page 3–27 as follows because a renewed LSCS FESOP Permit 

No. 099802AAA was issued on January 7, 2016: “Illinois air pollution control rules are issued 

under Title 35 of the IAC. Air emission sources at LSCS are regulated under a Federally 

Enforceable State Operating Permit (FESOP) (Permit No. 099802AAA, issued in 

December 2000January 7, 2016) (IEPA 2016).issued by the IEPA (IEPA 2000). A source is 

eligible for a FESOP (also known as “synthetic minor” air permit) if the potential to emit from the 

source triggers CAA permit program requirements but if maximum actual emissions are below, 

or can be restricted to remain below, major source thresholds. LSCS’s FESOP permit was 

issued in December 2000, and expired in December 2005. In accordance with 35 IAC Part 201 

and the Illinois Environmental Protection Act of 1970 (415 Illinois Compiled Statute (ILCS) 5/39), 

Exelon submitted a renewal application for the FESOP permit (on July 15, 2005) to the IEPA 90 

days before the expiration of the permit; therefore, the conditions of the FESOP are 

administratively extended. On April 7, 2015, the IEPA issued a draft FESOP permit for LSCS 

for public review and comment (IEPA 2015).”
Appendix A

A-8

Response: The commenter requests that Section 3.3.2 of the SEIS be updated to state that 

the LSCS FESOP permit was renewed and issued under the Illinois Environmental Protection 

Act of 1970 (IEPA) in January 2016. The NRC staff requested that Exelon provide a copy of the 

2016 FESOP permit because it had previously provided a copy of the 2000 FESOP permit in 

response to a 2015 request for additional information (RAI). The NRC staff reviewed the air 

permit and agrees with the comment. Section 3.3.2 of the SEIS has been revised to identify 

that the FESOP permit was issued by the IEPA in January 2016.

Comment L-052: In Section 3.3.3 on page 3–27, Correct the entry in the “2013” column and 

“CO” row of Table 3–4 as follows: “1.91.6.” This correction is needed because the value 

reported in the 2013 LSCS Annual Emissions Report is 1.754656 tons of CO or approximately 

1.6 metric tons (see Response to RAI MA-05 in Letter to NRC from Exelon Generation (M. 

Gallagher) dated 7/02/2015).

Response: The commenter requests that Table 3–4 correct the carbon monoxide emissions 

for the year 2013. The NRC staff agrees with the comment and the 2013 carbon monoxide 

emission was revised to 1.6 metric tons (MT) in Table 3–4 of the SEIS.

Comment L-077: In Section 4.3.5.1 on page 4–14, in the last bulleted item, the CO2e 

emissions from the NGCC alternative are stated to be “9.8 million tons per year.” This value is 

incorrect. The CO2e emission rate of 8.2 million MT per year is correct based on the cited 

emissions factor. However, 8.2 million MT converts to approximately 9 million tons, not 

9.8 million tons. The incorrect value appears twice –once in the bulleted list and again in the 

last (partial) paragraph at the bottom of page 4–14, and should be corrected in both locations.

Response: The commenter requests that Section 4.3.5.1 correct the carbon dioxide equivalent 

(CO2e) conversion from metric ton to ton. The NRC staff agrees with the commenter and has 

corrected 9.8 million tons to 9.0 million tons.

Comment L-078: In Section 4.3.6 on page 4–16 in the 4th line of the 1st paragraph, the text 

states that the NGCC portion of the Combination Alternative would have “a total net capacity of 

360 MWe.” That net capacity is consistent with the description of the combination alternative in 

Section 2.2.2.4 (see DSEIS page 2–14, lines 9 and 22). However, on page 4–17, in the partial 

paragraph before the bulleted list, the text states that the projected air emissions for the NGCC 

portion of the Combination Alternative were estimated “[a]ssuming a total gross capacity of 

360 MWe” (emphasis added), and the values for the emission rates presented in the bulleted list 

on p. 4–17 were calculated using 360 MWe as the gross capacity (306 MWe net). Accordingly, 

the NGCC emissions in the bulleted list are inconsistent with Section 2.2.2.4, and they need to 

be recalculated using a total net capacity of 360 MWe.

Response: The commenter requests that NGCC emissions for the Combination Alternative be 

recalculated to use a total net capacity of 360 megawatts electric (MWe). The NRC staff agrees 

with the commenter and has recalculated the emissions based on a 425-MWe gross capacity 

and an 85-percent capacity factor.

A.3.5 Water Resources

Comment E-001: The Draft SEIS states that the river intake pipeline has experienced “a 

number of breaks” resulting in flooding and erosion of areas around the breaks. We note these 

breaks are not safety related and were reported to both U.S. EPA and Illinois EPA, per 

provisions of the National Pollution Discharge Elimination System permit. The document states 

that several structural and procedural measures have been taken to address the issue. The 

Draft SEIS does not state whether the measures have successfully repaired the breaks and 

eliminated recurrence of this problem, including whether flooding and erosion have been 
Appendix A

A-9

successfully addressed. Recommendation: The Final SEIS should clarify whether the 

mentioned structural and procedural improvements to reduce incidences of leaks and improve 

response have been successful and whether the resulting flooding and erosion has been 

successfully addressed. We recommend any further work on the intake system be considered 

refurbishment activities and be included as part of the analysis in the Final SEIS.

Response: EPA requests that the final SEIS discuss whether the measures taken by Exelon, 

as cited in the SEIS, to prevent and respond to breaks that have occurred in LSCS’s river intake 

pipeline have been successful, including associated flooding and erosion. EPA also suggests 

that the operation and maintenance actions taken by Exelon be considered refurbishment

activities and included in the final SEIS.

The NRC staff agrees with the comment in part and disagrees with it in part. The discussion of 

pipeline failures is presented within the context of past and present actions at licensed nuclear 

power plants and includes an explanation on how they have shaped the current natural and 

human-built environment. These existing conditions serve as the baseline for the evaluation of 

the potential impacts of continued operations during the license renewal term. The NRC staff 

agrees that additional information on the nature of the impacts experienced to date and on 

measures taken to repair pipeline leaks and to restore the affected environment would be 

appropriate and informative. Therefore, the discussion in Section 3.1.3 was expanded in this 

regard. However, the NRC staff offers no assessment as to whether the actions taken by 

Exelon have been successful in reducing the frequency of pipeline failures. As noted by EPA, 

the pipeline serves no safety-related function; therefore, its operation is not directly regulated by 

the NRC. Exelon has taken action to report, respond, and repair pipeline failures in accordance 

with its operation and maintenance procedures and applicable State laws and regulations, 

including the reporting provisions contained in the National Pollutant Discharge Elimination 

System (NPDES) permit issued to LSCS.

The NRC staff also disagrees that any ongoing or future work undertaken by Exelon to reduce 

the frequency and impacts of pipeline breaks should be considered refurbishment and 

discussed as such in the SEIS. The NRC’s regulations at Title 10 of the Code of Federal 

Regulations (10 CFR) 51.53(c)(2) prescribe the content of ERs that reactor licensees seeking 

license renewal must submit to the NRC. In their ERs, licensees must describe in detail the 

affected environment around the plant, the modifications directly affecting the environment or 

any plant effluents, and any planned refurbishment activities. As summarized in Section 2.1.2 

of this SEIS, the NRC considers refurbishment to encompass the replacement and repair of 

major systems, structures, and components to ensure the safe and economic operation of 

nuclear plants beyond the current license term(s). In its ER, as indicated in Section 2.1.2 of this 

SEIS, Exelon did not identify any major refurbishment or replacement activities needed to 

support the continued operation of LSCS beyond the existing operating license terms. 

Therefore, the NRC staff considers Exelon’s actions to reduce the frequency and severity of 

pipeline breaks to constitute operation and maintenance, which Exelon would be expected to 

continue to perform during the current license terms regardless of a license renewal decision.

Comment L-053: In Section 3.5.1.1 on page 3–39 in line 17, correct the text as follows: 

“...sanitary effluent. These lagoons are clay and geotextile-lined impoundments and are located 

to the north ...” This correction is needed to accurately characterize the design of the sewage 

treatment lagoons, as described in the LSCS License Renewal Environmental Report, in 

Section 2.2.8 on page 2–16.

Response: The commenter requests that a statement regarding the construction of the 

sewage treatment lagoons be expanded for accuracy. The NRC staff agrees with the comment 

and revised the text as suggested.
Appendix A

A-10

Comment L-54: In Section 3.5.1.2 on page 3–39 in line 46, correct the text as follows because 

LSCS has a cooling pond rather than a cooling tower: “... essential cooling water systems. 

Cooling towerpond blowdown and other permitted effluent streams ...”

Response: The commenter requests that a statement regarding cooling blowdown be modified 

for accuracy. The NRC staff agrees with the comment and revised the text as suggested.

Comment L-055: In Section 3.5.1.2 on page 3–40 correct the “Sources” cited for Table 3–6 as 

follows: “Sources: Exelon 2011a, 2012a, 2013a, 2014a, 2014d2014b”. This correction is 

needed because the 2013 Illinois water survey report is listed in section 3.14 of the DSEIS as 

“Exelon 2014b”.

Response: The commenter indicates that a text reference citation in Table 3–6 is not correct. 

The NRC staff agrees with the comment. As noted by the commenter, the citation 

“Exelon 2014d” referred to the wrong reference document and was intended to cite the 2013 

Illinois water survey report. The citation in question has been revised to “Exelon 2014e” for 

accuracy with the references listed in Section 3.14, which have been reviewed and revised, as 

necessary, for accuracy.

Comment L-056: In Section 3.5.1.2 on page 3–41 in line 17, correct the text as follows:

“... vicinity of LSCS (Figure 3–53–11) and are listed in the Illinois Water Inventory Program. 

These are ...” This correction is needed because Figure 3–5 does not show the locations of the 

two industrial facilities mentioned in the text.

Response: The commenter requests that the text reference to Figure 3–5 be revised for 

accuracy. The NRC staff agrees with the comment and revised the figure reference as 

suggested.

Comment L-057: In Section 3.5.1.3 on page 3–43 in line 11, correct the text as follows 

because the plant’s outfalls are summarized in Table 3–7 rather than on the cited figure:

“...through the plant’s outfalls to the Illinois River, as summarized in FigureTable 3–7. The 

location of...”

Response: The commenter requests that the text reference to Figure 3–7 be revised to 

Table 3–7 for accuracy. The NRC staff agrees with the comment and revised the reference as 

suggested.

Comment L-058: In Section 3.5.1.3 on page 3–43 in lines 11 to 12, correct the text as follows: 

“The location of the LSCS’s primary outfall (001) to the Illinois River is shown in Figure 3–53–

11. This correction is needed because Figure 3–5 does not show the location of LSCS 

Outfall 001.

Response: The commenter requests that the text reference to Figure 3–5 be revised for 

accuracy. The NRC staff agrees with the comment and revised the figure reference as 

suggested.

Comment L-079: In Section 4.5.1.1 on page 4–23 in the 8th and 9th lines of the 1st full 

paragraph, correct the text as follows: “... Agrium U.S., Inc., and PCEPCS Phosphate, 

Marseilles Operation. These facilities are discussed in Section 3.5.1.2 and shown in 

Figure 3–53–11.” These corrections are needed because Figure 3–5 does not show the 

locations of the two industrial facilities mentioned in the text and because the name “PCE 

Phosphate” is incorrect.

Response: The commenter indicates that the name of one of two listed industrial facilities is 

incorrect and that a referenced figure number is in error. The NRC staff agrees with the 

comments and revised the facility name and figure number as suggested.
Appendix A

A-11

Comment L-080: In Section 4.5.1.2 on page 4–25 in the 4th line of the 1st full paragraph, 

correct the text as follows:

“... a maximum of 750 milligrams per liter (mg/L)a concentration below the applicable State of 

Illinois water quality standard for receiving waters as set forth in 35 IAC 302, which is less than 

half the total dissolved solids ...” This correction is needed due to recent LSCS operational 

procedure changes.

Response: The text has incorporated the more recent information.

A.3.6 Terrestrial Resources

Comment L-059: In Section 3.6.3 on page 3–54 in line 29, correct the text as follows because 

the cooling pond is located on the eastern side of the LSCS property: “A cooling pond occupies 

the westerneastern side of the site and accounts for about half of the site area.”

Response: The commenter requests that the NRC staff correct a reference to the location of 

the cooling pond on site. The NRC staff agrees with the comment and revised the statement as 

suggested.

Comment L-081: In Section 4.5.1.2 on page 4–35 in the 14th to 15th lines of the 3rd 

paragraph, correct the text as follows: “... The effects of climate change on terrestrial resources 

are discussed in Section 4.13.3.24.15.3.2...”

Response: The commenter requests that the NRC correct a reference to an SEIS section 

number. The NRC staff agrees with the comment and revised the statement as suggested.

Comment L-082: In Section 4.6.5 on page 4–36 in the 5th to 6th lines of the 3rd paragraph, 

correct the text as follows: “... The effects of climate change on terrestrial resources are 

discussed in Section 4.13.3.24.15.3.2...”

Response: The commenter requests that the NRC correct a reference to an SEIS section 

number. The NRC staff agrees with the comment and revised the statement as suggested.

Comment L-083: In Section 4.6.6 on page 4–36 in the 2nd line of the 1st paragraph, correct 

the text as follows: “... as discussed for the NGCC alternative in Section 4.3.3.14.6.5. 

Accordingly, the impacts to terrestrial ...”

Response: The commenter requests that the NRC correct a reference to an SEIS section 

number. The NRC staff agrees with the comment and revised the statement as suggested.

A.3.7 Aquatic Resources

Comment L-001: At Section 4.7.1.2 page 4–38, clarify the 2nd paragraph in Section 4.1.7.2 on 

p. 4–38 by adding a new sentence after the sentence on the 3rd and 4th lines in the paragraph, 

as follows: “Impingement can kill organisms immediately or contribute to a slower death 

resulting from exhaustion, suffocation, injury, and other physical stresses. However, 

impingement survival is common and impinged organisms often include those that are 

previously moribund, injured, or otherwise in poor health.”

Response: The commenter suggests that the NRC staff include a statement that impingement

survival is common. The NRC staff did not include the suggested statement because it does 

not agree that impingement survival is common. Impingement survival is variable and can be 

less than 1 percent at some power plants (Miller 2007; EPA 2014). The rate of impingement 

survivability depends on the species impinged, health of the impinged organism, age of the 

impinged organism, exposure to heat or other pollutants, time spent impinged, and occurrence 
Appendix A

A-12

of fish return systems or other technologies used to reduce impingement mortality 

(Miller et al. 2007; EPA 2014). As described in NUREG–1437, Generic Environmental Impact 

Statement for License Renewal of Nuclear Plants (GEIS) (NRC 2013a), although fish return 

systems or other technologies can decrease impingement mortality, some stressed and injured 

fish returned to the water body may take a number of days to die, and even individuals with 

minor damage may develop a bacterial or fungal infection that eventually leads to mortality. 

This comment did not result in any changes to the SEIS.

Comment L-002: At Section 4.7.1.2, page 4–40, clarify the 2nd paragraph under the heading 

“LOE 1: Impingement Studies” on p. 4–40 by adding a sentence in the 6th line as follows:

“... (Pimephales notatus; 5 percent). All other impinged species comprised less than 5 percent 

of the impinged fish (EA 2015). Gizzard shad was the most commonly impinged species and...”

Response: The commenter suggests that the NRC staff clarify that each species not described 

in the impingement summary paragraph comprised less than 5 percent of the impingement 

sample. The NRC staff did not include this statement because it is repetitive with the sentence 

located in Section 4.7.1.2, page 4-40, in the fourth paragraph under the heading entitled, 

“LOE 1: Impingement Studies.” This comment did not result in any changes to the SEIS.

Comment L-003: At Section 4.7.1.2, page 4–40, in the 4th paragraph under the heading 

“LOE 1: Impingement Studies” on p. 4–40, delete the 2nd sentence, as follows, because, as a 

result of the preceding comment, it will appear in the 2nd paragraph under the same heading:

“Both round goby and threadfin shad are invasive species. All other impinged species 

comprised less than 5 percent of the impinged fish (EA 2015).”

Response: The commenter suggests that the NRC staff delete a statement that each species 

not described in the impingement summary paragraph comprised less than 5 percent of the 

impingement sample. The NRC staff did not delete the statement because it describes the 

impacts from impingement to these species. This comment did not result in any changes to the 

SEIS.

Comment L-004: At Section 4.7.1.2, page 4–41, clarify the conclusion in the 2nd paragraph 

under the heading “LOE 1 Conclusion” on p. 4–41 by revising it as follows: “...the impacts of 

impingement on the aquatic community within the cooling pond are unknown because, they 

have not been addressed in studies as a wastewater treatment system, the LSCS closed-cycle, 

recirculating, cooling pond is exempt from impingement and entrainment monitoring 

requirements under Section 316(b) of the Clean Water Act (CWA). Accordingly, studies have 

not been conducted.”

Comment L-005: At Section 4.7.1.2, page 4–41, clarify the conclusion in the 2nd paragraph 

under the heading “LOE 2 Conclusion” by revising it as follows: “...the impacts of entrainment

on the aquatic community within the cooling pond are unknown because, they have not been 

addressed in studies as a wastewater treatment system, the LSCS closed-cycle, recirculating, 

cooling pond is exempt from impingement and entrainment monitoring requirements under 

Section 316(b) of the Clean Water Act (CWA). Accordingly, studies have not been conducted.”

Comment L-007: At Section 4.7.1.2, page 4–45, clarify the 1st sentence in the last paragraph 

under the heading “Overall Impingement and Entrainment Conclusion” by revising it as follows: 

“Although fish and aquatic biota are also impinged and entrained at the cooling pond screen 

house when cooling pond water is drawn into LSCS’s cooling system pond intake structure, the 

impacts of impingement and entrainment on the aquatic community within the cooling pond are 

unknown because, Exelon has not conducted any impingement or entrainment studies at the 

cooling pond intake, nor have any consistent fish monitoring studies been implemented in the 
Appendix A

A-13

cooling pond.as a wastewater treatment system, the LSCS closed-cycle, recirculating, cooling 

pond is exempt from impingement and entrainment monitoring requirements in Section 316(b) 

of the Clean Water Act (CWA).”

Response: The commenter suggests that the NRC staff revise the SEIS to state that the 

impacts of impingement and entrainment on the aquatic community within the cooling pond are 

unknown because, as a wastewater treatment system, the cooling pond is exempt from 

impingement and entrainment monitoring requirements in the CWA. The NRC staff does not 

agree with this comment because it is not the requirements of the CWA that make the 

impingement and entrainment impacts within the cooling pond unknown, but rather, the impacts 

are unknown because no impingement and entrainment studies exist to evaluate such impacts, 

regardless of the CWA requirements. The fact that cooling pond monitoring is not required

under Section 316(b) of the CWA does not preclude Exelon from conducting impingement and 

entrainment studies to better characterize the potential impacts to aquatic resources within the 

cooling pond for the purposes of developing a license renewal application. For example, in 

support of the South Texas Project (STP) license renewal application, the STP licensee

submitted a study that examined impingement and entrainment rates from the withdrawal of 

water from the STP cooling pond into its cooling water system (ENSR 2008). NRC (2013b) 

reviewed the impingement and entrainment study as part of its evaluation of operational impacts 

on aquatic resources within the cooling pond at STP. 

The NRC staff agrees, however, with the portion of the comment that states that the LSCS

closed-cycle, recirculating, cooling pond is exempt from impingement and entrainment

monitoring requirements under Section 316(b) of the Clean Water Act (CWA). For example, in 

Section 3.5.1.3 of the SEIS, the NRC staff states that the LSCS’s cooling pond is defined by the 

State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 

definition, the cooling pond is not waters of the State under 35 IAC 301.440 nor is it subject to 

State or Federal water quality standards. In the final SEIS, the NRC staff further clarifies in 

Section 3.5.1.3 that the LSCS closed-cycle, recirculating, cooling pond is exempt from 

impingement and entrainment monitoring requirements under Section 316(b) of the Clean Water 

Act (CWA).

Comment L-006: At Section 4.7.1.2, page 4–44, clarify the 1st full sentence in the partial 

paragraph at the top of page 4–44 by revising it as follows: “... The cooling pond system is 

similar to a closed-cycle cooling system, which is similar to cooling towers in that water in the 

pond continues to be recirculated through the plant for cooling, and only makeup water (water 

lost to evaporation or discharged as blowdown) is drawn directly from the Illinois River.”

Response: The commenter suggests that the NRC staff clarify that the cooling pond system is 

a closed-cycle cooling system, which is similar to cooling towers. The NRC staff agrees with 

part of this comment because, as described in the GEIS (NRC 2013a), a cooling pond system is 

a type of closed-cycle cooling system. Accordingly, the NRC revised the first part of the 

sentence to indicate that a cooling pond is a closed-cycle system. However, the NRC staff did

not include the suggested revision that a cooling-pond system is similar to cooling towers 

because the NRC staff determined in the GEIS (NRC 2013a) that the impacts to aquatic 

resources from power plants with a cooling pond system differ from power plants with cooling 

towers.

Comment L-008: At Section 4.7.1.2, page 4–45, clarify the last sentence in the last paragraph 

under the heading “Overall Impingement and Entrainment Conclusion” on p. 4–45 by revising it 

as follows: “... The NRC staff notes that the use at LSCS’s cooling pond intake structure of a 

shad net, bar grills, and traveling screens with 3/8-in. (0.95-cm) openings wouldeffectively

reducereduces the impacts from impingement and entrainment in the cooling pond.”
Appendix A

A-14

Response: The commenter suggests that the NRC staff revise the SEIS to state that a variety 

of engineered features effectively reduces impacts from impingement and entrainment in the 

cooling pond. The NRC staff did not incorporate this change because Exelon did not provide 

any studies or data that would support this statement or that evaluate the actual levels of 

impingement and entrainment at the LSCS’s cooling pond intake structure. This comment did 

not result in any changes to the SEIS.

Comment L-009: At Section 4.7.1.3, pages 4–49 to 4–51, Exelon Generation does not agree 

with the Staff’s decision to consider (under LOE 5) thermal impacts on aquatic organisms in the 

LSCS cooling pond, and in particular with the determination that thermal impacts on gizzard 

shad and threadfin shad (shad) due to continued operation of LSCS would be MODERATE. 

Exelon disagrees with the need to consider these impacts within the LSCS cooling pond for the 

following reasons:

1. There is no requirement for the staff to evaluate thermal impacts on organisms in the 

LSCS cooling pond. The Draft Supplemental Environmental Impact Statement (DSEIS) 

states that, “NRC’s regulations at 10 CFR Part 51 concerning license renewal reviews 

and the GEIS [Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants, Rev. 1] direct the NRC to consider all aquatic resources that may be affected by 

plant operations, regardless of the type of water body in which such resources reside.” 

DSEIS at 4–45. The DSEIS does not identify what regulation specifically provides this 

direction, nor has Exelon Generation identified which regulation in Part 51 supports this 

statement. The statements of consideration for the final rule also do not clarify this 

issue. See 78 Fed. Reg. 37,282, 37,304 (June 20, 2013). On the contrary,

10 CFR 51.53(c)(3)(ii)(A), which is quoted below, specifically discusses the withdrawal of 

makeup water from a river and the resulting aquatic impacts on stream communities, but 

establishes no requirements for impacts within cooling ponds:

“If the applicant’s plant utilizes cooling towers or cooling ponds and withdraws makeup 

water from a river, an assessment of the impact of the proposed action on water 

availability and competing water demands, the flow of the river, and related impacts on 

stream (aquatic) and riparian (terrestrial) ecological communities must be provided...”

Exelon Generation recognizes that the GEIS (p. 3–52) defines surface water resources 

to include “man-made reservoirs or other impoundments,” but that definition does not 

apply to aquatic resources, which is the relevant topic here. There is also a reference 

in the GEIS (p. 3–139) to potential adverse human health effects from microorganisms 

in thermal effluents, but again, that topic is not relevant to impacts on aquatic 

resources. And finally, the GEIS itself is not codified in regulation—only its conclusions 

are, most pertinently in the text quoted above.

2. The staff should not evaluate thermal impacts on organisms in the LSCS cooling pond, 

because the cooling pond is a wastewater treatment system. As the DSEIS 

acknowledges, the LSCS cooling pond is a “wastewater treatment system,” and 

therefore, is not a “water of the United States” under the Clean Water Act (CWA) or a 

“water of the State” under Illinois law. See DSEIS at 3–42. The DSEIS also notes on 

page 3–68, that “The cooling pond can be characterized as a highly managed 

ecosystem in which fish stocking by the IDNR [Illinois Department of Natural Resources] 

and other human activities primarily influence the species composition and population 

dynamics.” Therefore, the NRC should not be evaluating impacts on the aquatic 

environment in the cooling pond from LSCS’s thermal additions to the cooling pond 

water. Section 316(a) of the CWA, as its title states, provides “Effluent limits that will 

assure protection and propagation of balanced, indigenous population of shellfish, fish, 
Appendix A

A-15

and wildlife.” The CWA effluent limits, however, do not apply to influents into the LSCS 

cooling pond, which has no indigenous populations. Accordingly, there is no CWA 

requirement to protect organisms in the pond. To suggest otherwise through a National 

Environmental Policy Act (NEPA) analysis would be to suggest that an environmental 

standard impermissibly applies within a wastewater treatment system that is itself 

exempt from that standard.

3. Not evaluating thermal impacts on organisms in the LSCS cooling pond would be 

consistent with prior analyses for LSCS. The LSCS Final Environmental Statement at 

the Operating License stage (FES-O) noted that the conclusions regarding aquatic 

impacts in the FES at the Construction Permit stage remained valid, including the 

conclusion that “aquatic impacts from operation of the station will be confined to the 

Illinois River.” FES-O at 5–12. For the reasons stated above, Exelon Generation 

believes this conclusion remains valid at the license renewal stage.

4. The conclusion of “MODERATE” impacts on shad populations is oversimplified, and 

misleading. If the staff analyzes aquatic impacts within the LSCS cooling pond at all, the 

analysis of such impacts should begin from the premise that no aquatic populations 

(whether stocked or not) would exist in this location without the LSCS because the 

cooling pond was constructed to serve that plant. Also, Exelon Generation leases land 

near the pond to the IDNR for fish hatchery operations. Considering that baseline, any 

impacts on cooling pond organisms due to LSCS operation would necessarily be smaller 

than shutting the plant down, after which the hatchery and the organisms in the cooling 

pond may be eliminated entirely. Therefore, it is misleading and serves no use for 

agency decision making to assign a MODERATE impact for continued operation while 

assigning a SMALL impact for the No-Action Alternative. At a minimum, even if the 

SEIS were to consider thermal impacts on aquatic organisms in the cooling pond, it 

should recognize this complexity by either assigning a SMALL impact for continued 

operation but a MODERATE impact for the No-Action Alternative, or by not using the 

SMALL, MODERATE, and LARGE designations to characterize the impacts, as has 

been done elsewhere in the DSEIS for special status species and historic and cultural 

resources.

5. Considered on its own merits, the conclusion of “MODERATE” impacts on shad 

populations is not supported by facts. The basis provided by the Staff for MODERATE 

impacts are the declines in shad populations after fish kills “each summer.” DSEIS at 

4–50. While these events may have temporarily reduced the number of shad, even 

regular fish kills every year have not destabilized or noticeably altered any important 

attribute of the shad resource, as shown by the regular recovery of populations. 

Moreover, shad are not a desirable fish for the cooling pond. They are not stocked fish, 

and instead, as the DSEIS states, certain recreationally fished species are stocked “in 

part to limit the size of shad populations.”

DSEIS at 3–68 (emphasis added). This need to further limit shad populations, beyond 

the decreases in population inadvertently caused by fish kills, in order to protect the 

overall aquatic health of the cooling pond, suggests that the shad population should not 

be evaluated at all for impacts from operation of the LSCS. Furthermore, if IDNR were 

to determine that the aquatic health of the cooling pond required an increased shad 

population, there is no reason to believe that shad could not be stocked to 

accommodate the need, as the DSEIS reports is done for other species. DSEIS at 4–

50.
Appendix A

A-16

6. Past NRC practice is not dispositive. The DSEIS points to prior examples where the 

Staff considered aquatic impacts within cooling ponds in other license renewal SEISs, 

including Braidwood and other plants with environmental reviews based on the 

1996 GEIS. Exelon Generation objected on the record to this approach in the 

Braidwood SEIS, and the mere existence of prior Staff practice does not require the 

NRC to, going forward, impermissibly evaluate aquatic impacts on the LSCS cooling 

pond. Errors in legal interpretation should not be carried forward into new analyses.

Response: The commenter does not agree with the NRC staff’s analysis, which considers 

(under Line of Evidence (LOE) 5) thermal impacts in Section 4.7.1.3 on aquatic organisms in the 

LSCS cooling pond, and in particular with the NRC staff’s determination that thermal impacts on 

gizzard shad and threadfin shad (shad) due to continued operation of LSCS would be 

MODERATE. 

The NRC staff does not agree with the comment based on the following reasons. First, the 

NRC is not prohibited from considering the thermal impacts on aquatic organisms in the LSCS

cooling pond by either the National Environmental Policy Act of 1969, as amended (NEPA), or 

the NRC’s regulations implementing NEPA in 10 CFR Part 51. Instead, both NEPA and the 

NRC’s regulations implementing NEPA give the NRC broad discretion in determining the 

environmental impacts that it considers in support of a license renewal application. For 

instance, NEPA requires all Federal agencies, for major Federal actions significantly affecting 

the quality of the human environment, to provide a detailed statement on the environmental 

impacts of the proposed action. Environmental impacts may be those reasonably foreseeable 

impacts directly or indirectly caused by the action or the cumulative impact on the environment 

which results from the incremental impact of the action when added to other past, present, and 

reasonably foreseeable future actions. The NRC requires an applicant for a renewed operating 

license to submit information useful in aiding the NRC in complying with NEPA, such as a 

description of the affected environment around the plant and the impacts of license renewal on 

the environment, discussed in proportion to their significance. The NRC also uses a scoping

process to determine the scope of its environmental impact statement including those 

environmental impacts to be analyzed in depth and those whose discussion is to be limited. 

From the information submitted by the applicant and the information gathered as part of its 

scoping process, the NRC independently develops an environmental impact statement that 

considers and weighs the environmental impacts of the proposed action. The environmental 

impact statement will consider matters covered by environmental quality standards and 

requirements irrespective of whether a certification or license from the appropriate Federal, 

State, or local authority has been obtained. This environmental review process does not 

prohibit the NRC staff from considering the thermal impacts on aquatic organisms in cooling 

ponds within its environmental impact statement.

Second, considering the thermal impacts on aquatic organisms in the LSCS cooling pond is 

consistent with previous NRC evaluations of environmental impacts. In its 1996 environmental 

impact statement generically evaluating the environmental impacts of license renewal 

(NRC 1996) at Section 4.4.3, the NRC looked generically at the effects to the aquatic biota of 

cooling ponds from water quality degradation, impingement, entrainment, and thermal 

discharges. NRC (1996) determined that these effects are the same in cooling ponds as those 

considered for once-through cooling systems except that impacts in cooling ponds mainly 

influence aquatic communities that did not exist before creation of the cooling pond. 

NRC (1996) reviewed various reports regarding the impacts to aquatic organisms in cooling 

ponds and coordinated with other regulatory agencies and nuclear utilities. NRC (1996) 

concluded that, for some plants, the large volumes of water withdrawn, heated, and discharged 

back to the receiving water (such as cooling ponds) may cause adverse effects to fish 
Appendix A

A-17

populations during the license renewal term and, therefore, the impacts of fish entrainment and 

impingement and of thermal discharge effects could be SMALL, MODERATE, or LARGE for 

plants with once-through cooling and cooling ponds. This conclusion was affirmed by the 

NRC’s 2013 GEIS. Consistent with the NRC’s 1996 GEIS and 2013 GEIS, previous NRC 

operating license renewal environmental impact statements have considered the impacts on 

aquatic resources in cooling ponds (e.g., NRC 2008, 2013b, 2015). 

Based on the above, the NRC staff disagrees with the commenter’s suggestion that the NRC is 

prohibited from considering the thermal impacts on aquatic organisms in the LSCS cooling 

pond. 

The commenter also states that the NRC staff should not analyze the thermal impacts to aquatic 

resources within the cooling pond based on 10 CFR 51.53(c)(3)(ii)(A). The NRC staff does not 

agree with this portion of the comment because 10 CFR 51.53(c)(3)(ii)(A) describes the type of 

information that an applicant should include in its ER, not the type of analysis that the NRC staff 

should present in its environmental impact statement. Furthermore, the NRC staff analyzed the 

impacts described in 10 CFR Part 51.53(c)(3)(ii)(A) in Section 4.7.1.4, “Water Use Conflicts with 

Aquatic Resources,” which is a separate analysis from the thermal analysis presented in 

Section 4.7.1.3.

The commenter also suggests that the NRC staff should not analyze the impacts to aquatic 

resources in the cooling pond because the cooling pond is exempt from impingement and 

entrainment monitoring requirements under Section 316(b) of the CWA. The NRC staff does 

not agree with this statement because the lack of cooling pond monitoring requirements under 

Section 316(b) of the CWA does not preclude Exelon from conducting impingement and 

entrainment studies to better characterize the potential impacts to aquatic resources within the 

cooling pond, nor does it preclude the NRC staff from analyzing those impacts, as described 

above and in its response to Comments L-004, L-005, and L-007. 

The commenter states that the consideration of environmental impacts on aquatic organisms in 

the LSCS cooling pond should begin from the premise that no aquatic populations would exist in 

this location without the LSCS having been constructed in the first place. The staff disagrees 

with this statement because it doesn’t matter why the cooling pond currently exists; rather, 

NEPA and the NRC’s regulations implementing NEPA require the NRC staff to provide a 

detailed statement on the environmental impacts that the proposed action may have on 

currently existing resources, such as the cooling pond.

The commenter states that the No-Action alternative should be MODERATE with respect to 

thermal impacts on aquatic organisms in the cooling pond. The NRC staff agrees with this 

comment in part. As described in Section 4.7.2 of the SEIS, for the No-Action alternative, 

thermal discharge to the cooling pond would be greatly reduced and eventually stop. The 

cooling pond would likely experience shifts in the relative abundances of fish populations 

because less heat-tolerant species would no longer be stressed by thermal additions to the 

pond. Some fish populations, such as stocked recreational species that thrive in warmer 

waters, may experience population declines in the cooling pond. Given that these shifts in 

community structure would likely be noticeable for some species, the NRC staff revised the 

conclusion in Section 4.7.2 and determined that, for the No-Action alternative, the impacts 

would be SMALL to MODERATE within the cooling pond and SMALL within the Illinois River. 

The commenter also states that the No-Action alternative should assume that the hatchery and 

the organisms in the cooling pond may be eliminated entirely post-operation. The NRC staff 

does not agree with this part of the comment because, as described in Section 2.2.1, the 

No-Action alternative considers the impacts that arise directly as a result of plant shutdown, 

such as the reduction of thermal effluent discharged into the cooling pond. Section 2.2.1, 
Appendix A

A-18

further states that the environmental impacts from decommissioning and related activities, such 

as the potential elimination of the cooling pond, are not considered within the No-Action 

alternative. The commenter also suggests that the NRC staff not assign a SMALL, 

MODERATE, or LARGE impact determination for thermal impacts in the cooling pond, which 

the commenter suggests would follow the methodology in the special status species and historic 

and cultural resources analyses. The NRC staff does not agree with this comment because the 

special status species and historic and cultural resources sections do provide impact 

determinations, but they are based on the language in the Endangered Species Act of 1973, as 

amended (16 U.S.C. 1531 et seq.), for special status species and in Section 106 of the National 

Historic Preservation Act of 1966, as amended (16 U.S.C. 470 et seq.), for historic and cultural 

resources. Further, Table B–1 in Appendix B to Subpart A of 10 CFR Part 51 concludes that 

thermal impacts on aquatic organisms for plants with once-through cooling systems or cooling 

ponds may be SMALL, MODERATE, or LARGE, and Section 4.5 of NUREG–1555, Standard 

Review Plans for Environmental Reviews for Nuclear Power Plants: Environmental Standard 

Review Plan, Supplement 1, Revision 1 (NRC 2013b), directs the staff to characterize thermal 

impacts to aquatic resources according to these levels of impact. Therefore, failing to make 

such a conclusion would be inconsistent with the NRC’s regulations in 10 CFR Part 51 and 

guidance in NRC (2013c) concerning license renewal.

The commenter also states that the NRC staff’s conclusion of “MODERATE” impacts on shad 

populations is not supported by facts. The NRC staff does not agree with this comment for 

several reasons, as described below. As an initial matter, the commenter appears to confuse 

the definitions of MODERATE and LARGE by stating that it disagrees with the NRC staff’s 

conclusion of MODERATE because fish kills have not destabilized or noticeably altered shad 

populations. As defined in Table B–1 in Appendix B to Subpart A of 10 CFR Part 51 and as 

stated in Chapter 1 of the LSCS SEIS, the definition of MODERATE is that the environmental 

effects are sufficient to alter noticeably, but not to destabilize, important attributes of the 

resource (emphasis added). The NRC staff considers shad an important attribute of the aquatic 

community in the cooling pond because it is prey for many of the recreationally fished species 

within the cooling pond. The NRC’s standard review plan (NRC 2013b) defines species with 

important trophic links, such as predators or prey, as important species. Furthermore, the 

Illinois Department of Natural Resources (IDNR) has documented several instances of 

noticeable changes in the population of shad due to fish kills. As stated in Section 4.7.1.3, 

during IDNR surveys in the LSCS cooling pond, the gizzard shad catch per hour was 451 in 

2000 and was 108 in 2001 after the largest fish kill (Exelon 2002). Similarly, in a status review 

of the cooling pond in 2011, 2012, and 2014, IDNR noted the decline in the threadfin shad 

population due to fish kills during each summer (Exelon 2015). Shad populations generally 

recovered within 1 year after a kill occurred (Exelon 2002, 2015), and loss of shad did not 

substantially affect the community dynamics within the cooling pond (Exelon 2010, 2015). 

Based on the definition of important ecological resources in the NRC’s standard review plan 

(2013b), IDNR’s surveys that noted a noticeable decline in shad following large fish kills 

(Exelon 2002, 2015), and the likelihood that fish kills in the LSCS cooling pond would continue 

to occur during the license renewal term, the NRC staff determined that operation of the LSCS 

cooling system would have noticeable, or MODERATE, effects on threadfin shad and gizzard 

shad. The NRC staff also noted that fish kills would not be destabilizing because shad tend to 

recover within a year and because population declines do not substantially affect community 

dynamics within the cooling pond.

The NRC staff acknowledges that there is a degree of uncertainty regarding the magnitude of 

the impact to shad populations due to the fact that the best available information does not 

include the estimated population size of shad prior to and after a fish kill. Without this 

information, the NRC staff is not able to calculate the percent of the shad population that has 
Appendix A

A-19

been affected by each fish kill. In this situation, the Council on Environmental Quality’s 

“Collaboration in NEPA, A Handbook for NEPA Practitioners,” recommends that practitioners 

use the best available information. Therefore, the NRC staff has followed this guidance and has 

relied upon the best available data, which includes:

• Qualitative and quantitative reports that describe the number of fish affected by fish kills 

in the LSCS cooling pond (e.g., Exelon 2001, 2002, 2009, 2010),

• Annual fall fish surveys by IDNR (e.g., Exelon 2015),

• Exelon and IDNR reports and meeting notes that attribute shad declines to fish kills 

(e.g., Exelon 2002, 2015), and

• Temperature data within the cooling ponds and known thermal stress limits for fish 

species within the cooling pond (e.g., Exelon 2001, 2009, 2010, 2014, 2015). 

Comment L-060: In Section 3.7.1 on page 3–60 in line 2, correct the text as follows:

“... intake, and the Marseilles Lock and Dam, 2.4 mi (3.5 km) downstream of the LSCS

discharge ...” This correction is needed because, while the Marseilles Dam is 2.4 mi 

downstream from the LSCS discharge, the Marseilles Lock is 4.9 mi (7.9 km) downstream.

Response: The commenter suggests a revision to clarify the location of the Marseilles Lock 

and Dam. The NRC staff agrees with the commenter and revised Section 3.7.1 of the SEIS to 

state that the Marseilles Dam is 2.4 miles (mi) (3.5 kilometers (km)) downstream of the LSCS

discharge and that the Marseilles Lock is 4.9 mi (7.9 km) downstream of the LSCS discharge.

Comment L-061: In Section 3.7.1.1 on page 3–65 in Table 3–10, because the species 

“Micropterus dolomieu smallmouth bass” is not a member of the “Catostomidae” family, but 

rather is a species within the “Centrarchidae” family, the row containing “Micropterus dolomieu 

smallmouth bass” should be moved up to below the row containing “Lepomis macrochirus 

bluegill,” within the family “Centrarchidae.”

Response: The commenter suggests a revision to clarify that smallmouth bass (Micropterus 

dolomieu) is not a member of the Catostomidae family, but rather a member of the 

Centrarchidae family. The NRC staff agrees with this comment and has revised Table 3–10 to 

clearly indicate that smallmouth bass is a member of the Centrarchidae family.

Comment L-062: In Section 3.7.2.1 on page 3–68 in lines 10 to 11 correct the text as follows:

“...to the cooling pond started operations, at which point IDNR started stocking the cooling pond 

with species from the hatchery (EA 2002). IDNR assumed management of the hatchery in 

1984. Initially, IDNR stocked the LSCS cooling pond with...”

Response: The commenter suggests a revision to clarify that IDNR assumed management of 

the fish hatchery in 1984. The NRC staff agrees with the comment and made a clarification to 

the SEIS in Section 3.7.2.1 that IDNR assumed management of the fish hatchery in 1984.

Comment L-063: In Section 3.7.3.1 on page 3–70 in line 19, correct the text as follows:

“... species, such as walleye and tiger muskellunge.”

Response: The commenter suggests a revision in Section 3.7.3.1 to clarify that muskellunge, 

not tiger muskellunge, is a cool water species that has been stocked in the LSCS cooling pond. 

The NRC staff agrees with the comment and made a clarification to the SEIS in Section 3.7.3.1 

that muskellunge, not tiger muskellunge, is a cool water species that has been stocked in the 

LSCS cooling pond.
Appendix A

A-20

Comment L-064: In Section 3.7.3.1 on page 3–70 in lines 13 and 14, correct the text as 

follows:

“... study at the LSCS river intake. In response to this collection, Exelon noted that EA 

Engineering intends to request a scientific collector’s permit report from IDNRfile a scientific 

collectors report with IDNR. This species was not ...”

Response: The commenter suggests that the NRC staff revise the text to specify that 

EA Engineering intends to “file a scientific collectors report with IDNR” rather than “request a 

scientific collector’s permit report from IDNR.” The NRC staff agrees with this comment and has 

revised the text in Section 3.7.3.1 to state that “EA Engineering intends to file a scientific 

collectors report with IDNR.”

Comment L-065: In Section 3.7.3.1 on page 3–72 in line 3, correct the text as follows:

“... boatingcommercial barge accident (Kanter 2013). This species was not collected during 

LSCS preoperational ...”

Response: The commenter suggests that the NRC staff revise the text to specify that 

commercial barges were involved in the boating accident, as described in Kanter (2013). The 

NRC staff does not agree with the comment because Kanter (2013) does not specify whether 

the boats were commercially licensed or not. This comment did not result in any changes to the 

SEIS.

Comment L-066: In Section 3.7.4 on pages 3–72 and 3–73, either re-name section 3.7.4 as 

discussed below, or move the information about bryozoans to either section 3.7.1.1 or 

section 3.7.2.1 in the DSEIS. This correction is needed because, although bryozoans may be 

nuisance species, they are actually native to waters of Illinois including the Illinois River. As 

such, the inclusion of bryozoans in the section 3.7.4, Non-Native Species, discussion is 

inaccurate. Perhaps the easiest edit is to re-title the section as “Non-Native and Nuisance 

Species.” Bryozoans were described in the ER (Section 3.7.1.6, Invasive/Non-native Species) 

because they are invasive.

Response: The commenter suggests that the NRC staff rename Section 3.7.4 from 

“Non-Native Species” to “Non-Native and Nuisance Species” because the species discussed in 

Section 3.7.4 include both native and non-native nuisance species. The NRC staff agrees with 

this comment and renamed Section 3.7.4 from “Non-Native Species” to “Non-Native and 

Nuisance Species” to more accurately describe the type of aquatic species discussed in 

Section 3.7.4.

Comment L-084: In Section 4.7.1.2 on page 4–63 in the 7th line of the last paragraph, the text 

discussing the WOE approach incorrectly references “NRC 2013b” (Event Reporting 

Guidelines). It appears the staff intended to reference the SEIS for the South Texas Project 

license renewal, which is “NRC 2013c.” Accordingly, correct the text as follows:

“... (e.g., NRC 2010, 2013b2013c, 2015a, 2015b). Menzie et al. (1996) defines WOE as “...the 

process ...”

Response: The commenter suggests that the NRC staff correct a citation because it incorrectly 

references the wrong document, NRC’s Event Reporting Guidelines. The NRC staff agrees with 

this comment and has corrected the citation so that it references the correct document, the STP 

Final SEIS.
Appendix A

A-21

A.3.8 Historic and Cultural Resources

Comment L-085: In Section 4.9.4 on page 4–63 in the 1st line of the 1st paragraph, correct the 

text discussing the IGCC Alternative as follows: “...alternative is sited on the approximately 

250350 ac (101142 ha) of undeveloped land on the LSCS site, ...” This correction is needed 

because the amount of undeveloped land was updated to 350 ac in Exelon Generation’s 

response to RAI LU-01, which was provided to NRC by a letter dated July 2, 2015 (ADAMS 

Accession No. ML15195A373), and in Section 3.2 (p. 3–5) of the ER revisions, which were 

provided to NRC with a letter dated July 31, 2015 (ADAMS Accession No. ML15212A259). 

Note that Section 3.2.1.1 on p. 3–21, line 21 of the DSEIS identifies the correct acreage for 

undeveloped land.

Response: Section 4.9.4 has been revised as suggested.

Comment L-086: In Section 4.9.5 on page 4–63 in the 5th line of the 1st paragraph in 

Section 4.9.5 on p. 4–63, correct the text as follows: “... be used. If the power plant is sited on 

the approximately 250350 ac (101142 ha) of undeveloped land ...” This correction is needed 

because the amount of undeveloped land was updated to 350 ac in Exelon Generation’s 

response to RAI LU-01, which was provided to NRC by a letter dated July 2, 2015 (ADAMS 

Accession No. ML15195A373), and in Section 3.2 (p. 3–5) of the ER revisions, which was 

provided to NRC with a letter dated July 31, 2015 (ADAMS Accession No. ML15212A259). 

Note that Section 3.2.1.1 on p. 3–21, line 21 of the DSEIS identifies the correct acreage for 

undeveloped land.

Response: Section 4.9.5 has been revised as suggested.

A.3.9 Socioeconomics

Comment M-001: The analysis of socioeconomic impacts are incomplete. No analysis of 

impacts for early or unexpected closures were considered or provided. No mention or analysis 

of negative impacts resulting from an abrupt planned or unexpected early closure of LaSalle is 

presented. This is a significant omission, particularly in light of Exelon Corporation’s threat of 

two years ago to close reactors in Illinois on economic grounds. An abrupt end of LaSalle site 

operations would wreak economic havoc on affected governmental and essential service 

entities’.

The Safety Evaluation Report fails to recognize or mention events that could result in such a 

closure situation, such as an unexpected major accident resulting in immediate and presumably, 

premature closing, or NRC-ordered shutdown. It is irrational to assume the only socioeconomic 

effects of LaSalle’s presence will be positive ones. To minimize economic and service 

disruptions we believe that planning for some kind of eventual closure must be made long 

before it happens. We recommend that dependent government and tax entities begin formal 

negotiations with Exelon to establish an escrow of mitigation funds based on some mutually 

agreeable assessment and payment structure so that funds would be available to soften the 

economic blow of a plant closure.

Comment N-001: The Exelon Safety Evaluation Report (SER) documents a significant tax 

impact for the presence of the LaSalle Nuclear Station, yet only addresses the positive impacts. 

No mention or analysis of negative impacts resulting from abrupt, planned, or unexpected early 

closure of LaSalle is presented. This is a significant omission, particularly in light of Exelon 

Corporation's threat of two years ago to close reactors in Illinois on economic grounds. 

According to the Exelon SER LaSalle represents a sizeable portion of the County total tax base. 

It also accounts for large portions of the School District's adjusted property tax levy. These are 
Appendix A

A-22

not insignificant amounts. Their abrupt disappearance would wreak economic havoc on the 

affected governmental and essential service entities' ability to operate - just as Exelon's 

predecessor ComEd did to the community of Zion in 1997 when they unilaterally closed the Zion 

reactors.

The SER either fails to recognize or mention at all some of the possible events that could result 

in such a closure situation:

• Unexpected major accident, resulting in immediate and presumably premature 

closure

• NRC-ordered shut down

• Exelon's unilateral decision to close the plant on economic or other grounds, as it did 

at Zion, resulting in an immediate loss of about 55% of Zion's tax base

• Devaluation through sale, as occurred at the Clinton station, resulting in enormous 

loss of tax base

• Eventual old-age, license expiration closure (the outcome most hoped for)

Exelon being a business will certainly make the calculations it made when it closed Zion, and 

decide if LaSalle should continue to operate. 

In this omission the SER makes the same mistake the U.S. Government made when it invaded 

Iraq - it had no exit strategy. To simply assume that the only socio-economic effects of 

LaSalle's presence will be positive ones is simply irrational.

Recommendation: Planning for some kind of eventual closure must be made long before it 

happens to minimize economic and service disruptions to the entities whose tax base will be 

affected. Debate about the license extension serves as a good reminder of this fact, and an 

opportunity to take action. We recommend that dependent governmental and taxing entities 

begin formal negotiations with Exelon to establish an escrowed “closure mitigation fund,” based 

on some mutually agreeable assessment and payment structure, so that dependent entities will 

have some kind of temporary funds available to soften the economic blow of closure, and not 

radically disrupt essential services.

Response: The NRC staff assumes that the commenter is referring to Exelon’s ER rather than 

the safety evaluation report (SER) prepared by the NRC. With the exception of an unexpected 

major accident and an NRC-ordered shutdown for safety reasons, the possible events leading 

to the closure of LSCS identified in this comment involve energy planning decisions that would 

be made by Exelon and state officials. The NRC has no role in these energy planning 

decisions. In addition, the closure of LSCS could occur at any time, including after the 

expiration of either the current or renewed operating license.

Information about Exelon’s tax payments is described in Section 3.10.5, “Tax Revenue,” in the 

SEIS, and the socioeconomic impacts of station closure and the termination of reactor

operations caused by the expiration of the LSCS operating license are described as part of the 

“No-Action” alternative in Section 4.10.2 of Chapter 4 in the SEIS. The impacts of closing and 

decommissioning a nuclear power plant are also described in NUREG–0586, Final Generic 

Environmental Impact Statement on Decommissioning of Nuclear Facilities: Supplement 1, 

Regarding the Decommissioning of Nuclear Power Reactors (NRC 2002). The environmental 

consequences of decommissioning LSCS would be addressed as part of the license termination 

plan.

In regard to what is to be discussed in the ER, 10 CFR 51.45(c) states:
Appendix A

A-23

Environmental reports prepared at the license renewal stage under § 51.53(c) 

need not discuss the economic or technical benefits and costs of either the 

proposed action or alternatives except if these benefits and costs are either 

essential for a determination regarding the inclusion of an alternative in the range 

of alternatives considered or relevant to mitigation. In addition, environmental 

reports prepared under § 51.53(c) need not discuss issues not related to the 

environmental effects of the proposed action [license renewal] and its 

alternatives.

In Section 4.10.2, “No-Action Alternative,” under socioeconomic impacts, the NRC staff 

determined that not renewing the operating licenses and terminating reactor operations could 

noticeably impact socioeconomic conditions in the communities located near LSCS. 

Specifically, termination of power plant operations would result in the loss of jobs and income for 

individuals working at, or providing services to, LSCS and would reduce tax revenue in affected 

tax jurisdictions. Depending on the jurisdiction, socioeconomic impacts from the termination of 

nuclear plant operations could range from SMALL to LARGE.

Comment L-67: In Section 3.10.1 on page 3–83, correct the “Source” cited for Table 3–15 on 

p. 3–83 because, while “Exelon 2014” is cited, there is no corresponding entry for “Exelon 2014”

in the reference list in section 3.14. The source for the data presented in Table 3–15 is Exelon 

Generation’s response to RAI SE-01, which was provided to NRC in a letter dated July 2, 2015 

(ADAMS Accession No. ML15195A403).

Response: The NRC staff has revised the source citation in Table 3–15 and added the 

reference as suggested.

Comment L-068: In Section 3.10.1 on page 3–83 in line 9, the text citing the LSCS License 

Renewal Environmental Report (i.e., “Exelon 2014a”) should be corrected because the 

workforce information being presented is not based on Exelon 2014a. Rather, it is based on 

Exelon Generation’s response to RAI SE-01, which was provided to NRC in a letter dated 

July 2, 2015 (ADAMS Accession No. ML15195A403).

Response: The NRC staff has revised the reference citation as suggested.

Comment L-069: In Section 3.10.5 on page 3–94, Correct the “Source” cited for Table 3–27 on 

p. 3–94 because, while the text cites the LSCS License Renewal Environmental Report 

(i.e., “Exelon 2014a”) as the source for the 2013 tax data being presented, the data were not 

based on Exelon 2014a. Rather, the data are based on Exelon Generation’s response to 

RAI SE-02, which was provided to NRC in a letter dated July 2, 2015 (ADAMS Accession 

No. ML15195A404).

Response: The NRC staff has revised the source citation in Table 3–27 and added the 

reference as suggested.

Comment L-070: In Section 3.10.5 on page 3–95 in line 1, correct the text as follows:

“In addition, Exelon makes annual payments to the Illinois Emergency Preparedness

Management Agency for ...”

Response: The NRC staff has revised the text as suggested.

Comment L-071: In Section 3.10.5 on page 3–95, Correct the “Source” cited for Table 3–28 on 

p. 3–95 because, while the text cites the LSCS License Renewal Environmental Report 

(i.e., “Exelon 2014a”) as the source for the annual payments to IEMA being presented, the data 

were not based on Exelon 2014a. Rather, the data are based on Exelon Generation’s response 

to RAI SE-04, which was provided to NRC in a letter dated July 2, 2015 (ADAMS Accession 

No. ML15195A406).
Appendix A

A-24

Response: The NRC staff has revised the source citation in Table 3–28 and has added the 

reference as suggested.

Comment L-072: In Section 3.10.6 on page 3–95 in line 20, correct the text as follows:

“... the site. The Chicago, Rock Island & Pacific CSX Railroad is the closest railroad line to 

LSCS. It ...” This updated railroad information was provided in Exelon Generation’s response 

to RAI LU-03, which was provided to NRC in a letter dated July 2, 2015 (ADAMS Accession 

No.ML15195A375).

Response: The NRC staff has revised the text as suggested.

Comment L-087: In Section 4.10.5.2 on page 4–69 in the 1st line of the 1st paragraph, correct 

the text as follows: “Transportation impacts associated with construction and operation of a 

threefive-unit, NGCC power ...” This correction is needed because the NGCC alternative as 

described in Section 2.2.2.3 of the DSEIS would require five 560-MWe NGCC units to replace 

the generating capacity of the LSCS.

Response: The NRC staff has revised the text as suggested.

A.3.10 Human Health

Comment L-073: In Section 3.11.5 on page 3–100 in line 20, correct the text as follows 

because section 3.11.5 does not address electric shock hazards: “Two additional human health 

issues are addressed in this section:This section addresses physical occupational hazards and 

electric shock hazardsapplicable only to workers.

Response: This comment expresses concern that electric shock hazards are not addressed in 

Section 3.11.5. The NRC staff has updated the text in Section 3.11.5 to clarify that LSCS

maintains an Occupational Safety and Health Administration worker safety program that 

includes electric shock hazards.

Comment L-088: In Section 4.11.1.1 on page 4–73 in the last sentence, correct the text as 

follows: “... The permit limitsrequires monitoring and reporting of the average monthly and daily 

maximum rates of blowdown discharges to the river (Outfall 001) to a maximum rate of 

45 gallons per minute (gpm) (0.17 m3 per minute (m3/min)), ...”. This correction is needed 

because the NPDES permit does not set a maximum flow rate for the LSCS blowdown. The 

correct NPDES permit conditions are described in Section 3.5.1.3 of the DSEIS, and this 

change is consistent with that DSEIS section.

Response: This comment expresses concern that the NPDES permit requirements for LSCS

blowdown discharges to the river are not characterized correctly in Section 4.11.1.1. NRC staff 

agrees with this comment and updated the text in Section 4.11.1.1 to reflect the correct NPDES 

permit requirements.

A.3.11 Environmental Justice

Comment L-074: In Section 3.12.1 on page 3–102 in line 30, correct the text as follows 

because the ROI minority population data for 2014 is located in Table 3–21: “... 7.4 percent) 

and now comprise 30.5 percent of the ROI population (see Table 2.10.3–33–21). The ...”

Response: The NRC staff has revised the text as suggested.
Appendix A

A-25

A.3.12 Greenhouse Gas Emissions and Climate Change

Comment E-002: The Draft SEIS includes estimated greenhouse gas (GHG) emissions as 

result of the preferred alternative (beginning on page 4–104), including emissions from 

stationary combustion sources, fugitive emissions, purchased electricity, and refrigerant-related 

sources. Per Table 4–21, totals range from 34,228 to 39,997 metric tons of carbon dioxide 

equivalents per year (MT/yr of C02e). Table 4–22 lists the direct GHG emissions from operation 

of the proposed action and alternatives, which lists an estimated 1,022 MT/yr of C02e as a 

result of continued operation of LSCS. As stated in the footnote, direct impacts for the LSCS 

continued operation and new nuclear alternatives only include emissions from stationary 

combustion sources. EPA assumes that the emissions from other sources (e.g., fugitive 

emissions, purchased electricity, and refrigerant-related sources) are a result of necessary 

actions to ensure the continued safe operation of LSCS. Therefore, it is unclear why the 

analysis and Table 4–22 only include emissions from stationary combustion sources and not the 

other listed sources of GHG emissions. Recommendation: The Final SEIS should clarify why 

the alternatives analysis related to GHG does not include sources other than stationary 

combustion sources. We recommend the Final SEIS either explain in the narrative why the 

other sources of GHG (e.g., fugitive emissions, purchased electricity, and refrigerant-related 

sources) are not pertinent to the analysis and conclusion, or amend Table 4–22 to reflect an 

accurate accounting of GHG emissions from the two nuclear alternatives (LSCS continued 

operation and new nuclear).

Response: The commenter recommends that the SEIS clarify why Table 4–22 of the LSCS

SEIS only includes direct GHG emission from combustion sources or that the staff revise 

Table 4–22 to account for GHG emissions from various sources at LSCS. Table 4–22 of the 

SEIS only presents direct emissions resulting from operation of LSCS in order to provide a 

commensurate comparison of the proposed action (LSCS continued operation) and the 

Alternatives. The GHG emissions evaluated and presented in Table 4–22 for the Alternatives 

are the result of gas or coal combustion and, therefore, are direct emissions. As discussed in 

Section 4.15.3.1 of the SEIS, plant operations at LSCS release GHG emissions from stationary 

combustion sources, fugitive emissions, purchased electricity, and refrigerant-related sources. 

Purchased electricity is from an offsite electricity supplier; therefore, the emissions are indirect. 

The supplier, not LSCS, would account for the GHG emissions from purchased electricity. 

Thus, to provide a commensurate comparison of the GHG emissions of the Alternatives and the 

proposed action, direct emissions from LSCS were presented in Table 4–22.

Section 4.15.3.1 has been revised to clarify direct and indirect GHG emissions sources from 

operation of LSCS. Clarification has been provided in Table 4–22 explaining why only direct 

emissions are provided, and Table 4–22 GHG emissions from LSCS were revised to include 

direct emissions from stationary combustion sources, fugitive emissions, and refrigerant related 

sources, but not indirect emissions from purchased electricity for the reason discussed above. 

Additionally, Section 4.16.11 was also revised to present direct LSCS GHG emissions.

Comment M-002: Inadequate attention is being paid to water availability at the LaSalle Nuclear 

Power Plant under potential future climate disruption conditions. Historically, LaSalle Nuclear 

Power Plant has been one of the Illinois reactor sites most sensitive to water availability. 

Extreme droughts in 1998, 2005, and 2006, have brought the reactors close to mandatory 

shutdowns to stay within EPA thermal pollution limits. The forecast for the future of Illinois 

climate over the next few decades indicate it will approach that of current day west Texas. This 

will have severe impacts on the aquatic system in the area, and on the availability of water for 

intake and discharge at LaSalle. A more thorough re-examination of LaSalle’s ability to safely 
Appendix A

A-26

operate, obtain sufficient cooling water, and not thermally and radiologically damage the local 

aquatic ecosystem is in order in this re-licensing proceeding.

Comment N-002: Historically, the LaSalle NPP has been one of the Illinois reactor sites most 

sensitive to water availability under severe drought conditions (e.g., 1998; 2005; 2006). It’s 

siting on a portion of the Illinois river network that is shallower than other parts has brought the 

reactors close to mandatory shutdown to stay within EPA regulatory limits for thermal pollution 

during extreme droughts on more than one occasion over the past two decades. 

Forecasts for the future of Illinois’ climate over the next few decades indicate it approaching that 

of current- day West Texas. This will have severe impacts on the aquatic systems in the area; 

and on the availability of water for intake and discharge for LaSalle. 

A more thorough re-examination of LaSalle's ability to safely operate, obtain sufficient cooling 

water, and not thermally and radiologically damage the local aquatic eco-system is in order in 

this relicensing proceeding.

Response: The commenters request that the LSCS SEIS consider water availability and the 

ability for LSCS to safely operate under potential future climate conditions. As summarized in 

Section 4.1 and as further discussed in Section 4.15.3.2 of the SEIS, impacts to facility 

operations from climate change are not evaluated in the SEIS because the scope of the 

environmental review focuses on the evaluation of impacts from continued operation of LSCS 

on environmental resources. Accordingly, Sections 4.5 and 4.7 of this SEIS present the NRC 

staff’s analysis of the potential environmental impacts of license renewal and continued 

operations on water resources and aquatic resources, respectively, including water use 

conflicts, water availability, and impacts to aquatic resources.

Section 4.15.3.2 of the SEIS evaluates potential climate change impacts on environmental 

resources, including water resources and aquatic resources. Specifically, the water resources 

cumulative impact discussion in Section 4.16.3 evaluates climate change impacts on surface 

water as a result of changes in temperature and precipitation. This section explains that higher 

air temperatures and increased runoff associated with heavy precipitation events could impact 

the thermal regime of the Marseilles Pool of the Illinois River. The implications for potential 

climate-induced changes on cooling pond temperatures and evaporative losses from LSCS’s 

cooling pond are also discussed in Section 4.16.3 of the SEIS. To inform the NRC’s operating 

reactor licensing environmental reviews, the NRC uses consensus information from the 

U.S. Global Change Research Program (USGCRP). The USGCRP integrates and presents the 

prevailing consensus of Federal research on climate and global change, as sponsored by 

13 Federal agencies.

Furthermore, nuclear power plants are required to operate in accordance with technical 

specifications, which are part of the NRC operating license. Technical specifications, in part, 

are intended to ensure the ability of a licensed nuclear power plant to cope with natural 

phenomena hazards, such as ensuring that adequate cooling water is available under adverse 

conditions, such as drought. For example, as described in Section 3.5.1.2 of the LSCS SEIS, 

Exelon has plans and procedures in place to take necessary actions under adverse 

environmental conditions of drought and high water temperatures to ensure that technical 

specifications and environmental permit requirements are met. Failure to meet technical 

specifications may require the plant to reduce power or to shut down.

The NRC also conducts safety reviews before allowing licensees to make operational changes 

due to changing environmental conditions. Additionally, the NRC evaluates nuclear power plant 

operating conditions and physical infrastructure to ensure ongoing safe operations through its 

Reactor Oversight Process. If new information about changing environmental conditions 
Appendix A

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becomes available, the NRC will evaluate the new information to determine whether any 

safety-related changes are needed at existing nuclear power plants. The NRC does not wait for 

a licensee to identify such conditions. This process is separate and distinct from the NRC’s 

license renewal environmental review that is conducted in accordance with the National 

Environmental Policy Act (NEPA).

Comment L-010: Table ES–1, in the executive summary on page xxi labeled “Summary of 

NRC Conclusions Relating to Site-Specific Impacts of License Renewal,” (emphasis added) 

indicates that Global Climate Change Cumulative Impacts are “MODERATE.” As explained 

further in comments below regarding Section 4.16.11, this entry in Table ES–1 is misleading to 

decision makers and the public in that it fails to meaningfully inform them about either the nonsite-specific nature of cumulative impacts from GHG emissions or the net beneficial contribution 

of site specific LaSalle County Station (LSCS) GHG emissions. Accordingly, the table should 

be modified to clarify these points of confusion.

Response: The commenter requests that Table ES–1 be revised to clarify the incremental 

impact from continued operation of LSCS on Global Climate Change. The NRC staff agrees 

with the comment and has added a footnote to Table ES–1 to clarify the incremental impact of 

continued operation of LSCS on Global Climate Change.

Comment L-011: At Section 4.15.3.1, pages 4–105, Table 4–21 reports an incorrect value for 

GHG emissions from purchased electricity at LSCS during 2011. The amount of GHG 

emissions from 2011 purchased electricity reported in Table 4–21 erroneously duplicates the 

value for 2012 (i.e., 36,066 MT/yr of CO2e). The 2011 value should be 33,493 MT/yr of CO2e. 

This error in the 2011 “Purchased Electricity” column also causes an error for 2011 in the “Total”

column. Hence, the total LSCS GHG emissions for 2011 should be 37,424 MT/yr of CO2e.

Response: The commenter requests that GHG emissions for the year 2011 for purchased 

electricity be corrected. The NRC staff agrees with the comment. Table 4–21 erroneously 

duplicated the 2012 GHG emission values for purchased electricity. Table 4–21 was revised to 

provide the correct GHG emission value for purchased electricity for the year 2011, and the total 

GHG emissions value for the year 2011 was also corrected.

Comment L-012: The following comment applies to Sections 4.15.3 and 4.15.3.21 on

pages 4–104 and from pages 4–107 to 4–113. The introduction to Section 4.15.3 on p. 4–104 

states that the subsections within Section 4.15.3 “discuss GHG [Greenhouse Gas] emissions 

released from operation of LSCS and the environmental impacts that could occur from changes 

in climate conditions. The cumulative impacts of GHG emissions on climate are discussed in 

Section 4.16.11...” Section 4.15.3.1 then describes GHG emissions that would result from the 

proposed action (i.e., LSCS license renewal) and alternatives, and Section 4.15.3.2 provides an 

extended discussion of the impacts of general climate change on resource areas.

The purpose of Section 4.15.3.2, is unclear. Accordingly, it should be either deleted or revised 

to more clearly explain how extraordinarily small the contribution of LSCS GHG emissions 

during operation is to general climate change impacts in comparison to the global, U.S., Illinois 

State, and other LaSalle County GHG emissions, as shown in Table 4–23. In addition, given 

that all of the power generation alternatives (except new nuclear) would produce annual GHG 

emissions several orders of magnitude greater than LSCS operation (see Table 4–22), 

Section 4.15.3.2 should point out that the proposed action would have a net beneficial effect on 

global climate change because LSCS produces miniscule GHG emissions. Accordingly, 

continued operation of LSCS would serve to reduce emissions from base load power generation 

in comparison to most replacement power alternatives. It is only through base load, clean 

energy, such as nuclear power, that significant reductions in GHG emissions can be achieved. 

Without noting such information in Section 4.15.3.2, the reader is left with the impression that 
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GHG emissions from LSCS have some measurable causal relationship to the climate change 

impacts discussed the section, when no such relationship exists. As a result, Section 4.15.3.2 

is misleading to the public as written and not helpful for agency decision-making.

Response: The commenter states that the purpose of Section 4.15.3.2 of the SEIS is unclear 

and requests that it be deleted or revised to discuss that the contribution of GHG emissions 

from continued operation are small and that license renewal under the proposed action would 

reduce emissions from base load power generation. Further, the commenter expresses 

concern that Section 4.15.3.2 is misleading by suggesting that GHG emissions from LSCS

measurably contribute to climate change impacts as discussed in Section 4.15.3.2.

The purpose of Section 4.15.3.2 is to discuss observed changes, including trends in climate, 

projected climate change during the license renewal term, and the potential impacts of climate 

change on environmental resources. The NRC staff disagrees that Section 4.15.3.2 of the SEIS 

should be deleted or should be revised to include the specific statements requested by the 

commenter for the following reasons. First, as discussed in the 2013 license renewal GEIS, to 

comply with the Commission’s direction in CLI-09-21 (NRC 2009), the NRC staff includes, in 

each SEIS, a plant-specific analysis of any impacts caused by GHG emissions over the course 

of the license renewal term, as well as any impacts caused by potential climate change on 

affected resources during the license renewal term. Second, the SEIS section immediately 

preceding Section 4.15.3.2 (i.e., Section 4.15.3.1) states that GHG emissions from the proposed 

action (continued operation of LSCS) results in the lowest GHG emissions when compared to 

GHG emissions from the Alternatives (which is discussed under the section entitled, “Summary 

of GHG Emissions from the Proposed Action and Alternatives”). Therefore, the NRC staff 

disagrees with the comment that Section 4.15.3.2 should be revised to state that GHG 

emissions from continued operation of LSCS are small because this issue is discussed in 

Section 4.15.3.1. Third, Section 4.15.3.2 clearly indicates that the potential environmental 

impacts from climate change presented in the section are based on climate model simulations 

under future global GHG emission scenarios rather than on a single GHG emission source. 

This provides the reader with the necessary context to evaluate the potential collective 

contribution of all GHG emitters and its potential impact on environmental resources.

The introductory paragraph of Section 4.15.3 was revised to clarify the scope of the analysis 

provided in Section 4.15.3.2.

Comment L-092: In Section 4.15.3.1, pages 4–105, Table 4–21, correct the “Purchased 

Electricity” and “Total” columns in the “2011” row as follows:

Year Purchased Electricity Total

2011 36,06633,493 39,99737,424

See DSEIS Section 4.18, References, Exelon 2015d (ADAMS Accession No. ML15195A350).

Response: The commenter requests that GHG emissions for the year 2011 for purchased 

electricity be corrected in Table 4–21. The NRC staff agrees with the comment. Table 4–21 

was revised to provide the correct GHG emission for purchased electricity for the year 2011, 

and total GHG emissions for the year 2011 was also corrected.

A.3.13 Cumulative Impacts On Global Climate Change

Comment M-003: The overall impacts of nuclear energy production in Illinois are positive. 

Alternative sources of energy generation in Illinois would create more negative impacts

environmentally, particularly in the area of CO2 emissions. The Illinois Clean Energy Coalition’s 
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study in 2014 showed that Illinois’s nuclear fleet prevents the emission of over 92 million tons of 

CO2. We cannot quickly or easily replace nuclear generation with other clean sources that can 

be relied on to produce electricity 24hrs/day 7days/week. The loss of any of Illinois’s nuclear 

plants would require us to increase our use of fossil fuels. This would move us in the wrong 

direction with respect to carbon emissions.

Response: Text was added to Section 4.16.11 that discusses the net beneficial effect of the 

proposed action when compared to the GHG emissions by the Alternatives. Continued 

operation of LSCS (the proposed action) effectively results in GHG emissions avoidance.

Comment L-013: The following comment applies to Sections 4.16.11 from pages 4–129 

to 4–132. The evaluation of cumulative impacts of greenhouse gas (GHG) emissions from 

continued operation of LSCS on Global Climate Change in this section and the resulting 

conclusion of “Site-Specific” MODERATE impacts as reported in Table ES–1, leave the reader 

with the incorrect impression that LSCS’s operation for another 20 years would have some 

measurable, negative impact on global climate change, when it could not. As presented, and as 

explained in detail below, the overall analysis and conclusion is not helpful to an agency 

decision maker nor does it accurately inform the public, because it fails to convey the fact that 

nuclear power is one of the few base load electricity solutions to avoid release of GHG 

emissions and, therefore, the net effect of the proposed action will be beneficial.

Exelon recommends that the NRC resolve this misinformation by abandoning the categories of 

SMALL, MODERATE, and LARGE to label cumulative Global Climate Change impacts. These 

three categories are inapplicable for this topic and detract from, rather than inform, the NEPA

analysis. There is no requirement for the DSEIS to shoehorn all impact areas into these three 

categories. Nor does the license renewal GEIS specify the use of these categories for all 

analyses, or for cumulative Global Climate Change impacts in particular. Moreover, there is 

precedent for the NRC to take an alternative approach. For example, the LSCS DSEIS itself 

does not use these three categories for impacts in the following areas: Special Status Species 

and Habitats, Historic and Cultural Resources, Environmental Justice, or cumulative 

Socioeconomic or Environmental Justice impacts. Instead, in Table ES–1 the NRC provides a 

high-level tailored summary of the impacts in each of these areas. Thus, there is a well-worn, 

viable path for the NRC to discuss the beneficial impacts on Global Climate Change of 

operating LSCS for another 20 years. Consistent with the Staff’s conclusions in these other 

areas, and as explained below, Exelon recommends the following conclusion for cumulative 

Global Climate Change impacts: “The proposed action would result in reduced GHG emissions 

in comparison to the reasonable alternatives and would have a beneficial effect on overall 

cumulative global climate change impacts and goals.”

Another alternative would be to not discuss cumulative impacts on Global Climate Change in 

the SEIS at all. There is precedent for a federal agency to not perform, or include in an EIS a 

discussion of, a cumulative impacts analysis when the net effect of the proposed action is 

shown to be beneficial.

The approaches suggested above are acceptable for the following reasons:

1. To reach its finding of MODERATE impacts, the Staff has added the miniscule GHG 

emissions from ancillary operations at LSCS (e.g., backup diesel generators) to the total 

GHGs released in the State of Illinois and elsewhere, while simultaneously ignoring the 

millions of metric tons of GHG emissions that will be avoided by having clean, nuclear 

energy generation from LSCS continue for another 20 years. See DSEIS, Tables 4–22 

and 4–23; see also The White House, Office of Press Secretary, “Fact Sheet: Obama 

Administration Announces Actions to Ensure that Nuclear Energy Remains a Vibrant 

Component of the United States’ Clean Energy Strategy” (Nov. 6, 2015) (“Nuclear 
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power, which in 2014 generated about 60 percent of carbon-free electricity in the United 

States, continues to play a major role in efforts to reduce carbon emissions from the 

power sector”), available at https://www.whitehouse.gov/the-pressoffice/2015/11/06/fact-sheet-obama-administration-announces-actions-ensure-nuclearenergy; The Brattle Group, “Pennsylvania Nuclear Power Plants’ Contribution to the 

State Economy,” at 11–12 (Sept. 2015) (calculating the “substantial carbon dioxide and 

criteria pollutant emissions” prevented by operating nuclear power plants), available at 

http://www.nuclearmatters.com/resources/reports-studies/document/Nuclear-MattersReport_Pennsylvania-Value-of-Nuclear.pdf. Ignoring the net beneficial effect of the 

proposed action on Global Climate Change when compared to the effects of other 

reasonable alternatives is a clear failure to consider relevant facts.

The NRC states that it derived the NEPA impact categories of SMALL, MEDIUM, and 

LARGE from CEQ regulations. See, e.g., Final Report, “Generic Environmental Impact 

Statement for License Renewal of Nuclear Plants,” NUREG–1437, Rev. 1, at S–6 

(“The NRC’s standard of significance for impacts uses the Council on Environmental 

Quality (CEQ) terminology for “significantly” (40 CFR 1508.27), which requires 

consideration of both “context” and “intensity.” Based on this, the NRC established 

three levels of significance for potential impacts: SMALL, MODERATE, and LARGE.”). 

As applied to cumulative impacts on Global Climate Change, however, the NRC’s 

approach is inconsistent with CEQ’s regulations. See 40 CFR 1500.1(c) (“Purpose” of 

CEQ regulations) (“The NEPA process is intended to help public officials make 

decisions that are based on understanding of environmental consequences, and take 

actions that protect, restore, and enhance the environment.”); 40 CFR 1500.2 (“Policy” 

in CEQ regulations) (“Federal agencies shall to the fullest extent possible: (b) 

Implement procedures to make the NEPA process more useful to decisionmakers and 

the public;”).

2. The Staff concluded in the DSEIS that the impacts of GHG emissions from past, present, 

and foreseeable future actions on global climate change are MODERATE with or without 

the operation of LSCS for another 20 years. However, reporting this finding of 

MODERATE cumulative impacts in the DSEIS is misleading to the public and 

meaningless to decisionmakers, because no applicable frame of reference has been 

provided. The DSEIS lacks a discussion of the frame of reference for GHGs suggested 

in the Draft CEQ guidance on how GHGs should be addressed in NEPA documents. 

See CEQ, Revised Draft Guidance for Federal Departments and Agencies on 

Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in 

NEPA Reviews, 79 Fed. Reg. 77,802 (Dec. 24, 2012). That guidance states:

“Finally, when discussing GHG emissions, as for all environmental impacts, it can be 

helpful to provide the decisionmaker and the public with a frame of reference. To 

provide a frame of reference, agencies can incorporate by reference applicable agency 

emissions targets such as applicable Federal, state, tribal, or local goals for GHG 

emission reductions to provide a frame of reference and make it clear whether the 

emissions being discussed are consistent with such goals. For example, Bureau of 

Land Management projects in California, especially joint projects with the State, look at 

how the agency action will help or hurt California in reaching its emission reduction 

goals under the State’s Assembly Bill 32 (Global Warming Solutions Act), which helps 

frame the context for the BLM NEPA analysis.”

Id. at 77,826; see also USEPA, “Consideration of Cumulative Impacts in EPA Review 

of NEPA Documents,” EPA 315-R-99-002 (May 1999) (“EPA reviewers should 

recommend that the proper spatial scope of the analysis include geographic areas that 
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sustain the resources of concern. Importantly, the geographical boundaries should not 

be extended to the point that the analysis becomes unwieldy and useless for decisionmaking.”), available at https://www.epa.gov/sites/production/files/2014-

08/documents/cumulative.pdf.

The DSEIS should compare the cumulative impacts of the proposed LSCS license 

renewal with the cumulative impacts of the reasonable alternatives. And the benefits of 

LSCS license renewal in meeting Illinois public policy goals for controlling GHG 

emissions should be discussed in comparison to the reasonable alternatives. See, 

e.g., Illinois Governor’s Office, Executive Order on Climate Change and Greenhouse 

Gas Reduction, 2006–11 (Oct. 5, 2006) (establishing a Climate Change Advisory 

Group and stating that “Illinois is a national leader in addressing climate change 

by...proposing an aggressive energy independence plan that includes strategies to 

reduce carbon emissions,...), available at 

http://www.illinois.gov/Government/ExecOrders/Documents/2006/execorder2006-

11.pdf.

3. Similarly, Federal courts have interpreted NEPA to require a “useful analysis of the 

cumulative impacts of past, present, and future projects.” City of Carmel-by-the-Sea v. 

U.S. Dept. of Transp., 123 F.3d 1142, 1160 (9th Cir. 1997). This means that the EIS 

must analyze the combined effects of proposed actions in sufficient detail to be “useful to 

a decision maker in deciding whether, or how, to alter the program to lessen cumulative 

impacts.” Id. (quoting Natural Res. Def. Council v. Hodel, 865 F.2d 288, 299 (D.C. 

Cir. 1988)). The conclusion of MODERATE cumulative impacts without context is not 

useful for a decision maker or to the public.

4. As indicated in Exelon’s ER (Section 4.12), the NRC regulations governing the 

cumulative impacts analysis for license renewal are focused on the cumulative impacts 

of actions “occurring in the vicinity of the nuclear plant” and on “regional resource 

characteristics” (quoting 10 CFR 51.53(c)(3)(ii)(O) and 10 CFR Part 51, Subpart A, 

Appendix B, Table B–1). There is no regulatory requirement for the NRC to consider the 

cumulative impacts of GHG emissions on Global Climate Change. If the NRC proceeds 

to evaluate such impacts, however, it must do so in a manner that is useful to agency 

decision makers and informs the public. See Hodel, 865 F.2d at 299. To evaluate and 

report the findings of cumulative impacts on global climate change in the manner done in 

the DSEIS, without focusing on the net benefits of the proposed action and placing the 

impacts in the context of meeting public policy goals for controlling GHG emissions, 

would neither be useful to decision makers nor inform the public.

5. Other agencies take a different approach for dealing with the same topic. For example, 

the Federal Energy Regulatory Commission (FERC) very recently assessed the 

cumulative impacts on global climate change from a natural gas pipeline expansion 

project. See FERC, Southeast Market Pipelines Project, Final Environmental Impact 

Statement at 3–295 to 3–298 (Dec. 2015), available at 

http://elibrary.ferc.gov:0/idmws/file_list.asp?document_id=14409956. FERC stated that 

because natural gas emits less CO2 than other fuel sources, such as fuel oil or coal 

which could reasonably be the fuel of choice at electric generating stations if the pipeline 

was not extended, it anticipated that the project would “reduce current GHG 

emissions...” Emphasis added. Similarly, FERC noted that the overall lifecycle GHG 

emissions from natural gas plants are significantly lower than other fuel source 

alternatives (e.g., coal). Based on this comparison to alternatives, and focusing on the 

CEQ regulations to assess significance, FERC concluded that the gas pipeline project it 

evaluated “would not significantly contribute to cumulative global climate impacts.” Id. at 
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3–298; see also 40 CFR 1508.27 (explaining that the assessment of the significance of 

an environmental impact requires consideration of both context and intensity, including 

whether an action “is related to other actions” that could have cumulatively significant 

impacts).

FERC did not find it necessary or appropriate to reach a conclusion on the cumulative 

impacts of all projects worldwide on global climate change (including the incremental 

contribution of the new pipeline), as the DSEIS does for LSCS license renewal. Such a 

vague, broad and all-encompassing inquiry into projects related and unrelated to the 

proposed action is not informative to decision makers. FERC also did not assess the 

project as a contributor of GHGs despite the obvious fact that fossil-fuel-powered 

construction and inspection equipment—that would release GHGs—would be used for 

the project. FERC’s approach provides a relevant line of inquiry and formulation of the 

conclusion for decision makers and the public. See also Christopher, “Success by a 

Thousand Cuts: The Use of Environmental Impact Assessment in Addressing Climate 

Change,” Vt. J. of Envtl. L. 549, 594 (2008) (noting that EISs for wind farms often 

consider climate impacts by comparing a baseline alternative in which CO2 emitters 

continue operations with a zero emissions alternative offered by wind energy).

6. Courts have held that when a proposed action will lead to a net beneficial environmental 

impact in a particular area, then the environmental review need not address the 

cumulative impact of the proposed action in that particular area. This is because a 

cumulative impacts analysis and discussion in an EIS helps identify mitigating actions. 

See generally 40 CFR § 1508.25(b)(3) (scope includes mitigating actions). When a 

proposed action has a net beneficial effect in a particular area, however, there is no 

logical reason to modify that beneficial project or mitigate the beneficial impact, simply 

because other past, present, or reasonably foreseeable future projects in the area may 

have negative effects.

For example, in San Francisco Baykeeper v. U.S. Army Corps of Engineers, the court 

considered challenges to the environmental review of proposed dredging and seaport 

renovations. Baykeeper argued that the Corps’ NEPA reviews omitted a cumulative 

impacts discussion about the effect of the dredging and renovations on the introduction 

of invasive marine species. Baykeeper argued that the invasive species would be 

introduced to the bay through discharge of ballast water from ships, and that the 

dredging and renovations would increase the number of ships and, therefore, the 

volume of ballast water discharged. But smaller ships require more ballast water than 

larger, more stable ships. The Corps had concluded that the larger ships that would be 

able to visit the port after the dredging and renovations would, over time, replace the 

smaller, more numerous ships that required more ballast water. Accordingly, the 

Corps concluded that the proposed actions would reduce the cumulative volume of 

ballast water being discharged to the bay, and thereby have a beneficial effect on the 

risk of introducing invasive marine species transported in ballast water. See 

219 F.Supp.2d 1001, 1008–14 (N.D.Cal. 2001).

The court rejected Baykeeper’s arguments, holding that because the proposed action 

would have a beneficial effect on the risk of invasive species introduction, there was no 

obligation to discuss the cumulative impacts of invasive species in detail. See id. at 

1013–14. In dicta, the court suggested that it would have rejected the challenge even 

if, during one of the transitional years of the renovation, there was an increase in 

ballast waste discharge. Id. at 1017 n.9; see also Defenders of Wildlife v. Babbit, 

130 F.Supp.2d 121, 137 (D.D.C. 2001) (holding that because the “net effect” of the 

proposed actions on pronghorn species will be beneficial, there was no need for a 
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cumulative impacts analysis of other projects for this proposed action). The 

contribution of LSCS to Global Climate Change is similar to the port renovations 

considered in San Francisco Baykeeper: LSCS’s contribution has a net benefit to 

Global Climate Change when compared to reasonable alternatives. Accordingly, the 

NRC could prepare the SEIS without an analysis of cumulative impacts.

7. Exelon provided similar comments on the DSEISs for Braidwood. See NUREG–1437, 

Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 

Supplement 55, Regarding Braidwood Station, Units 1 & 2 at A–92 to A–93 (Nov. 2015). 

The NRC staff did not accept those comments, primarily because, citing 40 CFR 1508.7, 

the NRC staff concluded that the relevant inquiry focused on the “cumulative impact of 

GHG emissions resulting from continued operation of Braidwood on global climate 

change when added to the aggregate effects of other past, present, and reasonably 

foreseeable future actions...” Id. at A–93. Exelon does not agree with the manner in 

which the staff has applied that regulatory provision. As previously noted, the 

incremental impact of additional GHG emissions from continued operation is de minimis, 

and as stated in the LSCS DSEIS and in the FSEIS for Braidwood, climate change is 

projected to occur “with or without” continued operation. This is not a case where the 

proposed project has a small but noticeable contribution to a larger impact. Quite the 

opposite. Like the proposed port renovations in San Francisco Baykeeper, which would 

lead to a reduction in the risk of invasive species impacts, and the S.E. Market pipeline 

analyzed by FERC, the most notable environmental result of LCSC’s operation of 

another 20 years would be millions of tons of avoided emissions (i.e., a beneficial 

impact). See 219 F.Supp.2d at 1013–14. The analysis used and conclusions reached 

in the DSEIS disregard this critical fact and, as such, fail to be useful to decision makers 

or inform the public.

Commentators have recognized that “even the most miniscule emission becomes 

significant when added to the cumulative impact of global emissions.” See Wishnie, 

Student Article, “EPA for a New Century: Climate Change & the Reform of the 

National Environmental Policy Act,” 16 N.Y.U. Envtl. L.J. 628, 646 (2008). But without 

a reasonable process, the cumulative impact analysis would create an “unworkable 

burden for agencies” as they consider smaller and smaller impacts. Id. Therefore, the 

analysis must focus on the relevant question of what the environmental impacts of the 

proposed action will be, in comparison to alternatives and in the context of public policy 

goals for controlling GHG emissions. See Gold and Imwalle, “Accounting for Climate 

Change in Environmental Review Documents,” Trends, Newsletter of the ABA 

Section of Environment, Energy, & Resources, at 8 (Jan. 2008).

Exelon provides some suggestions for text edits in the comments that follow. A holistic revision 

to the DSEIS’ discussion about cumulative impacts on Global Climate Change is, however, 

required.

Response: The commenter recommends that, for SEIS Section 4.16.11, “Global Climate 

Change,” the NRC staff (1) should not apply impact levels (SMALL, MODERATE, or LARGE), 

(2) should discuss the net beneficial effect of the proposed action on global climate change and 

compare it to the Alternatives, (3) should include a frame of reference for GHG emissions, and 

(4) should provide an ROI for the cumulative analysis with an appropriate scope. The 

commenter provided examples on how other agencies have assessed cumulative impacts on 

global climate change in environmental review documents. Alternatively, the commenter 

recommends that, if Section 4.16.11 of the SEIS is not revised to discuss the items noted, the 

SEIS should not discuss cumulative impacts on global climate change and delete this section 
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because the commenter believes it does not accurately inform the public on the benefits of 

LSCS operation on climate change.

The NRC staff does not agree with the commenter that Section 4.16.11 of the SEIS should be 

deleted. On June 20, 2013, the NRC published a final rule (78 FR 37282) revising its 

environmental protection regulation, 10 CFR Part 51, “Environmental Protection Regulations for 

Domestic Licensing and Related Regulatory Functions.” The final rule updates the potential 

environmental impacts associated with the renewal of an operating license for a nuclear power 

reactor for an additional 20 years. In this rule, the NRC states that it would include, within every 

license renewal SEIS, a “plant-specific analysis of any impacts caused by GHG emissions over 

the course of the license renewal term as well as any impacts caused by potential climate 

change upon the affected resources.” The NRC staff considers the scope of impacts from GHG 

emissions to be inclusive of direct, indirect, and cumulative impacts. This commitment was 

made in the 2013 final rule and affirmed by the Commission consistent with the Commission’s 

previous direction in CLI-09-21 (November 3, 2009).

The commenter further requests that the NRC staff not apply impact levels to the Global Climate 

Change section because there is no requirement to apply impact levels to all resource areas. In 

doing so, the NRC is not being consistent with CEQ regulations, 40 CFR 1500.1(c) and 

40 CFR 1500.2. The commenter identifies that there are resource areas for which impact levels 

are not applied (Special Status Species and Habitats, Historic and Cultural Resources, 

Environmental Justice, or cumulative Socioeconomic or Environmental Justice impacts); 

therefore, Global Climate Change should take such an alternative approach. The NRC staff 

disagrees with the commenter’s characterization. The impact significance levels assigned for 

the resource areas that the commenter has identified are reported in accordance with statutory 

findings or policy determinations rather than SMALL, MODERATE, or LARGE. Use of the latter 

adjectival significance levels would be superfluous and inappropriate for these resources areas. 

For instance, as explained in Table ES–1, the NRC staff reports the effects from continued 

operation of LSCS during the license renewal period for special status species and habitats in 

terms of the findings under the Endangered Species Act of 1973, as amended (i.e., no effect, 

are not likely to adversely affect, are likely to adversely affect, or are likely to jeopardize the 

listed species or adversely modify the designated critical habitat of Federally listed species 

populations or their critical habitat). Similarly, for Historic and Cultural Resources, the NRC 

reports the effects from continued operation of LSCS during the license renewal period in terms 

of the criteria under the National Historic Preservation Act of 1966 for adverse effects on historic 

properties (i.e., no historic properties are present, historic properties are present but are not 

adversely affected, or there is an adverse effect). As discussed in the 2013 final rule and in the 

2013 license renewal GEIS, NRC’s Policy Statement on the Treatment of Environmental Justice 

Matters in NRC Regulatory and Licensing Actions (69 FR 52040; August 24, 2004) requires a 

determination of whether human health and environmental effects of continued operations 

during the license renewal term and refurbishment associated with license renewal on minority 

populations and low-income populations would be disproportionately high and adverse. Absent

a statutory or policy determination, the NRC staff believes it is appropriate to use the NRC’s 

established levels of significance for potential impacts as described in Section 1.4 of the SEIS 

for Global Climate Change. As discussed in the 2013 license renewal GEIS, the NRC’s 

standard of significance for impacts uses the CEQ terminology for “significantly” 

(40 CFR 1508.27), which requires consideration of both “context” and “intensity.” The NRC staff 

does not agree with the commenter that the use of the three significance levels (SMALL, 

MODERATE, or LARGE) as applied to the cumulative impacts on Global Climate Change are 

inconsistent with CEQ’s regulations. Cumulative impacts can result from individually minor, but 

collectively significant, actions taking place over a period time.
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The Global Climate Change discussion does provide an ROI. The section identifies that “[d]ue 

to the global significance of GHG emissions, this global climate change cumulative impacts 

analysis considers the entire Earth’s atmosphere and therefore global emissions (as opposed to 

county, state, or national emissions).” As discussed in Section 4.16.11, GHG emissions are 

transported and become well mixed throughout the Earth’s atmosphere, their impact on climate 

is long lasting as a result of their long atmospheric lifetime, and the extent and nature of climate 

change is not specific to where GHGs are emitted. Therefore, given the atmospheric lifetime of 

GHGs, atmospheric mixing, and the global implications of GHG emissions, it would be 

inappropriate to arbitrarily set a smaller ROI (i.e., county or state) as a physical boundary on 

GHG emissions.

The NRC staff agrees with the commenter that Section 4.16.11 of the LSCS should discuss the 

net beneficial effect of the proposed action when compared to the Alternatives. This discussion 

was added to Section 4.16.11 and the conclusion was also revised accordingly. The NRC staff 

also agrees with the commenter that a frame of reference should be provided. A discussion on 

Illinois GHG reduction goals has been included in Section 4.16.11.

Comment L-014: In Section 4.16.11 on page 4–129 revise lines 8 and 9 as follows:

“... addresses the impact of GHG emissions resulting from worldwide past, present, and 

reasonably foreseeable human activities continued operation of LSCS on global climate change 

when added to the aggregate effects of other past, present, and reasonably foreseeable future 

actions.”

As it appears in the DSEIS, the text implies that operation of LSCS provides some substantial 

contribution to the GHG emissions discussed in section 4.16.11, but as shown in Tables 4–22 

and 4–23, it does not. As a further example, none of the 94.1 MMT of CO2 emissions reported 

in Illinois from electricity generation in reference EIA 2015a, which is cited by the NRC Staff in 

the DSEIS, came from nuclear power plants.

Response: The commenter requests a revision to a statement in Section 4.16.11 that it 

believes inaccurately implies that LSCS operations have a substantial contribution to GHG 

emissions. The NRC staff does not agree with the proposed revision or with the comment that 

the current statement implies that LSCS substantially contributes to GHG emissions. The 

statement as it is currently phrased by the NRC staff is wholly consistent with the concept of 

cumulative impacts as defined in the CEQ’s regulations for implementing NEPA: “‘Cumulative 

impact’ is the impact on the environment which results from the incremental impact of the action 

when added to other past, present, and reasonably foreseeable future actions regardless of 

what agency (federal or non-federal) or person undertakes such other actions” 

(40 CFR 1508.7). This definition has also been incorporated by reference into the NRC’s 

regulations for implementing NEPA in 10 CFR Part 51. Further, cumulative impacts may result 

when the environmental effects associated with the proposed action are overlaid on, or added 

to, temporary or permanent effects associated with other past, present, and reasonably 

foreseeable actions. Cumulative impacts can result from individually minor, but collectively 

significant, actions taking place over a period of time. Regardless, Section 4.16.11 states that 

the incremental impact from the contribution of GHG emissions from continued operation of 

LSCS on climate change would be SMALL and minor when compared to global emissions. No 

change was made to the SEIS in response to this comment.

Comment L-015: In Section 4.16.11 on page 4–130, revise the text in line 2 as follows: “... 

performance rate standards for non-nuclear power plants that should be achieved by 2030. 

Future actions ... “
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Response: The commenter requests that the subject statement clarify that performance

standards are applicable to non-nuclear power plants. The NRC staff agrees with the comment 

and revised the statement in Section 4.16.11 to state “performance rate standards for fossil 

fuel-fired power plants” to use the language specifically contained in the Clean Power Plan.

Comment L-016: In Section 4.16.11 on page 4–130, revise the text in line 5 as follows: 

“...non-nuclear electricity generation, industrial processes, and agriculture. As presented in 

Section 4.15.3, ...”

Response: The commenter requests that the subject statement identify that GHG emissions 

from electricity generation sources account for non-nuclear electricity generation sources. The 

NRC staff agrees that revising the subject statement would clarify the electricity generation 

sources. The statement has been revised to identify the specific sources and to state: “EPA’s 

U.S. inventory of GHG emissions illustrates the diversity of GHG sources, such as electricity 

generation (including fossil fuel combustion and incineration of waste), industrial processes, and 

agriculture.”

Comment L-017: In Section 4.16.11 on page 4–130, revise the text in line 6 as follows: 

“...direct GHG emissions from combustion sources resulting from ancillary operations at LSCS

range from ...”

Response: The commenter requests that the word “ancillary” be added to the subject 

statement. The NRC staff agrees with the comment and has made this change.

Comment L-018: In Section 4.16.11 on page 4–130, revise the text in line 7 as follows: “...and 

total annual emissions range from 34,228 to 39,99738,623 MT CO2eq. In ...”

This change is necessary because there are errors in Table 4–21 (p. 4–105), from which the 

information in line 7 on p. 4–130 was taken. The value in Table 4–21 for the 2011 LSCS GHG 

emissions from purchased electricity should be 33,493 MT CO2e instead of 36,066 (see 

reference Exelon 2015d). As a result, the associated LSCS 2011 total GHG emissions should 

be 37,424 MT CO2e. After the correction is made, the 2014 total of 38,623 MT CO2e becomes 

the upper bound for the range of potential annual GHG emissions at LSCS. Therefore, 

38,623 MT CO2e per year should be used in the discussion in Section 4.16.11 on p. 4–130.

Response: The commenter requests that the range of GHG emissions from LSCS operation 

provided in Section 4.16.11 of the SEIS be revised. The NRC staff has deleted total GHG 

emissions from the subject statement as explained in response to Comment E-002; therefore, 

this revision is no longer necessary.

Comment L-019: In Section 4.16.11 on page 4–130, revise line 10 as follows:

“...level, GHG emissions from LSCS are minorminiscule relative to these inventories; this is 

evident, as ...”

Response: The commenter requests that the subject statement be revised to state “miniscule” 

rather than “minor” in comparing LSCS’s GHG contributions to other inventories. The NRC staff 

disagrees that the change is necessary because the statement in question references

Table 4–23 where a quantitative comparison can be made. No change was made to the SEIS 

in response to this comment.

Comment L-020: In Section 4.16.11 on page 4–130, revise the sentence that begins in line 11 

as follows: “The emissions impact of a single source on climate change—both additions of 

GHGs and avoided GHGs—requires ...”

Response: The commenter requests that the subject statement be revised to state that 

emission impacts include GHG increases and avoided GHGs. The NRC staff does not agree 
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with the comment and disagrees that the change is necessary because climate models use net 

GHG concentration scenarios. No change was made to the SEIS in response to this comment.

Comment L-021: In Section 4.16.11 on page 4–130, Revise the sentence that ends in line 14 

as follows: “...the year 2030) is dependent on past GHG emissions and, necessarily, avoided 

emissions

Response: The commenter requests that the subject statement be revised to include avoided 

emissions. The NRC staff does not agree with the comment and disagrees that the change is 

necessary because climate models use net GHG concentrations. No change was made to the 

SEIS in response to this comment.

Comment L-022: In Section 4.16.11 on page 4–130, revise the text in line 15 as follows: “ ... 

occur with or without the present and future GHG emissions from LSCS and the avoided GHG 

emissions that LSCS provides. In fact, as shown in Table 4–22, in comparison to replacement 

power scenarios, other than new nuclear, continued operation of LSCS would lead to the 

avoidance of GHG emissions that are far larger (by orders of magnitude) than LSCS’s GHG 

emissions. The NRC staff concludes ...”

Response: The commenter requests that the subject statement be revised. The NRC staff 

does not agree with the comment that the identified statement be revised to discuss avoided 

emissions. However, a discussion on avoided GHG emissions has been added to 

Section 4.16.11 preceding the paragraph of concern to the commenter.

Comment L-023: In Section 4.16.11 on page 4–130, revise the text in line 25 as follows:

“Therefore, the cumulative impact of GHG emissions on climate change from all sources 

throughout the world is noticeable but not ...”

Response: The commenter requests that the subject statement be revised and provided

recommended changes. The NRC staff does not agree with the recommended changes; 

however, it revised the subject statement to clarify global GHG emissions from past, present, 

and reasonably foreseeable future actions. Therefore, the cumulative impact of global GHG 

emissions from past, present, and reasonably foreseeable future actions on climate change is 

noticeable, but not destabilizing.

Comment L-024: In Section 4.16.11 on page 4–130, Revise the text in lines 26 and 27 as 

follows: “ ... destabilizing. The NRC staff concludes that the cumulative impacts of GHG 

emissions from past, present, and reasonably foreseeable future actions are MODERATE. 

However, asAs ...”

Response: The commenter requests that the cumulative impact conclusion for Global Climate 

Change be deleted. The NRC staff does not agree with the comment. Section 4.16.11 states 

that due to the global significance of GHG emissions, the global climate change cumulative 

impacts analysis considers the entire Earth’s atmosphere and, therefore, global emissions (as 

opposed to county, state, or national emissions). Further, Section 4.16.11 of the SEIS presents 

scientific research to support the MODERATE impact level and conclusion. Climate change 

research and climate models indicate that short-term climate change is projected to occur with 

or without present and future GHG emissions. In other words, even if GHG emissions were to 

be completely eliminated, the Earth’s average surface temperature will continue to increase, 

and climate-related changes will persist over the next few decades. The magnitude of the 

continued increase in GHG emission rates will determine the amount of additional future 

warming and long-term (beyond 2030) climate change. Because climate change and 

climate-related changes have been observed on a global level (Section 4.15.13.10 of the SEIS) 

and because climate models indicate that future climate change will continue, the cumulative 
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impact of GHG emissions on global climate is MODERATE (i.e., the cumulative impact of GHG 

emissions on climate change is noticeable, but not destabilizing).

Comment L-025: In Section 4.16.11 on page 4–130, Revise the text in line 29 as follows: “... 

LSCS, when compared to global emissions, are minor. A significance level characterization for 

such emissions during the LSCS license renewal term, however, is not meaningful to agency 

decision makers because cumulative impacts of GHG emissions on global climate change will 

take place with or without continued operation of LSCS, and because continued operation of 

LSCS would have a net beneficial effect on GHG emissions and thus on overall cumulative 

global climate change. Therefore, the staff has not assigned a significance level 

characterization to cumulative Global Climate Change impacts...”

Response: The commenter requests that the cumulative impact conclusion for Global Climate 

Change include a discussion on why a significance impact level is not appropriate for 

cumulative Global Climate Change impacts. The NRC staff does not agree with the comment. 

As provided in response to Comment L-024, Section 4.16.11 of the SEIS presents scientific 

research to support the MODERATE impact level and conclusion. No change was made to the 

SEIS in response to this comment.

Comment L-026: In Section 4.16.11 on page 4–130, in footnote (d) of Table 4–23, the DSEIS 

cites the wrong reference for the LSCS GHG emissions. The LSCS GHG emissions data 

(presented in Table 4–21 of the DSEIS) was provided in Exelon’s response to RAI MA-07 

(ML15195A350), which is reference “Exelon 2015d” in section 4.18.

Response: The commenter requests that the reference cited in footnote (d) of Table 4–23 be 

corrected. Footnote (d) in Table 4–23 has been revised to identify that the source for GHG 

emissions is Exelon 2015d in accordance with the references in Section 4.17 of the SEIS.

Comment L-093: In Section 4.16.11 on page 4–130 in Table 4–23, correct footnote (d) as 

follows: (d) Emissions rounded from and obtained from Exelon 2015c2015d. This correction is 

needed because the LSCS GHG emissions data (presented in Table 4–21 of the DSEIS) was 

provided to the NRC in Exelon’s response to RAI MA-07 (ADAMS Accession 

No. ML15195A350), which is listed as “Exelon 2015d” in DSEIS Section 4.18, References.

Response: The commenter requests that the reference cited in footnote (d) of Table 4–23 be 

corrected. Footnote (d) in Table 4–23 has been revised to identify that the source for GHG 

emissions is Exelon 2015d in accordance with the references in Section 4.17 of the SEIS.

A.3.14 Waste Management

Comment M-006: You can’t say that there are no impacts from the storage of high-level waste

at nuclear power plants around the country until a study of storage impacts is completed.

Response: The comment concerns the environmental impacts of the storage of spent fuel at 

nuclear power plants. The NRC’s regulations in 10 CFR Part 20, Part 50, and Part 72 require 

that spent nuclear fuel be stored and maintained in a safe and secure manner while a nuclear 

power plant is operating and after the plant operating license expires. Power reactors must limit 

radiation doses to workers and the public, including at spent fuel pools and cask storage 

facilities. The facilities are under constant monitoring and surveillance. The spent fuel remains 

under the direct control of the licensee and the regulatory oversight of the NRC until its ultimate 

disposition.

Exelon is required to safely handle, process, and store spent fuel in accordance with NRC 

regulations. Spent fuel is stored on site in a combination of two types of NRC-approved 

methods: storage in a spent fuel pool and in dry casks. Both of these methods maintain the 
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spent fuel in a safe configuration. Additionally, to ensure the long-term safety of spent fuel, 

Exelon is required by 10 CFR 50.54(bb) to maintain adequate funding for the safe long-term 

storage of spent fuel on site.

Section 4.11.1.2, “Onsite Storage of Spent Nuclear Fuel,” of the GEIS (NRC 2013b) discusses 

the impacts from the onsite storage of spent fuel at nuclear power plant sites during the license 

renewal term. As discussed in Section 4.13.1 of this SEIS, the NRC staff did not identify any 

new and significant information with respect to spent fuel storage during its review of Exelon’s 

ER, the site audit, or the scoping process. As such, there are no impacts expected for spent 

fuel storage during the period of extended operation beyond those discussed in the GEIS 

(NRC 2013b), which concludes that the impacts are SMALL.

Regarding the long-term storage of spent nuclear fuel beyond the licensed life for operation of a 

reactor, on August 26, 2014, the Commission approved the Continued Storage Rule at 

10 CFR 51.23 and associated NUREG–2157, Generic Environmental Impact Statement for 

Continued Storage of Spent Nuclear Fuel (Continued Storage GEIS) (NRC 2014). The 

Continued Storage GEIS provides the technical basis for the revised 10 CFR 51.23. The 

Continued Storage Rule adopts the generic impact determinations made in NUREG–2157 and 

codifies the NRC’s generic determinations regarding the environmental impacts of continued 

storage of spent nuclear fuel beyond a reactor’s operating license (i.e., those impacts that could 

occur as a result of the storage of spent nuclear fuel at at-reactor or away-from-reactor sites 

after a reactor’s licensed operational life and until a permanent repository becomes available). 

In accordance with 10 CFR 51.23, the impact determinations in NUREG–2157 regarding 

continued storage are deemed incorporated into the SEIS for LSCS license renewal. Therefore, 

the environmental impacts of the storage of spent fuel at nuclear power plants have been 

evaluated and, thus, this comment did not result in any changes to the SEIS.

A.3.15 SAMA

Comment L-089: In Section 4.11.1.2 on page 4–78 in the list of SAMA evaluation components 

provided in the 2nd full paragraph under the heading “Overview of SAMA Process,” insert a new 

component between the existing items (2) and (3), and renumber the list, as follows:

“(3) Exelon screened out SAMA candidates that are not applicable to the LSCS plant design or 

are of low benefit in boiling water reactors (BWRs) such as LSCS, as well as candidates that 

have already been implemented at LSCS or whose benefits have been achieved at LSCS using 

other means.

(3)(4) Exelon estimated the costs of implementing the unscreened SAMA candidates, and those 

whose estimated implementation cost exceeded the maximum possible averted cost-risk were 

also screened out.

(5) Exelon estimated how much each remaining unscreened SAMA could reduce risk. Referred 

to as potential benefits of implementing each SAMA, those estimates were developed in terms 

of dollars in accordance with NRC guidance for performing regulatory analyses. The costs of 

implementing the candidate SAMAs were also estimated Sensitivity analyses were performed 

by Exelon to quantify effects on the SAMA evaluation. (4) Exelon compared the implementation 

cost andwith the benefit offor each remaining unscreened SAMA candidate to determine 

whether it was potentially cost beneficial (the benefits of the SAMA exceeded its cost). 

Sensitivity analyses were then performed by Exelon to quantify effects on the cost-benefit 

evaluation.”

This correction is needed because, as written, item (4) states that “Exelon compared the cost 

and benefit of each remaining SAMA to determine...” (emphasis added), but there is nothing in 
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the list that describes the early screening steps, which cause there to be such “remaining” 

SAMAs.

Response: The commenter requests that the SAMA methodology be corrected. The change is 

consistent with SAMA guidance and has been changed as requested.

Comment L-090: In Section 4.11.1.2, both Table 4–14 on page 4–79 and Table F–1 on page 

F–3 contain a row indicating that “Loss of Feedwater” contributes 1.1E-8/yr to the CDF. The 

entry in each table should be replaced by 1.2E-7/yr. See Table F.2–2 in Appendix F to the 

LSCS ER.

Response: The commenter requests that values in the tables be made consistent. The tables 

were made consistent as requested. The percent change in core damage frequency (CDF) was 

negligible, and the staff agrees with the comment.

Comment L-091: In Section 4.11.1.2, on page 4–83 in the 2nd paragraph, correct the text as 

follows: “... Table 4–16 summarizes the assumptions used to estimate the risk reduction for 

each evaluatedpotentially cost-beneficial SAMA, the estimated risk reduction in terms of CDF

percent reduction, population dose, offsite economic cost, and the estimated total benefit 

(present value) of the averted risk...” This correction is needed because Table 4–16 in the 

DSEIS only addresses the potentially cost beneficial SAMAs. Appendix F in the DSEIS 

contains a table that includes all of the evaluated SAMAs.

Response: The commenter requests that the statement regarding the reference to Table 4–16 

be corrected. The NRC staff agrees with the comment and has revised the text as suggested.

Comment L-094: In Appendix F on page F–1 line 16, as is stated in Section 4.11.1.2 of the 

DSEIS (p. 4–82), the number of SAMA candidates initially identified for LSCS is 26 rather than 

27.

Response: The NRC staff agrees with the comment and revised the text as suggested.

Comment L-095: As documented in section 4.11.1.2, page 4–82, 26 SAMAs were originally 

identified and 2 were originally screened on cost. As was documented in RAI responses 

(ADAMS Accession No. ML15149A370), one of these 2 SAMAs was subsequently determined 

to not be screened on cost in Phase 1 due to modeling corrections.

Response: The NRC staff agrees with this comment and revised the text appropriately.

Comment L-096: In Appendix F on page F–6, line 15 correct the text as follows:

“... open supporting requirements, threefour are related to documentation and three have a 

relatively ...” This change is needed because DA-C10 is a documentation issue.

Response: The NRC staff agrees with the comment and revised the text as suggested. 

DA-C10 is a documentation issue.

Comment L-097: In Appendix F on page F–33 in Table F–6 correct the entry in the column 

labeled “Baseline (Internal + External),” and row labeled “6 – CREATE ECCS SUCTION 

STRAINER BACKFLUSH CAPABILITY WITH RHRSW” as follows:

Individual SAMA Assumption Baseline (Internal + External)

6 – CREATE ECCS SUCTION’’’ $88K $87K

Response: The NRC staff agrees with the comment and revised the text as suggested.
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Comment L-098: In Appendix F on page F–34 in Table F–6, the modeling description for 

SAMA 11 provided in the column labeled “Individual SAMA and Assumption” is incorrect. The 

text appears to be the same as for SAMA 8, and it should be replaced with text appropriate for 

SAMA 11.

Response: The NRC staff agrees with the comment and revised the text as provided for 

SAMA 11 in the ER.

Comment L-099: In Appendix G on page G–5 in Table G–2, the column labeled “Source” cites 

“Exelon 2015a, 2015b” in two rows—the row labeled “Dose rate at 1 m from vehicle, mrem/hr”

and the row labeled “Packaging dimensions, m.” However, Section G.5, References (p. G–13), 

contains only a single “Exelon 2015” entry (Exelon Generation’s response to RAI TR-09, 

ML15240A002). Accordingly, reference information for “Exelon 2015b” should be added in 

Section G.5.

Response: This comment notes discrepancies with the references cited in Appendix G. The 

NRC staff agrees with this comment and has updated the references and the text and 

corresponding tables in Appendix G to reflect the proper citations.
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A.4 Copies of Comments with Identifying Numbers
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A.5 References

10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

protection against radiation.”

10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

production and utilization facilities.”

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 72. Code of Federal Regulations, Title 10, Energy, Part 72, “Licensing 

requirements for the independent storage of spent nuclear fuel, high-level radioactive waste, 

and reactor-related Greater than Class C waste.”

40 CFR Part 1500. Code of Federal Regulations, Title 40, Part 1500 Protection of Environment, 

Council on Environmental Quality Purpose, Policy, and Mandate, Section 1500.1 Purpose, 

Section 1500.2 Policy, Section 1508.7 Cumulative Impact, Section 1508.27 Significantly.

69 FR 52040. U.S. Nuclear Regulatory Commission. “Policy statement on the treatment of 

environmental justice matters in NRC regulatory and licensing actions.” Federal Register

69(163):52040–52048. August 24, 2004.

78 FR 37282. U.S. Nuclear Regulatory Commission. “Revisions to environmental review for 

renewal of nuclear power plant operating licenses.” Federal Register 78 (119): 37282–37324. 

June 20, 2013.

80 FR 5793. U.S. Nuclear Regulatory Commission. “LaSalle County Station, Units 1 and 2, 

notice of intent to prepare an environmental impact statement and conduct the scoping process; 

public meetings and request for comment.” Federal Register 80(22):5793–5795. 

February 3, 2015.

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

[EA] EA Engineering, Science, and Technology, Inc. 2015. Final Impingement and Entrainment 

Characterization Study LaSalle County Station. Prepared for Exelon Generation Company, 

LLC, Kennett Square, Pennsylvania. August 2015. Deerfield, Illinois. ADAMS 

No. ML15243A204.

[ENSR] ENSR Corporation. 2008. Aquatic Ecology—Main Cooling Reservoir and Circulating 

Water Intake Structure Study, Unit 3 and 4, Licensing Project. Prepared for STP Nuclear 

Operating Company. Houston, TX: ENSR. 53 p. ADAMS No. ML11256A057. 

[EPA] U.S. Environmental Protection Agency. 2014. Benefits Analysis for the Final Section 

316(b) Existing Facilities Rule. EPA-821-R-14-005. May 2014. Available at 

https://www.epa.gov/sites/production/files/2015-05/documents/cooling-water_phase4_benefits_2014.pdf (accessed 27 April 2016). 

[Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 

Manager, LaSalle County Station to U.S. NRC, Document Control Desk. Subject: 

Environmental Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle 

County Station. August 17, 2001. ADAMS No. ML012330070.

[Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 

Assurance Manager, LaSalle County Station to U.S. NRC, Document Control Desk. Subject: 

Environmental Protection Plan and Operating Report Appendix B to Facility License 

No. NPF–11 and NPF–18. April 29, 2002. ADAMS No. ML021330421.
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[Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 

LaSalle County Station to U.S. NRC, Document Control Desk. Subject: Environmental 

Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle County Station. 

July 22, 2009. ADAMS No. ML092040381.

[Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 

LaSalle County Station to U.S. NRC, Document Control Desk. Subject: Environmental 

Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle County Station. 

August 25, 2010. ADAMS No. ML102371289.

[Exelon] Exelon Generation Company, LLC. 2014. Applicant’s Environmental Report—

Operating License Renewal Stage LaSalle County Station, Unit 1 License No. NPF–11, Unit 2 

License No. NPF–18. Chicago, Illinois: Exelon. December 9, 2014. ADAMS 

Nos. ML14343A849, ML14343A883, and ML14343A897.

[Exelon] Exelon Generation Company, LLC. 2015. Letter from M.P. Gallagher, Vice President, 

License Renewal Projects, to NRC Document Control Desk. Subject: Response to NRC 

Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 

Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. ADAMS 

No. ML15195A351. 

Federal Water Pollution Control Act (Clean Water Act) of 1972, as amended. 

33 U.S.C. § 1251 et seq. Rivers and Harbors Appropriation Act of 1899, as amended. 

33 U.S.C. § 403 Section 10.

Illinois Environmental Protection Act of 1970. 415 ILCS 5/Title VI. Illinois Compiled Statutes. 

Chapter 415, 5, “Noise.”

Kanter R. 2013. Environmental Almanac: Rare mussel found in Illinois River. News Gazette. 

Sunday, July 7, 2013.

Miller, Eric F. 2007. Post-Impingement Survival and Inferred Maximum Thermal Tolerances for 

Common Nearshore Marine Fish Species of Southern California. Bulletin of the Southern 

California Academy of Sciences: Vol. 106: Iss. 3. Available at 

http://scholar.oxy.edu/scas/vol106/iss3/3 (accessed 27 April 2016).

National Historic Preservation Act of 1966, as amended. 54 USC 300101 et seq.

National Environmental Policy Act of 1969, as amended. 42 U.S.C. § 4321 et seq.

[NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement

for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG–1437, 

Volumes 1 and 2. May 31, 1996. ADAMS Nos. ML040690705 and ML040690738. 

[NRC] U.S. Nuclear Regulatory Commission. 2002. Final Generic Environmental Impact 

Statement on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the 

Decommissioning of Nuclear Power Reactors. NUREG–0586, Volumes 1 and 2. Washington, 

DC: NRC. November 30, 2002. 516 p. ADAMS Nos. ML023470327, ML023500228, and 

ML023500295.

[NRC] U.S. Nuclear Regulatory Commission. 2008. Generic Environmental Impact Statement

for License Renewal of Nuclear Plants, Supplement 32: Regarding Wolf Creek Generating 

Station. Washington, DC: NRC. NUREG–1437. May 2008. 487 p. 

ADAMS No. ML081260608.
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[NRC] U.S. Nuclear Regulatory Commission. 2009. In the matter of Duke Energy Carolinas, 

LLC (Combined License Application for William States Lee III Nuclear Station, Units 1 and 2); in 

the matter of Tennessee Valley Authority (Bellefonte Nuclear Power Plant, Units 3 and 4), 

Commission Order CLI–09–21. November 3, 2009.

[NRC] U.S. Nuclear Regulatory Commission. 2013a. Generic Environmental Impact Statement

for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG–1437, Revision 1, 

Volumes 1, 2, and 3. June 30, 2013. ADAMS No. ML13107A023.

[NRC] U.S. Nuclear Regulatory Commission. 2013b. Standard Review Plans for Environmental 

Reviews for Nuclear Power Plants Supplement 1: Operating License Renewal Final Report. 

Washington, DC: NRC. NUREG–1555, Supplement 1. June 30, 2013. ADAMS 

No. ML13106A246.

[NRC] U.S. Nuclear Regulatory Commission. 2013c. Final Supplemental Environmental Impact 

Statement Regarding South Texas Project. Washington, DC: NRC. NUREG–1437, 

Supplement 48. November 2013. ADAMS No. ML13322A890.

[NRC] U.S. Nuclear Regulatory Commission. 2014. Generic Environmental Impact Statement

for Continued Storage of Spent Nuclear Fuel. Washington, DC: NRC, Office of Nuclear 

Material Safety and Safeguards. NUREG–2157, Volumes 1 and 2. September 2014. 

ADAMS Nos. ML14196A105 and ML14196A107.

[NRC] U.S. Nuclear Regulatory Commission. 2015. Final Supplemental Environmental Impact 

Statement Regarding Braidwood Station. Washington, DC: NRC. NUREG–1437, 

Supplement 55. ADAMS No. ML15062A428. 
APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

B-1

B. Applicable Laws, Regulations, and Other Requirements

There are a number of Federal laws and regulations that affect environmental protection, health, 

safety, compliance, and consultation at every nuclear power plant licensed by the U.S. Nuclear 

Regulatory Commission (NRC). Certain Federal environmental requirements have been 

delegated to state authorities for implementation, enforcement, or oversight. Furthermore, 

states have also enacted laws to protect public health and safety and the environment. It is the 

NRC’s mission, among other things, to ensure that U.S. nuclear power plants are operated in a 

manner that provides adequate protection of the public health and safety and of the 

environment through compliance with applicable Federal and state laws, regulations, and other 

requirements.

The requirements that may be applicable to the operation of NRC-licensed nuclear power plants 

encompass a broad range of Federal and state laws and regulations, addressing environmental, 

historic and cultural, health and safety, transportation, and other concerns. Generally, these 

laws and regulations are relevant to how the work involved in performing the proposed action 

would be conducted to protect workers, the public, and environmental resources. Some of 

these laws and regulations require permits or consultation with other Federal agencies or state, 

tribal, or local governments.

The Atomic Energy Act of 1954, as amended (AEA) (42 United States Code (U.S.C.) § 2011 

et seq.), authorizes any state to enter into agreement with the NRC to assume regulatory 

authority for certain activities (see 42 U.S.C. § 2021). For example, through this Agreement 

State Program, Illinois assumed regulatory responsibility over certain byproduct, source, and 

quantities of special nuclear materials not sufficient to form a critical mass. The Illinois 

Emergency Management Agency (IEMA), Division of Nuclear Safety, administers several 

programs to protect citizens and the environment, including: a comprehensive monitoring 

system for the 11 operating nuclear power reactors in Illinois, inspection and regulation of 

radioactive materials licensees and x-ray machines, and oversight of cleanup efforts at sites 

contaminated with radioactive materials (IEMA undated).

In addition to carrying out some Federal programs, state legislatures develop their own laws. 

State statutes supplement, as well as implement, Federal laws for the protection of air, water 

quality, and groundwater. State legislation may address solid waste management programs, 

locally rare or endangered species, and historic and cultural resources.

The Clean Water Act (CWA) (33 U.S.C. § 1251 et seq.) allows for primary enforcement and 

administration through state agencies, provided that 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 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 or, in 

the case of states where the authority has been delegated from the EPA, such as Illinois, a 

State Pollutant Discharge Elimination System permit. 

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, whereas the CWA only regulates surface waters. The Illinois Environmental Protection 

Agency (IEPA), Bureau of Water, Water Pollution Control, conducts the numerous programs, 

including permit programs and surface water quality monitoring and assessment programs, to 

protect and enhance the quality of the state’s surface waters (IEPA undated).
Appendix B

B-2

B.1 Federal and State Requirements

LaSalle County Station, Units 1 and 2 (LSCS), are subject to Federal and State requirements. 

Table B–1 lists the principal Federal and State laws and regulations that are used or mentioned 

in this supplemental environmental impact statement (SEIS) for LSCS.

Table B–1. Federal and State Requirements

Law/regulation Requirements

Current operating license and license renewal

Atomic Energy Act of 1954, 

as amended (AEA), 

42 U.S.C. § 2011 et seq.

The AEA and the Energy Reorganization Act of 1974, as amended

(42 U.S.C. § 5801 et seq.), give the NRC the licensing and regulatory 

authority for nuclear energy uses within the commercial sector. These 

regulations give the NRC responsibility for licensing and regulating 

commercial uses of atomic energy and allow the NRC to establish dose

and concentration limits for protection of workers and the public for 

activities under NRC jurisdiction. The NRC implements these

responsibilities through regulations set forth in Title 10 of the Code of 

Federal Regulations (10 CFR).

National Environmental 

Policy Act of 1969, as 

amended (NEPA), 

42 U.S.C. § 4321 et seq.

NEPA requires Federal agencies to integrate environmental values into 

their decisionmaking process by considering the environmental impacts of 

proposed Federal actions and reasonable alternatives to those actions. 

NEPA establishes policy, sets goals (in Section 101), and provides means 

(in Section 102) for carrying out the policy. Section 102(2) contains 

action-forcing provisions to ensure that Federal agencies follow the letter 

and spirit of the Act. For major Federal actions significantly affecting the 

quality of the human environment, Section 102(2)(C) of NEPA requires 

Federal agencies to prepare a detailed statement that includes the 

environmental impact of the proposed action and other specified 

information.

Title 10 of the Code of 

Federal Regulations

(10 CFR), Energy, Part 51

Regulations in 10 CFR Part 51, “Environmental protection regulations for 

domestic licensing and related regulatory functions,” contain 

environmental protection regulations applicable to the NRC’s domestic 

licensing and related regulatory functions. These regulations implement 

Section 102(2) of NEPA.

10 CFR Part 54 Regulations in 10 CFR Part 54, “Requirements for renewal of operating 

licenses for nuclear power plants,” govern the issuance of renewed 

operating licenses and renewed combined licenses for nuclear power 

plants licensed pursuant to Sections 103 or 104b of the AEA and Title II of 

the Energy Reorganization Act. The regulations focus on managing the

effects of aging during the period of extended operation on the 

functionality of specific structures and components. The rule is intended 

to ensure that important systems, structures, and components will 

maintain their intended functions during the period of extended operation.
Appendix B

B-3

Law/regulation Requirements

10 CFR Part 50 Regulations in 10 CFR Part 50, “Domestic licensing of production and 

utilization facilities,” are NRC regulations issued under the AEA and Title II 

of the Energy Reorganization Act to provide for the licensing of production 

and utilization facilities. This part also gives notice to all persons who 

knowingly provide to any licensee, applicant, contractor, or subcontractor, 

components, equipment, materials, or other goods or services, that relate 

to a licensee’s or applicant’s activities subject to this part, that they may be 

individually subject to NRC enforcement action for violation of 10 

CFR 50.5.

Air quality protection

Clean Air Act (CAA),

42 U.S.C. § 7401 et seq.

The CAA is intended to “protect and enhance the quality of the Nation’s air 

resources so as to promote the public health and welfare and the 

productive capacity of its population.” The CAA establishes requirements

to ensure maintenance of air quality standards and authorizes individual 

states to manage permits. Section 118 of the CAA requires each Federal 

agency, with jurisdiction over properties or facilities engaged in any activity 

that may result in the discharge of air pollutants, to comply with all 

Federal, state, inter-state, and local requirements with regard to the 

control and abatement of air pollution. Section 109 of the CAA directs the 

U.S. Environmental Protection Agency (EPA) to set National Ambient Air 

Quality Standards (NAAQS) for criteria pollutants. The EPA has identified 

and set NAAQS for the following criteria pollutants: particulate matter, 

sulfur dioxide, carbon monoxide, ozone, nitrogen dioxide, and lead. 

Section 111 of the CAA requires establishment of national performance 

standards for new or modified stationary sources of atmospheric 

pollutants. Section 160 of the CAA requires that specific emission 

increases must be evaluated before permit approval to prevent significant 

deterioration of air quality. Section 112 requires specific standards for 

release of hazardous air pollutants (including radionuclides). These 

standards are implemented through plans developed by each state and 

approved by the EPA. The CAA requires sources to meet standards and 

obtain permits to satisfy those standards. Nuclear power plants may be 

required to comply with the CAA Title V, Sections 501–507, for sources 

subject to new source performance standards or sources subject to 

National Emission Standards for Hazardous Air Pollutants. Emissions of 

air pollutants are regulated by the EPA in 40 CFR Parts 50 to 99.

Illinois Administrative Code 

(IAC), Title 35, 

“Environmental Protection,” 

Subtitle B, “Air Pollution,” 

Chapter I, “Pollution Control 

Board,” Subchapter a, 

“Permits and General 

Provisions,” Part 201, 

“Permits and General 

Provisions”

This part of the IAC sets standards for air emissions from auxiliary boilers, 

emergency generators, radwaste volume reduction system, cooling 

towers, and ancillary operations.
Appendix B

B-4

Law/regulation Requirements

Water resources protection

Clean Water Act (CWA), 

33 U.S.C. § 1251 et seq., 

and the NPDES

(40 CFR 122)

The CWA was enacted to “restore and maintain the chemical, physical, 

and biological integrity of the Nation’s waters.” The Act requires each 

Federal agency, with jurisdiction over properties or facilities engaged in 

any activity that may result in the discharge or runoff of pollutants to 

surface waters, to comply with all Federal, state, inter-state, and local 

requirements. As authorized by the CWA, the National Pollutant 

Discharge Elimination System (NPDES) permit program controls water 

pollution by regulating point sources that discharge pollutants into waters 

of the United States. The NPDES program requires all facilities that 

discharge pollutants from any point source into waters of the United States 

to obtain an NPDES permit. A nuclear power plant may also participate in 

the NPDES General Permit for Industrial Stormwater due to stormwater

runoff from industrial or commercial facilities to waters of the United 

States. EPA is authorized under the CWA to directly implement the 

NPDES program; however, EPA has authorized many states to implement 

all or parts of the national program. Section 401 of the CWA requires 

states to certify that the permitted discharge would comply with all 

limitations necessary to meet established state water quality standards, 

treatment standards, or schedule of compliance.

The U.S. Army Corps of Engineers is the lead agency for enforcement of 

CWA wetland requirements (33 CFR Part 320). Under Section 401 of the 

CWA, the EPA or a delegated state agency has the authority to review 

and approve, condition, or deny all permits or licenses that may result in a 

discharge to waters of the State, including wetlands.

Coastal Zone Management 

Act of 1972, as amended

(CZMA), 16 U.S.C. § 1451 

et seq.

Congress enacted the CZMA in 1972 to address the increasing pressures 

of over-development upon the Nation’s coastal resources. The National 

Oceanic and Atmospheric Administration administers the Act. The CZMA 

encourages states to preserve, protect, develop, and, where possible, 

restore or enhance natural coastal resources such as wetlands, 

floodplains, estuaries, beaches, dunes, barrier islands, and coral reefs, as 

well as the fish and wildlife using those habitats. Participation by states is 

voluntary. To encourage states to participate, the CZMA makes Federal 

financial assistance available to any coastal state or territory, including 

those on the Great Lakes, that are willing to develop and implement a 

comprehensive coastal management program.

IAC, Title 35, 

“Environmental Protection,” 

Subtitle C, “Water Pollution,” 

Chapter I, “Pollution Control 

Board,” Part 309, “Permits”

This part of the IAC implements the NPDES program under the CWA.

Wild and Scenic Rivers Act, 

16 U.S.C. § 1271 et seq.

The Wild and Scenic Rivers Act created the National Wild and Scenic 

Rivers System, which was established to protect the environmental values 

of free flowing streams from degradation by impacting activities, including 

water resources projects.

415 Illinois Compiled 

Statutes (ILCS) 5, 

“Environmental Protection 

Act,” Title III, “Water 

Pollution”

This part of the ILCS sets forth Illinois State standards for water pollution.
Appendix B

B-5

Law/regulation Requirements

Waste management and pollution prevention

Resource Conservation and 

Recovery Act (RCRA), 

42 U.S.C. § 6901 et seq.

RCRA requires the EPA to define and identify hazardous waste; establish 

standards for its transportation, treatment, storage, and disposal; and 

require permits for persons engaged in hazardous waste activities. 

Section 3006 (42 U.S.C. 6926) allows states to establish and administer 

these permit programs with EPA approval. EPA regulations implementing 

the RCRA are found in 40 CFR Parts 260 through 283. Regulations 

imposed on a generator or on a treatment, storage, and/or disposal facility 

vary according to the type and quantity of material or waste generated, 

treated, stored, and/or disposed. The method of treatment, storage, 

and/or disposal also impacts the extent and complexity of the 

requirements.

Pollution Prevention Act, 

42 U.S.C. § 13101 et seq.

The Pollution Prevention Act establishes a national policy for waste 

management and pollution control that focuses first on source reduction, 

then on environmental issues, safe recycling, treatment, and disposal.

10 CFR Part 20 Regulations in 10 CFR Part 20, “Standards for protection against 

radiation,” establish standards for protection against ionizing radiation 

resulting from activities conducted under licenses issued by the NRC. 

These regulations are issued under the AEA and the Energy 

Reorganization Act.

The purpose of these regulations is to control the receipt, possession, use, 

transfer, and disposal of licensed material by any licensee in such a 

manner that the total dose to an individual (including doses resulting from 

licensed and unlicensed radioactive material and from radiation sources 

other than background radiation) does not exceed the standards for 

protection against radiation prescribed in the regulations in this part.

IAC Title 35, “Environmental 

Protection,” Subtitle G, 

“Waste Disposal,” Chapter I, 

“Pollution Control Board,” 

Subchapter c, “Hazardous 

Waste Operating 

Requirements,” Part 722, 

“Standards Applicable to 

Generators of Hazardous 

Waste”

This part of the IAC establishes standards for generators of hazardous 

waste.

IAC Title 35, “Environmental 

Protection,” Subtitle C, 

“Water Pollution,” Chapter II, 

“Environmental Protection 

Agency,” Part 391, “Design 

Criteria for Sludge 

Application on Land”

This part of the IAC presents criteria for transporting, storing, and applying 

sludge on land in an environmentally acceptable manner. In addition, it 

identifies methods of sludge transportation, handling, storage, application 

and monitoring to control potential environmental problems.
Appendix B

B-6

Law/regulation Requirements

IAC Title 32, “Energy,” 

Chapter II, “Illinois 

Emergency Management 

Agency,” Subchapter d, 

“Low Level Radioactive 

Waste/Transportation,” 

Part 609, “Access to 

Facilities for Treatment, 

Storage, or Disposal of 

Low-Level Radioactive 

Waste” 

This part of the IAC establishes one of the systems for the regulation of 

the use of facilities in the State of Illinois to: (1) collect, store, treat or 

dispose of low-level radioactive waste; (2) maintain a data base as to the 

location of all such waste in the State of Illinois; and (3) implement some 

of the requirements, prohibitions and mandates of the Compact, the 

Radioactive Waste Compact Enforcement Act (45 ILCS 141), the 

Radioactive Waste Tracking and Permitting Act (420 ILCS 37) and the 

Illinois Low-Level Radioactive Waste Management Act (420 ILCS 20). 

This Part establishes a system for monitoring and tracking shipments of 

low-level radioactive waste into, out of or within the State of Illinois for the 

purpose of tracking the points of origin of the shipments, as transported to 

the places of destination of the shipments. This Part establishes an 

enforcement and verification system directed to the movements of 

low-level radioactive waste into, out of or within the State of Illinois. This 

Part applies to any generator, broker, owner or operator of any treatment 

or disposal facility, or to any person who sends low-level radioactive waste 

into, within or out of the State of Illinois. 

Protected species

Endangered Species Act

(ESA), 16 U.S.C. § 1531 

et seq.

The ESA was enacted to prevent the further decline of endangered and 

threatened species and to restore those species and their critical habitats. 

Section 7 of the Act requires Federal agencies to consult with the U.S. 

Fish and Wildlife Service or the National Marine Fisheries Service (NMFS)

on agency actions that may affect listed species or designated critical 

habitats.

Magnuson–Stevens Fishery 

Conservation and 

Management Act (MSA),

16 U.S.C. § 1801 et seq.

The MSA governs marine fisheries management in U.S. Federal waters. 

The Act created eight regional fishery management councils and includes 

measures to rebuild overfished fisheries, protect essential fish habitat, and 

reduce bycatch. Under Section 305 of the Act, Federal agencies are 

required to consult with NMFS for any agency actions that may adversely 

affect essential fish habitat.

Historic preservation and cultural resources

National Historic 

Preservation Act (NHPA), 

16 U.S.C. § 470 et seq.

The NHPA was enacted to create a national historic preservation program, 

including the National Register of Historic Places and the Advisory Council 

on Historic Preservation. Section 106 of the Act requires Federal 

agencies to take into account the effects of their undertakings on historic 

properties. The Advisory Council on Historic Preservation regulations 

implementing Section 106 of the Act are found in 36 CFR Part 800. The 

regulations call for public involvement in the Section 106 consultation 

process, including Indian Tribes and other interested members of the 

public, as applicable.

B.2 Operating Licenses and Other Permits

Table B–2 lists the licenses and permits issued by Federal, state, and local authorities for 

activities at LSCS.
Appendix B

B-7

Table B–2. Licenses and Permits

Permit Number Dates Responsible Agency

Operating license NPF-11 Issued: 04/17/1982

Expires: 04/17/2022 NRC

Operating license NPF-18 Issued: 12/16/1983

Expires: 12/16/2023 NRC

NPDES permit IL0048151 Issued: 07/05/2013

Expires: 07/31/2018

IEPA, Division of 

Water Pollution Control

Federally enforceable state 

operating permit (FESOP) for 

air emissions from 

emergency generators, 

storage tanks, and 

dispensing facilities

Application 

#75040086

ID# 099802AAA

Issued: 01/07/2016

Expires: 08/12/2025 IEPA, Division of 

Air Pollution Control

Notification of hazardous 

waste activity as a small 

quantity generator of 

hazardous waste

ILD000803643 Not Applicable IEPA, Bureau of Land

Department of Army permit 

for maintenance dredging at 

river screen house intake

CEMVR-OD-P-2015-

1458

Issued: 01/25/2016

Expires: 03/18/2017

U.S. Army Corps of 

Engineers

Waste tracking permit for 

shipments of low-level 

radioactive waste

IL-0104 Not Applicable IEMA, Division of 

Nuclear Safety

License to deliver radioactive 

material to processing facility 

in Tennessee

T-IL009-L14 Renewed annually

Tennessee Department 

of Environment and 

Conservation

Permit to deliver radioactive 

material to disposal facility in 

Utah

010000028 Renewed annually Utah Department of 

Environmental Quality

Dam safety regarding 

operation and maintenance of 

cooling reservoir dam

DS2000237

Issued: 12/20/2000

Expires: Not 

Applicable

Illinois Department of 

Natural Resources, Office 

of Water Resources

Hazardous materials 

certificate of registration 051713 550 083VX Issued: 05/17/2013

Expires: 06/30/2016

U.S. Department of 

Transportation, Pipeline 

and Hazardous Materials 

Safety Administration

Sources: Exelon 2014, 2015
Appendix B

B-8

B.3 References

10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

production and utilization facilities.”

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.”

40 CFR Part 122. Code of Federal Regulations, Title 40, Protection of Environment, Part 122, 

“EPA administered permit programs: the National Pollutant Discharge Elimination System.”

49 CFR Part 107. Code of Federal Regulations, Title 49, Transportation, Part 107, “Hazardous 

materials program procedures.”

49 U.S.C. 5108. United States Code, Title 49, Chapter 51, Part 5108, “Registration.”

[IAC] Illinois Administrative Code Title 32, Chapter II, Subchapter d, Part 609, “Access to 

facilities for treatment, storage, or disposal of low-level radioactive waste.”

[IAC] Illinois Administrative Code Title 35, Subtitle B, Chapter I, Subchapter a, Part 201, 

“Permits and general provisions.”

[IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter I, Part 309, “Permits.”

[IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter II, Part 391, “Design criteria for 

sludge application on land.”

[IAC] Illinois Administrative Code Title 35, Subtitle G, Chapter I, Subchapter c, Part 722, 

“Standards applicable to generators of hazardous waste.”

415 ILCS 5/Tit. II. Illinois Compiled Statutes. Chapter 415, 5, “Environmental Protection Act,” 

Title II, “Air pollution.”

415 ILCS 5/Tit. III. Illinois Compiled Statutes. Chapter 415, 5, “Environmental Protection Act,” 

Title III, “Water pollution.”

[AEA] Atomic Energy Act of 1954, as amended. 42 U.S.C. § 2011 et seq.

[CAA] Clean Air Act of 1963, as amended. 42 U.S.C. § 7401 et seq.

[CWA] Clean Water Act of 1977, as amended. 33 U.S.C. § 1251 et seq.

[ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. § 1531 et seq.

[Exelon] Exelon Generation Company, LLC. 2014. LaSalle County Station, Units 1 and 2 

License Renewal Application, Applicant’s Environmental Report. December 9, 2014. 

Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 

ML14343A897.

[Exelon] Exelon Generation Company, LLC. 2015. E-mail from N. Ranek, Exelon, to 

D. Drucker, NRC. Subject: RE: USACE permit. December 10, 2015. ADAMS 

No. ML15363A237.

[FWCA] Fish and Wildlife Coordination Act of 1934, as amended. 16 U.S.C. § 661 et seq.

[IEMA] Illinois Emergency Management Agency, Division of Nuclear Safety. Undated. 

Available at <http://www.illinois.gov/iema/Pages/default.aspx> (accessed 3 September 2015).
Appendix B

B-9

[IEPA] Illinois Environmental Protection Agency, Bureau of Water. Undated. “Water Pollution 

Control.” Available at <http://www.epa.state.il.us/water/index-wpc.html> (accessed 

September 3, 2015). 

[MMPA] Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. § 1361 et seq.

[MSA] Magnuson–Stevens Fishery Conservation and Management Act, as amended. 

16 U.S.C. § 1801 et seq.

[NHPA] National Historic Preservation Act of 1966, as amended. 16 U.S.C. § 470 et seq.

Pollution Prevention Act of 1990. 42 U.S.C. § 13101 et seq.

[RCRA] Resource Conservation and Recovery Act of 1976, as amended. 

42 U.S.C. § 6901 et seq.

Wild and Scenic Rivers Act, as amended. 16 U.S.C. § 1271 et seq.

CONSULTATION CORRESPONDENCE 

C-1

C. Consultation Correspondence

C.1 Endangered Species Act (ESA) Section 7 Consultation

C.1.1 Federal Agency Obligations Under ESA Section 7

As a Federal agency, the U.S. Nuclear Regulatory Commission (NRC) must comply with the 

Endangered Species Act of 1973, as amended (16 United States Code (U.S.C.) 1531 et seq., 

herein referred to as ESA), as part of any action authorized, funded, or carried out by the 

agency, such as the proposed agency action that this supplemental environmental impact 

statement (SEIS) evaluates—whether to issue renewed licenses for the continued operation of 

LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years beyond the current 

license terms. Under section 7 of the ESA, the NRC must consult with the U.S. Fish and 

Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) (referred to jointly as 

“the Services” and individually as “Service”), as appropriate, to ensure that the proposed agency 

action is not likely to jeopardize the continued existence of any endangered or threatened 

species or result in the destruction or adverse modification of designated critical habitat.

The ESA and the regulations that implement ESA section 7 (Title 50 of the Code of Federal 

Regulations (50 CFR) Part 402, “Interagency cooperation—Endangered Species Act of 1973, 

as amended”) describe the consultation process that Federal agencies must follow in support of 

agency actions. As part of this process, the Federal agency shall either request that the 

Services provide a list of any listed or proposed species or designated or proposed critical 

habitats that may be present in the action area or request that the Services concur with a list of 

species and critical habitats that the Federal agency has created (50 CFR 402.12(c)). If it is 

determined that any such species or critical habitats may be present, the Federal agency is to 

prepare a biological assessment to evaluate the potential effects of the action and determine 

whether the species or critical habitat are likely to be adversely affected by the action 

(16 U.S.C. 1536(c), 50 CFR 402.12(a)). Further, biological assessments are required for any 

agency action that is a “major construction activity” (50 CFR 402.12(b)), which the ESA 

regulations define to include major Federal actions significantly affecting the quality of the 

human environment under the National Environmental Policy Act of 1969, as amended 

(42 U.S.C. 4321 et seq., herein referred to as NEPA) (50 CFR 402.02).

Federal agencies may fulfill their obligations to consult with the Services under ESA section 7 

and to prepare a biological assessment in conjunction with the interagency cooperation 

procedures required by other statutes, including NEPA (50 CFR 402.06(a)). In such cases, the 

Federal agency should include the results of the ESA section 7 consultation in the NEPA 

document (50 CFR 402.06(b)). Accordingly, Section C.1.2 describes the biological assessment 

prepared for the proposed agency action evaluated in this SEIS, and Section C.1.3 describes

the chronology and results of the ESA section 7 consultation.

C.1.2 Biological Assessment

The NRC considers this SEIS to fulfill its obligation to prepare a biological assessment under 

ESA section 7. Accordingly, the NRC did not prepare a separate biological assessment for the 

proposed LSCS license renewal.

Although the contents of a biological assessment are at the discretion of the Federal agency 

(50 CFR 402.12(f)), the ESA regulations suggest information that agencies may consider for 

inclusion. The NRC has considered this information in the following sections.
Appendix C

C-2

Section 3.8 describes the action area and the Federally listed and proposed species and 

designated and proposed critical habitat that have the potential to be present in the action area. 

This section includes information pursuant to 50 CFR 402.12(f)(1), (2), and (3).

Section 4.8 provides an assessment of the potential effects of the proposed LSCS license 

renewal on the species and critical habitat present and the NRC’s effect determinations, which 

are consistent with those identified in Section 3.5 of the Endangered Species Consultation 

Handbook (FWS and NMFS 1998). The NRC also addresses alternatives to the proposed 

action. This section includes information pursuant to 50 CFR 402.12(f)(4) and (5).

C.1.3 Chronology of ESA Section 7 Consultation

Upon receipt of Exelon’s license renewal application, the NRC staff considered whether any 

Federally listed or proposed species or designated or proposed critical habitats may be present 

in the action area (as defined at 50 CFR 402.02) for the proposed LSCS license renewal. No 

species under the NMFS’s jurisdiction occur within the action area. Therefore, the NRC staff did 

not consult with the NMFS. With respect to species under the FWS’s jurisdiction, in late 

February 2015, NRC staff filled an online form for an updated protected species list for LSCS on 

the FWS’s Environmental Conservation Online System (ECOS), Information for Planning and 

Conservation (IPaC). FWS (2015b) responded with a list of threatened and endangered 

species that may occur in the project location and may be affected by the Federal action. In 

October 2015, NRC staff checked the FWS (2015a) online Illinois County distribution of listed 

species for updates. From this, the NRC staff compiled a list of ESA-protected species and 

critical habitats in the vicinity of the facility. 

In Section 3.8, the NRC staff concludes that no ESA-protected species or critical habitats occur 

in the action area, and, in Section 4.8, concludes that the proposed action would have no effect 

on any ESA-protected species or critical habitats. The FWS (2013) does not typically provide its 

concurrence with “no effect” determinations by Federal agencies. Thus, the ESA does not 

require further informal consultation or the initiation of formal consultation with the FWS for the 

proposed LSCS license renewal. Nonetheless, because this SEIS constitutes the NRC’s 

biological assessment, the NRC staff submitted a copy of the draft SEIS to the FWS for its 

review in accordance with 50 CFR 402.12(j).

Table C–1 lists the correspondence related to the NRC’s ESA obligations with respect to its 

review of the LSCS license renewal application.

Table C–1. ESA Section 7 Consultation Correspondence

Date

Sender and 

Recipient Description ADAMS No.(a)

February 27, 2015 FWS to NRC List of threatened and endangered species that 

may occur in your proposed project location, 

and/or may be affected by your proposed 

project

ML15126A069

March 3, 2015 NRC to FWS Request for scoping comments/notification of 

scoping meetings

ML15062A534

(a) These documents can be accessed through the NRC’s Agencywide Documents Access and Management 

System (ADAMS) at http://adams.nrc.gov/wba/.
Appendix C

C-3

C.2 Essential Fish Habitat Consultation

The NRC must comply with the Magnuson–Stevens Fishery Conservation and Management 

Act, as amended (16 U.S.C. § 1801 et seq., herein referred to as MSA), for any actions 

authorized, funded, or undertaken, or proposed to be authorized, funded, or undertaken that 

may adversely affect any essential fish habitat (EFH) identified under the MSA.

In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that the NMFS has not designated 

EFH under the MSA in the Illinois River and that the proposed LSCS license renewal would 

have no effect on EFH. Thus, the MSA does not require the NRC to consult with the NMFS for 

the proposed LSCS license renewal.

C.3 National Historic Preservation Act of 1966 Consultation

The National Historic Preservation Act of 1966, as amended (NHPA), requires Federal agencies 

to consider the effects of their undertakings on historic properties and consult with applicable 

state and Federal agencies, tribal groups, and individuals and organizations with a 

demonstrated interest in the undertaking before taking action. Historic properties are defined as 

resources that are eligible for listing on the National Register of Historic Places. The historic 

preservation review process (Section 106 of the NHPA) is outlined in regulations issued by the 

Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800. In accordance with 36 

CFR 800.8(c), the NRC has elected to use the NEPA process to comply with its obligations 

under Section 106 of the NHPA.

Table C–2 lists the chronology of consultations and consultation documents related to the NRC 

Section 106 review. The NRC staff is required to consult with the noted agencies and 

organizations in accordance with the statutes listed above.

Table C–2. NHPA Correspondence

Date Sender and Recipient Description ADAMS No.(a)

February 9, 2015 D. Wrona (NRC) to R. Nelson 

(ACHP)

Request for scoping

comments/notification of 

Section 106 review

ML15023A094

February 9, 2015 D. Wrona (NRC) to A. Haaker, Illinois 

Historic Preservation Agency

Request for scoping

comments/notification of 

Section 106 review

ML15022A578

February 9, 2015 D. Wrona (NRC) to J. Greendeer, 

Ho-Chunk Nation

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to S. Cadue, 

Kickapoo Tribe of Indians of the 

Kickapoo Reservation in Kansas

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to G. Salazar, 

Kickapoo Tribe of Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to D. Lankford, 

Miami Tribe of Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to J. Froman, 

Peoria Tribe of Indians of Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML15023A139
Appendix C

C-4

Date Sender and Recipient Description ADAMS No.(a)

February 9, 2015 D. Wrona (NRC) to J. Barrett, Citizen 

Potawatomi Nation

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to J. Bender, Sac 

and Fox Tribe of the Mississippi in 

Iowa/Meskwaki

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to B. Robidoux, Sac 

and Fox Nation of Missouri in 

Kansas and Nebraska

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to G. Thurman, Sac 

and Fox Nation

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to J. Warren, 

Pokagon Band of Potawatomi

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to H. Frank, Forest 

County Potawatomi

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to K. Meshigaud, 

Hannahville Indian Community

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to S. Ortiz, Prairie 

Band of Potawatomi Nation

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

February 9, 2015 D. Wrona (NRC) to J. Blackhawk, 

Winnebago Tribe of Nebraska

Request for scoping

comments/notification of 

Section 106 review

ML15023A139

April 1, 2015 R Leibowitz, Illinois Historic 

Preservation Agency to D. Wrona 

(NRC)

Illinois Historic Preservation 

Agency Section 106 

Clearance (IHPA Log 

#009031615)

ML15106A791

August 6, 2015 R. Chazell (NRC) to File Summary of visit to Illinois 

Historic Preservation 

Agency associated with the 

LaSalle County Station,

Units 1 and 2, License 

Renewal Application 

Environmental Audit

ML15205A286

August 6, 2015 R. Leibowitz, Illinois Historic 

Preservation Agency to C. Bladey 

(NRC)

No historic properties are 

affected. The proposed 

action complies with section 

106 of National Historic 

Preservation Act of 1966.

ML16082A274

(a) These documents can be accessed through the NRC’s ADAMS at http://adams.nrc.gov/wba/.
Appendix C

C-5

C.4 References

36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

Part 800, “Protection of historic properties.”

50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

“Interagency cooperation—Endangered Species Act of 1973, as amended.”

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

[FWS] U.S. Fish and Wildlife Service. 2013. “Endangered Species Program: What We Do: 

Consultations: Frequently Asked Questions.” July 15, 2013. Available at 

<http://www.fws.gov/endangered/what-we-do/faq.html#8> (accessed 5 June 2014).

[FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 

Endangered, Threatened, and Candidate Species. Midwest Region. Updated 

September 30, 2015. Accessed October 9, 2015. Available at 

<http://www.fws.gov/midwest/endangered/lists/illinois-cty.html>

[FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC. Subject: LaSalle 

Power Plant License Renewal. List of threatened and endangered species that may occur in 

your proposed project location, and/or may be affected by your proposed project. 

February 27, 2015. ADAMS No. ML15126A069.

[FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 

Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 

Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 

Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf> 

(accessed 8 July 2013).

Magnuson–Stevens Fishery Conservation and Management Act, as amended. 

16 U.S.C. § 1801 et seq.

National Environmental Policy Act of 1969, as amended. 42 U.S.C. § 4321 et seq.

National Historic Preservation Act of 1966, as amended. 54 U.S.C. § 300101 et seq.

CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE

D-1

D. 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 license renewal 

application (LRA) environmental review for LaSalle County Station, Units 1 and 2 (LSCS) other 

than consultation correspondence and comments received during the scoping process. 

Consultation correspondence is listed and discussed in Appendix C of this supplemental 

environmental impact statement (SEIS). Scoping comments are provided and addressed in 

Appendix A of this SEIS and in the Scoping Summary Report (see Table D–1 below). All 

documents 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 Documents Access and Management 

System (ADAMS), which provides text and image files of the NRC’s public documents in 

ADAMS. The ADAMS accession number for each document is included in the following table.

D.1 Environmental Review Correspondence

Table D–1 lists the environmental review correspondence, by date, beginning with the request 

by Exelon Generation Company, LLC (Exelon) to renew the operating licenses for LSCS.

Table D–1. Environmental Review Correspondence

Date Correspondence Description ADAMS No.

December 9, 2014 Transmittal of LSCS LRA from Exelon to NRC ML14343A840

December 11, 2014 Receipt and availability of LSCS LRA ML14337A267

December 29, 2014 Letter from Illinois Environmental Protection Agency to NRC 

regarding LSCS Clean Water Act Section 401 Certification

ML15022A325

January 26, 2015 Determination of acceptability and sufficiency for docketing, 

proposed review schedule, and opportunity for a hearing 

regarding the application, for renewal of the operating 

licenses for LSCS

ML15021A451

January 27, 2015 Notice of intent to prepare an environmental impact 

statement and conduct scoping for LSCS license renewal

ML15005A480

March 10, 2015 Transcript from afternoon public scoping meeting ML15083A538

March 10, 2015 Transcript from evening public scoping meeting ML15089A580

March 31, 2015 Transmittal of severe accident mitigation alterative (SAMA)

audit plan from NRC to Exelon

ML15083A546

April 24, 2015 SAMA audit summary ML15106A812

April 28, 2015 Transmittal of environmental audit plan from NRC to Exelon ML15106A392

April 30, 2015 Transmittal of SAMA requests for additional information 

(RAIs) from NRC to Exelon

ML15114A320

May 20, 2015 Environmental audit summary ML15132A674

May 22, 2015 Transmittal of environmental RAIs from NRC to Exelon ML15142A764

May 29, 2015 Exelon response to SAMA RAIs ML15149A370

June 25, 2015 Summary of teleconference between NRC and Exelon

regarding transportation impacts for LSCS high burnup fuel

ML15167A486
Appendix D

D-2

Date Correspondence Description ADAMS No.

June 25, 2015 Transmittal of RAIs regarding transportation impacts for 

LSCS high burnup fuel from NRC to Exelon

ML15167A488

July 2, 2015 Exelon response to environmental RAIs ML15195A351

July 8, 2015 Scoping Summary Report ML15147A380

July 24, 2015 Exelon response to RAIs regarding transportation impacts for 

LSCS high burnup fuel

ML15205A003

July 31, 2015 Exelon transmittal of revisions to the License Renewal 

Application Environmental Report

ML15212A259

August 28, 2015 Revised response to RAIs regarding transportation impacts 

for LSCS high burnup fuel

ML15240A002

September 21, 2015 Resubmittal of Index Item # 058 (“ER References to be 

Docketed”) from Exelon

ML15273A423
ACTIONS AND PROJECTS CONSIDERED IN THE CUMULATIVE 

IMPACTS ANALYSIS

E-1

E. Projects and Actions Considered in the Cumulative Impacts

Analysis

Table E–1 identifies actions and projects considered in the U.S. Nuclear Regulatory

Commission (NRC) staff’s analysis of cumulative impacts related to the environmental analysis

of the continued operation of LaSalle County Station, Units 1 and 2 (LSCS). Potential

cumulative impacts associated with these actions and projects are addressed in Section 4.16 

of this Supplemental Environmental Impact Statement. However, not all actions or projects

listed in this appendix are considered in each resource area because of the uniqueness of the

resource and its geographic area of consideration.

Table E–1. Projects and Actions Considered in Cumulative Impact Analysis

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Nuclear Projects

Clinton Power Station, 

Unit 1

Nuclear power plant, 

one 1,067-MWe 

General Electric Type 6 

reactor

DeWitt County, IL, 

approximately 

75 mi (121 km) 

south. 50-mi 

(80 km) radius

overlaps with that 

of LSCS

Operational 

(NRC 2015a)

Byron Station, Units 1 

and 2

Nuclear power plant, 

two 1,121-MWe 

Westinghouse 4-loop 

reactors

Ogle County, IL, 

approximately 

65 mi (105 km) 

north-northwest. 

50-mi (80 km) 

radius overlaps 

with that of LSCS

Operational (NRC 2015b, 

2015c)

Braidwood Station, 

Units 1 and 2

Nuclear power plant, 

two 1,121-MWe 

Westinghouse 4-loop 

reactors

Will County, IL, 

approximately 

23 mi (37 km) 

east

Operational (NRC 2015d, 

2015e)

Dresden Nuclear 

Power Station, Units 2 

and 3

Nuclear power plant, 

two 867-MWe 

General Electric Type 3 

reactors

Grundy County, 

IL, approximately 

23 mi (37 km) 

east-northeast

Operational (NRC 2015f, 

2015g)

Dresden Nuclear 

Power Station, Unit 1

Nuclear power plant

(undergoing 

decommissioning)

Grundy County, 

IL, approximately 

23 mi (37 km) 

east-northeast

Shut down in 

October 1978 and is 

currently in SAFSTOR. 

No dismantlement 

activities are under way. 

All spent fuel from DNPS 

Unit 1 transferred to the 

onsite Independent 

Spent Fuel Storage 

Installation (NRC 2015h)
Appendix E

E-2

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Quad Cities Nuclear

Power

Station, Units 1 and 2

Nuclear power plant,

two 867-MWe

General Electric Type 3

reactors

Rock Island

County, IL,

approximately 

91 mi (146 km) 

west-northwest. 

50 mi (80 km)

radius overlaps

with that of LSCS

Operational

(NRC 2015i, 2015j)

Renewable Energy Projects

Grand Ridge Wind 

Farm

140-unit wind farm with 

210 MW generating capacity

and 34 MW energy storage 

support facility

Immediately west 

of LSCS property 

and extending 

southwest 

approximately

8 mi (13 km)

Operational 

(Invenergy 2015a, 

2015b, 2015c, 2015d; 

Windpower 2015a, 

2015b, 2015c, 2015d)

Top Crop Wind Farm 200-unit wind farm with 

300 MW generating capacity

Grundy, LaSalle 

and Livingston 

Counties, IL, 

approximately 

6 mi (10km) 

south-southeast

Operational (EIA 2015a, 

2015b; 

Windpower 2015e, 

2015f; 

EDP Renewables 2015)

Grand Ridge Solar

Farm

Solar photovoltaic facility 

with 20 MW generating 

capacity

Streator, IL, 

approximately 

8 mi (13 km) 

southwest

Operational 

(EIA 2015c, 

Invenergy 2015e)

Minonk Wind Farm 100-unit wind farm with 

192 MW generating 

capacity

Woodford and 

Livingston 

Counties, IL, 

approximately 

27 mi (43 km) 

southwest

Operational (EIA 2015d, 

Mortenson 2015)

Streator-Cayuga 

Ridge Wind Farm

150-unit wind farm with 

300 MW generating 

capacity

Livingston County, 

IL, approximately 

18 mi (29 km) 

southeast

Operational (EIA 2015e, 

Windpower 2015g)

Starved Rock Power 

Station

Hydroelectric dam with 

6.8 MW generating 

capacity

On Illinois River, 

approximately 

17 mi (28 km) 

west-northwest 

Operational (EIA 2015f)

Midwest Hydro LLC Hydroelectric dam with 

3.6 MW generating 

capacity

On Fox River, 

approximately 

12 mi (19 km) 

northwest

Operational (EIA 2015g)

Morris Genco LLC Waste-to-energy 

biomass-fueled facility 

with 2 MW generating 

capacity

Grundy County, 

IL, approximately 

17 mi (27 km) 

northwest

Operational (EIA 2015h)
Appendix E

E-3

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Prairie View 

Renewable Energy

Waste-to-energy 

biomass-fueled facility 

with 4.8 MW generating 

capacity

Will County, IL, 

approximately 

30 mi (49 km) 

east-northeast

Operational (EIA 2015i)

Fossil Fuel Projects

Peru City Power Plant Petroleum-fueled plant with 

27.5 MW generating 

capacity

Peru, IL, 

approximately 

24 mi (38 km) 

north

Operational (EIA 2015g)

Oglesby Gas Plant Natural gas-fueled plant with 

54 MW generating capacity

Oglesby, IL, 

approximately 

21 mi (34 km) 

west-northwest

Operational (EIA 2015j)

Morris Cogeneration 

LLC

Natural gas-fueled plant with 

176 MW generating capacity

Morris IL, 

approximately 

21 mi (34 km) 

northwest

Operational (EIA 2015k)

Kendall County 

Generation

Natural gas-fueled plant with 

1,140 MW generating 

capacity

Kendall County,

IL, approximately 

27 mi (43 km) 

northeast

Operational (EIA 2015l)

Manufacturing Facilities

Agrium Inc. Fertilizer solution 

storage facility 

Marseilles, IL 

approximately 

5 mi (8 km) north

Operational 

(Agrium 2015, 

EPA 2015a)

Glen-Gery Marseilles 

Plant

Brick manufacturer Marseilles, IL 

approximately 

5 mi (8 km) north

Operational 

(EPA 2015a, 

Glen-Gery 2015)

Independence Tube 

Corporation

Structural steel tubing 

manufacturer

Marseilles, IL 

approximately 

5 mi (8 km) north

Operational 

(EPA 2015a, 

Independence 2015)

PotashCorp - PCS 

Phosphate Marseilles 

Operation

Phophate animal feed 

production

Marseilles, IL 

approximately 

5 mi (8 km) north

Operational 

(EPA 2015a, 

PotashCorp 2015)

SABIC Innovative 

Plastics

Plastic fabrication Ottawa IL, 

approximately 

7.5 mi (12 km) 

northwest

Operational 

(EPA 2015a, 

SABIC 2015)

CF Industries Seneca 

Ammonia Terminal

Fertilizer distribution terminal Seneca, IL 

approximately 

5 mi (8 km) 

northeast

Operational 

(CFIndustries 2015,

EPA 2015a)

H.B. Fuller Industrial adhesive, coating, 

and sealant manufacturer

Morris, IL 

approximately 

7 mi (11 km) 

northeast

Operational 

(EPA 2015a, 

H.B. Fuller 2015)
Appendix E

E-4

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Landfills

LandComp Landfill 188 ac (76 ha) municipal 

solid waste landfill

Ottawa, IL, 

approximately 

14 mi (2 km) 

northwest

Operational until 2034 

(IEPA 2013, 2015)

Environtech, Inc. 169 ac (68 ha) municipal 

solid waste landfill

Morris, IL, 

approximately 

17 mi (27 km) 

northeast

Expected to close 2015

(IEPA 2013, 2015)

Livingston Landfill 550 ac (223 ha) municipal 

solid waste landfill

Livingston, IL, 

approximately 

22 mi (35 km) 

south

Operational until 2037

(IEPA 2013, 2015)

Prairie View Recycling 

and Disposal Facility

408 ac (165 ha) municipal 

solid waste landfill

Wilmington, IL, 

approximately 

30 mi (48 km) 

northeast within 

former Joliet Army 

Ammunition Plant

Operational until 2040, 

(IEPA 2013, 2015)

Water Supply and Treatment Facilities

City of Marseilles, 

water supply

Withdraws groundwater

obtained from wells in the 

Cambrian-Ordovician 

Aquifer.

Approximately 

6 mi (10 km) 

north-northwest

Operational (EPA 2015b, 

Exelon 2014)

City of Seneca, water 

supply

Withdraws groundwater

obtained from wells in the 

Cambrian-Ordovician 

Aquifer.

Approximately 

6 mi (10 km) 

north-northeast

Operational (EPA 2015b, 

Exelon 2014)

Village of Grand 

Ridge, water supply

Withdraws groundwater

obtained from wells in the 

Buried Bedrock Valleys 

Aquifer.

Approximately 

8.5 mi (13.5 km) 

east

Operational (EPA 2015a, 

Exelon 2014)

City of Marseilles, 

wastewater treatment

Water treatment with 

discharge to the Illinois River

Approximately 

6 mi (10 km) 

north-northwest

Operational (EPA 2015a)

Various minor NPDES

wastewater

discharges

Various businesses with 

smaller wastewater

discharges

Within 50 mi 

(80 km)

Operational (EPA 2015a)

Mining Projects

U.S. Silica Sandstone mine and silica 

production facility

Ottawa, IL, 

approximately 

12 mi (19.5 km) 

northwest

Operational (EPA 2015a, 

U.S. Silica 2015)

Unimin Corporation Sandstone mine and silica 

production facility

Utica, IL, 

approximately 

18.5 mi (30 km) 

northwest

Operational (EPA 2015a, 

Unimin 2015)
Appendix E

E-5

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Northern White Sand 

LLC

Sandstone mine and silica 

production facility that is 

proposing 350 ac (142 ha) 

expansion.

Utica, IL, 

approximately 

16.5 mi (26.5 km) 

northwest

Operational 

Proposed expansion is 

pending before the 

LaSalle County Board 

(EPA 2015a, 

NewsTribune 2014)

Mississippi Sand LLC Proposed 314 ac (127 ha) 

sandstone mine near 

eastern entrance to Starved 

Rock State Park

Ottawa, IL, 

approximately 

17 mi (27 km) 

north-northwest, 

near eastern 

entrance to 

Starved Rock 

State Park

On hold pending legal 

challenges 

(NewsTribune 2014)

Remediation Site

Joliet Army 

Ammunition Plant

14-sq mi (36-sq. km) military 

complex operated from early 

1940s through 1977 to 

manufacture, load, 

assemble, and package 

high-explosive artillery 

shells, bombs, mines, and 

small-arms ammunition. 

Other activities on site 

included testing of 

ammunition, washout and 

renovation of shells, and 

burning and demolition of 

explosives.

Joliet, IL, 

approximately 

28 mi (45 km) 

northeast

Ongoing remediation 

under the purview of the 

U.S. Army. Land use 

controls are restricting 

land uses; portions are 

now under productive 

reuse by the U.S. Forest 

Service (Midewin 

National Tallgrass 

Prairie), the Veteran’s 

Administration (Abraham 

Lincoln National 

Cemetery), Will County 

(500-ac [202-ha] landfill), 

and productive uses 

through commercial and 

industrial redevelopment 

(EPA 2013).

Parks and Recreation Sites

LaSalle Lake State 

Fish and Wildlife Area

2,058 ac (833 ha) lake that 

serves as the cooling lake 

for LaSalle County Station. 

Managed for public boating 

and fishing.

Onsite Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015a)

Marseilles State Fish 

and Wildlife Area

2,550 ac (1,032 ha) tract that 

serves as joint-use area for 

the Illinois Department of 

Natural Resources (as a 

hunting and habitat 

management site) and the 

Illinois National Guard (for 

live-fire training when 

hunting seasons are closed). 

Approximately 

1.5 mi (2.4 km) 

north

Operational. 

Cooperatively managed 

by Illinois Department of 

Natural Resources and 

Illinois Department of 

Military Affairs through 

Memorandum of 

Agreement 

(IDNR 2015b, 

ING undated)
Appendix E

E-6

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Illini State Park 510 ac (206 ha) park along 

the south bank of the Illinois 

River. Hiking, fishing, 

boating and camping occur 

within the park.

Approximately 

6 mi (10 km) 

north-northwest

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015c)

Buffalo Rock State 

Park

298 ac (121 ha) park along 

the north bank of the Illinois 

River. Hiking, fishing, and 

camping occur within the 

park.

Approximately 

13.5 mi (22 km) 

northwest

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015d)

Gebhard Woods 

State Park

30 ac (12 ha) park along the 

north bank of the Illinois 

River. Hiking, fishing, 

boating and camping occur 

within the park.

Approximately 

14 mi (23 km) 

northeast

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015e)

Starved Rock State 

Park

2,700 ac (1,093 ha) park 

containing sandstone buttes, 

18 canyons, waterfalls, and 

13 mi (21 km) of hiking trails. 

Camping, fishing, boating 

and hunting also occur within 

the park.

On Illinois River, 

approximately 

15 mi (24 km) 

northwest

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015f)

Matthiessen State 

Park

1,938 ac (784 ha) park 

containing forested canyons, 

rock formations and water 

falls. Hiking, camping, 

biking, and horseback riding 

occur within the park.

18 mi (29 km) 

west

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015g)

Goose Lake Prairie 

State Natural Area

2,537 ac (1,026 ha) area 

representing largest remnant 

of prairie in Illinois. Used for 

hiking, picnicking, crosscountry skiing and hunting

Approximately 

20 mi (31 km) 

north-northeast. 

Adjacent to 

Heidecke Lake 

State Fish and 

Wildlife Area

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015h)

Heidecke Lake State 

Fish and Wildlife Area

1,300 ac (526 ha) lake 

managed for public fishing 

and hunting. Originally 

constructed in 1978 as the 

cooling lake for the former 

Collins Generating Station 

Approximately 

20 mi (31 km) 

north-northeast. 

Adjacent to Goose 

Lake Prairie State 

Natural Area

Operational. Managed 

by Illinois Department of 

Natural Resources

(IDNR 2015i)

Recreational Areas Various parks, boat 

launches, and campgrounds 

Within 10 mi 

(16 km)

Operational
Appendix E

E-7

Project Name Summary of Project

Location

(Relative 

to LSCS) Status

Other Projects

Future Urbanization Construction of housing units 

and associated commercial 

buildings; roads, bridges, 

and rail; water and/or 

wastewater treatment and 

distribution facilities; and 

associated pipelines as 

described in local land-use 

planning documents

Throughout region Construction would occur 

in the future, as 

described in State and 

local land-use planning 

documents.

Key: ac = acres; ha = hectares; km = kilometers; mi = miles; NPDES = National Pollutant 

Discharge Elimination System; sq. = square

E.2 References

Agrium. 2015. “Marseilles Solution Storage.” Available at <http://www.agrium.com/en/whatwe-do/locations> (accessed 8 September 2015).

CFIndustries. 2015. “Seneca Ammonia Terminal.” Available at 

<http://www.cfindustries.com/distribution_seneca-terminal.html> (accessed 18 August 2015).

EDP Renewables. 2015. “Illinois/Top Crop Factsheet.” Available at <http://topcrop.edprwindfarms.com/wp-content/uploads/sites/14/2014/03/Top-Crop_Fact-Sheet_6.25.15.pdf> 

(accessed 7 August 2015).

[EIA] U.S. Energy Information Administration. 2015a. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Blackstone [Top Crop] Wind Farm LLC.” 

Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015).

[EIA] U.S. Energy Information Administration. 2015b. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Blackstone II [Top Cropn II] Wind Farm LLC.” 

Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015).

[EIA] U.S. Energy Information Administration. 2 015c. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Grand Ridge Solar Farm.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).

[EIA] U.S. Energy Information Administration. 2015d. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Minonk Wind Farm.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).

[EIA] U.S. Energy Information Administration. 2015e. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Streator Cayuga Ridge South.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015).

[EIA] U.S. Energy Information Administration. 2015f. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Peru Hydro.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).

[EIA] U.S. Energy Information Administration. 2015g. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Dayton Hydro.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).
Appendix E

E-8

[EIA] U.S. Energy Information Administration. 2015h. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Morris Genco LLC.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015).

[EIA] U.S. Energy Information Administration. 2015i. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Prairie View.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 17 August 2015).

[EIA] U.S. Energy Information Administration. 2015j. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Oglesby.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).

[EIA] U.S. Energy Information Administration. 2015k. “Illinois State Profile and Energy 

Estimates, Profile Overview Interactive Map – Morris Cogeneration LLC.” Available at 

<http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).

[EIA] U.S. Energy Information Administration. 2015l. “Illinois State Profile and Energy 

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Appendix E

E-10

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Appendix E

E-11

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U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR LASALLE 

COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE 

RENEWAL APPLICATION REVIEW

F-1

F. U.S. Nuclear Regulatory Commission Staff Evaluation of Severe 

Accident Mitigation Alternatives for LASALLE COUNTY STATION, 

UNITS 1 AND 2, in Support of License Renewal Application 

Review

F.1 Introduction

Exelon Generation Company, LLC (Exelon) submitted a license renewal application for LaSalle 

County Station (LSCS), Units 1 and 2. Exelon assessed severe accident mitigation alternatives

(SAMAs) for LSCS in Appendix F of its Environmental Report (ER) (Exelon 2014a). This 

assessment was based on the most recent LSCS probabilistic risk assessment (PRA) available 

at that time, a plant-specific offsite consequence analysis performed using the MELCOR 

Accident Consequence Code System (MACCS2) Version 1.13.1 computer code, and insights 

from the LSCS individual plant examination (IPE) and individual plant examination of external 

events (IPEEE). In identifying and evaluating potential SAMAs, Exelon considered SAMAs that 

addressed the major contributors to core damage frequency (CDF) and release frequency at 

LSCS, as well as SAMA candidates from six other boiling water reactor (BWR) plants. Exelon 

initially identified 26 potential SAMAs. Then, Exelon reduced the list to 25 unique SAMA 

candidates by eliminating SAMAs that are not applicable to LSCS, that have already been 

implemented at LSCS, or that have excessive implementation costs. Next, Exelon assessed 

the costs and benefits associated with each of the 25 potential SAMAs and concluded that 

14 SAMA candidates were potentially cost beneficial at the 95th percentile. Exelon performed 

sensitivity analyses on the real discount rate, CDF uncertainty at the 95th percentile, as well as 

the offsite consequence parameters, and considered those results in the cost-benefit analysis. 

As an additional sensitivity analysis in the ER, Exelon considered the planned installation of a 

hardened vent pipe as the base case to provide supplemental information on potentially 

cost-beneficial SAMAs following the vent pipe installation. 

Based on a review of Exelon’s SAMA assessment and the SAMA audit held on April 7‒8, 2015, 

the U.S. Nuclear Regulatory Commission (NRC) staff issued requests for additional information 

(RAIs) to Exelon by letter dated April 30, 2015 (NRC 2015). Key questions concerned the 

differences between LSCS Units 1 and 2, systems shared between the two units and how these 

are modeled in the PRA; the definition and assignment of accident classes; additional details on 

the Level 2 and Level 3 PRA models, including the basis for representative sequences for each 

release category; the determination of the frequency of the intact release category; the 

identification and screening of candidate SAMAs; the potential for additional SAMAs to mitigate 

fire risk; the evaluation of the risk reduction of certain SAMAs; and the basis for the SAMA cost 

estimates. By letter dated May 29, 2015, Exelon submitted additional information that included 

revisions and a correction, which changed the determination of one SAMA from potentially cost

beneficial in the ER to not cost beneficial (Exelon 2015). Exelon’s responses addressed the 

NRC staff’s concerns.

The evaluation of the LSCS SAMA analysis is presented below.

F.2 Estimate of Risk for LSCS

Exelon’s estimates of offsite risk at LSCS are summarized in Section F.2.1. The summary is 

followed by the NRC staff’s review of Exelon’s risk estimates in Section F.2.2.
Appendix F

F-2

F.2.1 Exelon’s Risk Estimates

Exelon combined two distinct analyses to form the basis for risk estimates used in the SAMA

analysis: (1) the LSCS Level 1 and Level 2 PRA models and (2) a supplemental analysis of 

offsite consequences and economic impacts (essentially a Level 3 PRA model) developed 

specifically for the SAMA analysis. The Level 1 model is a significant upgrade and revision of 

the IPE Level 1 model, while the Level 2 model is an update of the prior large early release 

frequency (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 

and Level 2 PRA models available at the time of the ER, referred to as the LSCS PRA 2013A 

(or LS213A) model. This LSCS PRA includes internal flooding but does not include external 

events.

The LSCS CDF is approximately 2.6×10−6 per year (Exelon 2014a). Exelon did not explicitly 

include the contribution from external events within the LSCS SAMA risk estimates; however, it 

did account for the potential risk reduction benefits associated with external events by 

multiplying the estimated benefits for internal events by 5.2. This is discussed further in 

Section F.2.2.2.

The breakdown of CDF by initiating event is provided in Table F–1. As shown in this table, 

events initiated by a turbine trip with bypass, a dual unit loss of offsite power (LOOP), a loss of 

instrument air, and a loss of condenser vacuum are the dominant contributors to the CDF. In a 

response to RAIs, Exelon identified that station blackout (SBO) contributes 6.4×10−7 per year, or 

25 percent of the total CDF for internal events while anticipated transients without scram 

(ATWS) contributes 4.9×10−7 per year, or approximately 19 percent, of the total CDF for each 

unit (Exelon 2015).

Regarding Level 2 analysis, Exelon stated:

The expansion of the LERF model to a full Level 2 model involved a 

reassessment of the timing and release categorization of each containment event 

tree (CET) end state. To perform this reassessment, MAAP calculations for each 

accident class were performed and used to assess the CET end states. Each 

CET node was evaluated and updated to reflect the current state of knowledge 

regarding Level 2 accident phenomenology. The end state timing was also 

updated to reflect the current emergency plan and evacuation time estimates.

The Level 2 model uses three general containment event tree (CET) types to assess the 

accident progression during a core damage event. CETs contain both phenomenological and 

containment system status events. Level 1 core damage sequences are binned into plant 

damage states (PDSs) or accident classes, which provide the interface between the Level 1 and 

Level 2 CET analysis. Each accident class bin is entered into the CET, resulting in 

15 LSCS-specific CETs. The CET is linked directly to the Level 1 event trees, and CET nodes 

are evaluated using supporting fault trees (Exelon 2015).

The result of the Level 2 PRA is a set of 13 release bins or categories with their respective 

frequency and release characteristics. The results of this analysis for LSCS are provided in 

Tables F.2–5, F.2–6, F.3–15, F.3–16, and F.3–19 of the ER (Exelon 2014a). The categories 

were defined based on the timing of release (three release time ranges) and the magnitude of 

release (four release magnitude ranges). One additional release category was included for an 

intact containment.

For the SAMA analysis, the release category for high magnitude and early timing was divided 

into two bins (one with containment isolation and one without). Due to the small release

category contributions from six categories, the number of release category bins was reduced to 

eight cases. The frequency of each release category was obtained by summing the frequency 
Appendix F

F-3

of the individual accident progression CET endpoints binned into the release category. Source 

terms were developed for each of the 13 release categories using the results of Modular 

Accident Analysis Program (MAAP) Version 4.0.5 computer code calculations (Exelon 2014a).

Exelon computed offsite consequences for potential releases of radiological material using the 

MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its 

determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 

site-specific input values for core radionuclide inventory, source term and release 

characteristics, site meteorological data, projected population distribution and growth within a 

50-mile (80-km) radius, emergency response evacuation modeling, and economic data. The 

estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and 

occupational dose) is based on guidance in NUREG/BR–0184 (NRC 1997a). In its calculation 

for replacement power costs, Exelon accounted for the increased electric power output of LSCS

compared to the generic reactor power output presented in NUREG/BR–0184 (NRC 1997a).

Table F–1. LaSalle County Station CDF for Internal Events

Initiating Event

CDF(a)

(per year)

Percent CDF

Contribution

Turbine Trip with Bypass 5.6×10−7 22

Dual Unit Loss of Offsite Power 3.1×10−7 12

Loss of Instrument Air 2.8×10−7 11

Loss of Condenser Vacuum 2.7×10−7 10

Fire Protection System Pipe Rupture in Reactor Building 1.9×10−7 7

Main Steam Isolation Valve Closure 1.4×10−7 5

Loss of Turbine Building Component Cooling Water 1.2×10−7 5

Loss of Feedwater 1.2×10−7 5

Loss of Offsite Power 7.2×10−8 3

Manual Shutdown 5.9×10−8 2

Inadvertently Open Relief Valve 5.9×10−8 2

Loss of 125 V Direct Current Bus 2A 5.1×10−8 2

Loss of 125 V Direct Current Buses 2A and 2B 3.9×10−8 2

Other Initiating Events(b) 3.3×10−7 13

Total (Internal Events)(c) 2.58×10−6 100

(a) CDF based on Fussell-Vesely importance and total CDF.

(b) Other initiating events each contributing less than 2 percent to total CDF.

(c) Column totals may be different because of rounding.

Key: CDF = core damage frequency

Source: Exelon 2014a

In the ER, as updated by the response to RAIs (Exelon 2015), Exelon calculated the dose risk 

to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to the population within 

80 km (50 mi) of the LSCS site. The offsite economic cost risk was calculated to be 

$57,700 per year. The breakdown of the population dose risk by containment release category

is summarized in Table F–2. The medium magnitude, intermediate release category accounted 
Appendix F

F-4

for 52 and 62 percent of the population dose risk and offsite economic cost risk, respectively. 

Additionally, two categories (medium magnitude, early release and high magnitude, early 

releases for breaks outside containment) together accounted for approximately 41 and 

31 percent of the population dose risk and offsite economic cost risk, respectively.

F.2.2 Review of Exelon’s Risk Estimates 

Exelon’s determination of offsite risk at the LSCS site is based on the following three major 

elements of the analysis:

(1) Upgraded Level 1 risk model that supersedes the 1994 IPE/IPEEE submittal 

(CECO 1994), a new interim fire PRA and the seismic and other external event 

analyses of the 1994 IPE/IPEEE submittal;

(2) Expanded Level 2 risk model; and

(3) MACCS2 analyses performed by Exelon to translate fission product source terms 

and release frequencies from the Level 2 PRA model into offsite consequence 

measures.

The NRC staff reviewed each of these analyses to determine the acceptability of the LSCS risk 

estimates for the SAMA analysis.

Table F–2. Base Case Mean Population Dose Risk and

Offsite Economic Cost Risk for Internal Events

Release Category Population Dose Risk(a) Offsite Economic Cost Risk

ID(b)

Frequency

(per year) person-rem/year % Contribution $/year % Contribution

H/E–BOC(c) 8.3×10‒8 1.3×100 18 7.2×103 13

H/E 6.0×10‒8 3.2×10‒1 4 2.8×103 5

H/I(d) 1.9×10‒8 1.1×10‒1 1 9.7×102 2

M/E 2.4×10‒7 1.7×100 23 1.0×104 18

M/I(d) 1.0×10‒6 3.9×100 52 3.6×104 62

L/E 3.9×10‒7 8.7×10‒2 1 1.3×102 0.2

L/I(d) 1.5×10‒7 1.1×10‒1 1 1.8×102 0.3

CI 6.2×10‒7 1.4×10‒3 <0.1 1.0×100 <0.1

Total 2.6×10−6 7.6×100 100 5.8×104 100

(a)Unit Conversion Factor: 1 Sv = 100 rem

(b)Release Mode Nomenclature (Magnitude/Timing)

Magnitude:

High (H)—Greater than 10 percent release fraction for cesium iodide

Medium (M)—1 to 10 percent release fraction for cesium iodide

Low (L)—0.1 to 1 percent release fraction for cesium iodide

Low-Low (LL)—Less than 0.1 percent release fraction for cesium iodide

Containment intact (CI)—Much less than 0.1 percent release fraction for cesium iodide

Timing:

Early (/E)—Less than 5 hours

Intermediate (/I)—5 to 24 hours

Late (/L)—Greater than 24 hours
Appendix F

F-5

Release Category Population Dose Risk(a) Offsite Economic Cost Risk

(c)Contributions from initiators with breaks outside containment (BOC)

(d)The release categories for late timing were negligible and subsumed into the intermediate release categories for 

H, M, and L releases. Categories for LL magnitude releases were negligible and subsumed into the L release 

category with intermediate timing.

Sources: Exelon 2014a, 2015

F.2.2.1 Internal Events CDF Model

Commonwealth Edison Company submitted a combined IPE/IPEEE report to fulfill the 

requirements of Generic Letter 88-20 (NRC 1988). This submittal was brief and referred to the 

information in NUREG/CR–4832, “Analysis of the LaSalle Unit 2 Nuclear Power Plant: Risk 

Methods Integration and Evaluation Program (RMIEP),” which was performed by Sandia 

National Laboratories (SNL) and sponsored by the NRC (NRC 1992).

The NRC staff’s review of the LSCS IPE is described in its 1995 memorandum (NRC 1995). 

Based on its review of the LSCS nuclear power plant IPE submittal and associated 

documentation, the NRC staff concluded that the licensee met the intent of Generic Letter 88-20 

(NRC 1988). As indicated in the NRC staff review, while the licensee concluded that no 

vulnerabilities exist at LSCS, the licensee cited potential improvements identified and discussed 

in Volume 3, Part 1 of the RMIEP report. These potential improvements are discussed in 

Section F.3.2.

There have been numerous revisions to the LSCS PRA since the original 1994 IPE submittal. 

A listing of the complete revision history of the LSCS PRA, since the original IPE submittal, was 

provided in the ER (Exelon 2014a) and in response to an NRC staff RAI (Exelon 2015). The 

PRA revision history is summarized in Table F–3. A comparison of the CDF for internal events 

between the 1994 IPE and the current PRA model indicates there has been a significant 

reduction in total CDF (point estimate including internal floods from 3.4×10−5 per year8 to 

2.6×10−6 per year).

The CDF value from the 1994 IPE (3.4×10−5 per year) is within the range of CDF values 

reported in the IPEs for BWR 5/6 plant units. In NUREG–1560, CDF values ranged from 1×10−5 

per year to 4×10−5 per year (NRC 1997b). It is recognized that other plants have updated the 

values for CDF subsequent to the IPE submittals to reflect modeling and hardware changes.

The NRC staff considered the peer review performed for the LSCS PRA and the potential 

impact of the review findings on the SAMA evaluation. In the ER, Exelon described the 

2008 Boiling Water Reactor Owners Group (BWROG) peer review of the LSCS PRA. The peer 

review was indicated to be performed against Addendum B of the then current PRA Standard 

(ASME/ANS 2005) with the criteria in Regulatory Guide 1.200, Revision 1 (NRC 2007),

including the NRC positions stated in Appendix A of the regulatory guide.

Exelon indicated that a PRA update was conducted in 2011 that addressed the majority of the 

2008 peer review findings and American Society of Mechanical Engineers/American Nuclear 

Society (ASME/ANS) PRA standards supporting requirements assigned a Capability Category II 

or lower. In ER Table F.2–7 (Exelon 2014a), a summary was presented on the remaining open 

 8 The 3.4×10−6 per year total CDF is the sum of the point estimates for internal events and internal floods 

from RMIEP, as given in the Technical Evaluation Report attached to the NRC review of the LSCS IPE 

(NRC 1995).
Appendix F

F-6

supporting requirements identified from the peer review as not meeting Capability Category II 

and associated findings, along with an assessment of the impact on the base PRA. Of the six 

open supporting requirements, four are related to documentation and two have a relatively 

minor impact on the PRA results.

The NRC staff has determined that Exelon has demonstrated sufficient internal events PRA 

quality by addressing the peer review open findings noted above consistent with the guidance in 

Nuclear Energy Institute (NEI) 05-01 (NEI 2005) and that the final resolution of the findings 

provides reasonable assurance of a minimal impact on the results of the SAMA analysis. As 

previously indicated, the 2013A update to the PRA model (LS213A) is the most recent 

evaluation of the risk profile at LSCS for internal events. Exelon indicates this PRA model is 

documented as an application-specific model developed for use in the SAMA application. The 

current PRA model of record is the 2011A PRA. In the 2013A model, Level 1 logic from the 

2011A model was not changed beyond what was required to integrate it with the Level 2 model. 

CDF portions of the 2011A and 2013A PRA models are identical. Therefore, updates 

performed in the 2011A model to resolve the peer review comments were carried into the 

2013A model.

Section F.2 of the ER states that the LSCS PRA is a Unit 2 model. Because the units are nearly 

identical, the PRA for Unit 2 is considered to be applicable to Unit 1, unless otherwise noted. In 

an RAI, the NRC staff asked Exelon to provide a brief description of the differences between the 

units, particularly those differences that might impact internal flooding and their impacts on the 

unit risk. Exelon responded that the major difference between the units is that the common or 

“0” diesel generator is located in the Unit 1 Auxiliary Building and the “0” diesel generator 

cooling water pump is located in the Unit 1 Division 1 core standby cooling system (CSCS) 

pump room. A flood event that initiates in the Unit 1 Division 1 CSCS pump room does not 

propagate from this room, because the surrounding areas are protected by a water tight door 

and walls. Exelon indicated that this specific flood scenario is a negligible contributor to risk on 

both units because it only impacts one division of CSCS equipment. The Unit 1 CDF

contribution from a flood in this area would be slightly higher than Unit 2 because the internal 

flood also will impact the Unit 1 residual heat removal service water (RHRSW) pumps. The 

Unit 1 RHRSW pumps do not have a function for Unit 2; therefore, loss of these pumps has no 

quantitative impacts on the Unit 2 CDF values. Because these flood scenarios have a negligible 

CDF impact and a limited impact on plant equipment and operator response, Exelon concluded 

there would be no impact on the SAMA evaluation. Exelon also discussed the general plant 

layout; internal flooding scenarios; and other asymmetries between units, including the power 

supplies for the shared systems. Exelon concluded and the NRC staff agrees that none of the 

minor differences has an impact on the SAMA evaluation (Exelon 2015).
Appendix F

F-7

Table F–3. Summary of Major PRA Models and Corresponding CDF and LERF Results

PRA Model Summary of Significant Changes From Prior Model

CDF(a)(b)

(per year)

LERF(a)(b)

(per year)

IPE (4/1994) • IPE 3.4×10−5

mean value 

Not 

Quantified

Updated IPE 

(1996)

• Converted to CAFTA linked fault tree

• Incorporated plant procedure changes and modifications

1.0×10−5 (c) Not 

Quantified

1999 Rev.1

(11/1999)

• Increased credit for offsite AC power recovery

• Took appropriate credit for turbine-driven feedwater pump 

and main condenser

• Corrected RCIC AC power dependency

• Revised containment modeling to not always core 

damage upon containment failure

• Revised service water system model

• Credited diesel fire pump for injection post containment 

challenge

8.6×10−6 1.5×10−6

2000A

(1/2000)

• Credited increased 125 V DC battery life for extended 

RCIC operability

• Included room cooling dependency for ECCS systems

• Included realistic assessment of post venting equipment 

reliability

• Updated CCF probabilities

• Expanded treatment of HRA dependencies

• Incorporated internal flood scenarios

• Incorporated unit electrical crossties

• Credited recovery of station air for containment venting 

during long-term loss of decay heat removal

5.9×10−6(d) 1.0×10−6

2000C(e)

(3/2000)

• Revised turbine building flood model

• Updated HRA

8.2×10−6(d) Not 

Quantified

2001A

(8/2001)

• Changed turbine building flood model to reflect changes in 

the pipe inspection program

• revised the scram failure probabilities based on new 

industry data

• incorporated updated service water pump success criteria 

based on LSCS historical operating practices

5.7×10−6(d) 6.7×10−7
Appendix F

F-8

PRA Model Summary of Significant Changes From Prior Model

CDF(a)(b)

(per year)

LERF(a)(b)

(per year)

2003A

(6/2003)

• Revised component failure data including extensive use of 

plant-specific component failure data gathered from the 

LSCS Maintenance Rule program

• Revised initiating events data utilizing the latest LSCS

operating experience

• Added alternate configuration logic for all systems with 

alternate/standby trains

• Added logic for newly installed redundant 125 V DC 

backup battery chargers on both divisions of Unit 2

• Added new logic for the trailer-mounted Station Air 

compressor to the model 

• Revised Station Air success criteria 

6.6×10−6(d) 3.6×10−7

2006A

(1/2007)

• Model modified to reflect the emergency operating 

procedures for LSCS which differ from the generic 

BWROG EPGs in that they do not direct ADS inhibit 

unless a failure to scram occurs (or power is unknown)

• Updated the turbine building flooding accident sequences 

• Allocated LOCA frequencies on a location and sizespecific basis

• Updated data to use the most current industry data and 

plant-specific data

8.1×10−6 3.1×10−7

2006B

(5/2007)

• Completely revised internal flooding analysis

• Added additional dependent HEPs to recovery files

• Quantified several support system initiator fault trees and 

added frequencies to model

3.6×10−6 3.0×10−7

2006C

(1/2008)

Subject of 2008 Peer Review

• Revised RHR suppression pool cooling model to address 

error

• Updated several fault tree logics to address internal 

review issue

• Revised several CCF probabilities

• Revised frequency for medium below core LOCA

• Added additional flood scenario links in system fault tree 

models

• Added coincident maintenance links in system fault trees

4.0×10−6 3.0×10−7
Appendix F

F-9

PRA Model Summary of Significant Changes From Prior Model

CDF(a)(b)

(per year)

LERF(a)(b)

(per year)

2011A

(3/2013)

• Updated transient frequencies and component failure 

rates using latest plant data

• Deleted loss of bus 241Y and 242Y as initiating events 

because loss of these buses does not result in a scram 

• Refined treatment of the ECCS water hammer scenarios

• Crediting closure of the reactor building ventilation check 

dampers as a potential flood mitigation strategy

• Deleted most coincident maintenance terms as these 

events did not meet the current definition of the 

ASME/ANS PRA Standard 

• Re-evaluated categorization of mitigated ATWS 

(i.e., SLBC successfully injected) scenarios with 

subsequent failure of containment heat removal from 

Class IV to Class II

• Corrected probability of failure of ADS due to environment 

from 1.0 to 10−3 based on the controls/steam sensitive 

portion of the ADS system is not in the reactor building

• Revised the probability for preexisting containment failure 

modes from 5×10−3 to 2.3×10−3 to be consistent with 

current industry information

2.6×10−6 1.3×10−7

2013A

(7/2014)

• Replace LERF model with full Level 2 model 2.6×10−6 1.4×10−7

(a) All values assumed to be point estimates unless indicated to be otherwise.

(b) Models prior to 2000A version did not include internal flooding.

(c) CDF value based on information in NUREG–1560, Volume 3, Table B–1. Note that this NUREG volume did not 

contain specific details on the reported CDF values.

(d) CDF values include 1×10-7 per year due to seismic events. LERF value is unknown.

(e) 2000B model was not issued in any regulatory applications.

Key: AC = alternating current; ADS = automatic depressurization system; ATWS = anticipated transients without 

scram; BWROG = Boiling Water Reactor Owners Group; CAFTA = Computer-Aided Fault Tree Analysis; 

CDF = core damage frequency; CCF = common cause failure; DC = direct current; ECCS = emergency core cooling 

systems; EPG = emergency procedure guidelines; HEP = human error probability; HRA = human reliability analysis; 

IPE = individual plant examination; LERF = large early release frequency; LOCA = loss-of-coolant accident;

LSCS = LaSalle County Station; PRA = probabilistic risk assessment; RCIC = reactor core isolation cooling, 

RHR = residual heat removal; SLBC = standby liquid control

Sources: Exelon 2014a, 2015

In response to an NRC staff RAI to identify shared plant systems, or those that could be 

cross-tied between units, and to describe the modeling, including the treatment of unavailability 

during outages or accidents involving the other unit, Exelon responded that the most significant 

piece of equipment shared between units is the common or “0” diesel generator. This diesel 

generator is shared between the Unit 1 and Unit 2 Division 1 AC power divisions. Modeling of 

this component assumes that it loads automatically to the modeled unit 50 percent of the time 

when demanded. The model includes an operator action to manually align the “0” diesel 

generator to the modeled unit if the “0” diesel generator does not automatically align to the unit.

The model also includes an operator action related to the failure to control the loading of the 

diesel generator when it is aligned to both units. Exelon further indicated that the Division 1 and 
Appendix F

F-10

Division 2 AC safety-related 4 (kV) buses can be cross-tied between units, which provides a 

means to power these buses via the opposite unit offsite power sources. The PRA model 

includes the opposite unit offsite power sources, divisional crosstie breakers, and the operator 

action necessary to complete this alignment.

Other shared systems include the instrument air system, the service water system, and the fire 

protection system (FPS). Other than the “0” diesel generator, crosstie breakers, and AC power 

supplies, the model does not explicitly consider the impacts of events occurring at one unit that 

affect the other unit. Service water and instrument air have the capability to support both units

simultaneously during events at both units. With respect to the FPS, it could be aligned to both 

units and could be shared for injection. However, the PRA model does not account for this 

condition probabilistically. For all shared systems, system unavailability during outages is 

considered in the development of system maintenance unavailability basic events.

(Exelon 2015).

Exelon stated in the ER: 

The freeze date for data and plant modifications to be considered for the Level 1 

portion of the LS213A model (the 2011 LSCS PRA update, LS211A) is 

December 31, 2010. The Emergency Operating Procedures (EOPs) and Severe 

Accident Guidelines (SAGs) used in this analysis are those in place as of the 

freeze date. No significant plant modifications affecting the risk profile were 

performed since the PRA model freeze date. EOP and SAG changes made 

since the freeze date were reviewed and incorporated, as necessary, into the 

LS213A model. The freeze date for the LS213A model was December 31, 2013.

In an RAI, the NRC staff asked Exelon to identify any planned changes or modifications to the 

LSCS design (other than the hardened pipe vent), operation, reactor power level, fuel cycle, or 

fuel design that might affect the SAMA analysis and describe their expected impacts. In 

response, Exelon indicated that the PRA open items tracking database (commonly referred to 

as the updating requirement evaluation (URE) database) was reviewed and no outstanding 

modifications were identified, with the exception of the necessary plant modifications to meet 

the NRC order related to the Near Term Task Force (NTTF) on Fukushima. In particular, these 

changes will be made in relation to mitigating strategies (EA-12-049) and the installation of the 

hardened pipe containment vent (EA-12-050) (Exelon 2015).

As noted above, the CDF due to ATWS events is 4.9x10-7 per year9 or 19 percent of the total 

CDF for internal events. In response to an RAI to discuss the reasons for the relatively high 

contribution to the total CDF for internal events, Exelon responded by summarizing the plant 

design and operating features that affect the ATWS CDF. The joint human error probabilities 

(HEPs) for operator actions that must be performed in short time windows are prevalent in the

ATWS cutsets and are the dominant contributors to CDF from this accident class. Some short 

time windows for response are due to the plant design and the lack of a redundant, 

high-pressure, high-volume injection system for use in these scenarios. The only high-pressure, 

high-volume injection system available in an ATWS is feedwater. Emergency operating 

procedures require the high-pressure core spray system to be secured, and the Reactor Core 

Isolation Cooling System (RCIC) is a low-volume system. The capability of feedwater is limited 

by the rate at which water can be made up to the condenser.

Exelon further provided the ATWS CDF and relative contribution to total CDF for a number of 

other BWR units. Exelon concluded that, in general, ATWS CDF and the percent contribution of

 9 This value does not include the CDF contribution from mitigated ATWS events for which standby liquid 

control (SBLC) injection is successful but core damage occurs due to subsequent coolant injection or 

heat removal failures.
Appendix F

F-11

ATWS to the CDF vary significantly in the industry, and values can be found both above and

below those documented for LSCS (Exelon 2015).

The NRC staff noted that Section F.2.3.1 of the ER states “all ATWS events are modeled as a 

turbine trip.” In response to an RAI to clarify this statement, Exelon indicated that this statement 

was intended to explain the prior statement in the ER that “The turbine trip initiating event is 

important to note because it also represents the ATWS frequency.” A better way to describe the 

relationship of the turbine trip initiator to the ATWS is that ATWS sequences are a large 

contributor to the percentage of CDF attributed to the turbine trip initiating event. Exelon noted 

that other initiating events also result in ATWS sequences (Exelon 2015).

On the basis of the NRC staff’s evaluation of internal events Level 1 PRA previously described 

in this subsection, and Exelon’s response to the NRC staff RAIs, the NRC staff concludes that 

the internal events Level 1 PRA model is of sufficient quality to support the SAMA evaluation.

F.2.2.2 External Events

As previously indicated, the LSCS PRA used for the SAMA analysis does not include external 

events. In the absence of such an analysis, Exelon used the results of a new interim fire PRA 

and the LSCS IPEEE to identify the highest risk accident sequences and the potential means of

reducing the risk posed by those sequences and to estimate the benefit of potential SAMAs, as 

discussed below and in Section F.3.2.

The LSCS IPEEE was submitted in April 1994 (CECO 1994) in response to Supplement 4 of

Generic Letter 88-20 (NRC 1991). The submittal cited the external events analysis performed 

as part of the NRC-sponsored RMIEP analysis of LSCS (NRC 1992). This analysis included 

internal fire, internal flood, and seismic risk assessments, as well as a probabilistic bounding 

analysis of the other external hazards (turbine-generated missiles, accidental aircraft impacts, 

high winds, transportation and nearby facility accidents, and external flooding). The IPEEE did 

not provide a definition of a vulnerability and did not identify any plant improvements resulting 

from the fire, seismic, or other external hazard analyses in the IPEEE submittal. The RMIEP 

report identified two issues in the fire area that were “provided to the station for disposition.” 

These were (1) to install tops on the main control room electrical panels and (2) to institute an 

inspection program for penetration seals at the top of switchgear panels. The disposition of 

these improvements is discussed in Section F.3. Upon completion of the NRC staff review of 

the IPEEE submittal and the supporting RMIEP work, the NRC staff concluded that the 

licensee’s IPEEE process is capable of identifying the most likely severe accidents and severe 

accident vulnerabilities and the LSCS IPEEE has met the intent of Supplement 4 to Generic 

Letter 88-20 (NRC 2000).

The LSCS IPEEE seismic assessment used the simplified seismic PRA performed for the 

RMIEP project. This analysis resulted in a point estimate CDF of 6.0x10-7 per year due to 

seismic events. The dominant seismic CDF sequences are listed in Table F–4.

The RMIEP seismic PRA used seismic hazard curves available at that time. In the ER, Exelon

provided an updated seismic CDF utilizing currently available hazard curves and the conditional 

core damage probabilities for each accident sequence and ground motion acceleration range 

provided in the RMIEP report. This yielded a seismic CDF of 6.6x10-7 per year. In response to 

an NRC staff RAI to provide more information on the source of these hazard curves, Exelon 

indicated that the LSCS hazard curves used in the SAMA analysis are the same as the LSCS 

hazard curves included in the response to the NRC’s NTTF on Fukushima Recommendation 2.1

(Exelon 2014b, 2015).
Appendix F

F-12

Also in response to an NRC staff RAI, Exelon provided the LSCS seismic CDF using the 

simplified methodology from the Generic Issue (GI) 199 evaluation (NRC 2010). The LSCS 

seismic CDF using this methodology was found to be 2.3x10-6 per year, based on peak ground 

acceleration (Exelon 2015). The NRC staff notes that this seismic CDF is somewhat larger than 

that based on the RMIEP conditional core damage probabilities, which can be expected based 

on the simplified nature of the GI-199 estimate.

Table F–4. Dominant LSCS Contributors to Seismic CDF

Sequence Sequence Description

CDF*

(per year)

Contribution 

to Total 

Seismic CDF*

(percent)

LOOP-Trans-3 LOOP, HPCS, and RCIC fail due to seismic failure 

of CST, low-pressure injection fails due to random 

electrical support failures

2.8×10-7 42

LOOP-Trans-4 LOOP, HPCS, and RCIC fail due to failure of 

reactor level instrumentation or seismic failure of 

CST, depressurization fails

2.2×10-7 35

LOOP-Trans-1 LOOP, HPCS fails due to random events, 

containment heat removal fails and low-pressure 

injection fails 

7.5×10-8 11

Small-LOCA-3 Small LOCA, HPCS, and RCIC fail, low-pressure 

injection fails

3.4×10-8 5

*Based on RMIEP seismic CDF of 6.6×10-7 per year (NRC 1992) and percent contribution given in the ER 

(Exelon 2014a)

KEY: CDF = core damage frequency; CST = condensate storage tank; ER = environmental report; 

HPCS = high pressure core spray; LOCA = loss-of-coolant accident; LOOP = loss of offsite power; 

LSCS = LaSalle County Station; RCIC = reactor core isolation cooling; RMIEP = Risk Methods Integration 

and Evaluation Program

As discussed in Section F.3, Exelon reviewed the dominant sequences listed in Table F–4 to 

identify potential SAMAs to mitigate those sequences. The total updated seismic CDF was 

used in developing the external events multiplier, as discussed later in this subsection.

Seismic walkdowns of LSCS Units 1 and 2 were conducted as part of Exelon’s actions in 

response to the 50.54(f) letter (NRC 2012a) requesting information related to the Fukushima 

Daiichi NTTF recommendations. Exelon reported that the walkdowns resulted in no adverse

anchorage conditions, no adverse seismic spatial interactions, and no other adverse seismic 

conditions associated with the items on the seismic walkdown equipment list (SWEL) for either 

unit. Similarly, area walk-bys resulted in no adverse seismic conditions associated with other 

systems, structures, or components located in the vicinity of the SWEL item(s). The Unit 1 

seismic walkdown identified 9 minor conditions while the Unit 2 walkdown identified 10 minor 

conditions. Other than these minor conditions, the seismic walkdowns identified no degraded, 

nonconforming, or unanalyzed conditions that required either immediate or follow-on action 

(Exelon 2012a, 2012b). The NRC staff notes that the agency’s and industry’s response to the 

Fukushima Daiichi event includes additional seismic evaluations, as outlined in the 

NRC’s 50.54(f) letter dated March 12, 2012 (NRC 2012a).
Appendix F

F-13

While the LSCS IPEEE/RMIEP included an internal fire PRA, it has been superseded by a new 

interim LSCS fire PRA. The current LSCS fire PRA gives a fire CDF of 8.9×10-6 per year for 

Unit 1 and 9.4×10-6 per year for Unit 2. Table F–5 provides a summary of dominant fire zone 

CDF results from the LSCS fire PRA. The LSCS IPEEE fire assessment did not provide a 

definition of the term “fire vulnerability” nor identify fire-related improvements. As discussed 

above, the RMIEP report identified two issues in the fire area that were “provided to the station 

for disposition.” These were (1) to install tops on the main control room electrical panels and 

(2) to institute an inspection program for penetration seals at the top of switchgear panels. The

disposition of these improvements is discussed in Section F.3.

Exelon considers this fire model to be an interim implementation of NUREG/CR–6850 

(NRC 2005) because all tasks identified in that document were not completely addressed or

implemented in the model. The ER includes a listing of limitations of the current LSCS fire PRA 

relative to the tasks of NUREG/CR–6850 (NRC 2005). While some limitations may result in 

additional fire scenarios or impact the frequency of existing scenarios, others lead to 

conservatisms in the current result. Exelon also notes that the fire PRA utilizes the 

2006C internal events PRA, which is not integrated with the current internal events 2013A PRA. 

Accordingly, the LSCS fire PRA cannot be used in an integrated analysis with the internal 

events PRA. Therefore, the total fire CDF from the analysis was used to determine the external 

events multiplier, while the listing of dominant sequences was used to identify potential 

cost-beneficial SAMAs as allowed by the industry guidance in NEI 05-01 and further discussed 

in Section F.3.

The LSCS IPEEE/RMIEP analysis of high winds, tornadoes, external floods, and other external 

events (HFO) consisted of a bounding probabilistic assessment. For these events, the 

IPEEE/RMIEP concluded that these events were not significant contributors to plant risk and 

there were no improvements identified for these events (CECO 1994).

The ER discusses each of these external events and provides the following CDF estimates from 

RMIEP.

Turbine Generated Missiles (mean) 9.5×10-8 per year

Accidental Aircraft Impact (median) 5.0×10-7 per year

High Winds (median) 3.0×10-8 per year

Transportation & Nearby Facility Accidents10 3.0×10-8 per year

External Flooding3 3.0×10-8 per year

Total HFO external events 6.9×10-7 per year

The NRC staff considers the use of these CDFs consistent with the guidance provided in 

NEI 05-01.

 10 For the purposes of the SAMA analysis, external event frequencies for external flooding as well as 

transportation and nearby facility accidents are taken to be the same as the frequency for high winds.
Appendix F

F-14

Table F–5(a). Dominant LSCS Unit 1 Fire Zone 

Contributors to Fire CDF of 8.9×10-6 per year.

Fire Zone Zone Description

CDF

(per year)

Contribution 

to Total Fire 

CDF

(percent)

4F1 Unit 1—Division 1 Essential Switchgear Room 2.7×10-6 30

4E3-2 Unit 1—Division 2 Essential Switchgear Room 2.7×10-6 30

4C1 Control Room 5.9×10-7 7

4E1-2 Unit 1—Auxiliary Electric Equipment Room—Main AER 

Room

3.9×10-7 4

Table F–5(b). Dominant LSCS Unit 2 Fire Zone 

Contributors to Fire CDF of 9.4×10-6 per year

Fire Zone Zone Description

CDF

(per year)

Contribution 

to CDF

(percent)

4E4-2 Unit 2—Division 2 Essential Switchgear Room 2.9×10-6 30

4F2 Unit 2—Division 1 Essential Switchgear Room 2.7×10-6 29

4E2-2 Unit 2—Auxiliary Electric Equipment Room-Main AER 

Room

7.7×10-7 8

4C1 Control Room 5.9×10-7 6

Key: CDF = core damage frequency; LSCS = LaSalle County Station

The NRC staff notes that Exelon’s response to the NRC’s 50.54(f) letter (NRC 2012a) 

requesting information related to the Fukushima Daiichi NTTF recommendations includes a 

flooding walkdown and a flood hazards reevaluation. As reported in the NRC staff assessment 

of the walkdown report (NRC 2014), five deficiencies were identified during the course of the 

flooding walkdowns and entered into the corrective action program for tracking and resolution. 

Two deficiencies were related to lack of seal or significant rust in penetrations. 

Three deficiencies were related to exterior doors’ threshold elevations being lower than the 

calculated flood elevation. The NRC staff concluded that the licensee’s implementation of 

flooding walkdown methodology meets the intent of the walkdown guidance.

In the flood hazards reevaluation (Exelon 2014c), Exelon concluded that “The current design 

basis flood does not bound the reevaluated hazard for all applicable flood-causing mechanisms, 

combined-effect floods, associated effects, and/or flood event duration parameters.” Because 

of this result, Exelon is preparing a fully integrated assessment of these flood hazards. Exelon’s 

flood hazard evaluation also includes a summary of interim evaluations and actions taken or 

planned to address the instances for which the reevaluated hazard exceeds the design basis. 

These issues are being addressed via the ongoing Japan Lessons Learned program and 

implementation of the Fukushima Daiichi NTTF recommendations, including NRC Order 

EA-12-049, “Order to Modify Licenses with Regard to Requirements for Mitigation Strategies for 

Beyond-Design-Basis External Events” (NRC 2012b) and is outside the scope of the SAMA

analysis.
Appendix F

F-15

As discussed in the ER, there are no up-to-date quantitative external event models for LSCS, so 

a multiplier to the internal events PRA results was developed to account for risk contributions

from external events in the SAMA evaluation. For seismic contributions to risk, Exelon used the 

updated RMIEP seismic CDF value of 6.6×10−7 per year. For fire contributions to risk, Exelon 

used a Unit 2 fire CDF of 9.4×10−6 per year, discussed above. For HFO events, the value of 

6.9x10-7 per year was used.

Based on these results, Exelon indicated in the ER that the total CDF for external events is 

approximately 1.08×10−5 per year. The total CDF (internal and external events) is then 

approximately 1.33×10−5 per year or 5.2 times the CDF for internal events. This multiplier was 

used by Exelon in the SAMA analysis to account for the impact of external events on the 

calculated benefits.

The NRC staff agrees with the applicant’s overall conclusion concerning use of the multiplier to 

represent the impact of external events and finds that a multiplier of 5.2 will reasonably account

for external events in the SAMA evaluation.

F.2.2.3 Level 2 Fission Product Release Analysis

The NRC staff reviewed the general process Exelon used to translate the results of the Level 1 

PRA into containment releases, as well as the results of the Level 2 analysis, as described in 

the ER (Exelon 2014a) and Exelon’s responses to NRC staff RAIs (Exelon 2015). Exelon 

indicates that this PRA model is documented as an application-specific model developed for the 

use in the SAMA application. The SAMA Level 2 model is an expansion of the prior LERF-only 

model to a full Level 2 model.

The LSCS Level 1 PRA postulates accident sequences that lead to core damage and potentially 

challenge containment. These discrete accident sequences contribute to the CDF, represent 

the spectrum of possible challenges to containment, and are placed into functional sequence 

groupings (i.e., accident classes and subclasses). The Level 1 accident class bins are then 

used as the starting point for the Level 2 PRA CET analysis. Level 1 accident sequences and 

resulting cutsets are incorporated directly into the Level 2 analysis to maintain the propagation 

of dependencies. The accident classes and subclasses used for the LSCS SAMA analysis are 

summarized in ER Table F.2–3 (Exelon 2014a). 

The response of containment to core damage is analyzed by a CET for each accident class or 

subclass. Each node in the CET is evaluated using the nodal functional fault trees that include 

the following considerations:

• fault tree models from the Level 1 analysis for the system or function,

• any Level 2 limitations in timing, procedures, access, or dependencies,

• phenomenological effects, and

• environmental impacts on equipment or operator actions.

The CETs and the end-state assignments are based on deterministic core melt progression 

calculations. Exelon directly links the Level 1 and Level 2 models using a single top logic 

structure and quantifies them using the Electric Research Power Institute (EPRI)

Computer-Aided Fault Tree Analysis (CAFTA) software. Functional event nodes of the LSCS

Level 2 CET are:

• Containment Isolated (IS),

• RPV Depressurization (OP),
Appendix F

F-16

• Core Melt Arrested In-Vessel (RX),

• Combustible Gas Venting Initiated (GV),

• Containment Remains Intact (CZ),

• Injection Established to RPV or Drywell (TD),

• Containment Flooding Occurs with Drywell Vent (FC),

• Containment Heat Removal (HR),

• Containment Vent (CV),

• Suppression Pool Bypass (SP),

• No Large Containment Failure (NC),

• Inventory Makeup Available (MU),

• Drywell Intact (DI),

• Wetwell (WW) Airspace Failure, and

• Reactor Building Effectiveness (RB).

As described in ER Section F.2.1 (Exelon 2014a), the release categories were defined based on 

the timing and magnitude of releases. Each CET end state represents a radionuclide release to 

the environment and is assigned to a release category based on the CET sequence 

characteristics, MAAP 4.0.5 results, and a set of release category rules. When MAAP is not 

well suited to modeling the accident phenomena associated with a scenario, the scenario is 

modeled using conservative estimates (e.g., steam explosion) and insights from other Level 2 

PRA models from plants of a similar type.

ER Table F.2–6 provides a summary of the LSCS Level 2 release category frequencies for each 

of the 15 accident classes or subclasses (Exelon 2014a). For accident class II (accident 

sequences involving a loss of containment heat removal with the reactor pressure vessel initially 

intact but with post containment failure or venting induced by core damage), the NRC staff 

noted in an RAI that the subclasses listed in ER Table F.2–6 were different from those in ER

Table F.2–3. In response, Exelon indicated that the four accident Class II subclasses 

(II, IIE, IIV, IIVE), used in the SAMA analysis and included in ER Table F.2–6, represent early 

(IIE and IIVE) releases resulting from containment failure and containment venting, respectively; 

and non-early (II and IIV) releases resulting from containment failure and containment venting, 

respectively. Exelon indicated that for convenience in modeling, the Class II accident classes 

are separated into two CETs; one representing the early releases and the other representing

intermediate or late (non-early) releases for the containment failure sequences and two similar 

ones for venting sequences.

Exelon further indicated that the analysis of the timing of a General Emergency declaration has 

been evaluated from a probabilistic standpoint for Class II accident scenarios. This evaluation 

was performed because of the potential differences in interpretation of the Emergency Action 

Levels (EALs) and the probability that the Emergency Director could delay the declaration of the 

General Emergency resulting in an early release. Interviews of key emergency response 

personnel were performed to determine the best estimate probability that the EALs would be 

interpreted such that the General Emergency declaration would be delayed resulting in an early 

release as opposed to an intermediate or late release. These interviews consisted of case 

studies and a discussion of EALs. The mean probability of failure to declare a General 

Emergency with adequate time to take protection measures for the general public prior to 
Appendix F

F-17

containment failure is 5 percent or 0.05 based on expert opinions. As a result, the LSCS

Level 2 model is structured such that 5 percent of the Class II accidents can result in an “Early” 

release, but 95 percent of the Class II accident releases are “non-early” releases.

The NRC staff noted in an RAI that ER Table F.2–6, which provides the accident class 

frequency contribution to each release category, includes a significant intact containment

frequency for the Class II accident subclasses. Class II accidents are normally considered, and 

defined in ER Table 2–3, to include sequences where core damage occurs after containment 

failure; therefore, there should be no intact containment sequences in Class II. In response to 

the RAI to discuss the reasons for these results, Exelon indicated that the “intact” frequency was 

obtained from the difference between the CDF for each accident subclass and the total of all the 

other release category frequencies. As discussed above, the Class II accident classes are split 

into two timing categories; early and non-early and a separate Class II event tree was used for 

each category. For the early release class, the total Class II frequency is multiplied by 

0.05 when the CDF value is transferred into the Level 2 model. Then, the remaining event tree 

nodes are evaluated. This results in truncation of low-frequency sequences leading to the total 

of all the release categories being significantly less than the CDF for the Class II subclasses. 

To account for this undercounting of Class II releases, Exelon performed a sensitivity study to 

determine the impact of this truncation issue. The study was performed by setting the PRA 

model basic event related to the General Emergency declaration to 1.0 (instead of 0.95 and 

0.05) and requantifying the model. After quantification, the 95 percent and 5 percent split

between non-early and early releases were calculated. Because the results demonstrated that 

low-frequency sequences had previously been truncated from the final results, Exelon revised 

the release category frequencies in its response to the RAI (Exelon 2015, Table F.2–6 revised). 

Exelon noted that in the requantified results, there is still a very small unaccounted for frequency 

in the Level 2 release results due to additional truncated sequences (approximately 5 percent of 

the CDF). This release frequency was divided proportionally among each release category 

applicable to that accident class (i.e., Class II, IIE, IIV and IIVE). Exelon indicated that model 

truncation is a known source of uncertainty in model results and while the proportional 

redistribution of the truncated cutsets does not provide an exact solution to this quantification 

issue, it is considered to be a reasonable approximation of how these low contributors should be 

allocated to the release categories. Exelon concluded that any deviations between the true 

release category allocations of the truncated frequency and those resulting from the proportional 

distribution of the frequency would correlate to very small changes to the cost-benefit results; 

therefore, no impacts on the conclusions of the SAMA analysis were expected.

Exelon noted further that the Class II accident subclasses are the only accident classes where 

the CDF values were multiplied by a split fraction before transferring into the Level 2 fault trees. 

Therefore, the larger impact observed for this accident class is not applicable to other accident 

classes. Other truncation issues would be small and are bounded by the uncertainty in other 

inputs. Exelon concluded that the SAMA evaluation would not be impacted by model truncation 

issues.

The NRC staff agrees, for the purposes of the SAMA analysis, with the Exelon approach to 

resolving the issue associated with the original ER analysis of Class II release category 

assessment, the conclusions associated with this issue, and the more general issue of impacts 

from model truncation. The NRC staff also notes that the issue of how the “intact” release 

category frequency was determined for other accident classes would have a very small impact 

on the SAMA analysis because major accident class contributors to those other-than-Class II 

release categories that are most important to offsite cost risk (Classes IIID, IV, and V) had a 

zero “intact” containment frequency in the original ER analysis. Exelon’s revisions to 
Appendix F

F-18

the release category frequencies influenced the base case maximum averted cost risk (MACR) 

and the cost-benefit analysis for each SAMA (Exelon 2015).

Exelon developed the accident progression and associated release characteristics for each 

release category by using the results of MAAP Version 4.0.5 computer code calculations. 

A MAAP case was identified as a representative case for each of the LSCS Level 2 PRA 

release categories based on a review of the Level 2 model cutsets and the dominant types of 

scenarios that contribute to the release category. Tables F.3–17 and F.3–18 in the ER provide 

a description of the representative cases for each release category and additional information 

on the selection of these representative cases (Exelon 2014a).

With regard to the selection of representative cases, the NRC staff noted in an RAI that the 

dominant contributor to the low-magnitude early (L/E) release category is an ATWS sequence. 

This event sequence involves successful depressurization of the reactor pressure vessel (RPV) 

with core melt arresting in the vessel and a WW airspace failure. However, the MAAP scenario 

stated in ER Tables F.3–17 and F.3–18 to be used as the reference MAAP case for this 

sequence was not used to represent this release category. Instead, an alternate MAAP case 

with a significantly lower cesium iodide release fraction was stated to have been used. 

In response to the RAI, Exelon clarified that the reference MAAP cases in the Level 2 analysis 

are not necessarily exact models of the sequence but are instead used along with the Level 2 

Release Category rules to assign an appropriate end state to the Level 2 sequence

(Exelon 2015). A specific MAAP scenario modeling the dominant sequence for the L/E release 

category was not developed for the LSCS SAMA analysis. Rather, expert judgment and review 

of similar MAAP cases were used. In-vessel retention would be expected to reduce 

radionuclide release fractions significantly because (1) RPV injection post-core damage 

prevents further heat up of radionuclides, and (2) the suppression pool is not bypassed 

(i.e., fission products are retained in the pool instead of being released directly to the 

environment).

Exelon noted that while Tables F.3–17 and F.3–18 of the ER indicate that MAAP 

case LS130533B was used to represent the L/E release category, MAAP case LS130524B was 

actually used to represent the L/E release category indicated in Table F.3–19 of the ER. Use of 

the LS130524B scenario in place of the LS130533B scenario is conservative because the 

LS130524B release fractions bound the release fractions from the LS130533B scenario, and

the LS130524B scenario results in a substantial release of radionuclides several hours earlier

than the LS130533B scenario (containment breach in LS130524B vs. containment vent in

LS130533B). Both scenarios are containment flooding scenarios. As indicated above, the 

dominant release category sequence is an ATWS sequence with a WW airspace failure, 

successful RPV depressurization, in-vessel retention, and no suppression pool bypass. The 

MAAP case LS130524B represents an ATWS sequence with WW airspace failure, successful 

RPV depressurization, core spray available after core damage at vessel breach, and 

containment flooding. Use of MAAP scenario LS130524B to model this sequence as a 

surrogate for the L/E release category was judged by Exelon to be reasonable since 

LS130524B models containment flooding shortly after vessel breach, which mimics the actions 

of in-vessel retention by both cooling debris and retaining fission products in the local water 

inventory (i.e., scrubbing the release). The NRC staff reviewed the logic of this assessment of 

the release characteristics for the L/E release category and concludes that the results are 

acceptable for the purposes of the SAMA analysis because the release category is bounding 

and conservative.

In response to an NRC staff RAI to provide justification for the adequacy of the MAAP release 

fraction results from simulation times less than 48 hours past the declaration of a general 
Appendix F

F-19

emergency, Exelon discussed each of these MAAP analysis cases. The run times were 

considered adequate based on either: (i) results at the end of the run having reached an 

obvious plateau and being stable well before the end of the run, or (ii) the core debris being 

quenched in a large body of water (the suppression pool) and stabilized at a relatively low 

temperature (Exelon 2015). Based on this discussion and the fact that the run times were no 

more than 8.5 hours less than the desired run time, the NRC staff agrees that the run times

used in Exelon’s SAMA analysis are acceptable.

Section F.2.2.11 of the ER, titled "2013A UPGRADE" (Exelon 2014a), states:

In order to support the SAMA analysis, the LSCS LERF model was replaced by a 

full Level 2 model. The Level 1 logic from the 2011A model was not changed 

beyond what was required to integrate it with the Level 2 model. 

In response to an NRC staff RAI to describe the changes in the Level 2 model that are 

considered upgrades as opposed to updates and to describe the steps taken to assure technical 

adequacy of the 2013A Level 2 model, Exelon responded that the word “upgrade” in the 

subheading “2013A Upgrade” in Section F.2.2.11 of the ER was intended to have its common 

meaning rather than the meaning ascribed by the ASME/ANS PRA Standard (ASME/ANS 2009) 

and, in retrospect, was misleading. No change to the LERF analysis or methodology that would 

be considered an “upgrade” by the ASME/ANS PRA Standard definition was made during the 

model update that created the 2013A model. Accordingly, the 2013A model did not require a 

peer review. Exelon further indicated that it has implemented procedures and processes to 

assure the technical adequacy of the full power internal event (FPIE) PRA models. 

The 2013A model was reviewed and approved in accordance with these procedures and 

processes. (Exelon 2015).

On the basis of the NRC staff’s review of Exelon’s Level 2 model, the peer review performed on 

the 2006C PRA model, the general process Exelon used to translate the results of the Level 1 

PRA into containment releases, and Exelon’s responses to NRC staff RAIs, the NRC staff 

concludes that the Level 2 PRA as modified in response to the NRC staff RAIs is of sufficient 

quality to support the SAMA evaluation.

F.2.2.4 Level 3 Offsite Consequence Analysis

The NRC staff reviewed Exelon’s process to propagate the containment performance (Level 2) 

portion of the PRA to an assessment of offsite consequences (Level 3 PRA). Using the 

MACCS2 Version 1.13.1 code, Exelon determined the offsite consequences from potential 

releases of radioactive material (Exelon 2014a). In the Level 3 analysis, Exelon combined 

release fractions and release categories, discussed in Section F.2.2.3, with the calculated core 

inventory to yield potential source terms of radionuclides released to the outside environment. 

In response to an NRC staff RAI, Exelon indicated that the LSCS radionuclide inventory was 

calculated with ORIGEN Version 2.1 software (Exelon 2015). The NRC staff finds the 

MACCS2 and ORIGEN codes to be acceptable for the SAMA evaluation because the codes are 

widely used for radiological dose calculations resulting from airborne releases of radioactive 

material and radionuclide source term determinations, respectively.

Exelon determined radionuclide inventories in the core for a thermal power output of 

3489 (MWt). Because the current licensed core power level is 3546 MWt, Exelon applied a 

scaling factor of 1.0163 (3546 MWt/3489 MWt = 1.0163) to the radionuclide inventories in the 

core presented in Table F.3–11 of the ER (Exelon 2014a). In response to an NRC staff RAI on 

the core inventory calculation performed by Exelon for Unit 1, Exelon indicated that the core 

inventory calculation was bounding for either unit because time spent during refueling outages 

was ignored, an extended cycle length was modeled, and the higher activity value for each 
Appendix F

F-20

radioisotope was chosen from two results for the end of the fuel cycle (Exelon 2015). 

Furthermore, Exelon reported that the core design process ensures that the core inventory of 

each unit remains within the single design basis source term. The NRC staff finds that these 

reasons provide reasonable assurance that actual radionuclide core inventories will be lower 

than the radionuclide inventories used in the SAMA analysis. 

In response to an NRC staff RAI on planned changes or modifications to the LSCS design, 

operation, reactor power level, fuel cycle, or fuel characteristics, Exelon indicated planned 

modifications in response to the NRC order arising from the severe accidents at the Fukushima

Daiichi nuclear generating station, including mitigating strategies and installing a hardened pipe 

containment vent, as required by EA-12-050 and described within the ER. Additionally, Exelon 

highlighted its PRA sensitivity study that indicated modifications excluding the hardened pipe 

containment vent lowered the CDF by approximately 5 percent (Exelon 2015). The NRC staff 

finds the Exelon approach to not take credit for the hardened pipe containment vent or other 

modifications in the SAMA analysis to be conservative and acceptable because this treatment 

does not cause potentially cost-beneficial SAMAs to be missed. 

The NRC staff also requested additional information on the assumptions used to calculate the 

inventories of radioactive cobalt, and Exelon described that guidance values for cobalt were 

scaled to the core thermal power level of the LSCS units (Exelon 2015). Exelon further 

described that one of the cobalt radioisotopes was overestimated and explained the limited 

influence of cobalt radioisotopes to the offsite dose and offsite economic costs, which are 

dominated by other radionuclides in the core inventory. Because the radionuclide inventories 

for cobalt have not been underestimated and the offsite dose and offsite economic cost 

components provide the largest contributions to the MACR, the NRC staff agrees that the 

inventories for the radioisotopes of cobalt are acceptable for use in the SAMA analysis. 

The NRC staff concludes that the current radionuclide inventory calculations in Table F.3–11 of 

the ER (Exelon 2014a) are adequate for the estimation of offsite consequences because current 

calculations bound the expected radionuclide inventory for either reactor core, and Exelon’s 

additional information further justifies the appropriateness of the calculated core inventory.

Exelon presented the major input parameter values and assumptions of the offsite consequence 

analyses in Appendix F of the ER (Exelon 2014a). Exelon considered site-specific 

meteorological data for the calendar years 2010, 2011, and 2012. Meteorological data from 

2012 were selected for input to the MACCS2 code because they resulted in the highest 

population dose risk and offsite economic cost risk, as described in Section F.3.7 of the ER 

(Exelon 2014a). Exelon acquired meteorological data, such as wind speed, wind direction, 

atmospheric stability class, and precipitation, from onsite meteorological monitoring stations at 

LSCS. Atmospheric mixing heights were obtained from information published by the 

U.S. Environmental Protection Agency. The NRC staff finds the applicant’s modeling of 

atmospheric conditions and plume dispersion to be acceptable because it is supported by 

site-specific annual meteorological data and implemented using widely accepted software. 

Because selection of the 2012 meteorological data set resulted in the highest population dose 

risk and offsite economic cost risk, the NRC staff accepts its use in the SAMA evaluation.

Exelon addressed missing meteorological data either by interpolation or by substitution. For 

missing wind-speed data, a power law was used to convert wind speeds measured at different 

heights. For data gaps less than 6 hours, interpolation was performed with valid data 

immediately before and after the data gap. For data gaps greater than 6 hours, data 

substitution was performed with valid data for the same times from either the day before or after 

the missing data. Exelon indicated that missing data represented 2 percent or less for each of 

the three annual meteorological data sets. Because these percentages of missing data are 
Appendix F

F-21

reasonable and the methods used to substitute missing data are common remedies, the NRC 

staff finds these approaches to be acceptable for use in the SAMA analysis.

Having assessed the sensitivity to different annual meteorological data sets, release heights, 

plume heat, and deposition velocities, Exelon found the population dose risk and offsite 

economic cost risk either decreased (by as much as 9 percent) or increased slightly (by as 

much as 3 percent) due to the alternative inputs. In response to an NRC staff RAI, Exelon 

quantified the influence of precipitation on the population dose risk and offsite economic cost 

risk. Specifically, Exelon compared the total annual precipitation, population dose risk, and total 

offsite economic cost risk for the previously identified calendar years of 2010, 2011, and 2012 

and reported that the single year (2012) with the highest population dose risk and total 

economic cost risk had the lowest total annual precipitation (Exelon 2015). This observation 

indicated that other atmospheric parameters during the modeled release had a greater influence 

on the consequence analysis results than the time-integrated precipitation for the entire year. 

The NRC staff finds that the selection of the 2012 meteorological data and the other parameter 

values for atmospheric dispersion are appropriate for use in the SAMA analysis because 

changes to the analysis typically lower expected benefits for individual SAMAs and any small 

increases would not change the identification of cost-beneficial SAMAs. As previously 

described, the sources of data and models for atmospheric dispersion used by the applicant are 

appropriate for calculating consequences from potential airborne releases of radioactive 

material.

Exelon used the SECPOP2000 Version 3.12 code, projected the expected growth and 

distribution of population out to the year 2043, and reported that the total population within 

80 km (50 mi) surrounding LSCS is anticipated to increase from 1,546,445 in the year 2000 to 

approximately 3,107,897 in the year 2043, as shown in Table F.3–7 of the ER (Exelon 2014a). 

From Section F.3.2, as well as Tables F.3–1 and F.3–2 of the ER, Exelon considered census 

data from years 2000 and 2010, county growth rates for the year 2030, and transient population 

contributions in the projection. The NRC staff finds that the methodology for population 

projection is consistent with relevant guidance (NEI 2005). In response to an NRC staff RAI, 

Exelon indicated that the county population growth rate data were based on projections 

published by the State of Illinois (Exelon 2015). The NRC staff verified the appropriateness of 

selected data and compared the county growth rate data reported in the ER with the data 

source and found no discrepancies.

Compared to the previously discussed atmospheric parameters, Exelon reported greater 

influences on potential increases to the population dose risk and offsite economic cost risk from 

sensitivity assessments of the population within 80 km [50 mi], evacuation speed, intermediate 

phase resettlement, wealth values, and other economic inputs and rates. These results were 

presented in Section F.7.3 of the ER (Exelon 2014a). In response to an NRC staff RAI, Exelon 

confirmed that known SECPOP errors were prevented from influencing the SAMA analysis 

results and that manual entry of population and economic data conformed to formatting 

requirements (Exelon 2015). The NRC staff also requested supporting justification for spatial 

distribution assumptions used in the population projections. Exelon responded by explaining 

that the uniform population distribution within a county overestimates the population within 

80 km (50 mi) of the LSCS site because many of the highly dense population areas lie outside 

the radial distance of 80 km (50 mi), and portions of the highest populated counties that lie 

within that radial distance tend to be more rural, more suburban, and much less populated 

(Exelon 2015). The NRC staff finds the use of block-level census data to be acceptable 

because it is site-specific and more representative than uniformly distributed population 

estimates within a county. Because the applicant provided adequate RAI responses on the 

population projection, and because an additional analysis was performed by the applicant that 
Appendix F

F-22

demonstrated that the current approach was conservative, the NRC staff finds the methods, 

assumptions, and data used for estimating population to be reasonable and acceptable for 

purposes of the SAMA evaluation.

For the 16-km (10-mi) emergency planning zone at LSCS, Exelon considered site-specific 

information in LSCS evacuation time estimates in its determination of evacuation times, time 

delays, and travel speeds. For the baseline Level 3 calculation described in Section F.3.6 of the 

ER (Exelon 2014a), Exelon assumed 95 percent of the population within the emergency 

planning zone would evacuate with an evacuation speed of 1.6 meters per second (3.6 miles 

per hour). In a sensitivity analysis (Exelon 2014a), Exelon reported an increase in the 

population dose risk by 5 percent (negligible change to the offsite economic cost risk) due to an 

assumed factor-of-2 reduction in the average evacuation speed. Because Exelon used 

site-specific information and applied more pessimistic (lower) fractions for the evacuating 

population in the emergency planning zone compared to generic values, the NRC staff 

concludes that the evacuation assumptions and analyses are reasonable and acceptable for the 

purposes of the SAMA analysis at LSCS.

Exelon developed economic values using data from the 2007 National Census of Agriculture 

and Bureau of Economic Analysis for the counties within the 80-km (50-mi) radius of LSCS. 

Exelon updated economic values to a reference timeframe of July 2013 using the consumer 

price index from the Bureau of Labor Statistics. As stated in Table F.3–9 of the ER, weighted 

average wealth values were $283,637/person for nonfarm wealth and $11,937/hectare for 

farmland wealth. The NRC staff considers the values for nonfarm wealth to be reasonable 

ranges that would not be expected to result in underestimates of offsite economic cost risk. 

In response to an NRC RAI on more recent data from the 2012 National Census of Agriculture, 

Exelon assessed the differences and indicated that annual sales of farm products and farm 

wealth values from 2012 were typically larger than the 2007 data adjusted to 2013 values by the 

consumer price index (Exelon 2015). Overall differences in county data for the fraction of 

farmland and fraction of dairy farms were small between the 2012 and 2007 data sets. Having 

calculated that the farm-dependent costs comprise 5 percent of the total offsite economic cost 

risk, Exelon concluded that incorporation of the data from the 2012 National Census of 

Agriculture would not have a significant impact on the SAMA analysis (Exelon 2015). 

Farm-dependent costs do not influence the onsite and replacement power components of the 

total averted cost risk. Given that estimated benefits at the 95th percentile for SAMA candidates 

determined to be not cost beneficial were more than 20 percent below their estimated 

implementation costs in Exelon’s revised analysis (Exelon 2015), the NRC staff concludes that 

incorporation of 2012 agricultural data would not change the determination of cost-beneficial 

SAMAs. Additionally, extrapolation of economic data to the year of the assessment, and not 

through the period of extended operation, is consistent with guidance accepted by NRC 

(NEI 2005). Because Exelon’s assessment included site-specific data and followed an 

approach that is consistent with economic guidance, the NRC staff finds the data sources, 

adjustments, and considerations made by the applicant in the Level 3 analysis to be acceptable

for the SAMA analysis. 

Exelon estimated present dollar values based on the internal events PRA at LSCS and applied 

a multiplication factor of 5.2 to account for external events. As shown in Section F.4.6 of the ER 

(Exelon 2014a), offsite economic costs and offsite exposure costs provided the greatest 

contributions to the total dollar value at approximately 74 and 20 percent, respectively. Onsite 

cleanup and replacement power costs collectively contributed about 6.5 percent to the baseline 

total dollar value for a real discount rate of 3 percent. Onsite exposure costs contributed less 

than 1 percent. Section F.6 provides more detailed information on the cost-benefit calculation 
Appendix F

F-23

and its evaluation. Changes to the maximum averted cost risk as a result of Exelon’s revised 

analysis are presented in Section F.6.1. 

Exelon identified several critical input parameters to the MACCS2 code that potentially impact 

the Level 3 results and performed sensitivity analysis in Section F.7.3 of the ER (Exelon 2014A). 

The sensitivities were compared to the 95th percentile PRA results sensitivity which increases 

the averted cost-risk values for the SAMAs by a factor of 2.14 (214 percent). The 95th

percentile PRA results sensitivity bounded all of the cases and no additional SAMAs were 

identified that were not already identified in Section F.7.2 of the ER. On May 4, 2016, the 

Commission issued a decision (CLI-16-07) in the Indian Point Nuclear Generating Units 2 and 3 

(Indian Point) license renewal proceeding, in which it directed the staff to supplement the Indian 

Point SAMA analysis with additional sensitivity analyses. Specifically, the Commission held that 

documentation was lacking for two inputs (TIMDEC and CDNFRM) used in the MACCS2 

computer analyses, and that uncertainties in those input values could potentially affect the 

SAMA analysis cost-benefit conclusions. The Commission therefore directed the staff to 

perform additional sensitivity analyses. In response to an RAI relating to this Commission 

decision (ADAMS No. ML16188A187), Exelon developed a new MACCS2 TIMDEC and 

CDNFRM combined sensitivity case (TIMDEC CDNFRM) and applied the maximum values 

specified by the Commission (1 year (365 days) for TIMDEC and $100,000 for the CDNFRM 

values for the decontamination factor of 15) to all of the LaSalle release categories (ADAMS

No. ML16193A389). New Offsite Economic Cost Risk (OECR) and Population Dose Risk 

(PDR) values were calculated. The increases to the base case seen in the OECR was 

approximately 54 percent and in the PDR was approximately 2 percent for this TIMDEC 

CDNFRM sensitivity case. These increases are well within the bounds of the 214 percent

increase determined by the baseline with uncertainty (95th percentile) which was included as 

part of the SAMA candidate cost-benefit evaluation documented in Section F.7 of the 

Environmental Report. Therefore, no new SAMA candidates were identified as potentially 

cost-beneficial and no changes were made to the conclusions of the SAMA analysis based on 

this new TIMDEC CDNFRM sensitivity case. The NRC staff finds this determination to be 

acceptable for the SAMA analysis.

Based on its review of Exelon’s submissions, the NRC staff concludes that Exelon’s 

methodology to estimate offsite consequences for LSCS provides an acceptable basis to 

assess the risk reduction potential for SAMA candidates. Because the conservative modeling 

assumptions were included in the assessment and input data were either obtained for the LSCS 

site or found to be consistent with guidance values, the NRC staff concludes that the data and 

modeling assumptions for the Level 3 analysis are appropriate for the SAMA evaluation. 

Accordingly, the NRC staff based its assessment of offsite risk on the core damage frequencies, 

population doses, and offsite economic costs reported by Exelon.

F.3 Potential Plant Improvements

The process for identifying potential plant improvements, an evaluation of that process, and the 

improvements evaluated in detail by Exelon are discussed in this section.

F.3.1 Process for Identifying Potential Plant Improvements

Exelon identified potential plant improvements (SAMAs) by review of:

• LSCS PRA results and PRA group insights;

• Potentially cost-effective Phase 2 SAMAs from
Appendix F

F-24

− Susquehanna Steam Electric Station SAMA Analysis,

− Cooper Nuclear Station SAMA Analysis,

− Duane Arnold Energy Center SAMA Analysis,

− Nine Mile Point Unit 2 SAMA Analysis,

− Columbia Generating Station SAMA Analysis, and

− Grand Gulf Nuclear Station SAMA Analysis;

• LSCS IPE; and

• LSCS IPEEE.

Exelon indicated that in addition to the “Industry Phase 2 SAMA” review identified above, an 

industry-based SAMA list from NEI 05-01 (NEI 2005) was used to help identify the types of

changes that could be used to address the areas of concern identified through the LSCS

importance list review.

Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as 

Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the 

initial list of SAMAs and eliminated SAMAs from further consideration using the following 

criteria:

• Applicability to the plant: If a proposed SAMA does not apply to the LSCS

design or has already been implemented, it is not retained.

• Implementation cost greater than the screening cost: If the estimated cost of 

implementation is greater than the MACR, the SAMA is screened out from 

further analysis.

During this process, SAMA candidates 17 and 26 in Table F.5-4 of the ER (Exelon 2014a) were 

screened out based on exceeding the cost criteria.

11 Table F.6–1 of the ER (Exelon 2014a) 

provides a description of each of the 24 Phase II SAMA candidates, which was later revised to 

25 Phase II SAMA candidates in Exelon’s revised analysis (Exelon 2015).

In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as 

discussed in Sections F.4 and F.6. To account for the potential impact of external events, the 

estimated benefits based on internal events were multiplied by a factor of 5.2, as discussed in 

Section F.2.2.2.

F.3.2 Review of Exelon’s Process

Exelon’s efforts to identify potential SAMAs focused primarily on areas associated with LSCS

specific internal initiating events. The NRC staff reviewed the discussions of the SAMA

identification process and the listing of Phase I candidate SAMAs included in the ER.

The primary source of candidate SAMAs (22 of a total of 26) was the review of the LSCS

Level 1 and Level 2 importance analysis. Four additional SAMAs were identified based on the 

review of other BWR cost-effective SAMAs and the review of external events.

 11 The results of a sensitivity analysis to determine the impact of a correction to the Level 2 model 

discussed above, resulted in one of the Phase I SAMAs (SAMA 26) being retained that was originally 

screened out. 
Appendix F

F-25

In the ER, Exelon provided a tabular listing of the Level 1 PRA basic events sorted according to 

their risk reduction worth (RRW) (Exelon 2014a). These results were reviewed by Exelon to 

identify those potential risk contributors that made a significant contribution to CDF. The RRW 

rankings were reviewed down to 1.01. Events below this point would influence the CDF by less 

than 1 percent and thus were judged, by Exelon, to be highly unlikely contributors for the 

identification of cost-beneficial enhancements. These basic events, which included component 

failures, operator actions, initiating events, and sequence identification markers (or flags), were 

reviewed to determine any additional mitigating actions that may need to be considered.

In the ER, Exelon provides a discussion of the appropriate importance threshold for the 

identification of candidate SAMAs. Guidance in NEI 05-01 indicates that “dominant risk 

contributors” should be considered, but a “dominant” risk contributor was not clearly defined. 

The NEI 05-01 example uses an RRW of 1.005, which corresponds to the ASME/ANS PRA 

Standards (ASME/ANS 2009) definition of risk significant events. A 1 percent change in LSCS

CDF corresponds to approximately 3×10-8 per year compared to Regulatory Guide 1.174 

(NRC 2011) definition that anything less than a 1×10-6 per year is a “very small change.” It is 

noted that an RRW of 1.01 corresponds to a maximum averted cost risk (including external 

events) of approximately $56,000, if it is assumed that a SAMA is 100 percent effective in 

eliminating the events contribution to CDF and that the total cost-risk is proportional to CDF. 

As Exelon indicates, while this is larger than a typically assumed simple procedure change cost 

of $50,000, the cost for a procedure change can vary widely depending on complexity of the 

change and the systems involved.

Considering the above and that (1) the Exelon review of the LSCS importance analyses results 

includes, in addition to basic events, accident sequence markers and the individual contributors 

to these sequences, which effectively results in looking at risk contributors that are lower than 

the RRW threshold; and (2) a separate review of the important contributors to fire and seismic

risk for candidate SAMAs was performed, as discussed below, the NRC staff therefore 

concludes that Exelon’s use of an RRW threshold of 1.01 for identifying candidate SAMAs from 

the Level 1 internal events importance analysis is acceptable.

In the ER, Exelon also provided tabular listings of the Level 2 PRA basic events for the 

combined “High” (H/E-BOC, H/E, H/I), the “Medium Early” (M/E), and the “Medium 

Intermediate” (M/I) release categories. These release categories combine to represent over 

97 percent of the offsite risk. Exelon used an RRW cutoff of 1.03 when reviewing these basic 

events for additional SAMA candidates. While higher than the cutoff used for the Level 1 

review, the NRC staff considers this to be acceptable based on their combined contribution to 

offsite risk, the release frequency of each is a relatively small part of the total release frequency 

(6 to 36 percent), and many of the events are also included in the Level 1 importance review.

The NRC staff developed several RAIs during its review of Exelon’s assessment of SAMAs. 

The following discussion summarizes these RAIs and Exelon’s responses (Exelon 2015).

The NRC staff noted that the turbine trip with bypass initiating event (%TT) is indicated to have 

a frequency of 0.8 per year, which implies that a number of turbine trips with bypass have 

occurred over the LSCS operating history and asked if any of these occurrences suggest 

possible cost-beneficial SAMAs. Exelon responded that the LSCS turbine trip initiating event 

frequency is based on a Bayesian update of a generic prior for the period of 2006−2010, which 

includes two plant-specific events (one for each unit). Review of the two plant-specific events 

used in the Bayesian update indicates that the causes of the events are not related to one 

another, and that the site has taken corrective action to address the root causes of the events. 

These conditions do not imply any outlier behavior at LSCS or indicate that there is a potential 

to identify cost-beneficial SAMAs related to turbine trip events.
Appendix F

F-26

The NRC staff noted that the discussion of potential SAMAs for a significant number of events 

involve water-hammer-induced loss of coolant accidents (LOCAs) related to the generation of a 

LOCA signal on high drywell pressures when an actual LOCA does not exist. These events are 

mitigated by SAMA 7, and the NRC staff asked Exelon to provide more detail on the water 

hammer scenarios and the potential for other SAMAs to mitigate the water-hammer-induced 

core damage. In response, Exelon provided a discussion of the four typical cases associated 

with water hammer events at LSCS and the potential for other SAMAs. Exelon indicated that 

procedures already are in place and credited in the PRA for the operators to prevent residual 

heat removal (RHR) starting (and thereby preventing the conditions that lead to a water 

hammer) for certain scenarios and that installing fast-acting valves (that also would prevent the 

conditions that lead to water hammer) would be expensive and have some adverse 

consequences. Exelon clarified that the “LOOP-delayed LOCA” scenario, that was stated to not 

have been modeled in the PRA, is a series of operator actions required to address the 

automated actuations that occur in some potential water hammer scenarios. These actions are 

not explicitly included in the PRA because the dominant contributors to core damage are 

considered to be the water hammer events. Exelon concluded and the NRC staff agrees that 

including these scenarios in the PRA model would result in a very small change in plant risk that 

would impact neither the SAMA identification process nor the conclusions of the SAMA analysis.

The NRC staff noted that for an event involving an emergency core cooling systems (ECCS)

room cooling fan failing to run, Exelon indicated that previous LSCS evaluations could not 

demonstrate that portable fans would provide adequate cooling for the reactor building corner 

rooms when the normal cooling system failed. Exelon was asked to discuss this previous 

evaluation and if sufficient cooling can be achieved if the portable fans can provide air 

movement through the room coolers, assuming cooling water remains available. In response, 

Exelon provided the results of a cost-benefit assessment for a SAMA that utilized portable fans 

and ducting to provide air flow through modified room coolers. This assessment assumed that 

the previously described commitment to install a reliable hardened pipe containment vent

(SAMA 1) had been implemented thereby resulting in a benefit including uncertainty of 

approximately $42,000 versus a cost of $475,000.

The NRC staff noted that for an event where the operator fails to recover low-pressure systems, 

the discussion indicates that low-pressure systems would not have the power to function. 

Exelon was asked to consider the potential for utilizing a fire truck or other portable 

self-powered pumps for injection into the containment. Exelon responded that SAMA 1 (reliable 

hardened pipe containment vent) with its planned implementation and SAMA 8 (portable 

480V AC generator) were determined to be potentially cost beneficial and are proposed in the 

ER to address the risk contributions from this event. The combination of these two SAMAs 

would help prevent core damage by providing a means for (i) containment heat 

removal/pressure control via the reliable hardened pipe containment vent, and (ii) maintaining 

RPV injection using the existing FPS connection, by providing long-term support for the safety 

relief valves (SRVs) so that they do not reclose and cause RPV re-pressurization. The addition 

of a portable self-powered injection pump without SAMA 8 for these contributors would provide 

very little additional benefit. There would be no apparent reduction in the implementation cost, 

and it would serve the less desirable function of mitigating a core-damage event rather than 

preventing core damage. Exelon concluded and the NRC staff agrees that the use of a portable 

self-powered pump is not considered to be the optimal choice for mitigating the risk associated 

with the cited event.

Exelon’s discussion of the review of industry cost-beneficial SAMAs included Grand Gulf 

SAMA 59 (to increase operator training to alternate the operation of ECCS pumps for 

loss-of-room cooling). Exelon stated that rather than cycling large pumps in scenarios where 
Appendix F

F-27

the cooling system is lost, a more effective means of maintaining injection with the ECCS

pumps is considered to be through the use of portable/temporary cooling alignment, which is 

addressed in the LSCS importance list review by SAMA 16. In an RAI, the NRC staff asked 

Exelon to consider a SAMA similar to Grand Gulf’s SAMA 59 for rooms where the use of 

portable fans may not be effective. In response, Exelon provided a discussion of the various 

cases where use of portable fans may not be effective and pointed out that most are mitigated 

by the hardened pipe containment vent (SAMA 1), which Exelon has already committed to 

installing. Exelon concluded and the NRC staff agrees that once the requirement to install the 

reliable hardened pipe containment vent has been implemented, the potential benefit of a 

procedure change to cycle the ECCS pumps would be small (Exelon 2015).

While the LSCS IPE submittal did not identify any vulnerability, as discussed in the NRC’s IPE 

Safety Evaluation Report, the IPE did cite NUREG/CR–4832, Volume 3, Part 1, for insights into 

potential improvements to:

• Eliminate the sneak circuit in the RCIC isolation logic that results in the RCIC 

steam line inboard isolation valve closing when offsite AC power is lost and 

the appropriate diesel generator starts.

• Change the RCIC room temperature isolation logic so that, in cases where 

AC power from Train A has failed but AC power from Train B is available, this 

isolation logic does not isolate if no other ECCS is working.

• Change the venting procedure so that venting does not result in severe 

environments in the reactor building. 

In response to an NRC staff RAI to discuss the current status of these potential improvements, 

Exelon replied, for the first two improvements listed above, changes have been made so that 

the described sneak circuit and the RCIC isolation no longer exist at LSCS. For the third listed 

improvement, design improvements were considered and dispositioned at the time of the IPE

and no design changes were made at that time to install a hardened pipe containment vent and 

prevent the rupture of the containment vent piping. Rather, procedure changes were made to 

acknowledge the design deficiency and initiate alignment of alternate injection systems prior to 

containment venting, if at all possible. Changes also were made to procedures to control 

containment pressure within a specific range during the venting evolution. The potential for 

containment vent path rupture/failure will be addressed through the installation of the reliable 

hardened pipe containment vent (SAMA 1) (Exelon 2015).

Based on the above discussion, the NRC staff concludes that the set of SAMAs evaluated in the 

ER, together with those identified in response to NRC staff RAIs, addresses the major 

contributors to the CDF for internal events.

As previously discussed, the best available information on seismic and internal fire risk is not 

compatible with the internal events risk model. Consequently, the search for SAMA candidates 

to mitigate these risks was based on a review of the dominant risk contributors identified and 

discussed in Section F.2.2.2.

In the ER, Exelon discussed the dominant seismic risk sequences listed in Table F–4

(Exelon 2014a), remarked that changes to LSCS as well as reanalysis of important failures has 

led to reductions in the significance of several of these sequences, and identified two SAMA

candidates that mitigate the seismic risk. The NRC staff notes that the lowest seismic risk 

contribution considered has a CDF of approximately 1 percent of the CDF for internal events. 

This value corresponds to a benefit of $11,000 if mitigating only the seismic risk, or $56,000 if 

mitigating all the other risk contributors. The NRC staff concludes that this is an acceptably low 
Appendix F

F-28

cutoff for identification of SAMA candidates since it is lower than the typical cost for revising a 

procedure.

The ER also includes a discussion of the contributors to the dominant fire zone risks listed in 

Table F–5 (Exelon 2014a). This discussion describes the important fire scenarios that 

contribute to the fire CDF for this fire zone, the results of a review of the important cutsets, and 

those SAMAs that would reduce the frequency of these fire scenarios. Exelon’s review and 

analysis did not identify any unique SAMAs for mitigating these fire scenarios, but Exelon 

concluded that three of the previous SAMA internal events would significantly impact the fire 

risk.

Exelon noted that the largest unreviewed fire zone represents less than 2.5 percent of the 

overall total CDF, including external events or about $142,000. In response to an RAI to 

consider additional fire zones, Exelon provided a discussion of 15 additional fire zones with 

benefits down to $37,500 per unit. This value was based on a procedure development cost of 

$50,000 for the first unit and half of that for the second unit, averaging $37,500 per unit. The 

contributors to the fire risk for each of these zones were reviewed by Exelon to determine if

there were any procedure changes that could be potentially cost beneficial. The results of this

review are presented in the RAI response on a zone-by-zone basis. No potentially 

cost-beneficial procedure changes were identified (Exelon 2015).

In an RAI, the NRC staff noted that fires in the Division 1 and Division 2 essential switchgear 

rooms for each unit comprise 60 percent of the total fire CDF and that the only SAMA proposed

for mitigating these fires is SAMA 1, installing a reliable hardened pipe containment vent. 

SAMA 1 only mitigates the adverse consequences of venting and does not mitigate the direct 

impact of the fire. The NRC staff asked Exelon to discuss these fire scenarios and the potential 

for other SAMAs to directly mitigate the fire at an earlier stage of the scenario or to mitigate 

events in the cutsets other than adverse conditions due to venting. Exelon indicated that 

79 percent of the contributions are cases in which injection is initially available but subsequently 

fails due to harsh environmental conditions after containment failure. The unavailability of the 

containment vent is due to fire-induced failures associated with vent valve support systems, with 

the vent valve control cables, or both. The reliable hardened pipe containment vent (SAMA 1) 

eliminates support system requirements and would provide a means of preventing the

containment failures and vent path failures that lead to loss of injection capability.

Further, for the remaining 21 percent of the contributors, hardware failures result in the 

unavailability of injection systems, such that even if a containment vent path were available, 

core damage would still occur. The hardware failures are comprised of both failures of the 

4 kV AC power sources that support the injection systems and the failures of the injection 

system components themselves. LSCS already has the B.5.b pump, which can provide this 

RPV injection capability for the long-term scenarios that are characteristic of these contributors, 

but it is not currently credited in the PRA model. LSCS operators have been trained to use the 

B.5.b pump and the current emergency operating procedures include the B.5.b pump as a 

potential alternate RPV injection source that could be used to mitigate the Division 1 and 

Division 2 essential switchgear room fire scenarios. In addition, diverse and flexible coping 

capability, “FLEX” (NRC 2012b), is intended to provide a separate set of portable makeup 

pumps that also could be used to perform this function. While the details of the FLEX changes 

are not finalized, they would further improve the capability of LSCS to respond to these types of 

scenarios (Exelon 2015).

In an RAI, the NRC staff noted that the largest contributing fire scenario to the Auxiliary 

Electrical Equipment Room fire risk is a bounding cable fire caused by hot work but no SAMAs 

were identified to mitigate this risk. The NRC staff asked Exelon to discuss the potential for a 
Appendix F

F-29

SAMA to mitigate this risk. In response, Exelon indicated that the transient fire ignition 

frequency calculated for a fire compartment considers the potential for ignition due to “hot work” 

(cutting, grinding, or welding tasks), among other sources. Based on the 2009 LSCS Fire PRA, 

the hot work influence factor for the Auxiliary Electrical Equipment Room is “low,” which is the 

lowest possible factor for this area. Procedures already are in place that require a fire watch to 

be posted (with portable extinguishers available) and for nearby equipment to be protected 

when “hot work” is being performed. These practices already are accounted for in the fire risk 

evaluation for the Auxiliary Electrical Equipment Room. Based on these considerations, no 

potential SAMAs related to hot work limitations are available that would yield a measurable 

change in Auxiliary Electrical Equipment Room fire risk. Because the hot work is associated 

with a bounding transient fire scenario that is assumed to lead to failure of all equipment in the 

fire compartment, further details are not available to generate additional SAMAs to mitigate the 

fire beyond those associated with the initiating event frequency (Exelon 2015).

As discussed in Section F.2.2.2, the LSCS IPEEE did not provide a definition of vulnerability 

and did not identify any plant improvements resulting from the fire, seismic, or other external 

events analyses. However, the RMIEP report identified two issues in the fire area that were 

“provided to the station for disposition.” These issues were to install tops on the main control 

room electrical panels and to institute an inspection program for penetration seals at the top of 

switchgear panels. As discussed in the ER, these improvements were not implemented. Based 

on the current understanding of fires in electrical panels, such as those installed at LSCS, and 

on industry guidance for the treatment of fire in these panels in NUREG/CR–6285, Exelon

concluded that these two identified potential improvements would not be effective in mitigating 

the associated fire risk.

In an RAI, the NRC staff noted that the RMIEP Summary (NUREG/CR–4832, Volume 1) 

identifies the common cause failures (CCF) of the CSCS cooling water pumps as the dominant 

events in the seismic risk reduction importance assessment. In response to the RAI to discuss 

these events and their importance in the seismic analysis used for SAMA identification, Exelon

discussed the internally cited conflicting information in Volume 1 (Summary) and Volume 8 

(Seismic Analysis) and concluded that CCFs of the CSCS cooling water pumps do not appear 

to drive the results of seismic risk at LSCS. While no SAMAs were generated to directly 

address these specific failures, the consequences of the CCF of the CSCS cooling water pumps 

is essentially a long-term SBO, a scenario previously addressed by SAMAs evaluated in the 

LSCS analysis. SAMA 27 mitigates cases in which RCIC remains available (not failed by 

seismically induced failure of the condensate storage tank), and SAMA 26 reduces the risk

associated with scenarios in which RCIC is not available. These SAMAs are considered by 

Exelon to adequately address any potential contributions from CCF of the CSCS cooling water 

pumps. In addition, Exelon stated that review of the LOOP and dual unit LOOP contributors 

from the LSCS 2013A PRA model indicates that CCFs of the CSCS pumps are low contributors 

to those scenarios. If, as stated in Section 4.5.1 of NUREG/CR–4832 Volume 1, the dominant

seismic sequences are “all seismically induced losses of offsite power and look exactly like the

equivalent internally initiated sequences except that no credit is given for recovering offsite

power,” then the conclusion would be that CCF of the CSCS cooling water pumps are not

significant contributors to seismic risk. Exelon also noted that subsequent to the completion of 

the RMIEP analysis, Commonwealth Edison (now Exelon) performed a review of that study and 

largely used the results as the basis for the combined IPE and IPEEE submittal. Exelon 

indicated that one of the conclusions of the review effort, documented in the executive summary 

of the April 1994 IPE/IPEEE (CECO 1994), is that Commonwealth Edison considered the “Beta 

factor” CCF process used in the RMEIP analysis to be overly conservative (Exelon 2015). As 

stated earlier, the Exelon IPEEE analysis of other external hazards (high winds, tornadoes, 
Appendix F

F-30

external floods, and other external events) did not identify opportunities for improvements for 

these events.

As discussed in Section F.2.2.2, the LSCS external flooding design and capability was 

assessed in the engineering walkdowns and flood hazard reevaluation required for the response 

to the Fukushima Daiichi NTTF’s Recommendation 2.3 (NRC 2012a). The walkdown identified 

deficiencies that are being addressed through the LSCS corrective action program, while the 

results of the hazard reevaluation led to the requirement for the performance of a full external 

flooding integrated assessment, now underway. These issues are being addressed via the 

ongoing Japan Lessons Learned program and implementation of the Fukushima Daiichi NTTF 

recommendations, including NRC Order EA-12-049, “Order to Modify Licenses with Regard to 

Requirements for Mitigation Strategies for Beyond-Design-Basis External Events” (NRC 2012b). 

The NRC staff concludes that for the purposes of SAMA identification, external flooding is 

adequately addressed. Since external flooding is not a significant contributor to plant risk, a 

cost-beneficial SAMA is not likely to be identified. Additionally, the ongoing programs described 

above provide improvements to the external flooding risk that are more conservative than a 

cost-beneficial SAMA.

Regarding the prevention of water hammer events, the NRC staff questioned Exelon about 

potentially lower cost alternatives to SAMA 7 (alter the LOCA signal logic to require both high 

drywell pressure and low RPV water level for initiation of a LOCA signal). In non-LOCA 

transient scenarios, the heat load rejected to the containment is sufficient to prompt the initiation 

of suppression pool cooling (SPC), but even with SPC in operation, the drywell pressure will 

reach 2 psig and a LOCA signal will register. If a consequential LOOP occurs with the LOCA 

signal, the RHR discharge line can drain to the suppression pool in the ~45 seconds between 

RHR pump load shed and the time it is reloaded on the diesel-backed bus, which sets up a 

water hammer condition in the voided pipe. The lower cost alternative would be to change the 

suppression pool cooling operating procedures or practices to reduce the chances of the 2 psi 

high drywell pressure signal being reached for normal transients. In response, Exelon indicated 

that no changes to the LSCS operating procedures would reduce the chance that the 2 psig 

high drywell pressure signal would be reached in the scenarios of interest. The issue is that in 

the scenarios of interest (initiators that result in the loss of containment cooling), SPC does not 

have the capacity to remove enough heat to prevent the containment pressure from exceeding 

2 psig without venting containment in accordance with normal operating procedures to maintain 

containment pressure less than the LOCA signal initiation pressure setpoint. Any changes to 

the suppression pool cooling system operating procedures intended to increase the time 

available between the initiating event and the 2 psig high drywell pressure signal would have a 

very small impact on risk. Human error probabilities (HEPs) are influenced by a number of 

factors, including time available for response. In this case, the HEP for the operator action to 

vent the containment to prevent the high drywell signal is not significantly impacted by timing 

considerations, and increasing the time available to the operators would correlate to very small 

averted cost-risk values. The more difficult mitigating actions for water hammer scenarios are 

associated with the approximate 20-second time interval between the occurrence of the loss of 

the running pump on the LOCA-induced LOOP and the time when the pumps are automatically 

started and reloaded onto the emergency bus. This short time period is not associated with the 

operation of suppression pool cooling; therefore, a SAMA would have no benefit to these 

scenarios. In these scenarios, the operators must put the pump in pull-to-lock to prevent restart 

and then fill and vent the system to ensure a water hammer does not occur (Exelon 2015).

The NRC staff notes that the set of SAMAs submitted is not all-inclusive because additional, 

possibly even less expensive, alternatives can always be postulated. However, the NRC staff 

concludes that the benefits of any additional modifications are unlikely to exceed the benefits of 
Appendix F

F-31

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 Exelon used a systematic and comprehensive process for 

identifying potential plant improvements for LSCS, and that the set of potential plant 

improvements identified by Exelon is reasonably comprehensive and, therefore, acceptable. 

This search included reviewing insights from the plant-specific risk studies, and reviewing plant 

improvements considered in previous SAMA analyses. While explicit treatment of external 

events in the SAMA identification process was limited, the NRC staff has determined that the 

prior implementation of plant modifications and the absence of external event vulnerabilities 

reasonably justify examining primarily the internal events risk results for this purpose.

F.4 Risk Reduction Potential of Plant Improvements

Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II 

evaluation in a revised analysis (Exelon 2015). The SAMA evaluations were generally 

performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit 

of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be 

optimistically low, thereby overestimating the benefit of the SAMA. In other cases, it was 

assumed that the SAMA eliminated all of the risk associated with the proposed enhancement. 

The NRC staff notes that this bounding approach overestimates the benefit and therefore 

is appropriately conservative.

Exelon used model requantification to determine the potential benefits for each of the SAMAs. 

The CDFs, population dose reductions, and offsite economic cost reductions were estimated 

using the LSCS PRA model. The changes made to the model to quantify the impact of each 

SAMA are described in Section F.6 of the ER. Table F–6 summarizes the assumptions used to 

estimate the risk reduction for each evaluated SAMA, the estimated risk reduction in terms of 

CDF percent reduction, population dose, offsite economic cost, and the estimated total benefit 

(present value) of the averted risk. The determination of the benefits for the various SAMAs is 

further discussed in Section F.6.

The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction 

estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that 

resulted from this review follow.

The discussions of SAMA 8 in Section F.6.8 of the ER and SAMA 14 in Section F.6.13 of the 

ER include the statement “Flow from the fire protection system, in its current configuration, is 

only adequate in cases where RCIC....” In response to an RAI to discuss what is meant by 

“current configuration,” and the potential for a SAMA to address the FPS configuration and 

make it possible to use without prior RCIC operation, Exelon responded that there are two major 

issues that preclude the use of the FPS for RPV makeup in early time frames to prevent core 

damage. The first is related to the low flow rate of the makeup path, and the second is related 

to the relatively long time that is required to align the FPS for injection. The connection that is 

currently used to provide RPV makeup from the FPS consists of fire hoses that are manually 

aligned between the FPS header and the feedwater injection lines. The RPV pressure must be

reduced below 75 psig for Unit 1 and 60 psig for Unit 2 to achieve a flow rate of 200 gpm into 

the RPV and would be successful only after 4 hours following initial high pressure injection and 

subsequent RPV depressurization. Prior to 4 hours, decay heat levels would be such that 

200 gpm would be insufficient for RPV makeup. Relative to the second issue, Exelon indicated 

that operator interviews indicate that about 40 minutes are required to establish the flow path 

from the FPS to the RPV. It would not be possible to align this injection path even if adequate 
Appendix F

F-32

flow could be obtained from the FPS to make up for boil-off. Exelon indicated and the NRC staff 

agrees that both of these issues were assumed mitigated by SAMA 18, “Improvement of the 

Connection Between the Fire Protection and Feedwater Systems.” While this SAMA was 

developed to reduce the alignment time such that it would be possible to perform the alignment 

in cases where RCIC injection fails, one of the assumptions made in the SAMA 18 assessment 

was that the improved connection also would improve the flow rate of FPS injection to a point 

where it could provide adequate makeup in loss of all injection scenarios (Exelon 2015).

In Section F.6.13 of the ER, the discussion of SAMA 14 (provide a portable DC source to 

support RCIC and SRV operation) indicates that the PRA model was changed to include a 

lumped event to represent the 480 V AC power source that feeds the Division 1 battery 

chargers. The SAMA description and the basic events cited to be mitigated by this SAMA 

indicated that a DC power source to directly supply an engineered safety feature (ESF) DC 

distribution panel is needed. In response to an RAI to discuss the inclusion of an AC power 

supply in the model, Exelon responded that the description of the PRA model changes related 

to the lumped event that was added to “represent the 480V AC power source that feeds the 

Division 1 battery charger” is erroneous and that the text should read “a lumped event was 

added to represent the 125 V DC generator that would supply 125 V ESF DC distribution 

panel 1(2)11Y.” The detailed PRA model change descriptions documented in Section F.6.13 of 

the ER accurately describe how the lumped event (basic event ID “SAMA 14”) was incorporated 

into the PRA model for SAMA 14 (Exelon 2015).

In an RAI, the NRC staff noted that SAMA 7 (water hammer prevention) and SAMA 25 (periodic 

training on water hammer scenarios resulting from a false LOCA signal) both are intended to 

mitigate the water hammer scenarios involving SPC operation interrupted by a LOOP. The 

changes made to the model and the impacts on population dose risk and offsite economic cost 

risk are significantly different for the two SAMAs. In response to the NRC staff RAI to discuss 

these SAMAs and their analyses in more detail to justify these differences, Exelon responded 

that SAMA 7 and SAMA 25 are different approaches to addressing the risk associated with 

water hammer events at LSCS. While the different approaches might be expected to lead to 

some differences in the CDF and risk impact of the two SAMAs, the difference in person-rem 

and offsite economic risk impacts reported in the ER was found to be due to a recently 

discovered error in a supporting spreadsheet calculation for SAMA 25. Exelon provided 

corrected values in the RAI response and indicated that the reduced benefit for SAMA 25 

changed its disposition from cost beneficial to not cost beneficial (Exelon 2015). The NRC staff 

agrees that these values are correct.

The NRC staff noted that SAMA 9 (Develop flood zone specific procedures) and SAMA 11 

(Provide the capability to trip the FPS pumps) both address internal flooding; whose principal 

contributor is a FPS pipe rupture in the reactor building. The assumption that all of the relevant 

internal flooding risk will be eliminated by implementing SAMA 9, lowers the overall CDF by

9 percent and results in this SAMA being cost beneficial. As stated in Section F.6.11 of the ER, 

SAMA 11 is designed to eliminate the FPS’s flow. For SAMA 11, there is less than a 2 percent 

reduction in CDF. In response to an RAI to discuss the FPS design, the FPS pipe break 

scenarios, and associated modeling to support the above results, Exelon responded that the 

primary reason for the significant difference between SAMA 9 and SAMA 11 risk reductions is 

that they target different portions of flooding risk. SAMA 9 targets all flooding initiators while 

SAMA 11 targets only a subset of FPS flooding scenarios. SAMA 9 was conservatively 

modeled by assuming that it eliminated all internal flooding risk. The 9 percent reduction in CDF 

is consistent with the CDF values reported for the internal flooding initiators in Table F.2–2 of 

the ER. SAMA 11 provides only a means of tripping the FPS pumps in the main control room, 

which helps reduce the risk of FPS flooding events that require a rapid response (i.e., large 
Appendix F

F-33

breaks) but would only have a small impact on the longer term FPS flooding scenarios. Since 

SAMA 11 only improves the reliability of one human action in the PRA model, only a small

improvement in CDF is expected. In contrast, SAMA 9 improves the reliability of all human 

response actions to all flood scenarios and, therefore, has a larger overall impact on the model

(Exelon 2015).

The NRC staff reviewed Exelon’s bases for calculating the risk reduction for the various plant 

improvements and concludes, with the above clarifications and corrections, that the rationale 

and assumptions for estimating risk reduction are reasonable and generally conservative 

(i.e., the estimated risk reduction is higher than what would actually be realized). Accordingly, 

the NRC staff based its estimates of averted risk for the various SAMAs on Exelon’s risk 

reduction estimates.
F-34

Table F–5. SAMA Cost-Benefit Screening Analysis for LSCS Station(a)

Individual SAMA and Assumption

% Risk Reduction(b) Total Bene

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Ba

U

p

1 – INSTALL RELIABLE HARD PIPE CONTAINMENT VENT 28 36 43 2.5M 

SAMA 1 Modeling: The model was modified by eliminating the support system dependencies, improving the reliability of th

reflect simplification of the controls, and eliminating the events related to vent path rupture and leakage.

2 – AUTOMATE SUPPRESSION POOL COOLING 14 20 25 1.4M 

SAMA 2 Modeling: The fault tree incorporated the automation of suppression pool cooling alignment by changing the inde

IDs for suppression pool cooling initiation to alternate IDs. This accomplishes two functions: (i) assignment of alternate fa

are representative of an automated function, and (ii) prevent the recovery logic from identifying suppression pool cooling in

human actions and preclude the suppression pool cooling initiation failures from dependent human error combinations.

3 – PASSIVE VENT PATH 36 51 61 1.0M 

SAMA 3 Modeling: The basic event for the operator action for venting was replaced with a new placeholder event with a v

the creation of dependent operator actions, including the vent action). The hardware failures associated with the vent path 

retained to approximate the potential failures of the rupture disk (with the support system dependencies removed).

4 – INSTALL A KEYLOCK MSIV LOW LEVEL ISOLATION 

BYPASS SWITCH 16 12 10 674K 

SAMA 4 Modeling: The independent human error probability to bypass the main steam isolation valve low level isolation i

and the joint human error probabilities that include this action have been eliminated.

5 – AUTOMATE SBLC INITIATION 8 7 6 386K 

SAMA 5 Modeling: The automatic SBLC initiation capability is modeled by manipulation of associated basic events. Early 

event ID (2SLOP-LVLCTRLH--) was changed to “SAMA5” and set to a probability of 10‒6 to reduce the independent failure 

value and prevent the inclusion of dependent operator action combinations with SBLC initiation failures, consistent with the 

6 – CREATE ECCS SUCTION STRAINER BACKFLUSH 

CAPABILITY WITH RHRSW 1 1 1 87K 

SAMA Modeling: The contribution related to common cause failure strainer clogging was eliminated by setting the corresp

the cutset files to zero.
F-35

Individual SAMA and Assumption

% Risk Reduction(b) Total Bene

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Ba

U

p

7 – WATER HAMMER PREVENTION 7 <1 <1 51K 

SAMA 7 Modeling: Water hammer events were eliminated from the results through manipulation of the cutsets. The relev

scenarios are all characterized by two events that identify the residual heat removal train that is placed in suppression poo

response to the high suppression pool temperature. Setting these events to zero approximates the impact of eliminating t

events associated with the LOCA signal actuated solely on high drywell pressure.

8 – OBTAIN A 480V AC PORTABLE GENERATOR TO SUPPLY 

THE 125V DC BATTERY CHARGERS AND PROCEDURALIZE ITS 

USE

4 4 4 259K 

SAMA 8 Modeling: The 480V AC generator capability has been approximated by adding the diesel fire pump as a low pre

for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represen

source that feeds the Division 1 battery chargers.

9 – DEVELOP FLOOD ZONE SPECIFIC PROCEDURES 9 3 3 224K 

SAMA 9 Modeling: Initiating event frequencies for flooding events were set to zero in the cutsets.

10 – CHANGE THE LOGIC TO CLOSE THE TURBINE DRIVEN 

FEEDWATER PUMP DISCHARGE VALVES WHEN THE PUMPS 

ARE NOT RUNNING

9 21 23 1.3M 

SAMA 10 Modeling: The human failure event associated with closing the turbine driven feedwater pump discharge valves 

event with a failure probability of 10‒4. This treatment reduces the independent contribution of the isolation failure and pre

of dependent human error combination, including the operator action to isolate the valves.

11 – PROVIDE THE CAPABILITY TO TRIP THE FPS PUMPS 

FROM THE MAIN CONTROL ROOM 2 <1 <1 21K 

SAMA 11 Modeling: The human failure event associated with tripping the fire protection pumps and isolating the service w

fire protection header is not used in any dependent operator action combinations, so this SAMA was modeled by changing 

probability for the operator action in the cutsets.

12 – CROSSTIE THE HIGH PRESSURE CORE SPRAY AND 

FEEDWATER INJECTION LINES FOR ATWS MITIGATION 19 21 16 1.1M 

SAMA 12 Modeling: This SAMA makes use of an existing injection system (high pressure core spray) to provide high pres

scenarios. This SAMA eliminates the contribution of all ATWS events by setting the accident Class IV flag (RCVCL-4A) to 
F-36

Individual SAMA and Assumption

% Risk Reduction(b) Total Bene

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Ba

U

p

14 – PROVIDE A PORTABLE DC SOURCE TO SUPPORT RCIC 

AND SRV OPERATION 9 7 7 444K 

SAMA 14 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low pressur

SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent th

source that feeds the Division 1 battery chargers.

15 – TIE RHRSW TO THE LPCS SYSTEM FOR ISLOCA 

MITIGATION 37 57 57 3.4M 

SAMA 15 Modeling: Changes were made to both the main fault tree and the recovery fault tree. The cross-tie was assum

injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHR

ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the c

logic was added at the sequence level for BOC and ISLOCA sequences where credit was not previously taken for any low 

systems. The logic also was added to the existing fault tree structure in scenarios where venting or containment failure re

injection systems.

16 – PROVIDE PORTABLE FANS FOR ALTERNATE ROOM

COOLING IN THE CSCS VAULTS 14 12 15 866K 

SAMA 16 Modeling: The alternate CSCS room cooling capability was approximated by deleting the gates associated with 

(excluding the automatic initiation failures, which are already addressed in the model).

18 – IMPROVE THE CONNECTION BETWEEN THE FIRE 

PROTECTION AND FEEDWATER SYSTEMS 9 9 10 609K 

SAMA 18 Modeling: The fault tree was updated to credit the FPS in the places where LPCI and LPCS are credited, but th

the LOCA and IORV initiating event and for water hammer scenarios. In addition, the logic was changed to include the FP

the early SBO scenarios in which the ADS is available for those sequences not impacted by the LPCS-LPCI gate.

19 – PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 

TO THE LPCS SYSTEM FOR LOCA MITIGATION 38 58 58 3.4M 

SAMA 19 Modeling: The inclusion of the RHRSW-LPCS cross-tie required changes to both the main fault tree and the rec

cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the 

(existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an e

failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences where 

previously taken for any low pressure injection systems. The logic also was added to the existing fault tree structure in sce

or containment failure resulted in the loss of injection systems.
F-37

Individual SAMA and Assumption

% Risk Reduction(b) Total Bene

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Ba

U

p

20 – IMPROVE VACUUM BREAKER RELIABILITY BY INSTALLING 

REDUNDANT VALVES IN EACH LINE 1 2 2 113K 

SAMA 20 Modeling: The installation of the redundant vacuum breakers is modeled by setting the probability of the vacuum 

reclose to zero. It is assumed that there are no negative consequences associated with installing the redundant vacuum b

failure to open probability of the vacuum breakers is not increased).

21 – INSTALL AUTOMATIC ATWS LEVEL CONTROL SYSTEM 14 14 12 754K 

SAMA 21 Modeling: The SAMA is modeled by setting the early and late level control actions to zero in the fault tree.

22 – HYDROGEN IGNITORS IN PRIMARY CONTAINMENT <1 1 1 34K 

SAMA 22 Modeling: The SAMA is modeled by setting the failure probability of hydrogen detonation to zero in the cutsets.

23 – ENHANCE FUEL POOL EMERGENCY MAKEUP PUMP

AND CONNECTION 27 46 52 3.0M 

SAMA 23 Modeling: The inclusion of the fuel pool emergency makeup pump cross-tie required changes to be made to bo

and the recovery fault tree. The cross-tie was assumed to require the residual heat removal B injection path (existing logic 

system). The logic was added to the existing fault tree structure in scenarios where venting or containment failure resulted 

systems.

24 – PROVIDE INTER DIVISION 4 KV AC CROSSTIE CAPABILITY 5 5 6 367K 

SAMA 24 Modeling: The implementation of the inter-division cross-tie is modeled by including the other two diesel genera

as potential power supply sources for a given emergency bus.

25 – PERIODIC TRAINING ON WATER HAMMER SCENARIOS 

RESULTING FROM A FALSE LOCA SIGNAL 5 <1 <1 42K 

SAMA 25 Modeling: This SAMA was modeled by changing basic event values in the cutsets to reflect the improved reliab

venting action for preventing a LOCA signal in non-LOCA cases.

26 – SEISMICALLY QUALIFIED LOW-PRESSURE RPV MAKEUP 

CAPABILITY 28 33 39 2.3M 

SAMA 26 Modeling: Changes were made to both the main fault tree and the recovery fault tree. Logic was added to the e

structure in scenarios where LPCI and LPCS are credited and where containment failure results in the loss of injection sys

environmental conditions. Logic was included in the fault tree preclude credit for loss of inventory scenarios where the 600 

makeup rate may be inadequate (e.g., LOCA events and makeup to prevent RPV melt-through).
F-38

Individual SAMA and Assumption

% Risk Reduction(b) Total Bene

CDF

Population 

Dose OECR

Baseline 

(Internal + 

External)

Ba

U

p

27 – PRECLUDE EMERGENCY DEPRESSURIZATION WHEN 

RCIC IS THE ONLY INJECTION SYSTEM AVAILABLE AND 

PROVIDE LONG-TERM DC POWER

4 3 3 196K 

SAMA 27 Modeling: The SAMA is modeled by setting the failure probability of sequences in which RCIC is initially operati

in the cutsets.

(a) SAMAs in bold are potentially cost beneficial. Potentially cost-beneficial SAMAs relate to both LSCS units, Unit 1 and Unit 2.

(b) Risk reduction percentages displayed in this table were obtained from the ER (Exelon 2014a) prior to Exelon’s revised results (Exelon 

percentages for the revised benefit results were not provided.

(c) Exelon identified potentially cost-beneficial SAMAs by comparing the total benefit with uncertainty at the 95th percentile to the estima

Total benefit and cost values presented in this table were obtained from Exelon’s revised results (Exelon 2015).

Key: AC = alternating current; ADS = automatic depressurization system; ATWS = anticipated transients without scram; BOC = break o

CDF = core damage frequency; CSCS = core standby cooling system; DC = direct current; ECCS = emergency core cooling system; 

system; ID = identification; IORV = inadvertent/stuck open relief valve; ISLOCA = interfacing-systems loss-of-coolant accident; LPCI = 

injection; LPCS = low pressure core spray; LOCA = loss-of-coolant accident; LSCS = LaSalle County Station; MSIV = main steam iso

OECR = offsite economic cost risk; RCIC = reactor core isolation cooling; RHRSW = residual heat removal service water; RPV = reac

SAMA = severe accident mitigation alternative; SBO = station blackout; SBLC = standby liquid control; SRV = safety relief valve

Sources: Exelon 2014a, 2015
Appendix F

F-39

F.5 Cost Impacts of Candidate Plant Improvements

Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other 

licensees’ estimates for similar improvements and the development of site-specific cost 

estimates where appropriate.

SAMA cost estimates were based on initial hardware, installation, and implementation costs. 

In response to an NRC staff RAI to provide further information as to what was included in the 

LSCS cost estimates, Exelon clarified that maintenance and testing costs during the license 

renewal period were conservatively not included in the estimate (Exelon 2015).

The NRC staff reviewed the applicant’s cost estimates presented in Section F.6 of the ER 

(Exelon 2014a). For certain improvements, the NRC 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.

The NRC staff noted that a few SAMAs (e.g., 8, 14, and 27) involve the use of equipment that 

may be available as a result of the B.5.b program and asked Exelon to discuss this further and 

the impact on the cost-benefit analysis. Exelon responded that the B.5.b program at LSCS

includes a small generator that is used to support two individual SRV solenoids to hold the 

SRVs open after 125V DC battery depletion, but the generator does not power the station 

battery chargers and it is not designed to support the RCIC system through direct DC feeds. 

Because of these limitations, the B.5.b generator is not a viable substitute for the generators 

that have been proposed for SAMAs 8, 14, and 27; therefore, the availability of the 

B.5.b generator would not reduce the implementation costs for these SAMAs. With the above 

clarifications, the NRC staff concludes that the cost estimates provided by Exelon are sufficient 

and appropriate for use in the SAMA evaluation.

F.6 Cost-Benefit Comparison

Exelon’s cost-benefit analysis and the NRC staff’s review are described in the following 

sections.

F.6.1 Exelon’s Evaluation

The methodology used by Exelon was based primarily on NRC’s guidance for performing 

cost-benefit analysis, NUREG/BR–0184 (NRC 1997a) and industry guidance (NEI 2005) 

endorsed by NRC. As described in Section F.4 of the ER (Exelon 2014a), the modified 

maximum averted cost risk (MMACR) was determined for each SAMA according to the 

following formula, which the staff accepts as mathematically equivalent to the formula in the 

NUREG/BR–0184: 

MMACR = EEM (WPHA + WEA + WO + WCD + WRP) 

where

EEM = external event multiplier (unitless)

WPHA = present value of averted offsite exposure cost ($)

WEA = present value of averted offsite economic cost ($)

WO = present value of averted onsite exposure cost ($)
Appendix F

F-40

WCD = present value of averted onsite cleanup cost ($)

WRP = present value of averted replacement power cost ($)

Exelon’s derivation of each of the associated costs is presented separately in this section. For

each SAMA, the applicant’s analysis determined percentage reductions in population dose risk 

(PDR%), offsite economic cost risk (OECR%), and onsite cost risk (OCR%). The internal and 

external benefit from the implementation of an individual SAMA is determined from these 

percentage reductions and their associated present value costs according to the following 

formula:

SAMA Benefit = EEM [PDR% WPHA + OECR% WEA + OCR% (WO + WCD + WRP)]

For each SAMA, the estimated benefit is compared to the cost of implementation. If the cost of 

implementing the SAMA is larger than the benefit associated with the SAMA, the SAMA is not 

considered to be cost beneficial. If the cost of implementing the SAMA is smaller than the 

benefit associated with the SAMA, the SAMA is considered to be cost beneficial. In the ER, 

Exelon calculated the net value for individual SAMAs in a similar manner. Positive net values 

indicated a potentially cost-beneficial SAMA, and negative net values implied that the SAMA 

was not cost beneficial.

In accordance with NUREG/BR–0058 guidance (NRC 2004) that states present worth estimates 

should be developed using both the 3 percent and 7 percent discount rates, Exelon conducted a 

baseline analysis using the 3 percent discount rate and a sensitivity analysis using the 7 percent 

discount rate (Exelon 2014a). Additional sensitivity analyses were performed by the applicant to 

quantify influences on the calculated benefits from the 95th percentile PRA results, offsite 

consequence modeling parameter changes, and assumed implementation of a hardened pipe 

containment vent. Additional details on the sensitivity analysis are presented in Section F.6.2.

Averted Offsite Exposure Cost (WPHA)

Exelon defined WPHA cost as the monetary value of accident risk avoided from population doses 

after discounting (Exelon 2014a). The WPHA costs were calculated using the following formula:

WPHA = Averted public dose risk (person-rem per year)

× monetary equivalent of unit dose ($2,000 per person-rem)

× present value conversion factor (NRC 1997a)

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 because of a single accident. Rather, it is the present value of a stream of potential 

losses extending over the remaining lifetime (in this case, the 20-year renewal period) of the 

facility. Thus, it reflects the expected annual loss caused by 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 a discount rate of 3 percent, 

Exelon calculated the WPHA cost of $213,863 due to internal events in the ER (Exelon 2014a).

Averted Offsite Economic Cost (WEA)

Exelon defined WEA as the monetary value of risk avoided from offsite property damage after 

discounting (Exelon 2014a). The WEA values were calculated using the following formula:

WEA = Annual offsite property damage risk before discounting in dollars per year

× present value conversion factor (NRC 1997a)

For a discount rate of 3 percent, Exelon calculated the WEA cost of $802,484 due to internal 

events in the ER (Exelon 2014a).
Appendix F

F-41

Averted Onsite Exposure Cost (WO)

Exelon defined WO as the avoided onsite exposure (Exelon 2014a). Similar to the WPHA

calculations, the applicant calculated costs for immediate onsite exposure. Long-term onsite 

exposure costs were calculated consistent with guidance in the Regulatory Analysis Technical 

Evaluation Handbook (NRC 1997a), which included an additional term for accrual of 

long-term doses.

Exelon derived the values for averted occupational exposure from information provided in 

Section 5.7.3 of the Regulatory Analysis Technical Evaluation Handbook (NRC 1997a). Best 

estimate values providing for an immediate occupational dose (3,300 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 using the equations provided in the handbook 

in conjunction with a monetary equivalent of unit dose of $2,000 per person-rem, a real discount 

rate of 7 percent, and a time period of 20 years to represent the license renewal period. 

Immediate and long-term onsite exposure costs were summed to determine the WO cost. For a 

discount rate of 3 percent, Exelon calculated the WO cost of $1,597 due to internal events in the 

ER (Exelon 2014a).

Averted Onsite Cleanup Cost (WCD)

Exelon defined WCD as the avoided cost for cleanup and decontamination of the site 

(Exelon 2014a). The applicant derived the values for WCD based on information provided in 

Section 5.7.6 of NUREG/BR–0184, the Regulatory Analysis Technical Evaluation Handbook

(NRC 1997a). 

Averted cleanup and decontamination costs were calculated using the following formula:

WCD = Annual CDF × 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 Technical Evaluation Handbook to be $1.5×109 (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 a discount rate of 3 percent, Exelon calculated the 

WCD cost of $50,284 due to internal events in the ER (Exelon 2014a).

Averted Replacement Power Cost (WRP) 

Exelon defined WRP as the avoided costs of replacement power (Exelon 2014a). Long-term 

replacement costs were calculated using the following formula:

WRP = Annual CDF × present value of replacement power for a single event 

× factor for remaining service years for which replacement power is required

× reactor power scaling factor

Exelon based its calculations on the net electric output for LSCS, specifically 

1,210 megawatt-electric (MWe), and scaled up from reference plant value of 910 MWe specified 

in NUREG/BR–0184 (NRC 1997a). For a discount rate of 3 percent, Exelon calculated WRP

costs of $18,955 due to internal events in the ER (Exelon 2014a).

Modified Maximum Averted Cost Risk (MMACR)

Using the above equations and an annual CDF of 2.58×10‒6, Exelon estimated the total present 

dollar value equivalent associated with completely eliminating severe accidents caused by 

internal events, referred to as the MACR, to be about $1,087,183 at a single unit for a discount 

rate of 3 percent in the ER (Exelon 2014a). In Exelon’s revised analysis, the MACR increased 

to approximately $1,168,000. To account for the risk contributions from external events and 
Appendix F

F-42

yield the internal and external benefit, Exelon selected an external event multiplier (EEM) value 

of 5.2 for LSCS, as described in Section F.4.6.2 of the ER (Exelon 2014a). By multiplying 

MACR and EEM, Exelon estimated MMACR to be about $5,657,600 for a single unit with a 

discount rate of 3 percent, as presented in Section F.4.6.3 of the ER (Exelon 2014a). In 

Exelon’s revised analysis, the MMACR increased to $6,073,600 (Exelon 2015). As described 

above in the SAMA benefit formula, components of the MMACR calculation factor into the 

benefit determination for individual SAMAs. When Exelon revised its analysis in response to 

RAIs from the NRC staff, updates were not presented for the individual components of MACR 

(WPHA, WEA, WO, WCD, WRP).

Exelon’s Results

If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 

was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 

SAMA candidate was considered to be potentially cost beneficial. Results of the cost-benefit 

evaluation are presented in Table F–5. Exelon’s cost-benefit analysis identified 14 SAMA 

candidates determined to be potentially cost beneficial at the 95th percentile on an individual 

basis:

• SAMA 2: Automate suppression pool cooling.

• SAMA 3: Passive vent path.

• SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level 

isolation bypass switch.

• SAMA 5: Automate standby liquid control (SBLC) initiation.

• SAMA 8: Obtain a 480 V AC portable generator to supply the 125 V DC 

battery chargers and proceduralize its use.

• SAMA 9: Develop flood zone specific procedures.

• SAMA 10: Change the logic to close the turbine driven feedwater pump 

discharge valves when the pumps are not running.

• SAMA 14: Provide a portable DC source to support RCIC and SRV 

operation.

• SAMA 15: Tie RHRSW to the low-pressure core spray (LPCS) system for 

interfacing systems loss-of-coolant accident (ISLOCA) mitigation.

• SAMA 16: Provide portable fans for alternate room cooling in the CSCS 

vaults.

• SAMA 18: Improve the connection between the fire protection and 

feedwater systems.

• SAMA 19: Provide remote alignment capability of RHRSW to the LPCS 

system for LOCA mitigation.

• SAMA 21: Install Automatic ATWS level control system.

• SAMA 23: Enhance fuel pool emergency makeup pump and connection.

When the planned installation of a hardened pipe containment vent is considered as the base 

case, the number of SAMA candidates considered to be potentially cost beneficial at the 

95th percentile may decrease. Because a new baseline is established following the 

implementation of a SAMA, which further influences the benefits provided by the remaining 
Appendix F

F-43

SAMA candidates, Exelon defined an optimal set to containing SAMAs that, if implemented, 

would render the remaining SAMAs to be not cost beneficial. Acknowledging Exelon’s planned 

installation of the hardened pipe containment vent (SAMA 1), additional modifications included 

in the optimal set are SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). 

Assessment of the optimal set was performed prior to Exelon generating revised results in 

response to the NRC staff’s RAIs (Exelon 2015). Exelon is referring the 14 potentially 

cost-beneficial SAMAs from its revised analysis (Exelon 2015) to the LSCS Plant Health 

Committee for further implementation considerations within the established plant procedural 

process, as indicated in Section 4.15 of the ER (Exelon 2014d).

F.6.2 Review of Exelon’s Cost-Benefit Evaluation

During its review of the cost-benefit analysis performed by Exelon, the NRC staff compared the 

applicant’s approach with guidance in NUREG/BR–0184 (NRC 1997a) and discount rate 

guidelines in NEI 05-01 (NEI 2005). NEI guidance states that two sets of estimates should be 

developed for discount rates of 7 percent and 3 percent (NEI 2005). Exelon performed 

assessments using both discount rates. Exelon provided a baseline set of results using a 

discount rate of 3 percent. For the other types of potential sensitivity analyses suggested 

(NEI 2005), the NRC staff finds that Exelon’s information provided in the ER submittal and 

subsequent RAI responses on plant modifications, peer review findings or observations, and 

evacuation speeds have been adequately addressed in the baseline analysis, as discussed in 

this appendix. As previously indicated, Exelon performed the cost-benefit evaluation using an 

analysis time period of 20 years. Because Exelon explicitly accounted for uncertainty in its 

sensitivity analysis by applying a multiplication factor of 2.14 and the results of the sensitivity 

analysis were used to identify additional potentially beneficial SAMAs, the NRC staff finds that 

an additional sensitivity analysis for a timeframe longer than 20 years is not necessary. 

Although longer timeframes would increase estimated benefits compared to baseline results, 

the 20-year timeframe is consistent with the later expiration month of December 2043 for a 

renewed license of Unit 2 stated in Section 1.1 of the ER (Exelon 2014a), and it is unlikely that 

influences from a longer timeframe would exceed the factor of 2.14 already considered by 

Exelon. Based on its review of the applicant’s cost-benefit evaluation, the NRC staff determined 

that the applicant’s approach is consistent with the guidance and acceptable.

The applicant considered possible increases in benefits from analysis uncertainties on the 

results of the SAMA assessment. In the ER (Exelon 2014a), Exelon indicated that the 

95th percentile value of the LSCS CDF was greater than the mean CDF by a factor of 2.14, and 

thus, a multiplication factor of 2.14 was selected to account for uncertainty. This multiplication 

factor was applied in addition to the separate external events multiplication factor of 5.2 

(Exelon 2014a). Exelon’s assessment accounted for the potential risk-reduction benefits 

associated with both internal and external events. The NRC staff considers the multipliers 

of 2.14 for uncertainty and 5.2 for external events at LSCS to provide an adequate margin and 

are, therefore, acceptable for the SAMA analysis. 

Using Exelon’s information presented in the ER (Exelon 2014a), the NRC staff spot checked the 

applicant’s calculations of delta CDF (i.e., percentage reduction in CDF due to accumulated 

differences in the release categories for a specific SAMA candidate compared to the base 

case), population dose risk, and offsite economic cost risk. By applying the formula for SAMA 

benefit presented in Section F.6.1 and comparing the results with those presented in the ER 

(Exelon 2014a), the NRC staff found the results to be in agreement and within small round-off 

errors.
Appendix F

F-44

Exelon’s revised cost-benefit analysis identified 14 SAMA candidates as potentially cost 

beneficial at the 95th percentile (Exelon 2015). From its sensitivity analyses in the ER, no 

additional SAMA candidates were determined to be potentially cost beneficial. As described in 

Section F.3.2, the NRC staff asked the applicant to evaluate potentially lower cost alternatives

to SAMA 7. From its review of the original SAMA analysis and additional information, the NRC 

staff agrees with Exelon’s disposition of potentially lower cost alternatives.

Because Exelon’s cost-benefit evaluations have been reviewed by the NRC staff and Exelon 

satisfactorily addressed NRC staff questions regarding the evaluations, the NRC staff concludes 

that the cost-benefit evaluations are of sufficient quality to support the SAMA evaluation. 

Therefore, the NRC staff concludes that, with the exception of the potentially cost-beneficial 

SAMAs discussed above, the costs of the other SAMAs evaluated would be higher than their

associated benefits and not cost beneficial.

F.7 Conclusions

Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 

updated probabilistic safety assessment models, SAMA-related industry documentation, 

plant-specific enhancements, and its review of SAMA candidates from potential improvements 

primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 

SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 

been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 

costs and benefits associated with each of the 25 potential SAMAs shown in Table F–5. Exelon 

concluded that 14 SAMA candidates were potentially cost beneficial at the 95th percentile. 

Despite it being not cost beneficial, Exelon has decided to proceed with the modification to 

install a hardened pipe containment vent regardless of cost. Exelon also performed a sensitivity 

analysis, and no additional SAMA candidates were identified as potentially cost beneficial. 

Because the potentially cost-beneficial SAMAs do not relate to aging management during the 

period of extended operation, their implementation is not required as part of license renewal 

pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.” Nevertheless, as stated in 

Section 4.15 of the ER (Exelon 2014d), Exelon indicated that the potentially cost-beneficial 

SAMAs are being referred to the LSCS Plant Health Committee for further implementation

considerations within the established plant procedural process.

The NRC staff reviewed Exelon’s SAMA analysis and concludes that the methods used and the 

implementation of the methods were sound. On the basis of the applicant’s treatment of SAMA 

benefits and costs, the NRC staff finds that the SAMA evaluations performed by Exelon are 

reasonable and sufficient for the license renewal submittal. The NRC staff concurs with 

Exelon’s conclusion that 14 SAMA candidates are potentially cost beneficial for LSCS and notes 

that Exelon’s assessment was based on generally conservative treatment of costs, benefits, and 

uncertainties. Based on the NRC staff’s review of Exelon’s SAMA evaluations, including 

Exelon’s response to the NRC staff’s RAIs, the NRC staff concludes that Exelon has adequately 

identified areas where 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 NRC staff concludes that further evaluation by Exelon of the 

14 SAMA candidates identified by Exelon as being potentially cost beneficial is warranted.

The NRC staff also evaluated whether any of the potentially cost-beneficial SAMAs identified 

are subject to aging management such that they would be within the scope of license renewal. 

The evaluation considered any structures, systems, and components associated with these 

SAMAs that perform intended functions without moving parts or without a change in 
Appendix F

F-45

configuration or properties and would not be subject to replacement based on a qualified life or 

specified time period. The NRC staff determined that 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 in accordance with 

10 CFR Part 54.

F.8 References

10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.”

[ASME/ANS] (American Society of Mechanical Engineers/American Nuclear Society). 2005. 

Addenda RA-Sa-2003 and RA-Sb-2005 to ASME RA-S-2002, Standard for Probabilistic Risk 

Assessment for Nuclear Power Plant Applications. December 2005.

[ASME/ANS] American Society of Mechanical Engineers and American Nuclear Society. 2009.

Addenda to ASME/ANS RA-S–2008, Standard for Level 1/Large Early Release Frequency 

Probabilistic Risk Assessment for Nuclear Power Plant Applications. New York, NY: ASME. 

ASME/ANS RA-Sa-2009. February 2, 2009. 352 p. This document is proprietary and available 

for sale on www.asme.org.

[CECO] Commonwealth Edison Company. 1994. LaSalle County Nuclear Power Station, 

Individual Plant Examination and Individual Plant Examination (External Events). April 1994.

[Exelon] Exelon Generating Company, LLC. 2012a. “Seismic Walkdown Report In Response 

To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 

Recommendation 2.3: Seismic for the LaSalle County Station, Unit 1, Report Number: 

12Q0108.50-R-001, Revision 1. November 27, 2012. ADAMS No. ML12353A225.

[Exelon] Exelon Generating Company, LLC. 2012b. “Seismic Walkdown Report In Response 

To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 

Recommendation 2.3: Seismic for the LaSalle County Station, Unit 2, Report Number: 

12Q0108.50-R-002, Revision 1. November 27, 2012. ADAMS No. ML12353A207.

[Exelon] Exelon Generation Company, LLC. 2014a. “Applicant’s Environmental Report, 

Operating License Renewal Stage, LaSalle County Station. Appendix F: Severe Accident 

Mitigation Alternatives Analysis.” ADAMS No. ML14343A897. December 2014. 

[Exelon] Exelon Generation Company, LLC. 2014b. Letter from Glen T. Kaegi to NRC 

Document Control Desk. Subject: Exelon Generation Company, LLC, Seismic Hazard and 

Screening Report (Central and Eastern United States (CEUS) Sites), Response to NRC 

Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the 

Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident. Exelon letter 

RS-14-068. March 31, 2014. ADAMS No. ML14091A013.

[Exelon] Exelon Generation Company, LLC. 2014c. Letter from T. John Conner to NRC 

Document Control Desk. Subject: Exelon Generation Company, LLC Response to 

March 12, 2012, Request for Information Enclosure 2, Recommendation 2.1, Flooding, 

Required Response 2, Flood Hazard Reevaluation Report. Exelon letter RS-14-055. 

March 12, 2014. ADAMS Nos. ML14079A425 and ML14079A426.

[Exelon] Exelon Generation Company, LLC. 2014d. “Applicant’s Environmental Report, 

Operating License Renewal Stage, LaSalle County Station.” ADAMS No. ML14343A883. 

December 2014.
Appendix F

F-46

[Exelon] Exelon Generation Company, LLC. 2015. Letter from M.P. Gallagher, Vice President,

License Renewal Projects Exelon Generation Company, LLC, to NRC Document Control Desk. 

Subject: Response to NRC Request for Additional Information on Severe Accident Mitigation 

Alternatives Regarding the LaSalle County Station, Units 1 and 2 License Renewal Application

Environmental Review. Letter RA15-032. May 29, 2015. ADAMS No. ML15149A370.

[NEI] Nuclear Energy Institute. 2005. Severe Accident Mitigation Alternative (SAMA) Analysis 

Guidance Document. Revision A. Washington, DC: NEI. NEI 05-01. November 2005. 79 p. 

ADAMS No. ML060530203.

[NRC] U.S. Nuclear Regulatory Commission. 1988. “Individual Plant Examination for Severe 

Accident Vulnerabilities—10 CFR 50.54(f).” Washington, DC: NRC. Generic Letter No. 88-20. 

November 23, 1988. Available at <http://www.nrc.gov/reading-rm/doc-collections/gencomm/gen-letters/1988/gl88020.html> (accessed 21 October 2014).

[NRC] U.S. Nuclear Regulatory Commission. 1991. “Individual Plant Examination of External 

Events for Severe Accident Vulnerabilities.” Washington, DC: NRC. Generic Letter No. 88-20, 

Supplement 4. June 28, 1991.

[NRC] U.S. Nuclear Regulatory Commission. 1992. Analysis of the LaSalle Unit 2 Nuclear 

Power Plant: Risk Methods Integration and Evaluation Program (RMIEP). Washington, DC: 

NRC. NUREG/CR–4832, Vols. 1‒9, 1992‒1993.

[NRC] U.S. Nuclear Regulatory Commission. 1995. Memorandum from M. Wayne Hodges, 

NRC, to Steven A Varga, NRC. Subject: Review of LaSalle Individual Plant Examination (IPE) 

Submittal-Internal Events. November 1, 1995.

[NRC] U.S. Nuclear Regulatory Commission. 1997a. Regulatory Analysis Technical Evaluation 

Handbook. Washington, DC: NRC. NUREG/BR–0184. January 1997. 308 p. ADAMS 

No. ML050190193.

[NRC] U.S. Nuclear Regulatory Commission. 1997b. Individual Plant Examination Program: 

Perspectives on Reactor Safety and Plant Performance,” NUREG–1560, Washington, D.C.

1997.

[NRC] U.S. Nuclear Regulatory Commission. 2000. Letter from Donna M. Skay to Oliver D. 

Kingsley, Commonwealth Edison Company. Subject: LaSalle County Station, Units 1 and 2, 

NRC Staff Evaluation of the Individual Plant Examination of External Events (IPEEE) Submittal. 

(TAC Nos. M83634 and M83635). December 8, 2000. ADAMS No. ML003776159.

[NRC] U.S. Nuclear Regulatory Commission. 2004. Regulatory Analysis Guidelines of the 

U.S. Nuclear Regulatory Commission. Revision 4. Washington, DC: NRC. NUREG/BR–0058. 

September 2004. 56 p. Available at<http://www.nrc.gov/reading-rm/doccollections/nuregs/brochures/br0058/> (accessed 21 October 2014).

[NRC] U.S. Nuclear Regulatory Commission. 2005. EPRI/NRC-RES Fire PRA Methodology 

for Nuclear Power Facilities. Vols. 1 and 2. Washington, DC: NRC. NUREG/CR–6850. 

September 2005. ADAMS Nos. ML052580075 and ML052580118.

[NRC] U.S. Nuclear Regulatory Commission. 2007. An Approach for Determining the 

Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities. 

Revision 1. Regulatory Guide 1.200. January 2007. ADAMS No. ML070240001.

[NRC] U.S. Nuclear Regulatory Commission. 2010. Letter from T. McGinty, Director, to All 

Holders of an Operating License. Subject: NRC Information Notice 2010-18: Generic 

Issue 199, “Implications of Updated Probabilistic Seismic Hazard Estimates in Central and 

Eastern United States on Existing Plants.” September 2, 2010. ADAMS No. ML101970221.
Appendix F

F-47

[NRC] U.S. Nuclear Regulatory Commission. 2011. An Approach for Using Probabilistic Risk 

Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis. 

Revision 2. Regulatory Guide 1.174. May 2011. ADAMS No. ML100910006.

[NRC] U.S. Nuclear Regulatory Commission. 2012a. Letter from E. Leeds, Director, to All 

Power Reactor Licensees. Subject: Request for information pursuant to Title 10 of the Code of 

Federal Regulations 50.54(f) regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term 

Task Force review of insights from the Fukushima Dai-ichi accident. March 12, 2012. ADAMS 

No. ML12053A340.

[NRC] U.S. Nuclear Regulatory Commission. 2012b. Letter from E. Leeds, Director, to All 

Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status.

EA-12-049. Subject: Issuance of Order to Modify Licenses with Regard to Requirements for 

Mitigation Strategies for Beyond-Design-Basis External Events. March 12, 2012. ADAMS 

No. ML12054A735.

[NRC] U.S. Nuclear Regulatory Commission. 2014. Letter from Blake Purnell, Project 

Manager, NRC, to Michael J. Pacilio, Senior Vice President, Exelon Generation Company. 

Subject: LaSalle County Station, Units 1 and 2 - Staff Assessment of the Flooding Walkdown 

Report Supporting Implementation of the Near-Term Task Force Recommendation 2.3 Related 

to the Fukushima Dai-ichi Accident. (TAC Nos. MF0240 and MF0241). June 30, 2014. 

ADAMS No. ML14177A859.

[NRC] U.S. Nuclear Regulatory Commission. 2015. Letter from D. Drucker, Environmental 

Project Manager, to M.P. Gallagher, Vice President License Renewal Projects, Exelon

Generation Company, LLC. Subject: Request for Additional Information on Severe Accident 

Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2, License Renewal 

Application Environmental Review (TAC Nos. MF5567 and MF5568). April 30, 2015. ADAMS 

Nos. ML15114A320 and ML15114A102.

TRANSPORTATION IMPACTS OF HIGH BURNUP FUEL

G-1

G. Transportation Impacts of LSCS High Burnup Fuel

G.1 Introduction

The U.S. Nuclear Regulatory Commission (NRC) has generically determined in its license 

renewal application reviews that the environmental impacts of the transportation of fuel and 

radioactive wastes to and from nuclear power facilities are small for all reactors as long as 

certain specific conditions are met. The application for license renewal of LaSalle County

Station, Units 1 and 2 (LSCS) stated that the specific conditions that allow the transportation 

impacts of spent fuel to be generically determined to be small may not be met for LSCS. 

Therefore, this appendix provides the NRC staff’s analysis of the environmental impacts of 

transporting spent fuel from LSCS.

G.2 Background

The U.S. Nuclear Regulatory Commission (NRC) performed a generic analysis of the 

environmental effects of the transportation of fuel and waste to and from light-water reactors 

(LWRs) in WASH–1238, “Environmental Survey of Transportation of Radioactive Materials to 

and from Nuclear Power Plants” (AEC 1972), and in a supplement to WASH–1238,

NUREG–75/038 (NRC 1975), and found the impact to be small. These documents provided the 

basis for Table S–4 in Title 10 of the Code of Federal Regulations (CFR) Part 51.52(b) that 

summarizes the environmental impacts of transportation of fuel and waste to and from one 

3,000- to 5,000-megawatt-thermal (MWt) (1,000- to 1,500-megawatt-electric (MWe)) LWR. 

Impacts are provided for normal conditions of transport and accidents in transport for a 

reference 1,100-MWe LWR.12 Dose to transportation workers during normal transportation 

operations was estimated to result in a collective dose of 4 person-rem per reference 

reactor-year. The combined dose to the public along the route and the dose to onlookers were 

estimated to result in a collective dose of 3 person-rem per reference reactor-year.

Environmental risks of radiological effects during accident conditions, as stated in Table S–4, 

are small. Nonradiological impacts from postulated accidents were estimated as one fatal injury 

in 100 reference reactor-years and one nonfatal injury in 10 reference reactor-years. 

Subsequent reviews of transportation impacts in NUREG–0170, Final Environmental Statement 

on the Transportation of Radioactive Material by Air and Other Modes (NRC 1977), and 

NUREG/CR–6672, Reexamination of Spent Fuel Shipment Risk Estimates (Sprung et al. 2000),

concludes that impacts were bounded by Table S–4 in 10 CFR 51.52. In accordance with 

10 CFR 51.52(a), a full description and a detailed analysis of transportation impacts are not 

required in the initial licensing of an LWR (i.e., impacts are assumed to be bounded by 

Table S–4) if the reactor meets the following criteria:

• The reactor has a core thermal power level that does not exceed 3,800 MWt.

• Fuel is in the form of sintered uranium oxide pellets having a uranium-235 

enrichment not exceeding 4 percent by weight, and the pellets are encapsulated in 

Zircaloy-clad fuel rods.

 12 The transportation impacts associated with LSCS were normalized for a reference 1,100-MWe LWR at 

an 80-percent capacity factor for comparisons to Table S–4.
Transportation Impacts of High Burnup Fuel

G-2

• The average level of irradiation of the fuel from the reactor does not exceed 

33,000 megawatt-days per metric ton of uranium (MWd/MTU), and no irradiated fuel 

assembly is shipped until at least 90 days after it is discharged from the reactor.

• With the exception of irradiated fuel, all radioactive waste shipped from the reactor is 

packaged and in a solid form.

• Unirradiated fuel is shipped to the reactor by truck; irradiated fuel is shipped from the 

reactor by truck, rail, or barge; and radioactive waste other than irradiated fuel is 

shipped from the reactor by truck or rail.

The environmental impacts of the transportation of fuel and radioactive wastes to and from 

nuclear power facilities are resolved generically in 10 CFR 51.52 as long as the specific 

conditions in the rule (see above) are met. 

10 CFR 51.52 does not specifically address license renewal. However, NUREG–1437, Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS)

(NRC 2013), points out that nuclear fuel is needed for the operation of light water reactors 

during the license renewal term in the same way that it is needed during the current license 

period. Therefore, the factors that affect the data presented in Table S–4 of 10 CFR 51.52 do 

not change when a light water reactor is operating under a renewed license. The GEIS further 

states that the NRC reevaluated the transportation issues and the adequacy of Table S–4 for 

license renewal application reviews (NRC 2013). In 1999, the NRC issued an addendum to the 

GEIS (NRC 1999) in which the agency evaluated the applicability of Table S–4 to future license 

renewal proceedings, particularly because shipments of spent fuel were likely to involve more 

highly enriched fresh fuel (more than 4 percent as assumed in Table S–4) and higher-burnup

spent fuel (higher than 33,000 MWd/MTU as assumed in Table S–4). On the basis of the 

evaluations, the NRC concluded that the values given in Table S–4 would still be bounding, as 

long as the (1) enrichment of the fresh fuel was 5 percent or less, (2) burnup of the spent fuel 

was 62,000 MWd/MTU or less, and (3) higher-burnup spent fuel (higher than 

33,000 MWd/MTU) was cooled for at least 5 years before being shipped offsite.

The GEIS (NRC 2013) quotes the conclusion of the 1999 addendum as follows: 

The impacts of transporting spent fuel enriched up to 5 percent uranium-235 with 

average burnup for the peak rod to current levels approved by NRC up to 

62,000 MWd/MTU and the cumulative impacts of transporting high-level waste to 

a single repository, such as Yucca Mountain, Nevada are found to be consistent 

with the impact values contained in 10 CFR 51.52(c), Summary Table S–4, 

“Environmental Impact of Transportation of Fuel and Waste to and from One 

Light-Water-Cooled Nuclear Power Reactor.” If fuel enrichment or burnup

conditions are not met, the applicant must submit an assessment of the 

implications for the environmental impact values reported in 10 CFR 51.52.

Therefore, when the fuel burnup rate may exceed 62,000 MWd/MTU during the period of 

extended operation, further analysis of transportation impacts is warranted.

Exelon Generation Company, LLC (Exelon), submitted an environmental report (ER)

(Exelon 2014a) as part of its license renewal application (Exelon 2014b) for LSCS in 

December 2014. LSCS is located in north-eastern Illinois. Each LSCS reactor is a General 

Electric boiling water reactor (BWR), Type 5, with a thermal power rating of 3,546 MWt. The 

two reactors at LSCS have a combined electrical output of 2,327 MWe. Both LSCS units 

operate using low-enriched uranium dioxide fuel with enrichment not exceeding a nominal 

5.0 percent by weight of uranium-235; these units have been historically operated within a 

maximum analyzed fuel burnup rate of 62,000 MWd/MTU. However, during some future fuel 
Transportation Impacts of High Burnup Fuel

G-3

cycles, the peak fuel burnup is projected to exceed 62,000 MWd/MTU in some part-length fuel 

rods. The part-length fuel rods are attached to the fuel bundle lower tie plate and typically 

experience higher burnups and higher power than full-length rods due to the bottom-peaked 

axial power shapes that exist throughout a large portion of a BWR fuel cycle, and a 

representative high-burnup case was identified based on a burnup of 75,000 MWd/MTU and a 

uranium-235 enrichment of 5.0 percent by weight. Accordingly, Exelon provided a full 

description and detailed analyses of the transportation impacts of shipping irradiated fuel from 

LSCS in its ER (Exelon 2014a) and provided updates to that analysis by letters dated 

July 24, 2015 (Exelon 2015a), and August 28, 2015 (Exelon 2015b). In these analyses, the 

radiological impacts of transporting irradiated fuel from LSCS were calculated using the 

RADTRAN 6.02 computer code (Weiner et al. 2015). RADTRAN 6.02 was also used in this 

SEIS and is the most commonly used transportation impact analysis software in the nuclear 

industry. 

G.3 NRC Analysis of LSCS High Burnup Fuel Transportation Impacts

This section provides the NRC staff’s analysis of the environmental impacts of transporting 

spent fuel from LSCS to a monitored retrievable storage facility or a permanent repository for

normal operating conditions and transportation accidents.

For the purposes of this analysis, the NRC staff considered the proposed Yucca Mountain

repository site in Nevada as a surrogate destination. Currently, the NRC has not made a 

decision about the U.S. Department of Energy (DOE) application for the proposed geologic 

repository at Yucca Mountain. However, the NRC staff considers that an estimate of the 

impacts of the transportation of spent fuel to a possible repository in Nevada is a reasonable 

bounding estimate of the transportation impacts on a storage or disposal facility because of the 

distances involved and the representativeness of the distribution of members of the public in 

urban, suburban, and rural areas (i.e., population distributions) along the shipping routes. 

The NRC Yucca Mountain adjudicatory proceeding is currently suspended, and Yucca 

Mountain-related matters are pending in Federal Court. Regardless of the outcome of these 

proceedings, the NRC staff concludes that transportation impacts are roughly proportional to the 

distance from the reactor site to the repository site, in this case, Illinois to Nevada.

This NRC staff’s analysis is based on shipment of spent fuel by legal-weight trucks in shipping 

casks with characteristics similar to currently available casks (i.e., massive, heavily shielded, 

cylindrical metal pressure vessels). Because of the large size and weight of spent fuel shipping 

casks, each shipment is assumed to consist of a single shipping cask loaded on a modified 

trailer. These assumptions are consistent with those made in the evaluation of the 

environmental impacts of transportation of spent fuel in Addendum 1 to NUREG–1437 

(NRC 1999). Because the alternative transportation methods involve rail transportation or 

heavy-haul trucks, which would reduce the overall number of spent fuel shipments (NRC 1999), 

thereby reducing impacts, these assumptions are conservative. In addition, the use of current 

shipping cask designs for this analysis results in conservative impact estimates because the 

current designs are based on transporting short-cooled spent fuel (approximately 120 days out 

of reactor). Future shipping casks would be designed to transport longer cooled fuel (greater 

than 5 years out of reactor) and would require much less shielding to meet external dose

limitations. Therefore, future shipping casks are expected to have higher cargo capacities, thus 

reducing the numbers of shipments and associated impacts.

The NRC staff calculated radiological impacts of transportation of spent fuel using the 

RADTRAN 6.02 computer code (Weiner et al. 2015). Routing and population data used in 

RADTRAN 6.02 for truck shipments were obtained from the Transportation Routing Analysis 
Transportation Impacts of High Burnup Fuel

G-4

Geographical Information System (TRAGIS) routing code (ORNL 2015). The population data in 

the TRAGIS code are based on the 2010 Census. The traffic accident rates input to 

RADTRAN 6.02 were taken from Weiner et al. (2015). 

G.3.1 Normal Conditions

Normal conditions, sometimes referred to as “incident free” transportation, are transportation 

activities in which shipments reach their destination without an accident occurring en route. 

Impacts from these shipments would be from the low levels of radiation that penetrate the 

heavily shielded spent fuel shipping cask. Radiation exposures would occur to the following 

populations: (1) persons residing along the transportation corridors between LSCS and the 

proposed repository location, (2) persons in vehicles traveling on the same route as a spent fuel 

shipment, (3) persons at vehicle stops for refueling, rest, and vehicle inspections, and 

(4) transportation crew workers (drivers). This analysis assumed that the surrogate destination 

for the spent fuel shipments is the proposed Yucca Mountain repository site in Nevada. This 

assumption is conservative because it tends to maximize the shipping distance from LSCS.

The NRC staff assumed that the capacity of a truck shipment of reactor spent fuel was 

0.5 metric ton of uranium (MTU) per shipment, the same capacity as that used in WASH–1238 

(AEC 1972). Exelon assumed a shipping cask capacity of 0.5 MTU per shipment in its analysis 

(Exelon 2014a, 2015a, 2015b).

Appendix G input to RADTRAN 6.02 includes the total shipping distance between the origin and 

destination sites and the population distributions along the routes. This information was 

obtained by running the TRAGIS computer code (ORNL 2015) for highway routes from LSCS to 

the proposed Yucca Mountain repository site. The resulting route characteristics information is 

shown in Table G–1. For truck shipments, all the spent fuel is assumed to be shipped to the 

proposed Yucca Mountain repository site over designated highway-route controlled-quantity 

routes. In addition, TRAGIS data were used in RADTRAN 6.02 on a state-by-state basis. The 

use of state-specific data from TRAGIS increases precision and could allow the results to be 

presented for each state along the route between LSCS and the proposed Yucca Mountain 

repository site, if desired.

Table G–1. Transportation Route Information for Shipments from

LSCS to the Proposed Yucca Mountain Repository Site(a)

Reactor Site

One-Way Shipping Distance, km

Population Density, 

persons/km2 Stop Time 

per Trip, 

Total Rural Suburban Urban Rural Suburban Urban hr

LSCS 2,871 2,418 393 60 10 334 1,649 2.5

(a) This table presents aggregated route characteristics from Exelon (2014a, 2015a, 2015b). Input to the 

RADTRAN 6.02 computer code was disaggregated to a state-by-state level.

Radiation doses are a function of many parameters, including vehicle speed, traffic count, dose

rate, packaging dimensions, number in the truck crew, stop time, and population density at 

stops. A list of the values for these and other parameters and the sources of the information is 

provided in Table G–2.

For the purposes of this analysis, the transportation crew for spent fuel shipments delivered by 

truck is assumed to consist of two drivers. Escort vehicles and drivers were considered, but 

they were not included because their distance from the shipping cask would reduce the dose
Transportation Impacts of High Burnup Fuel

G-5

rates to levels well below the dose rates experienced by the drivers and the dose rates would be 

negligible (DOE 2002a). Stop times for refueling and rest were assumed to occur at the rate of 

30 minutes per 4 hours of driving time. TRAGIS outputs were used to determine the number of 

stops. Doses to the public at truck stops have been significant contributors to the doses

calculated in previous RADTRAN 6.02 analyses. For this analysis, doses to the public at 

refueling and rest stops (i.e., stop doses) are the sum of the doses to individuals located in two 

annular rings centered at the stopped vehicle, as illustrated in Figure G–1. The inner ring 

represents persons who may be at the truck stop at the same time as a spent fuel shipment and 

extends 1 to 10 m from the edge of the vehicle. The outer ring represents persons who reside 

near a truck stop and it extends from 10 to 800 m from the vehicle. This scheme is similar to 

that used by Sprung et al. (2000). Population densities and shielding factors were also taken 

from Sprung et al. (2000), which were based on observations in Griego et al. (1996).

Table G–2. RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters

Parameter

RADTRAN 6.02 

Input Value Source

Vehicle speed, km/hr State Specific Weiner et al. (2015)

Traffic count—Rural, vehicles/hr State Specific Weiner et al. (2015)

Traffic count—Suburban, vehicles/hr State Specific Weiner et al. (2015)

Traffic count—Urban, vehicles/hr State Specific Weiner et al. (2015)

Vehicle occupancy, persons/vehicle 1.5 DOE 2002b

Dose rate at 1 m from vehicle, 

mrem/hr

14 Exelon (2014a, 2015a, 2015b). Approximate 

dose rate at 1 m that is equivalent to the 

maximum dose rate allowed by Federal 

regulations (i.e., 10 mrem/hr at 2 m from the 

side of a transport vehicle)

Packaging dimensions, m Length—5.03

Diameter—0.88

Exelon (2014a, 2015a, 2015b)

Number of truck crew 2 AEC 1972; NRC 1977; DOE 2002b

Stop time, hr/trip Route Specific See Table G–1

Population density at stops, 

persons/km2

30,000 Sprung et al. 2000. Nine persons within 10 m 

of vehicle. See Figure G–1.

Minimum/maximum radii of annular 

area around vehicle at stops, m

1 to 10 Sprung et al. 2000

Shielding factor applied to annular 

area surrounding vehicle at stops, 

dimensionless

1

(no shielding)

Sprung et al. 2000

Population density surrounding truck 

stops, persons/km2

340 Sprung et al. 2000

Minimum/maximum radius of annular 

area surrounding truck stop, m

10 to 800 Sprung et al. 2000

Shielding factor applied to annular 

area surrounding truck stop, 

dimensionless

0.2 Sprung et al. 2000

The results of these normal (incident-free) exposure calculations are shown in Table G–3. 

Population dose estimates are given for workers (truck crew members), onlookers (doses to 
Transportation Impacts of High Burnup Fuel

G-6

persons at stops and persons on highways exposed to the spent fuel shipment), and persons 

along the route (persons living near the highway).

Shipping schedules for spent fuel generated by LSCS have not been determined. The NRC 

staff determined that it is reasonable to calculate annual doses assuming the annual number of 

spent fuel shipments is equivalent to the annual refueling requirements. Population doses were 

normalized to the reference LWR in WASH–1238 (880 MWe (net)) (AEC 1972). This 

corresponds to a 1,100-MWe LWR operating at 80-percent capacity.

Illustration of Truck Stop Model

Table G–3. Annual Normal (Incident-Free) Radiation Doses to Transport Workers and the 

Public from Shipping Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 

Site, Normalized to Reference LWR (880 MWe (net))

Site

Normalized 

Average Annual 

Shipments

Normalized Impacts, Person-rem/yr

Workers

Public—

Onlookers

Public—

Along Route

Reference LWR (WASH–1238) 60 2.1 26 0.48

LSCS 40 1.4 17 0.32

Table S–4 Condition – 4 3 3
Transportation Impacts of High Burnup Fuel

G-7

The bounding cumulative doses to the exposed population given in Table S–4 are as follows:

• 4 person-rem per reactor-year to transport workers and

• 3 person-rem per reactor-year to general public (onlookers) and members of the 

public along the route.

The calculated population doses to onlookers for the reference LWR and the LSCS shipments 

exceed Table S–4 values. One of the key reasons for the higher population doses relative to 

Table S–4 is the longer shipping distances assumed for this analysis (i.e., to a proposed 

repository in Nevada) than the distances used in WASH–1238 (AEC 1972). WASH–1238 

assumed that each spent fuel shipment would travel a distance of 1,000 mi, whereas the 

shipping distances used in this SEIS were about 1,800 mi. If the shorter distance were used to 

calculate the impacts for LSCS spent fuel shipments, the doses to onlookers would be reduced 

by about 40 percent to 14 person-rem for the reference LWR and to 9.5 person-rem for the 

LSCS shipments. In addition, some of the other key conservative assumptions in the analysis 

were as follows:

• Use of the regulatory maximum dose rate (10 millirem (mrem) per hour at 2 m) in the 

RADTRAN calculations. The shipping casks assumed in the environmental impact 

statement prepared by DOE in support of the application for a geologic repository at 

the proposed Yucca Mountain repository site (DOE 2002a) would transport spent 

fuel that has cooled for a minimum of 5 years (see Subpart B of 10 CFR Part 961). 

Most spent fuel would have cooled for much longer than 5 years before being

shipped to a possible geologic repository. Based on this, shipments from LSCS also 

are expected to be cooled for longer than 5 years. Consequently, the estimated 

population doses in Table G–3 could be further reduced if more realistic dose rate 

projections are used.

• Use of the shipping cask capacity used in WASH–1238 (AEC 1972). The 

WASH–1238 analyses that form the basis for Table S–4 assumed that spent fuel

would be shipped at least 90 days after discharge from a current LWR. The spent 

fuel shipping casks described in WASH–1238 were designed to transport 

90-day-cooled fuel; therefore, their shielding and containment designs must 

accommodate this highly radioactive cargo. Shipping cask capacities assumed in 

WASH–1238 were approximately 0.5 MTU per truck cask. DOE (2008) assumed a 

10-year cooling period for spent fuel to be shipped to the repository. This cooling 

period allowed DOE to increase the assumed shipping cask capacity to about 

0.88 MTU per truck shipment of spent fuel. The NRC staff believes this is a 

reasonable projection for future spent fuel truck shipping cask capacities. If this 

assumption was used in this SEIS, the number of shipments of spent fuel would be 

reduced by about 40 percent to 23 shipments with a similar reduction in incident-free 

radiological impacts.

• Use of 30 minutes as the average time at a truck stop in the calculations. Many 

stops made for actual spent fuel shipments are of short duration (i.e., 10 minutes) for 

brief visual inspections of the cargo (e.g., checking the cask tie-downs). These stops 

typically occur in minimally populated areas (e.g., an overpass or freeway ramp in an 

unpopulated area). Furthermore, empirical data provided by Griego et al. 1996 

indicate that a 30-minute duration is toward the high end of the stop time distribution. 

Average stop times observed by Griego et al. 1996 were about 18 minutes. More 

realistic stop times would further reduce the population doses in Table G–3.
Transportation Impacts of High Burnup Fuel

G-8

A sensitivity study was performed by the NRC staff to demonstrate the effects of using more 

realistic dose rates and stop times on the incident-free population dose calculations for shipments 

of LSCS spent fuel. For this sensitivity study, the dose rate was reduced to 5 mrem per hour, 

which is the approximate 50-percent confidence interval of the dose rate distribution estimated by 

Sprung et al. (2000) for future spent fuel shipments. The number of shipments was reduced to 

23 shipments per year, and the stop time was reduced to 18 minutes per stop. All other 

RADTRAN 6.02 input values were unchanged. The result is that the annual crew doses, onlooker 

doses, and doses to persons along the route were reduced by about 80 percent of the annual 

doses shown in Table G–3 to 0.29 person-rem, 2.7 person-rem, and 0.078 person-rem, 

respectively. If the shipping distance was reduced from 1,800 mi to 1,000 mi as discussed above, 

the annual crew doses, onlooker doses, and doses to persons along the route would be further 

reduced to 0.16 person-rem, 1.5 person-rem, and 0.043 person-rem, respectively.

Radiation protection experts assume that any amount of radiation may pose some risk of 

causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 

exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 

relationship between radiation dose and detriments, such as cancer induction. The National 

Research Council (National Research Council 2006) uses the linear, no-threshold dose 

response model as a basis for estimating the risks from low doses. This approach is accepted 

by the NRC as a conservative method for estimating health risks from radiation exposure, 

recognizing that the model may overestimate those risks. Based on this method, the NRC staff 

estimated the risk to the public from radiation exposure using the nominal probability coefficient 

for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 

severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem. 

The coefficient is taken from the International Commission on Radiological Protection (ICRP) 

Publication 103 (ICRP 2007).

Both the National Council on Radiation Protection and Measurements (NCRP) and ICRP 

suggest that when the collective effective dose is smaller than the reciprocal of the relevant risk 

detriment (in other words, less than 1/0.00057, which is less than 1,754 person-rem), the risk 

assessment should note that the most likely number of excess health effects is zero 

(NCRP 1995; ICRP 2007). The annual public dose impacts for transporting spent fuel from 

LSCS to the proposed Yucca Mountain repository site were estimated to be about 

17 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 

NCRP (1995) suggest would most likely result in zero excess health effects. 

To place these impacts in perspective, the average U.S. resident receives about 311 mrem per 

year effective dose equivalent from natural background radiation (i.e., exposures from cosmic 

radiation; naturally occurring radioactive materials, such as radon; and global fallout from testing 

of nuclear explosive devices) (NCRP 2009). Using this average effective dose, the collective 

population dose from natural background radiation to the population along the route from LSCS

to the proposed Yucca Mountain repository site would be about 1.6x105 person-rem. Therefore, 

the radiation doses from transporting irradiated fuel from LSCS to the proposed Yucca Mountain 

repository site are minimal compared to the collective population dose to the same population 

from exposure to natural sources of radiation. This assessment is a comparative assessment 

for which there is no regulatory standard to base an impact level, and, again, it is provided only 

to place the impacts in perspective.

G.3.2 Radiological Impacts of Accidents

As discussed previously, the NRC staff used the RADTRAN 6.02 computer code to estimate the 

impacts of transportation accidents involving spent fuel shipments. RADTRAN 6.02 considers a 
Transportation Impacts of High Burnup Fuel

G-9

spectrum of postulated transportation accidents, ranging from those with high frequencies and 

low consequences (e.g., “fender benders”) to those with low frequencies and high 

consequences (i.e., accidents in which the shipping container is exposed to severe mechanical 

and thermal conditions).

Radionuclide inventories are important parameters in the calculation of accident risks. The 

radionuclide inventories used in this analysis were from the Exelon ER (Exelon 2014a, 2015a, 

2015b). The spent fuel inventory used in the NRC staff analysis is listed in Table G–4 and is 

based on a burnup of 75,000 MWd/MTU.

Robust shipping casks are used to transport spent fuel because of the radiation shielding and 

accident resistance required by 10 CFR Part 71. Spent fuel shipping casks must be certified 

Type B packaging systems, which means that they must withstand a series of severe postulated 

accident conditions with essentially no loss of containment or shielding capability. These casks 

also are designed with fissile material controls to ensure that the spent fuel remains subcritical 

under normal and accident conditions. According to Sprung et al. (2000), the probability of 

encountering accident conditions that would lead to shipping cask failure is less than 

0.01 percent (i.e., more than 99.99 percent of all accidents would result in no release of 

radioactive material from the shipping cask). The NRC staff assumed that shipping casks 

approved for transportation of LSCS spent fuel would provide equivalent mechanical and 

thermal protection of the spent fuel cargo.

Accident frequencies are calculated in RADTRAN 6.02 using user-specified accident rates and 

conditional shipping cask failure probabilities. State-specific accident rates were taken from 

Weiner et al. (2015) and used in the RADTRAN 6.02 calculations. Conditional shipping cask 

failure probabilities (i.e., the probability of cask failure as a function of the mechanical and 

thermal conditions applied in an accident) were taken from Sprung et al. 2000.

The RADTRAN 6.02 accident risk calculations were performed using the radionuclide 

inventories (curie(s) per metric ton of uranium [Ci/MTU]) in Table G–4 multiplied by the shipping 

cask capacity (0.5 MTU). The resulting risk estimates were then multiplied by assumed annual 

spent fuel shipments (shipments per year) to derive estimates of the annual accident risks 

associated with spent fuel shipments from LSCS to the proposed Yucca Mountain repository 

site in Nevada. As was done for routine exposures, the NRC staff assumed that the numbers of 

shipments of spent fuel per year are equivalent to the annual discharge quantities. For this 

assessment, release fractions for current-generation LWR fuel designs (Sprung et al. 2000) 

were used. 

The NRC staff used RADTRAN 6.02 to calculate the population dose from the released 

radioactive material from four of five possible exposure pathways.13 These pathways are as 

follows:

• External dose from exposure to the passing cloud of radioactive material 

(cloudshine).

• External dose from the radionuclides deposited on the ground by the passing plume 

(groundshine). The NRC staff’s analysis included the radiation exposure from this 

pathway even though the area surrounding a potential accidental release would be 

evacuated and decontaminated, thus preventing long-term exposures from this 

pathway.

 13 Internal dose from ingestion of contaminated food was not considered because the NRC staff assumed 

evacuation and subsequent interdiction of foodstuffs following a postulated transportation accident.
Transportation Impacts of High Burnup Fuel

G-10

• Internal dose from inhalation of airborne radioactive contaminants (inhalation).

• Internal dose from resuspension of radioactive materials that were deposited on the 

ground (resuspension). The NRC staff’s analysis included the radiation exposures 

from this pathway even though evacuation and decontamination of the area 

surrounding a potential accidental release would prevent long-term exposures.

Table G–4. Radionuclide Inventories Used in Transportation 

Accident Risk Calculations for the LSCS Reactors(a)(b)

Radionuclide

Inventory

Ci/Assembly Inventory Ci/MTU

Am-241 1.87x102 1.06x103

Am-243 1.76x101 9.96x101

Ce-144 2.42x103 1.37x104

Cm-242 7.42 4.20x101

Cm-243 8.06 4.56x101

Cm-244 3.46x103 1.96x104

Cs-134 1.38x104 7.81x104

Cs-137 3.65x104 2.07x105

Eu-154 1.52x103 8.60x103

Eu-155 5.84x102 3.31x103

H-3 1.83x102 1.04x103

Kr-85 2.39x103 1.35x104

Np-239 1.76x101 9.96x101

Pm-147 8.70x103 4.92x104

Pu-238 1.43x103 8.09x103

Pu-239 4.37x101 2.47x102

Pu-240 1.22x102 6.90x102

Pu-241 1.81x104 1.02x105

Ru-106 5.22x103 2.95x104

Sb-125 8.88x102 5.03x103

Sr-90 2.41x104 1.36x105

Sr-89 1.33x10-6 7.53x10-6

Y-90 2.41x104 1.36x105

Co-60 5.93x102 3.36x103

Co-58 3.96x10-6 2.24x10-5

Fe-59 3.65x10-11 2.07x10-10

Fe-55 3.50x102 1.98x103

Mn-54 2.42 1.37x101

Cr-51 6.48x10-17 3.67x10-16

Total 1.45x105 8.19x105
Transportation Impacts of High Burnup Fuel

G-11

Radionuclide

Inventory

Ci/Assembly Inventory Ci/MTU

(a) Multiply curie per assembly or MTU by 3.7x1010 to obtain becquerel 

per assembly or MTU.

(b) Radionuclide inventory is based on a burnup of 75,000 MWd/MTU.

Sources: Exelon (2014a, 2015a, 2015b)

Table G–5 presents the environmental consequences of transportation accidents when shipping 

spent fuel from LSCS to the proposed Yucca Mountain repository site. The shipping distances 

and population distribution information for the routes were the same as those used for the 

normal incident-free conditions (see Section G.3.1). The results are normalized to the 

WASH–1238 (AEC 1972) reference reactor (880-MWe) net electrical generation (1,100-MWe 

reactor operating at 80-percent capacity) to provide a common basis for comparison to the 

impacts listed in Table S–4. Note that the impacts (1.2x10−5 person-rem per year) are less than 

the reference LWR impacts (1.8x10−5 person-rem per year). The transportation accident impact 

analysis conducted by Exelon (Exelon 2014a, 2015a, 2015b) used methods and data that are 

similar to those used in this SEIS. The differences are insignificant in terms of the overall 

results.

Table G–5. Annual Spent Fuel Transportation Accident Impacts from Shipping Spent Fuel 

from LSCS to the Proposed Yucca Mountain Repository Site, Normalized to Reference 

LWR Reactor (880 MWe (net))

Site Normalized Average Annual 

Shipments

Normalized Population Impacts,

Person-rem/yr

Reference LWR (WASH–1238) 60 1.8x10−5

LSCS 40 1.2x10−5

Radiation protection experts assume that any amount of radiation may pose some risk of 

causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 

exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 

relationship between radiation dose and detriments, such as cancer induction. The National 

Research Council (National Research Council 2006) uses the linear, no-threshold dose 

response model as a basis for estimating the risks from low doses. This approach is accepted 

by the NRC as a conservative method for estimating health risks from radiation exposure, 

recognizing that the model may overestimate those risks. Based on this method, the NRC staff 

estimated the risk to the public from radiation exposure using the nominal probability coefficient 

for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 

severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem. 

The coefficient is taken from ICRP Publication 103 (ICRP 2007).

Both the NCRP and ICRP suggest that when the collective effective dose is smaller than the 

reciprocal of the relevant risk detriment (in other words, less than 1/0.00057, which is less than 

1,754 person-rem), the risk assessment should note that the most likely number of excess 

health effects is zero (NCRP 1995; ICRP 2007). The annual accident impacts from transporting 

spent fuel from LSCS to the proposed Yucca Mountain repository site were estimated to be 

about 1.2x10-5 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 

NCRP (1995) suggest would most likely result in zero excess health effects. 
Transportation Impacts of High Burnup Fuel

G-12

In addition, the collective population dose from natural background radiation to the population 

along the representative routes from LSCS to the proposed Yucca Mountain repository site 

would be about 1.6x105 person-rem. Therefore, the accident impacts from transporting spent 

fuel to the proposed Yucca Mountain repository site are minimal compared to the collective 

population dose to the same population from exposure to natural sources of radiation. This 

assessment is a comparative assessment for which there is no regulatory standard to base an 

impact level and is provided only to place the impacts in perspective.

G.3.3 Nonradiological Impacts of Accidents

A nonradiological accident is a truck accident in which the property damage, injuries, or fatalities 

are caused by the force of the impact; no release of, or exposure to, radiological materials 

occurs as a result of the truck accident. In WASH–1238 (AEC 1972) and NUREG–75/038 

(NRC 1975), the NRC staff assessed the impacts of these nonradiological truck accidents that 

may occur during the transport of fuel and waste to and from LWRs and estimated the impacts 

from these nonradiological accidents as one fatal injury in 100 reference reactor-years and one 

nonfatal injury in 10 reference reactor-years. Using data from the National Highway 

Transportation Safety Administration for large trucks over the period 2009 through 2013, NRC 

staff estimated that there would be less than one fatal injury per 100 reference reactor-years 

and less than one nonfatal injury per 10 reference reactor-years for shipments of spent fuel from 

LSCS to the proposed Yucca Mountain repository site. Therefore, the nonradiological impacts 

of accidents from the transportation of LSCS spent fuel would be small. 

G.4 Conclusions for Transportation Impacts of High Burnup Fuel

The NRC staff performed an independent confirmatory analysis of the impacts under normal 

operating and accident conditions of transporting irradiated fuel from LSCS to the proposed 

Yucca Mountain repository site. To make comparisons to Table S–4, the environmental impacts 

were adjusted (i.e., normalized) to the environmental impacts associated with the reference 

LWR in WASH–1238 (AEC 1972) by multiplying the LSCS impact estimates by the ratio of the 

total electric output for the reference reactor to the electric output of the LSCS reactors.

Because of the conservative approaches and data used to calculate impacts, the NRC staff 

does not expect the actual environmental effects to exceed those calculated in this SEIS. Thus, 

the NRC staff concludes that the environmental impacts of the transportation of irradiated fuel 

from LSCS would be SMALL and would be consistent with the environmental impacts

associated with the transportation of fuel and radioactive wastes to and from current-generation 

reactors presented in Table S–4 of 10 CFR 51.52.

The NRC staff concludes that transportation impacts are roughly proportional to the distance 

from LSCS to the repository site—in this case Illinois to Nevada. The distance from LSCS to 

any new planned repository in the contiguous United States would be no more than double the 

distance from LSCS to the proposed Yucca Mountain repository site. Doubling the 

environmental impact estimates from the transportation of spent reactor fuel, as presented in 

this section, would provide a reasonable bounding estimate of the impacts to meet the 

requirements of the National Environmental Policy Act of 1969, as amended 

(42 U.S.C. 4321 et seq.). The NRC staff concludes that the environmental impacts of these 

doubled estimates would not be significant and, therefore, would still be SMALL.
Transportation Impacts of High Burnup Fuel

G-13

G.5 References

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licensing of production and utilization facilities.” 

10 CFR Part 51. 2011. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

protection regulations for domestic licensing and related regulatory functions.” 

10 CFR Part 71. 2011. Code of Federal Regulations, Title 10, Energy, Part 71, “Packaging and 

transportation of radioactive material.” 

10 CFR Part 961. 2002. Code of Federal Regulations, Title 10, Energy, Part 961, “Standard 

contract for disposal of spent nuclear fuel and/or high-level radioactive waste.”

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Geologic Repository for the Disposal of Spent Nuclear Fuel and High-Level Radioactive Waste 

at Yucca Mountain, Nye County, Nevada.” Washington, DC: DOE. DOE/EIS-0250, Office of 

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<http://energy.gov/nepa/downloads/eis-0250-final-environmental-impact-statement> (accessed 

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[Exelon] Exelon Generation Company, LLC. 2015a. LaSalle County Station, Units 1 & 2, 

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NUREG-1437

Supplement 57

Final

Generic Environmental Impact Statement for License Renewal of Nuclear Plants 

Regarding LaSalle County Station, Units 1 and 2