Generic Environmental 

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 57

Regarding LaSalle County 

Station, Units 1 and 2

Draft Report for Comment

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 57
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Generic Environmental

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 57

Regarding LaSalle County 

Station, Units 1 and 2

Draft Report for Comment

Manuscript Completed: February 2016

Date Published: February 2016

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 57
1 Proposed Action Issuance of renewed operating licenses NPF-11 and NPF-18 for LaSalle 

2 County Station, Units 1 and 2 (LSCS), in LaSalle County, Illinois

3 Type of Statement Draft Supplemental Environmental Impact Statement

4 Agency Contact Mr. David Drucker

5 U.S. Nuclear Regulatory Commission (NRC)

6 Office of Nuclear Reactor Regulation

7 Mail Stop O-11F1

8 Washington, DC 20555-0001

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

10 E-mail: david.drucker@nrc.gov

11 Comments Any interested party may submit comments on this draft supplemental 

12 environmental impact statement. Please specify NUREG–1437, 

13 Supplement 57, draft, in your comments, and send them by the end of the 

14 comment period specified in the Federal Register notice announcing the 

15 availability of this report. Comments may be submitted electronically by 

16 searching for docket ID NRC-2014-0268 at the Federal rulemaking Web 

17 site, http://www.regulations.gov. Comments also may be mailed to the 

18 following address:

19 Chief, Rules, Announcements, and Directives Branch

20 Division of Administrative Services

21 Office of Administration

22 Mail Stop: OWFN-12 H08

23 U.S. Nuclear Regulatory Commission

24 Washington, DC 20555-0001

25 Please be aware that any comments that you submit to the NRC will be 

26 considered a public record and entered into the Agencywide Documents 

27 Access and Management System. Do not provide information you would 

28 not want to be publicly available.
iii

1 COVER SHEET

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

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

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

5 Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment

6 (NUREG–1437). LaSalle County Station is located in LaSalle County, Illinois.

7 For additional information or copies of this document contact:

8 Division of License Renewal

9 U.S. Nuclear Regulatory Commission

10 Office of Nuclear Reactor Regulation

11 Mail Stop O-11F1

12 11555 Rockville Pike

13 Rockville, Maryland 20852

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

15 Email: david.drucker@nrc.gov

16 ABSTRACT

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

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

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

20 This SEIS includes the preliminary analysis that evaluates the environmental impacts of the 

21 proposed action and alternatives to the proposed action. Alternatives considered include: 

22 (1) new nuclear power generation, (2) coal-integrated gasification combined-cycle, (3) natural 

23 gas combined-cycle (NGCC), (4) a combination of NGCC, wind, and solar generation, 

24 (5) purchased power, and (6) the no-action alternative (i.e., no renewal of the license).

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

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

27 option of license renewal for energy-planning decisionmakers would be unreasonable. The 

28 NRC staff based its recommendation on the following factors:

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

30 Impact Statement for License Renewal of Nuclear Plants;

31 • the Environmental Report submitted by Exelon;

32 • the NRC staff’s consultation with Federal, State, local, and Tribal Government 

33 agencies;

34 • the NRC staff’s independent environmental review; and

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

36 process.

v

1 TABLE OF CONTENTS

2 ABSTRACT.............................................................................................................................. iii

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

4 FIGURES................................................................................................................................. xv

5 TABLES ................................................................................................................................ xvii

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

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

8 1.0 INTRODUCTION.......................................................................................................... 1-1

9 1.1 Proposed Federal Action.................................................................................. 1-1

10 1.2 Purpose and Need for Proposed Federal Action .............................................. 1-1

11 1.3 Major Environmental Review Milestones.......................................................... 1-1

12 1.4 Generic Environmental Impact Statement........................................................ 1-2

13 1.5 Supplemental Environmental Impact Statement............................................... 1-4

14 1.6 Decisions to Be Supported by the SEIS........................................................... 1-5

15 1.7 Cooperating Agencies...................................................................................... 1-5

16 1.8 Consultations ................................................................................................... 1-5

17 1.9 Correspondence .............................................................................................. 1-6

18 1.10 Status of Compliance....................................................................................... 1-6

19 1.11 Related Federal and State Activities ................................................................ 1-6

20 1.12 References ...................................................................................................... 1-7

21 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION.......................................... 2-1

22 2.1 Proposed Action .............................................................................................. 2-1

23 2.1.1 Plant Operations during the License Renewal Term......................... 2-1

24 2.1.2 Refurbishment and Other Activities Associated with License 

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

26 2.1.3 Termination of Nuclear Power Plant Operations and 

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

28 2.2 Alternatives...................................................................................................... 2-3

29 2.2.1 No-Action Alternative ....................................................................... 2-3

30 2.2.2 Replacement Power Alternatives ..................................................... 2-4

31 2.2.2.1 New Nuclear Alternative................................................ 2-9

32 2.2.2.2 IGCC Alternative ......................................................... 2-11

33 2.2.2.3 NGCC Alternative........................................................ 2-13

34 2.2.2.4 Combination Alternative (NGCC, Wind, and Solar)...... 2-13

35 2.2.2.5 Purchased Power Alternative ...................................... 2-16

36 2.3 Alternatives Considered but Dismissed.......................................................... 2-17

37 2.3.1 Energy Conservation and Energy Efficiency .................................. 2-17

38 2.3.2 Solar .............................................................................................. 2-17
Table of Contents

vi

1 2.3.3 Wind .............................................................................................. 2-18

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

3 2.3.3.2 Wind Power with Storage ............................................ 2-19

4 2.3.3.3 Conclusion .................................................................. 2-19

5 2.3.4 Biomass......................................................................................... 2-19

6 2.3.5 Hydroelectric.................................................................................. 2-20

7 2.3.6 Wave and Ocean Energy ............................................................... 2-20

8 2.3.7 Fuel Cells....................................................................................... 2-21

9 2.3.8 Delayed Retirement ....................................................................... 2-21

10 2.3.9 Geothermal.................................................................................... 2-22

11 2.3.10 Municipal Solid Waste.................................................................... 2-22

12 2.3.11 Petroleum ...................................................................................... 2-23

13 2.3.12 Supercritical Pulverized Coal ......................................................... 2-23

14 2.4 Comparison of Alternatives ............................................................................ 2-23

15 2.5 References .................................................................................................... 2-27

16 3.0 AFFECTED ENVIRONMENT....................................................................................... 3-1

17 3.1 Description of Nuclear Power Plant Facility and Operation .............................. 3-1

18 3.1.1 External Appearance and Setting..................................................... 3-1

19 3.1.2 Nuclear Reactor Systems................................................................. 3-6

20 3.1.3 Cooling and Auxiliary Water Systems .............................................. 3-6

21 3.1.4 Radioactive Waste Management Systems ..................................... 3-13

22 3.1.4.1 Radioactive Liquid Waste Management ...................... 3-13

23 3.1.4.2 Radioactive Gaseous Waste Management.................. 3-15

24 3.1.4.3 Radioactive Solid Waste Management........................ 3-16

25 3.1.4.4 Radioactive Waste Storage......................................... 3-17

26 3.1.4.5 Radiological Environmental Monitoring Program ......... 3-17

27 3.1.5 Nonradioactive Waste Management Systems................................ 3-18

28 3.1.6 Utility and Transportation Infrastructure.......................................... 3-18

29 3.1.6.1 Electricity..................................................................... 3-19

30 3.1.6.2 Fuel............................................................................. 3-19

31 3.1.6.3 Water .......................................................................... 3-19

32 3.1.6.4 Transportation Systems............................................... 3-19

33 3.1.6.5 Power Transmission Systems ..................................... 3-20

34 3.1.7 Nuclear Power Plant Operations and Maintenance ........................ 3-20

35 3.2 Land Use and Visual Resources.................................................................... 3-21

36 3.2.1 Land Use ....................................................................................... 3-21

37 3.2.1.1 Onsite Land Use ......................................................... 3-21

38 3.2.1.2 Coastal Zone............................................................... 3-22

39 3.2.1.3 Offsite Land Use ......................................................... 3-22

40 3.2.2 Visual Resources ........................................................................... 3-24

41 3.3 Meteorology, Air Quality, and Noise............................................................... 3-24
Table of Contents

vii

1 3.3.1 Meteorology and Climatology......................................................... 3-24

2 3.3.2 Air Quality ...................................................................................... 3-25

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

4 3.4 Geologic Environment.................................................................................... 3-29

5 3.4.1 Physiography and Geology ............................................................ 3-29

6 3.4.2 Soils............................................................................................... 3-30

7 3.4.3 Seismic Setting .............................................................................. 3-34

8 3.5 Water Resources ........................................................................................... 3-35

9 3.5.1 Surface Water Resources .............................................................. 3-35

10 3.5.1.1 Surface Water Hydrology ............................................ 3-35

11 3.5.1.2 Surface Water Use...................................................... 3-39

12 3.5.1.3 Surface Water Quality and Effluents............................ 3-41

13 3.5.2 Groundwater Resources ................................................................ 3-46

14 3.5.2.1 Site Description and Hydrogeology ............................. 3-46

15 3.5.2.2 Groundwater Use ........................................................ 3-48

16 3.5.2.3 Groundwater Quality ................................................... 3-51

17 3.6 Terrestrial Resources..................................................................................... 3-52

18 3.6.1 LSCS Ecoregion ............................................................................ 3-52

19 3.6.2 LSCS Site Surveys, Studies, and Reports...................................... 3-53

20 3.6.3 LSCS Site ...................................................................................... 3-54

21 3.6.3.1 Vegetation................................................................... 3-54

22 3.6.3.2 Wildlife ........................................................................ 3-55

23 3.6.4 LSCS Wildlife Management Plan ................................................... 3-55

24 3.6.5 Important Species and Habitats ..................................................... 3-56

25 3.6.5.1 Important Species ....................................................... 3-56

26 3.6.5.2 Important Habitats....................................................... 3-58

27 3.6.6 Invasive and Non-Native Species................................................... 3-59

28 3.7 Aquatic Resources......................................................................................... 3-59

29 3.7.1 Illinois River ................................................................................... 3-59

30 3.7.1.1 Aquatic Communities in the Illinois River..................... 3-60

31 3.7.2 LSCS Cooling Pond ....................................................................... 3-67

32 3.7.2.1 Aquatic Community in the Cooling Pond ..................... 3-68

33 3.7.2.2 Cooling Pond Fish Kill Events...................................... 3-69

34 3.7.3 Important Species and Habitats ..................................................... 3-69

35 3.7.3.1 State-Listed Species ................................................... 3-69

36 3.7.3.2 Important Habitats....................................................... 3-72

37 3.7.4 Non-Native Species ....................................................................... 3-72

38 3.8 Federally Protected Species and Habitats...................................................... 3-73

39 3.8.1 Action Area .................................................................................... 3-73

40 3.8.2 Federally Protected Species and Habitats Considered................... 3-74

41 3.9 Historic and Cultural Resources..................................................................... 3-79
Table of Contents

viii

1 3.9.1 Cultural Background....................................................................... 3-80

2 3.9.2 Historic and Cultural Resources..................................................... 3-82

3 3.10 Socioeconomics............................................................................................. 3-82

4 3.10.1 Power Plant Employment and Expenditures .................................. 3-83

5 3.10.2 Regional Economic Characteristics................................................ 3-83

6 3.10.2.1 Employment and Income............................................. 3-84

7 3.10.2.2 Unemployment ............................................................ 3-86

8 3.10.3 Demographic Characteristics ......................................................... 3-86

9 3.10.3.1 Transient Population ................................................... 3-88

10 3.10.3.2 Migrant Farm Workers................................................. 3-89

11 3.10.4 Housing and Community Services ................................................. 3-90

12 3.10.4.1 Housing....................................................................... 3-91

13 3.10.4.2 Education .................................................................... 3-91

14 3.10.4.3 Public Water Supply .................................................... 3-91

15 3.10.5 Tax Revenues................................................................................ 3-93

16 3.10.6 Local Transportation ...................................................................... 3-95

17 3.11 Human Health................................................................................................ 3-96

18 3.11.1 Radiological Exposure and Risk..................................................... 3-96

19 3.11.2 Chemical Hazards.......................................................................... 3-97

20 3.11.3 Microbiological Hazards ................................................................. 3-97

21 3.11.3.1 Thermophilic Microorganisms of Concern ................... 3-98

22 3.11.3.2 Prevalence of Waterborne Diseases Associated 

23 with Recreational Waters............................................. 3-99

24 3.11.4 Electromagnetic Fields................................................................... 3-99

25 3.11.5 Other Hazards.............................................................................. 3-100

26 3.12 Environmental Justice.................................................................................. 3-101

27 3.12.1 Minority Population ...................................................................... 3-102

28 3.12.2 Low-Income Population................................................................ 3-102

29 3.13 Waste Management and Pollution Prevention.............................................. 3-106

30 3.13.1 Radioactive Waste ....................................................................... 3-106

31 3.13.2 Nonradioactive Waste.................................................................. 3-106

32 3.14 References .................................................................................................. 3-106

33 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS........................ 4-1

34 4.1 Introduction...................................................................................................... 4-1

35 4.2 Land Use and Visual Resources...................................................................... 4-1

36 4.2.1 Proposed Action............................................................................... 4-1

37 4.2.2 No-Action Alternative ....................................................................... 4-2

38 4.2.2.1 Land Use....................................................................... 4-2

39 4.2.2.2 Visual Resources .......................................................... 4-2

40 4.2.3 New Nuclear Alternative................................................................... 4-3

41 4.2.3.1 Land Use....................................................................... 4-3
Table of Contents

ix

1 4.2.3.2 Visual Resources .......................................................... 4-3

2 4.2.4 IGCC Alternative .............................................................................. 4-3

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

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

5 4.2.5 Natural Gas Combined-Cycle Alternative ......................................... 4-4

6 4.2.5.1 Land Use....................................................................... 4-4

7 4.2.5.2 Visual Resources .......................................................... 4-4

8 4.2.6 Combination Alternative (NGCC, Wind, Solar) ................................. 4-5

9 4.2.6.1 Land Use....................................................................... 4-5

10 4.2.6.2 Visual Resources .......................................................... 4-5

11 4.2.7 Purchased Power Alternative ........................................................... 4-6

12 4.2.7.1 Land Use....................................................................... 4-6

13 4.2.7.2 Visual Resources .......................................................... 4-6

14 4.3 Air Quality and Noise ....................................................................................... 4-6

15 4.3.1 Proposed Action............................................................................... 4-6

16 4.3.1.1 Air Quality ..................................................................... 4-6

17 4.3.1.2 Noise............................................................................. 4-7

18 4.3.2 No-Action Alternative ....................................................................... 4-7

19 4.3.2.1 Air Quality ..................................................................... 4-7

20 4.3.2.2 Noise............................................................................. 4-7

21 4.3.3 New Nuclear Alternative................................................................... 4-7

22 4.3.3.1 Air Quality ..................................................................... 4-7

23 4.3.3.2 Noise............................................................................. 4-9

24 4.3.4 IGCC Alternative ............................................................................ 4-10

25 4.3.4.1 Air Quality ................................................................... 4-10

26 4.3.4.2 Noise........................................................................... 4-13

27 4.3.5 NGCC Alternative .......................................................................... 4-13

28 4.3.5.1 Air Quality ................................................................... 4-13

29 4.3.5.2 Noise........................................................................... 4-15

30 4.3.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-16

31 4.3.6.1 Air Quality ................................................................... 4-16

32 4.3.6.2 Noise........................................................................... 4-18

33 4.3.7 Purchased Power Alternative ......................................................... 4-19

34 4.3.7.1 Air Quality ................................................................... 4-19

35 4.3.7.2 Noise........................................................................... 4-19

36 4.4 Geologic Environment.................................................................................... 4-20

37 4.4.1 Proposed Action............................................................................. 4-20

38 4.4.2 No-Action Alternative ..................................................................... 4-20

39 4.4.3 New Nuclear Alternative................................................................. 4-20

40 4.4.4 IGCC Alternative ............................................................................ 4-21

41 4.4.5 NGCC Alternative .......................................................................... 4-21
Table of Contents

x

1 4.4.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-21

2 4.4.7 Purchased Power Alternative ......................................................... 4-21

3 4.5 Water Resources ........................................................................................... 4-21

4 4.5.1 Proposed Action............................................................................. 4-22

5 4.5.1.1 Surface Water Resources ........................................... 4-22

6 4.5.1.2 Groundwater Resources.............................................. 4-24

7 4.5.2 No-Action Alternative ..................................................................... 4-26

8 4.5.2.1 Surface Water Resources ........................................... 4-26

9 4.5.2.2 Groundwater Resources.............................................. 4-26

10 4.5.3 New Nuclear Alternative................................................................. 4-26

11 4.5.3.1 Surface Water Resources ........................................... 4-26

12 4.5.3.2 Groundwater Resources.............................................. 4-27

13 4.5.4 IGCC Alternative ............................................................................ 4-27

14 4.5.4.1 Surface Water Resources ........................................... 4-27

15 4.5.4.2 Groundwater Resources.............................................. 4-28

16 4.5.5 NGCC Alternative .......................................................................... 4-28

17 4.5.5.1 Surface Water Resources ........................................... 4-28

18 4.5.5.2 Groundwater Resources.............................................. 4-29

19 4.5.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-29

20 4.5.6.1 Surface Water Resources ........................................... 4-29

21 4.5.6.2 Groundwater Resources.............................................. 4-30

22 4.5.7 Purchased Power Alternative ......................................................... 4-30

23 4.5.7.1 Surface Water Resources ........................................... 4-30

24 4.5.7.2 Groundwater Resources.............................................. 4-30

25 4.6 Terrestrial Resources..................................................................................... 4-30

26 4.6.1 Proposed Action............................................................................. 4-31

27 4.6.1.1 Generic GEIS Issues................................................... 4-31

28 4.6.1.2 Effects on Terrestrial Resources (Non-Cooling 

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

30 4.6.1.3 Water Use Conflicts with Terrestrial Resources........... 4-33

31 4.6.2 No-Action Alternative ..................................................................... 4-34

32 4.6.3 New Nuclear Alternative................................................................. 4-34

33 4.6.4 IGCC Alternative ............................................................................ 4-35

34 4.6.5 NGCC Alternative .......................................................................... 4-35

35 4.6.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-36

36 4.6.7 Purchased Power Alternative ......................................................... 4-37

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

38 4.7.1 Proposed Action............................................................................. 4-37

39 4.7.1.1 GEIS Category 1 Issues.............................................. 4-38

40 4.7.1.2 Impingement and Entrainment of Aquatic 

41 Organisms................................................................... 4-38
Table of Contents

xi

1 4.7.1.3 Thermal Impacts on Aquatic Organisms...................... 4-45

2 4.7.1.4 Water Use Conflicts with Aquatic Resources............... 4-52

3 4.7.2 No-Action Alternative ..................................................................... 4-52

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

5 4.7.4 IGCC Alternative ............................................................................ 4-53

6 4.7.5 NGCC Alternative .......................................................................... 4-54

7 4.7.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-54

8 4.7.7 Purchased Power Alternative ......................................................... 4-54

9 4.8 Special Status Species and Habitats.............................................................. 4-55

10 4.8.1 Proposed Action............................................................................. 4-55

11 4.8.2 No-Action Alternative ..................................................................... 4-57

12 4.8.3 New Nuclear Alternative................................................................. 4-57

13 4.8.4 IGCC Alternative ............................................................................ 4-58

14 4.8.5 NGCC Alternative .......................................................................... 4-58

15 4.8.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-59

16 4.8.7 Purchased Power Alternative ......................................................... 4-59

17 4.9 Historic and Cultural Resources..................................................................... 4-59

18 4.9.1 Proposed Action............................................................................. 4-60

19 4.9.2 No-Action Alternative ..................................................................... 4-62

20 4.9.3 New Nuclear Alternative................................................................. 4-62

21 4.9.4 IGCC Alternative ............................................................................ 4-62

22 4.9.5 NGCC Alternative .......................................................................... 4-63

23 4.9.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-63

24 4.9.7 Purchased Power Alternative ......................................................... 4-64

25 4.10 Socioeconomics............................................................................................. 4-64

26 4.10.1 Proposed Action............................................................................. 4-65

27 4.10.2 No-Action Alternative ..................................................................... 4-65

28 4.10.2.1 Socioeconomics .......................................................... 4-65

29 4.10.2.2 Transportation............................................................. 4-66

30 4.10.3 New Nuclear Alternative................................................................. 4-66

31 4.10.3.1 Socioeconomics .......................................................... 4-66

32 4.10.3.2 Transportation............................................................. 4-67

33 4.10.4 IGCC Alternative ............................................................................ 4-67

34 4.10.4.1 Socioeconomics .......................................................... 4-67

35 4.10.4.2 Transportation............................................................. 4-68

36 4.10.5 NGCC Alternative .......................................................................... 4-69

37 4.10.5.1 Socioeconomics .......................................................... 4-69

38 4.10.5.2 Transportation............................................................. 4-69

39 4.10.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-70

40 4.10.6.1 Socioeconomics .......................................................... 4-70

41 4.10.6.2 Transportation............................................................. 4-71
Table of Contents

xii

1 4.10.7 Purchased Power Alternative ......................................................... 4-71

2 4.10.7.1 Socioeconomics .......................................................... 4-71

3 4.10.7.2 Transportation............................................................. 4-71

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

5 4.11.1 Proposed Action............................................................................. 4-72

6 4.11.1.1 Normal Operating Conditions ...................................... 4-72

7 4.11.1.2 Environmental Impacts of Postulated Accidents .......... 4-75

8 4.11.2 No-Action Alternative ..................................................................... 4-88

9 4.11.3 New Nuclear Alternative................................................................. 4-89

10 4.11.4 IGCC Alternative ............................................................................ 4-89

11 4.11.5 NGCC Alternative .......................................................................... 4-90

12 4.11.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-90

13 4.11.7 Purchased Power Alternative ......................................................... 4-90

14 4.12 Environmental Justice.................................................................................... 4-91

15 4.12.1 Proposed Action............................................................................. 4-91

16 4.12.2 No-Action Alternative ..................................................................... 4-93

17 4.12.3 New Nuclear Alternative................................................................. 4-93

18 4.12.4 IGCC Alternative ............................................................................ 4-94

19 4.12.5 NGCC Alternative .......................................................................... 4-95

20 4.12.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-95

21 4.12.7 Purchased Power Alternative ......................................................... 4-96

22 4.13 Waste Management....................................................................................... 4-97

23 4.13.1 Proposed Action............................................................................. 4-97

24 4.13.2 No-Action Alternative ..................................................................... 4-98

25 4.13.3 New Nuclear Alternative................................................................. 4-98

26 4.13.4 IGCC Alternative ............................................................................ 4-98

27 4.13.5 NGCC Alternative .......................................................................... 4-99

28 4.13.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-99

29 4.13.7 Purchased Power Alternative ......................................................... 4-99

30 4.14 Evaluation of New and Potentially Significant Information.............................. 4-99

31 4.15 Impacts Common to All Alternatives............................................................. 4-100

32 4.15.1 Fuel Cycles .................................................................................. 4-100

33 4.15.1.1 Uranium Fuel Cycle................................................... 4-101

34 4.15.1.2 Replacement Power Plant Fuel Cycles...................... 4-102

35 4.15.2 Terminating Power Plant Operations and Decommissioning........ 4-102

36 4.15.2.1 Existing Nuclear Power Plant .................................... 4-103

37 4.15.2.2 Replacement Power Plants ....................................... 4-103

38 4.15.3 Greenhouse Gas Emissions and Climate Change ....................... 4-104

39 4.15.3.1 Greenhouse Gas Emissions from the Proposed 

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

41 4.15.3.2 Climate Change Impacts to Resource Areas............. 4-107
Table of Contents

xiii

1 4.16 Cumulative Impacts of the Proposed Action................................................. 4-113

2 4.16.1 Air Quality and Noise ................................................................... 4-113

3 4.16.1.1 Air Quality ................................................................. 4-114

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

5 4.16.2 Geology and Soils........................................................................ 4-115

6 4.16.3 Water Resources ......................................................................... 4-116

7 4.16.3.1 Surface Water Resources ......................................... 4-116

8 4.16.3.2 Groundwater Resources............................................ 4-120

9 4.16.4 Terrestrial Resources................................................................... 4-121

10 4.16.5 Aquatic Resources....................................................................... 4-124

11 4.16.5.1 Energy Development................................................. 4-124

12 4.16.5.2 Future Urbanization and Transportation 

13 Development............................................................. 4-125

14 4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas.... 4-125

15 4.16.5.4 Illinois Wildlife Conservation Plan.............................. 4-125

16 4.16.5.5 Conclusion ................................................................ 4-125

17 4.16.6 Historic and Cultural Resources................................................... 4-126

18 4.16.7 Socioeconomics........................................................................... 4-126

19 4.16.8 Human Health.............................................................................. 4-127

20 4.16.9 Environmental Justice.................................................................. 4-127

21 4.16.10 Waste Management..................................................................... 4-128

22 4.16.11 Global Climate Change................................................................ 4-129

23 4.16.12 Summary of Cumulative Impacts.................................................. 4-130

24 4.17 Resource Commitments............................................................................... 4-132

25 4.17.1 Unavoidable Adverse Environmental Impacts .............................. 4-132

26 4.17.2 Short-Term Versus Long-Term Productivity ................................. 4-133

27 4.17.3 Irreversible and Irretrievable Commitments of Resources ............ 4-133

28 4.18 References .................................................................................................. 4-134

29 5.0 CONCLUSION ............................................................................................................. 5-1

30 5.1 Environmental Impacts of License Renewal..................................................... 5-1

31 5.2 Comparison of Alternatives .............................................................................. 5-1

32 5.3 Recommendation............................................................................................. 5-1

33 6.0 LIST OF PREPARERS ................................................................................................ 6-1

34 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 

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

36 8.0 INDEX.......................................................................................................................... 8-1

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

38 APPENDIX B APPLICABLE LAWS, REGULATIONS, AND OTHER 

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

40 APPENDIX C CONSULTATION CORRESPONDENCE .....................................................C-1
Table of Contents

xiv

1 APPENDIX D CHRONOLOGY OF ENVIRONMENTAL REVIEW 

2 CORRESPONDENCE .................................................................................. D-1

3 APPENDIX E PROJECTS AND ACTIONS CONSIDERED IN CUMULATIVE IMPACTS 

4 ANALYSIS.................................................................................................... E-1

5 APPENDIX F U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 

6 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 

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

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

9 APPENDIX G TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL................G-1
xv

1 FIGURES

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

3 Figure 1–2. Environmental Issues Evaluated for License Renewal ..................................... 1-4

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

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

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

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

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

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

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

11 Figure 3–7. Site Physiography, LSCS Vicinity................................................................... 3-31

12 Figure 3–8. North-South Geologic Cross Section, LSCS Vicinity ...................................... 3-32

13 Figure 3–9. Bedrock Topography and Buried Valleys, LSCS Vicinity ................................ 3-33

14 Figure 3–10. The Upper Illinois River Basin and Drainage Basin Boundaries ..................... 3-37

15 Figure 3–11. LSCS Surface Water and Related Water Resource Features ........................ 3-38

16 Figure 3–12. LSCS Site Hydrogeologic Units...................................................................... 3-47

17 Figure 3–13. LSCS Groundwater Flow in Engineered Granular Fill .................................... 3-49

18 Figure 3–14. LSCS Hydrogeologic Cross-Section............................................................... 3-50

19 Figure 3–15. Icthyoplankton Sampling Location at the LSCS River Intake Structure........... 3-62

20 Figure 3–16. Sampling Locations in LSCS Aquatic Surveys ............................................... 3-63

21 Figure 3–17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS.................... 3-104

22 Figure 3–18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS............. 3-105

23 Figure G–1. Illustration of Truck Stop Model....................................................................... G-6

xvii

1 TABLES

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

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

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

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

6 Table 2–2. Summary of Environmental Impacts of Proposed Action and 

7 Alternatives.................................................................................................... 2-25

8 Table 3–1. LSCS Site Land Uses by Area ....................................................................... 3-21

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

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

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

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

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

14 LSCS ............................................................................................................. 3-40

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

16 LSCS ............................................................................................................. 3-43

17 Table 3–8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion............................... 3-52

18 Table 3–9. State-Listed Species in LaSalle County ......................................................... 3-56

19 Table 3–10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River............ 3-65

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

21 History Electrofishing Surveys from 1957 through 2009................................. 3-67

22 Table 3–12. Fish Stockings in the LSCS Cooling Pond 2008–2014................................... 3-68

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

24 County ........................................................................................................... 3-70

25 Table 3–14. Federally Listed Species and Designated Habitat in La Salle County, 

26 Illinois............................................................................................................. 3-75

27 Table 3–15. LSCS Employees Residence by County ........................................................ 3-83

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

29 2009-2013, 5-year estimates) ........................................................................ 3-84

30 Table 3–17. Major Employers in LaSalle County in 2009................................................... 3-85

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

32 unless otherwise indicated)............................................................................ 3-85

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

34 2014 (estimated), and Projected for 2020–2060 ............................................ 3-86

35 Table 3–20. Demographic Profile of the Population in the LSCS ROI in 2010 ................... 3-87

36 Table 3–21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County) ................... 3-87

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

38 LSCS ............................................................................................................. 3-88

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

40 within 50 mi (80 km) of LSCS (2012).............................................................. 3-90

41 Table 3–24. Housing in the LSCS ROI (2014 estimate)..................................................... 3-91

42 Table 3–25. Local Public Water Supply Systems............................................................... 3-92
1 Table 3–26. LSCS Power Block Tax Payments and Valuations 2007–2014 (in 

2 dollars)........................................................................................................... 3-93

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

4 Levy............................................................................................................... 3-94

5 Table 3–28. Annual Payments to Illinois Emergency Management Agency 2009–

6 2014............................................................................................................... 3-95

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

8 Annual Daily Traffic Count ............................................................................. 3-95

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

10 Table 4–2. Air Quality and Noise ....................................................................................... 4-7

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

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

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

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

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

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

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

18 Illinois, and NRC Effect Determinations for Proposed LSCS License 

19 Renewal......................................................................................................... 4-56

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

35 Table 4–23. Comparison of GHG Emission Inventories................................................... 4-130

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

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

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

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

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

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

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

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

xix

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

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

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

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

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

6 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 7

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

Table F–5(b). Dominant LSCS Unit 2 Fire Zone Contributors to Fire CDF of 9.4×10-6 9

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

11 Table F–6. SAMA Cost-Benefit Screening Analysis for LSCS Station.............................. F-33

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

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

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

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

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

17 Yucca Mountain Repository Site, Normalized to Reference 

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

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

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

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

22 Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 

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

xxi

1 EXECUTIVE SUMMARY

2 BACKGROUND

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

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

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

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

7 power reactor operating license requires preparation of an environmental impact statement 

8 (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that, in connection 

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

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

11 License Renewal of Nuclear Plants. 

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

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

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

15 LSCS, the NRC staff performed the following:

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

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

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

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

20 • conducted a review of the issues following the guidance set forth in

21 Standard Review Plans for Environmental Reviews for Nuclear Power Plants:

22 Environmental Standard Review Plan for Operating License Renewal (NUREG-1555

23 Supplement 1, Revision 1, Final Report); and

24 • considered public comments received during the scoping process.

25 PROPOSED ACTION

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

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

28 licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. The NRC’s 

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

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

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

32 existing license will not be deemed to have expired until the safety and environmental reviews 

33 are completed and until the NRC has made a final decision on whether to issue a renewed 

34 license for the additional 20 years. 

35 PURPOSE AND NEED FOR ACTION

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

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

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

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

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

xxii

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

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

3 as amended, environmental analysis that would lead the NRC to reject a license renewal 

4 application, the NRC does not have a role in the energy-planning decisions as to whether a 

5 particular nuclear power plant should continue to operate.

6 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL

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

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

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

10 criteria:

11 • The environmental impacts associated with the issue

12 are determined to apply either to all plants or, for some

13 issues, to plants having a specific type of cooling

14 system or other specified plant or site characteristics.

15 • A single significance level (i.e., SMALL, MODERATE,

16 or LARGE) has been assigned to the impacts except

17 for collective offsite radiological impacts from the fuel

18 cycle and from high-level waste and spent fuel

19 disposal.

20 • Mitigation of adverse impacts associated with the issue

21 is considered in the analysis, and it has been

22 determined that additional plant-specific mitigation

23 measures are likely not to be sufficiently beneficial to

24 warrant implementation.

25 For Category 1 issues, no additional site-specific analysis is 

26 required in this SEIS unless new and significant information is identified. Chapter 4 of this SEIS

27 presents the process for identifying new and significant information. Site-specific issues 

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

29 therefore, an additional site-specific review for these non-generic issues is required, and the 

30 results are documented in the SEIS. 

31 Neither Exelon nor the NRC identified information that is both new and significant related to 

32 Category 1 issues that would call into question the conclusions in the GEIS. This conclusion is 

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

34 the applicant’s activities, the public scoping process, and the findings from the environmental 

35 site audit conducted by the NRC staff. Therefore, the NRC staff relied upon the conclusions of 

36 the GEIS for all Category 1 issues applicable to LSCS. 

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

38 (Transportation), but this new information was not considered significant and therefore did not 

39 affect the conclusions for these issues presented in the GEIS. This new information is 

40 discussed in Section 4.15.1 and Appendix G of this SEIS.

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

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

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

44 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

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

2 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 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

Socioeconomic

Environmental Justice

Global Climate Change

All other resource areas

MODERATE to LARGE

MODERATE

See note below (e)

See note below (d)

MODERATE

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.

3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 

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

5 an environmental impact statement or environmental assessment for LSCS, 
Executive Summary

xxiv

1 10 CFR 51.53(c)(3)(ii)(L) requires Exelon to submit, with the ER, a consideration of alternatives

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

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

4 components, systems, procedures, and training.

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

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

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

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

9 ALTERNATIVES

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

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

12 renewing the LSCS operating licenses (the no-action alternative). The NRC staff considered 

13 the following feasible and commercially viable replacement power alternatives: 

14 • new nuclear power;

15 • coal-integrated gasification combined-cycle;

16 • natural gas combined-cycle (NGCC); and

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

18 • purchased power.

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

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

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

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

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

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

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

26 considered the following alternatives, but dismissed them: 

27 • energy conservation and energy efficiency,

28 • solar power,

29 • wind power,

30 • biomass,

31 • hydroelectric power,

32 • wave and ocean energy,

33 • fuel cells,

34 • delayed retirement,

35 • geothermal power,

36 • municipal solid waste,

37 • oil-fired power, and

38 • supercritical pulverized coal.
Executive Summary

xxv 

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

2 evaluating impacts from license renewal.

3 PRELIMINARY RECOMMENDATION

4 The NRC staff’s preliminary recommendation is that the adverse environmental impacts of 

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

6 energy-planning decisionmakers would be unreasonable. The NRC staff based its

7 recommendation on the following:

8 • the analyses and findings in the GEIS;

9 • the ER submitted by Exelon;

10 • the NRC staff’s consultation with Federal, State, local, and Tribal Government

11 agencies;

12 • the NRC staff’s independent environmental review; and

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

14 process.

Abbreviations and Acronyms

xxvii

1 ABBREVIATIONS AND ACRONYMS

2 ac acre(s)

3 AC alternating current

4 ACC averted cleanup and decontamination costs

5 ACHP Advisory Council on Historic Preservation

6 ADAMS Agencywide Documents Access and Management System

7 AEA Atomic Energy Act of 1954 (as amended)

8 AFW auxiliary feedwater

9 AMSAC ATWS mitigating system actuation circuitry

10 ANL Argonne National Laboratory

11 ANS American Nuclear Society

12 AOC averted offsite property damage costs

13 AOE averted occupational exposure

14 AOSC averted onsite costs

15 AP auxiliary power

16 APE averted public exposure

17 ASLB Atomic Safety and Licensing Board (NRC)

18 ASME American Society of Mechanical Engineers

19 ATWS anticipated transient(s) without scram

20 AWEA American Wind Energy Association

21 BEA Bureau of Economic Analysis

22 BLM Bureau of Land Management

23 BLS Bureau of Labor Statistics

24 BOEM Bureau of Ocean Energy Management

BTU/ft3 25 British thermal unit(s) per cubic foot

26 CAA Clean Air Act

27 CAES compressed air energy storage

28 CCS carbon capture and storage

29 CCW component cooling water

30 CDF core damage frequency

31 CEQ Council on Environmental Quality

32 CET containment event tree

33 CFE early containment failure

34 CFR Code of Federal Regulations
Abbreviations and Acronyms

xxviii

1 cfs cubic foot (feet) per second

2 CLB current licensing basis/bases

3 CO carbon monoxide

4 CO2 carbon dioxide

5 CO2/MWh carbon dioxide per megawatt hour

6 COL combined license

7 CVCS chemical and volume control system

8 CWA Clean Water Act

9 div. Division

10 DLOOP dual unit loss(es) of offsite power

11 DMS Diverse Mitigation System

12 DOE U.S. Department of Energy

13 DSIRE Database of State Incentives for Renewables and Efficiency

14 DSM demand-side management

15 ECCS emergency core cooling system

16 EFH essential fish habitat

17 EIA Energy Information Administration

18 EIS environmental impact statement

19 ELPC Environmental Law and Policy Center

20 Elv. elevation

21 EMF electromagnetic field

22 EPA U.S. Environmental Protection Agency

23 EPRI Electric Power Research Institute

24 EPZ emergency planning zone

25 ER Environmental Report

26 ERC Energy Recovery Council

27 ES Environmental Services

28 ESA Endangered Species Act of 1973, as amended

29 ESF engineered safety feature

30 ESFAS engineered safety features actuation system

31 ESP early site permit

32 ESW emergency service water

33 Exelon Exelon Generation Company, LLC

34 FEIS final environmental impact statement

35 FERC Federal Energy Regulatory Commission
Abbreviations and Acronyms

xxix

1 FESOP Federally Enforceable State Operating Permit

2 FIVE fire-induced vulnerability evaluation

3 FR Federal Register

4 FRN Federal Register notice

ft3 5 cubic foot (feet)

6 FW feedwater

7 FWCA Fish and Wildlife Coordination Act of 1934, as amended

8 FWS U.S. Fish and Wildlife Service

9 GEIS generic environmental impact statement

10 GI generic issue

11 GL generic letter

12 gpd gallon(s) per day

13 gpm gallon(s) per minute

14 ha hectare(s)

15 HCLPF high confidence in low probability of failure

16 HEP human error probability

17 HFE human failure event

18 HFO high winds, floods, and other

19 HRA human reliability analysis

20 HX heat exchanger

21 IDNR Illinois Department of Natural Resources

22 IDOT Illinois Department of Transportation

23 IDPH Illinois Department of Public Health

24 IEA International Energy Agency

25 IEPA Illinois Environmental Protection Agency

26 IGCC integrated gasification combined-cycle

27 IHPA Illinois Historic Preservation Agency

28 ILCS Illinois Compiled Statutes

29 INEEL Idaho National Engineering and Environmental Laboratory

30 IPE individual plant examination

31 IPEEE individual plant examination(s) of external events

32 ISLOCA interfacing-systems loss-of-coolant accident

33 JHEP joint human error probability

34 km kilometer(s)

35 kW kilowatt(s)
Abbreviations and Acronyms

xxx

1 kWe kilowatt(s) electric

kWh/m2 2 /d kilowatt hours per square meter per day

3 lb pound(s)

4 LER large early release

5 LERF large early release frequency

6 LMFW loss of main feedwater

7 LOCA loss-of-coolant accident

8 LOOP loss(es) of offsite power

9 Lpd liters per day

10 LRA license renewal application

11 LSCS LaSalle County Station, Units 1 and 2

12 m/s meter(s) per second

m3 13 cubic meter(s)

14 MAAP Modular Accident Analysis Program

15 MACCS2 MELCOR Accident Consequence Code System 2

16 MACR maximum averted cost risk

17 MATS Mercury and Air Toxics Standards

18 MCR main control room

19 mgd million gallons per day

20 mi mile(s)

21 MISO Midcontinent Independent System Operator

22 MMPA Marine Mammal Protection Act

23 MOV motor-operated valve

24 mph mile(s) per hour

25 MSA Magnuson–Stevens Fishery Conservation and Management Act, 

26 as amended through 2006

27 MUR measurement uncertainty recapture

28 MW megawatt(s)

29 MWe megawatt(s) electric

30 MWh megawatt hour(s)

31 MWt megawatt(s) thermal

32 NEIS National Energy Information Service

33 NEPA National Environmental Policy Act of 1969, as amended

34 NETL National Energy Technology Laboratory

35 NGCC natural gas combined-cycle
Abbreviations and Acronyms

xxxi

1 NHPA National Historic Preservation Act of 1966, as amended

2 NMFS National Marine Fisheries Service (of the National Oceanic and 

3 Atmospheric Administration)

4 NO2 nitrogen dioxide

5 NOx nitrogen oxide(s)

6 NPDES National Pollutant Discharge Elimination System

7 NRC U.S. Nuclear Regulatory Commission

8 NREL National Renewable Energy Laboratory

9 NRR Nuclear Reactor Regulation, Office of (NRC)

10 O3 ozone

11 OECR offsite economic cost risk

12 ORNL Oak Ridge National Laboratory

13 Pb lead

14 PDR population dose risk

15 PDS plant damage state

16 PEIS programmatic environmental impact statement

17 PL public law

18 PNNL Pacific Northwest National Laboratory

19 PORV power-operated relief valve

20 PRA probabilistic risk assessment

21 PV photovoltaic

22 PWR pressurized water reactor

23 RAI request(s) for additional information

24 RCP reactor coolant pump

25 RCRA Resource Conservation and Recovery Act of 1976, as amended

26 rem roentgen equivalent(s) man

27 RHR residual heat removal

28 ROI region(s) of influence

29 RPC replacement power cost

30 RPS reactor protection system

31 RPV reactor pressure vessel

32 RRW risk reduction worth

33 RTO Regional Transmission Organization

34 RWST refueling water storage tank

35 SAMA severe accident mitigation alternative
Abbreviations and Acronyms

xxxii

1 SAT system auxiliary transformer

2 SBO station blackout

3 SCPC supercritical pulverized coal

4 SEIS supplemental environmental impact statement

5 SER safety evaluation report

6 SG steam generator

7 SGTR steam generator tube rupture

8 SI safety injection

9 SMA seismic margin assessment

10 SO2 sulfur dioxide

11 SR supporting requirement

12 SSC structure, system, and component

13 SSEL Safe Shutdown Equipment List

14 Sv sievert(s)

15 SW service water

16 SX essential service water

17 syngas synthesis gas

18 TAC technical assignment control

19 TEEIC Tribal Energy and Environmental Information Clearinghouse

20 TS technical specification

21 U.S. United States

22 U.S.C. United States Code

23 UAT unit auxiliary transformer

24 UFSAR updated final safety analysis report

25 USDA U.S. Department of Agriculture

26 USGS U.S. Geological Survey

yd3 27 cubic yard(s)

28 W/m2 watt(s) per square meter
1-1

1 1.0 INTRODUCTION

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

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

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

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

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

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

8 license for up to an additional 20 years. The initial 40-year licensing period was based on 

9 economic and antitrust considerations rather than on technical limitations of the nuclear facility.

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

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

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

13 deny license renewal based on whether the applicant has demonstrated that the environmental 

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

15 operation.

16 1.1 Proposed Federal Action

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

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

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

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

21 1.2 Purpose and Need for Proposed Federal Action

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

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

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

25 determined by other energy-planning decisionmakers. This definition of purpose and need 

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

27 AEA or findings in the NEPA environmental analysis that would lead the NRC to reject a license 

28 renewal application (LRA), the NRC does not have a role in the energy-planning decisions of 

29 state regulators and utility officials as to whether a particular nuclear power plant should 

30 continue to operate.

31 1.3 Major Environmental Review Milestones

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

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

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

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

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

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

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

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

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

1-2

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

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

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

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

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

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

7 (NRC 2015b).

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

9 draft supplemental environmental impact statement (SEIS). This document is made available 

10 for public comment for 45 days. During this time, the NRC staff will host public meetings and 

11 collect public comments. Based on the information gathered, the NRC staff will amend the draft 

12 SEIS findings, as necessary, and will publish the final SEIS. Figure 1–1 shows the major 

13 milestones of the NRC’s LRA environmental review process.

14 Figure 1–1. Environmental Review Process

15

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

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

18 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 

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

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

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

22 1.4 Generic Environmental Impact Statement

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

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

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

1-3

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

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

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

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

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

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

7 Addendum 1 and Revision 1 to the GEIS.

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

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

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

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

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

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

14 • describes the activity that affects the environment,

15 • identifies the population or resource that is affected,

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

17 resource,

18 • characterizes the significance of the effect for both beneficial and adverse effects,

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

20 • considers whether additional mitigation measures would be warranted for impacts 

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

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

23 Environmental Quality terminology for “significant.” The NRC established three levels of 

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

25 SMALL: Environmental effects are not 

26 detectable or are so minor that they will neither 

27 destabilize nor noticeably alter any important 

28 attribute of the resource.

29 MODERATE: Environmental effects are 

30 sufficient to alter noticeably, but not to 

31 destabilize, important attributes of the resource.

32 LARGE: Environmental effects are clearly 

33 noticeable and are sufficient to destabilize important attributes of the resource.

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

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

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

37 issues are those that meet the following criteria:

38 • The environmental impacts associated with the issue have been determined to apply 

39 either to all plants or, for some issues, to plants having a specific type of cooling 

40 system or other specified plant or site characteristics.

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

42 to the impacts (except for collective offsite radiological impacts from the fuel cycle 

43 and from high-level waste and spent fuel disposal).

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

1-4

1 • Mitigation of adverse impacts associated with the issue has been considered in the 

2 analysis, and it has been determined that additional plant-specific mitigation

3 measures are likely not to be sufficiently beneficial to warrant implementation.

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

5 unless new and significant information is identified. The process for identifying new and 

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

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

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

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

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

11 Figure 1–2. Environmental Issues Evaluated for License Renewal

12 1.5 Supplemental Environmental Impact Statement

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

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

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

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

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

1-5

1 license renewal would be unreasonable. The NRC will make its final recommendation after 

2 considering comments received on the draft SEIS during the public comment period.

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

4 • reviewed the information provided in Exelon’s ER;

5 • consulted with Federal, state, and local agencies, and tribal nations; 

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

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

8 process).

9 New information can be identified from many 

10 sources, including the applicant, the NRC, other 

11 agencies, or public comments. If a new issue is 

12 revealed, it is first analyzed to determine whether 

13 it is within the scope of the license renewal 

14 environmental evaluation. If the new issue is not 

15 addressed in the GEIS, the NRC staff would determine the significance of the issue and 

16 document the analysis in the SEIS.

17 1.6 Decisions to Be Supported by the SEIS

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

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

20 follows:

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

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

23 adverse environmental impacts of license renewal are so great that 

24 preserving the option of license renewal for energy planning 

25 decisionmakers would be unreasonable.

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

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

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

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

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

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

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

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

34 1.7 Cooperating Agencies

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

36 agencies in the preparation of this SEIS.

37 1.8 Consultations

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

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

40 (16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 

41 (NHPA) (16 U.S.C. 470 et seq.), require Federal agencies to consult with applicable state and 

New and significant information. To merit 

additional review, information must be both new 

and bear on the proposed action or its impacts, 

presenting a seriously different picture of the 

impacts from those envisioned in the GEIS.
Introduction

1-6

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

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

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

4 documents:

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

6 • Illinois Historic Preservation Agency;

7 • Advisory Council on Historic Preservation;

8 • Ho-Chunk Nation;

9 • Miami Tribe of Oklahoma;

10 • Peoria Tribe of Indians of Oklahoma;

11 • Citizen Potawatomi Nation;

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

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

14 • Sac and Fox Nation;

15 • Pokagon Band of Potawatomi;

16 • Forest County Potawatomi;

17 • Hannahville Indian Community, Band of Potawatomi;

18 • Prairie Band Potawatomi Nation;

19 • Winnebago Tribe of Nebraska;

20 • Kickapoo Tribe in Kansas; and

21 • Kickapoo Tribe of Oklahoma.

22 1.9 Correspondence

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

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

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

26 1.10 Status of Compliance

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

28 state, and local requirements. Appendix F of the GEIS describes some of the major applicable 

29 Federal statutes. There are numerous permits and licenses issued by Federal, state, and local 

30 authorities for activities at LSCS. Appendix B contains further information about LSCS’s status 

31 of compliance.

32 1.11 Related Federal and State Activities

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

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

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

36 this SEIS. 
Introduction

1-7 

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

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

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

4 Ammunition Plant.

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

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

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

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

9 consultation correspondences.

10 1.12 References

11 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

12 protection regulations for domestic licensing and related regulatory functions.”

13 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

14 renewal of operating licenses for nuclear power plants.”

15 80 FR 5793. U.S. Nuclear Regulatory Commission. “LaSalle County Station, Units 1 and 2,

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

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

18 February 3, 2015.

19 80 FR 5822. U.S. Nuclear Regulatory Commission. “LaSalle County Station, Units 1 and 2, 

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

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

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

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

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

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

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

27 ML14343A897. 

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

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

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

31 16 U.S.C. §1801 et seq.

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

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

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

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

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

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

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

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

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

41 No. ML040690720.
Introduction

1-8

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

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

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

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

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

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

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

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

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

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

11 May 20, 2015. ADAMS No. ML15132A674.
2-1

1 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION

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

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

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

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

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

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

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

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

10 license renewal are so great that preserving the option of license renewal for energy-planning 

11 decisionmakers would be unreasonable (Title 10 of the Code of Federal Regulations

12 (10 CFR) 51.95(c)(4)).

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

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

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

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

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

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

19 would be the most likely alternative in any given case.

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

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

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

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

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

25 continued plant operations to the environmental impacts of alternatives.

26 2.1 Proposed Action

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

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

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

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

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

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

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

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

35 2.1.1 Plant Operations during the License Renewal Term

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

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

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

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

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

41 • reactor operation;

42 • waste management;
Alternatives Including the Proposed Action

2-2

1 • security;

2 • office and clerical work;

3 • surveillance, monitoring, and maintenance; and

4 • refueling and other outages.

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

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

7 manner as it does during the current license term except for, as appropriate, additional aging 

8 management programs to address structure and component aging in accordance with 

9 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants.”

10 2.1.2 Refurbishment and Other Activities Associated with License Renewal

11 Refurbishment activities include replacement and repair of major systems, structures, and 

12 components. For example, replacement activities may include replacement of recirculation 

13 piping systems for BWRs. The intent of the major refurbishment class of activities characterized 

14 in the GEIS (NRC 2013) is to encompass actions that typically take place only once in the life of 

15 a nuclear plant, if at all. Refurbishment activities may have an impact on the environment 

16 beyond those that occur during normal operations and may require evaluation depending on the 

17 type of action and the plant-specific design.

18 In preparation for its license renewal application, Exelon performed an evaluation of LSCS

19 structures, systems, and components in accordance with 10 CFR 54.21, “Contents of 

20 application—technical information,” to identify whether any major refurbishment activities would 

21 be necessary to support the continued operation of LSCS during the proposed 20-year period of 

22 extended operation (Exelon 2014).

23 Exelon did not identify any major refurbishment or replacement activities needed to support the 

24 continued operation of LSCS beyond the existing operating license term (Exelon 2014). 

25 Therefore, these activities are not discussed under the proposed action in Chapter 4.

26 2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning after the 

27 License Renewal Term

28 NUREG–0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 

29 Facilities: Supplement 1, Regarding the Decommissioning of Nuclear Power Reactors,

30 describes the impacts of decommissioning (NRC 2002). Most activities associated with plant 

31 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 

32 spent nuclear fuel) would remain unchanged, whereas others (e.g., waste management; office 

33 and clerical work; laboratory analysis; and surveillance, monitoring, and maintenance) would 

34 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 

35 operations; however, impacts from their physical presence may continue if they are not removed 

36 after reactor shutdown. For multiple-unit sites, such as LSCS, shared systems may operate at 

37 reduced capacities. Impacts associated with dedicated systems that remain in place or shared 

38 systems that continue to operate at normal capacities would remain unchanged.

39 Decommissioning will occur whether LSCS is shut down at the end of its current operating 

40 license term or at the end of the period of extended operation. There are no site-specific issues 

41 related to decommissioning. The license renewal GEIS concludes that license renewal would 

42 have a negligible (SMALL) effect on the impacts of terminating operations and decommissioning 

43 on all resources.
Alternatives Including the Proposed Action

2-3

1 2.2 Alternatives

2 As stated above, the NRC has the obligation to consider reasonable alternatives to the 

3 proposed action of renewing the licenses for the nuclear reactors at LSCS. To be reasonable, a 

4 replacement power alternative must be commercially viable on a utility scale and operational 

5 prior to the expiration of the reactor’s operating licenses, or expected to become commercially 

6 viable on a utility scale and operational prior to the expiration of the reactor’s operating licenses 

7 (NRC 2013). The 2013 GEIS update incorporated the latest information on replacement power 

8 alternatives; however, rapidly evolving technologies are likely to outpace the information 

9 presented in the GEIS. As such, a site-specific analysis of alternatives must be performed for 

10 each SEIS, taking into account changes in technology and science since the preparation of the 

11 GEIS.

12 Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 

13 not issue renewed licenses for LSCS). Sections 2.2.2.1–2.2.2.5 describe the characteristics of 

14 replacement power alternatives for LSCS.

15 2.2.1 No-Action Alternative

16 At some point, operating nuclear power plants will terminate operations and undergo 

17 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 

18 operating license of a nuclear power plant beyond the current operating license term. Under the 

19 no-action alternative, the NRC does not renew the operating licenses, and the LSCS plant shuts 

20 down at or before the end of the current licenses in 2022 and 2023. After shutdown, plant 

21 operators will initiate decommissioning in accordance with 10 CFR 50.82, “Termination of 

22 License.”

23 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 

24 SEIS. The environmental impacts from decommissioning and related activities are addressed in 

25 several other documents, including the decommissioning GEIS (NRC 2002); the license renewal 

26 GEIS, Chapter 4 (NRC 2013); and Chapter 4 of this SEIS. These analyses either directly 

27 address or bound the environmental impacts of decommissioning whenever Exelon ceases to 

28 operate LSCS.

29 Even with renewed operating licenses, LSCS will eventually shut down, and the 

30 environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time. 

31 As with decommissioning impacts, shutdown impacts are expected to be similar whether they 

32 occur at the end of the current license term or at the end of a renewed license term.

33 Termination of operations at LSCS would result in the total cessation of electrical power 

34 production. Unlike the alternatives described in Section 2.2.2, the no-action alternative does not 

35 meet the purpose and need of the proposed action because it does not provide a means of 

36 delivering baseload power to meet future electric system needs. Given the current need for the 

37 power generated by LSCS, the no-action alternative would likely create a need for a 

38 replacement power alternative. A full range of replacement power alternatives (including new 

39 nuclear, fossil fuels, and renewable energy sources) are described in the following section, and 

40 their potential impacts are assessed in Chapter 4. Although the NRC’s authority only extends to 

41 the decision of whether to renew the LSCS operating licenses, the replacement power 

42 alternatives described in the following sections represent possible options for energy-planning 

43 decisionmakers should the NRC choose not to renew the LSCS operating licenses.
Alternatives Including the Proposed Action

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1 2.2.2 Replacement Power Alternatives

2 In evaluating alternatives to license renewal, the NRC considered energy technologies or 

3 options currently in commercial operation, as well as technologies not currently in commercial 

4 operation but likely to be commercially available by the time the current LSCS operating 

5 licenses expire. The current operating licenses for the LSCS, Units 1 and 2, expire on 

6 April 17, 2022, and December 16, 2023, respectively. Alternatives that are not likely to be 

7 constructed, permitted, and connected to the grid by the time the LSCS licenses expire were 

8 eliminated from detailed consideration.

9 Alternatives that cannot provide the equivalent of LSCS’s current generating capacity and, in 

10 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 

11 reasonable alternatives, were not considered in detail. Each alternative eliminated is briefly 

12 discussed, and the basis for its elimination is provided in Section 2.3. In total, 17 alternatives to 

13 the proposed action were considered (see text box) and then narrowed to the 5 alternatives 

14 considered in Sections 2.2.2.1–2.2.2.5. The NRC staff evaluated the environmental impacts of 

15 these five alternatives and the no-action alternative. They are discussed in depth in Chapter 4 

16 of this SEIS.

17 The GEIS presents an overview of some energy technologies but does not reach conclusions 

18 about which alternatives are most appropriate. Because many energy technologies are 

19 continually evolving in capability and cost and because regulatory structures have changed to 

20 either promote or impede development of particular alternatives, the analyses in this chapter 

21 may include updated information from the following sources:

22 • U.S. Department of Energy (DOE), U.S. Energy Information Administration (EIA),

23 • other offices within the DOE,

24 • U.S. Environmental Protection Agency (EPA),

25 • industry sources and publications, and

26 • information submitted by Exelon in its ER.

27 The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 

28 impacts across several impact categories: land use and visual resources, air quality and noise, 

29 geologic environment, water resources, ecological resources, historic and cultural resources, 

30 socioeconomics, human health, environmental justice, and waste management. Most 

31 site-specific issues (Category 2) have been assigned a significance level of SMALL, 

32 MODERATE, or LARGE. For ecological and historic and archaeological resources, the impact 

33 significance determination language is specific to the authorizing legislation (e.g., Endangered 

34 Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), and National Historic Preservation 

35 Act of 1966, as amended (16 U.S.C. 470 et seq.)). The order of presentation of the alternatives

36 is not meant to imply increasing or decreasing level of impact. Nor does it imply that an 

37 energy-planning decisionmaker would be more likely to select any given alternative.

38 To ensure that the alternatives analysis is consistent with state or regional energy policies, the 

39 NRC reviewed energy-related statutes, regulations, and policies within the LSCS region. As a 

40 result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 

41 as well as a combination that includes both of them.

42 Region of Influence

43 LSCS is owned and operated by Exelon and provides electricity to the region of influence (ROI) 

44 through transmission lines owned by Commonwealth Edison (ComEd) (Exelon 2014). ComEd 
Alternatives Including the Proposed Action

2-5

1 operates under the PJM Interconnection, LLC 

2 (PJM), a regional transmission organization 

3 that coordinates the movement of wholesale 

4 electricity in 13 states across the Midwest 

5 and Northeast (Exelon 2014). ComEd 

6 provides service to 3.8 million customers

7 across northern Illinois. Its service territory 

8 borders Iroquois County to the south, the 

9 Wisconsin border to the north, the Iowa 

10 border to the west, and the Indiana border to 

11 the east (ComEd 2015). However, electricity 

12 consumption in Illinois is not limited to 

13 electricity that is generated within the State. 

14 Although northern Illinois relies on electricity 

15 from ComEd, the rest of Illinois and 

16 surrounding states, which are not part of the 

17 PJM, are part of the Midcontinent 

18 Independent System Operator, Inc. (MISO) 

19 (see Figure 2–1) (Exelon 2014).

20 If renewed licenses were not issued, 

21 replacement power for LSCS would be 

22 required in northern Illinois. Electricity could 

23 be replaced by generation sources from a 

24 variety of locations. Electricity could be 

25 transported from within the PJM; however, the PJM in Illinois is geographically distant from the 

26 rest of the PJM region (see Figure 2–1). It is also possible that electricity within MISO could be 

27 purchased by PJM, and efforts are currently being made to increase coordination and 

28 deliverability between the regional transmission organizations (Ott 2013b). In addition, the State 

29 of Illinois has a renewable portfolio standard that includes a stipulation that eligible renewable 

30 resources must be procured from facilities located in Illinois or the States that adjoin Illinois 

31 (Wisconsin, Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable 

32 resources can be obtained only from other regions of the country if they are not available in 

33 Illinois or in the adjoining States (ILGA 2011).

34 Because replacement power would be required in northern Illinois, and any renewable energy 

35 resources would need to be procured from facilities in Illinois or the adjoining States, the NRC 

36 staff evaluated the impacts of locating replacement power facilities within the States of Illinois, 

37 Indiana, Iowa, Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the 

38 ROI for the NRC staff’s analysis of alternatives. The NRC assumes that replacement power 

39 would either be produced in northern Illinois within the PJM region or would be purchased by 

40 PJM from MISO.

41 In 2012, electric generators in the ROI had a net summer generating capacity of approximately 

42 179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 

43 (27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c).

44 In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 

45 (MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 

46 nuclear (21 percent). Although natural gas makes up nearly 30 percent of the installed 

47 generating capacity in the ROI, it provides only 6 percent of electricity in the region. 

48 Nonhydroelectric renewable energy produced 1.3 percent of the electricity in the ROI 

49 (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

• solar power

• wind power

• biomass

• hydroelectric power

• wave and ocean energy

• fuel cells

• delayed retirement

• geothermal power

• municipal solid waste

• petroleum

• supercritical pulverized coal
Alternatives Including the Proposed Action

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

2 Source: MISO-PJM undated

3 Renewable Energy Legislation in the Region of Influence

4 Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 

5 States; therefore, any legislation targeting renewable energy in these States could impact a 

6 State’s incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 

7 Missouri, Wisconsin, and Michigan) have legally mandated renewable energy programs. The 

8 State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 

9 energy requirements. The paragraphs below briefly outline each State’s program, including 

10 renewable energy goals and benchmarks.

11 In August 2007, Illinois adopted a renewable portfolio standard that requires the State’s utilities 

12 to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 

13 which must come from wind. Solar PV must comprise 6 percent of the annual requirement for 

14 calendar year 2015 and thereafter. Other eligible sources include biomass and existing 

15 hydroelectric power (DSIRE 2015a). The law also includes an energy efficiency standard that 

16 requires utilities to implement cost-effective energy efficiency measures to meet energy savings 

17 of 1 percent by calendar year 2016 and thereafter (ILGA 2011). For electric utilities (including 

18 ComEd), eligible resources must be located in Illinois; resources can be purchased from 

19 adjoining States only if there are insufficient in-State resources (ILGA 2011).

20 Iowa’s Alternative Energy Production Law requires the State’s two investor-owned utilities to 

21 generate a combined total of 105 MW of their generating capacity from renewable energy 

22 sources. A 2007 order allows the utilities to participate in renewable energy credit trading 

23 programs by distinguishing between renewable electricity production capacity used to comply 

24 with Iowa law and that which can be used to satisfy other states’ renewable portfolio standards 

25 (DSIRE 2014).

26 Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 

27 increase their use of renewable sources by 15 percent by 2021 and includes a provision 

28 specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 

29 energy. Resources can be purchased from outside Missouri, but renewable energy generated 

30 in-State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2015b).
Alternatives Including the Proposed Action

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1 Wisconsin’s renewable portfolio standard requires utilities to produce 10 percent of their 

2 electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 

3 provision that allows electricity providers to create and sell or transfer renewable resource 

4 credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 

5 eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2015c).

6 Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 

7 10 percent of their retail electricity sales from renewable energy resources by 2015. 

8 The standard also allows energy efficiency and advanced cleaner energy systems to meet part 

9 of the requirement. Renewable energy credits can be purchased from in-State or out-of-State 

10 facilities, provided that the facilities are located within the retail electric service territory of a 

11 utility that is recognized by the Michigan Public Service Commission (DSIRE 2015d).

12 Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 

13 July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 

14 10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 

15 2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 

16 coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 

17 electricity from coal, and net-metered distributed generation facilities. Fifty percent of qualifying 

18 energy must come from within the State. Utilities that participate in the program and meet the 

19 program goals are eligible for incentives that are used to pay for the compliance projects

20 (DSIRE 2015e).

21 Kentucky is the only State in the ROI that does not have mandatory or voluntary renewable 

22 energy requirements.

23 Given known technological and demographic trends, the EIA predicts that 34 percent of 

24 electricity in the United States will be generated by coal in 2040 (EIA 2015). Natural gas 

25 generation rose from 16 percent in 2000 to 27 percent in 2013 and is projected to increase to 

26 31 percent in 2040 (EIA 2013a, 2015). Electricity generation from renewable energy is 

27 expected to grow from 13 percent of total generation in 2013 to 18 percent in 2040 (EIA 2015). 

28 However, there are uncertainties that could affect this forecast, particularly the implementation 

29 of policies aimed at reducing greenhouse gas emissions, which would have a direct effect on 

30 fossil fuel-based generation technologies.

31 The remainder of this section describes replacement power alternatives to license renewal

32 considered in depth. These include a new nuclear alternative in Section 2.2.2.1; a 

33 coal-integrated gasification combined-cycle (IGCC) alternative in Section 2.2.2.2; a natural gas 

34 combined-cycle (NGCC) alternative in Section 2.2.2.3; a combination natural gas, wind, and 

35 solar power alternative in Section 2.2.2.4; and a purchased power alternative in Section 2.2.2.5. 

36 Table 2–1 summarizes key design characteristics of the alternative technologies evaluated in 

37 depth. The environmental impacts of these alternatives are evaluated in Chapter 4.
Alternatives Including the Proposed Action

2-8

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

Considered in Depth(a) 2

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% 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 

6,749 ac (2,731 ha) 

(Ong et al. 2013). 

For the NGCC 

portion, land use 

would remain the 
Alternatives Including the Proposed Action

2-9 

New Nuclear 

Alternative IGCC Alternative NGCC Alternative

Combination 

Alternative

same at 94 ac 

(38 ha) 

(Exelon 2014).

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

1 2.2.2.1 New Nuclear Alternative

2 In this section, the NRC staff describes the new nuclear alternative. The NRC staff evaluates 

3 the environmental impacts from this alternative in Chapter 4.

4 The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 

5 to license renewal. For example, nuclear generation currently provides 21 percent of electricity 

6 generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; 

7 eight applicants have received renewed licenses, and three additional applicants have applied 

8 for renewed licenses from the NRC (including LSCS) (NRC 2015). In addition, there is interest 

9 in new nuclear power plant development in the region; combined operating license (COL) 

10 applications have been filed for two new nuclear power plants in the ROI. On July 24, 2008, 
Alternatives Including the Proposed Action

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1 Union Electric Company submitted a COL application for Callaway Plant, Unit 2, in Callaway

2 County, Missouri, on the existing Callaway site (AmerenUE 2009). However, Ameren UE has 

3 since announced that they are canceling their COL application (Barker 2015). An application 

4 was also filed in September 2008 for Enrico Fermi Atomic Power Plant, Unit 3, in Monroe 

5 County, Michigan, on the existing Fermi site. On May 1, 2015, the NRC issued a COL

6 authorizing DTE Electric Company to build and operate an economic simplified BWR at the 

7 Fermi site (Volume 80 of the Federal Register, 26302 (80 FR 26302)). The NRC staff 

8 determined that there may be sufficient time for Exelon to prepare and submit an application, 

9 build, and operate two new nuclear units using a certified design before the LSCS licenses 

10 expire in April 2022 and December 2023. 

11 In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 

12 would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 

13 existing ancillary facilities at those locations, such as support buildings and transmission 

14 infrastructure. In 1987, Illinois enacted a moratorium preventing the construction of new nuclear 

15 power plants within the State. Until the moratorium is lifted, a new nuclear alternative would 

16 require siting elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the 

17 Vogtle Electric Generating Plant (Vogtle), Units 3 and 4 (located in Waynesboro, Georgia), COL 

18 environmental impact statement for technological parameters for the new nuclear alternative

19 because the Vogtle, Units 3 and 4, COL considers two new nuclear reactor units with a similar 

20 output as LSCS and is representative of the reactors that could be constructed in the ROI 

21 before LSCS’s licenses expire (NRC 2011). As such, the NRC staff assumed 

22 two Westinghouse AP1000 reactors with a net electrical output of 2,240 MWe would replace 

23 LSCS’s current reactors for this alternative. The NRC staff estimated that 324 ac (131 ha) of 

24 land would be required on a long-term basis because of permanent facilities, and an additional 

25 232 ac (94 ha) would be disturbed for temporary facilities, a laydown area, and storage of 

26 dredge material (NRC 2008).

27 The heat rejection demands of a new nuclear alternative would be similar to those of LSCS. 

28 The new reactors may require a new cooling system (including natural draft cooling towers and 

29 intake and discharge structures). The NRC staff assumes that water requirements for the new 

30 nuclear alternative would be similar to current water use at LSCS. A new onsite transmission 

31 line and drinking water wells may be required if insufficient infrastructure occurs on the site. 

32 Construction materials would be delivered by a combination of rail spur, truck, and barge, 

33 depending on the specific site location. It is possible that modifications would be required to 

34 deliver such materials, depending on the existing infrastructure at the site; modifications could 

35 include new rail lines or access roads.

36 The NRC staff also considered the installation of multiple small modular reactors as an 

37 alternative to renewing the LSCS licenses. The NRC established the Advanced Reactor 

38 Program in the Office of New Reactors because of considerable interest in small modular 

39 reactors along with anticipated license applications by vendors. Small modular reactors are 

40 approximately 300 MW or less, would have lower initial capacity than that of large-scale units, 

41 and would have siting flexibility for locations that are not large enough to accommodate 

42 traditional nuclear reactors (DOE undated). As of October 2015, no applications for small 

43 modular reactors have been submitted to the NRC. The DOE has estimated that the technology 

44 may achieve commercial operation by 2021 to 2025 (DOE undated). Because small modular 

45 reactors are not expected to be operational at a commercial scale until near the time LSCS’s 

46 licenses expire, it is unlikely that eight new small modular reactors (the number of units required 

47 to replace LSCS’s current output) could be constructed in the ROI; therefore, this analysis 

48 focuses on nuclear generation by larger nuclear units.
Alternatives Including the Proposed Action

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1 2.2.2.2 IGCC Alternative

2 In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 

3 environmental impacts from this alternative in Chapter 4.

4 Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 

5 49 percent of installed generation capacity and accounted for 67 percent of all electricity 

6 generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 

7 and combines modern coal gasification technology with both gas-turbine and steam-turbine 

8 power generation. The technology is cleaner than conventional pulverized coal plants because 

9 some of the major pollutants are removed from the gas stream before combustion. An IGCC 

10 power plant consists of coal gasification and combined-cycle power generation. Coal gasifiers 

11 convert coal into a gas (synthesis gas, also referred to as syngas), which fuels the 

12 combined-cycle power generating units. The combined-cycle system for a 618-MWe IGCC 

13 power plant includes two combustion turbines, two heat recovery steam generators, and a 

14 steam turbine. The combined-cycle units combust gas in one or more combustion turbines, and 

15 the resulting hot exhaust gas is then used to heat water into steam to drive a steam turbine. 

16 The steam turbine then uses the heat from the gas turbine’s exhaust through a heat recovery 

17 steam generator to produce additional electricity (DOE 2010a). This two-cycle process has a 

18 high rate of efficiency because the exhaust heat that would otherwise be lost is captured and 

19 reused. In addition, the power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and 

20 particulate emissions by removing constituents from the syngas before combustion. Nearly 

21 100 percent of the nitrogen from the syngas would be removed before combustion in the gas 

22 turbines and would result in lower nitrogen oxide emissions compared to conventional coal-fired 

23 power plants (DOE 2010a).

24 IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 

25 repowering project in Indiana and the Polk Power Station in Florida are two examples of 

26 operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 

27 and multiple new projects have been proposed or have recently begun operations in the 

28 United States. The Duke Energy Edwardsport Generation Station (Edwardsport) in Indiana is a 

29 618-MWe IGCC power plant in the ROI that began commercial operation in June 2013. Duke 

30 Energy estimates that the IGCC plant will produce 10 times as much power as the retired coal 

31 plant it replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and 

32 particulates. The IGCC plant will reduce carbon emissions per megawatt hour by nearly half 

33 compared to conventional coal-fired plants (Duke Energy 2013). In addition, Edwardsport has 

34 the potential for carbon capture and geologic sequestration. Space has been reserved at the 

35 site for carbon dioxide capture equipment (NETL 2013b).

36 Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 

37 reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 

38 proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 

39 carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 

40 Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 

41 active; these projects are in the planning stages, or they have begun construction. 

42 Thirteen projects have been proposed and subsequently canceled for a variety of reasons, 

43 including air quality issues, state laws and regulations, redirected focus on gas-fired generation 

44 and renewables, and unanticipated rising costs (NETL 2013c).

45 IGCC technology and proposed projects have experienced a number of setbacks and 

46 opposition, hindering IGCC’s ability to fully integrate into the energy market. The most 

47 significant roadblock is IGCC’s high capital cost compared to conventional coal-fired power 

48 plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 
Alternatives Including the Proposed Action

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1 Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 

2 support because of escalating cost estimates (Reuters 2012). Other issues include construction 

3 timeline overruns, a limited track record for reliable performance, and opposition from an 

4 environmental perspective.

5 Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 

6 staff considers IGCC technology to be a reasonable source of baseload power to replace LSCS

7 by the time its licenses expire in 2022 and 2023 because of the current regulatory framework 

8 and the number of active IGCC plants within the ROI. On August 3, 2015, EPA signed a final 

9 rule for carbon pollution that would apply to new fossil fuel-fired power plants 

10 (80 FR 64661-65120). The action establishes performance standards for utility boilers and 

11 IGCC units based on partial implementation of a CCS system as a method of emission 

12 reduction. The emission limit for these sources is 1,305 lb carbon dioxide per megawatt hour 

13 (CO2/MWh), and any new coal-fired power plants could require CCS in order to achieve this

14 emission limit. 

15 Overall, the NRC staff considers IGCC power plants as an alternative to LSCS because the 

16 Edwardsport IGCC project in Indiana is currently in operation and because the Kemper County 

17 IGCC project in Mississippi is under construction. The technology parameters for these plants 

18 are considered the current state of technology and are used here to describe a hypothetical 

19 IGCC power plant located on an existing power plant site within the ROI.

20 To replace the electricity that LSCS generates, the NRC staff considered four IGCC units, each 

21 with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 

22 the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 

23 would burn a sub-bituminous coal based on the type of coal used in electric plants in Illinois. 

24 The NRC staff presumes that coal burned in Illinois will be representative of coal that would be 

25 burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 

26 units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 

27 removing constituents from the syngas. In addition, the units would be designed with the 

28 potential to add CCS later. Using CCS, carbon dioxide emission would be compressed and 

29 piped off site where it could be sold for beneficial use or geologic storage. 

30 The IGCC alternative would be located at an existing site (such as an existing power plant site) 

31 to maximize availability of infrastructure and to reduce other environmental impacts. Depending 

32 on the specific site location, there might be a need to construct new intake and discharge

33 facilities and a new cooling system. The IGCC alternative would use about the same amount of 

34 water as LSCS and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 

35 that the cooling system would use a closed-cycle system with mechanical draft cooling towers. 

36 This system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of 

37 water and would consume 20 million gpd (76 million Lpd). Onsite visible structures could 

38 include the boilers, exhaust stacks, intake and discharge structures, mechanical draft cooling 

39 towers, transmission lines, and an electrical switchyard. Construction materials would be 

40 delivered by a combination of rail spur, truck, and barge, depending on the specific site location. 

41 Modifications may be required to deliver such materials; modifications could include new rail 

42 lines or access roads.

43 The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 

44 renewing the LSCS licenses. SCPC was dismissed as the coal alternative because of new 

45 regulations aimed at limiting the environmental impacts from conventional pulverized coal 

46 plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC

47 for analysis.
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1 2.2.2.3 NGCC Alternative

2 In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 

3 environmental impacts from this alternative in Chapter 4.

4 Natural gas represents nearly 30 percent of installed generation capacity in the ROI but 

5 provides only 6 percent of all electrical power in the ROI (EIA 2014b, 2014c). Nationwide, the 

6 percentage of power generated by natural gas is expected to rise through 2040, although the 

7 actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 

8 NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 

9 license renewal because it is a feasible, commercially available option for providing electrical 

10 generating capacity beyond the expiration of LSCS’s current licenses.

11 Baseload NGCC power plants have proven their reliability and can have capacity factors as high 

12 as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 

13 natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 

14 steam generator to produce additional electricity. This two-cycle process has a high rate of 

15 efficiency because the exhaust heat that would otherwise be lost is captured and reused. Like 

16 other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 

17 carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 

18 gases per unit of electrical output than conventional coal-powered plants.

19 To replace the electricity that LSCS generates, the NRC staff considered five NGCC units, each 

20 with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 

21 configuration consists of two combustion turbine generators, two heat recovery steam 

22 generators, and one steam turbine generator with mechanical draft cooling towers for heat 

23 rejection. The power plant is assumed to incorporate a selective catalytic reduction system to 

24 minimize the plant’s nitrogen oxide emissions (NETL 2007).

25 This 2,800-MWe NGCC plant would consume 124 billion cubic feet (3,500 million cubic meters) 

26 of natural gas annually, assuming an average heat content of 1,021 British thermal units per 

27 cubic foot (EIA 2013c). Natural gas would be extracted from the ground through wells, and then 

28 it would be treated to remove impurities and blended to meet pipeline gas standards before 

29 being piped through the State pipeline system to the plant site. This NGCC alternative would 

30 produce relatively little waste, primarily in the form of spent catalysts used for control of nitrogen 

31 oxide emissions.

32 The NGCC alternative would be located on undeveloped land at LSCS to maximize availability 

33 of infrastructure and to reduce other environmental impacts. Depending on the specific site 

34 location, there might be a need to construct new intake and discharge facilities and a new 

35 cooling system. Because NGCC power plants generate much of their power from a gas-turbine 

36 combined-cycle plant and because the overall thermal efficiency of this type of plant is high, an 

37 NGCC alternative would require less cooling water than LSCS would. This system would 

38 withdraw 17 million gpd (64 million Lpd) of water and would consume 13 million gpd 

39 (49 million Lpd). The NRC staff assumes that the cooling system would use a closed-cycle

40 system with mechanical draft cooling towers. Onsite visible structures could include the cooling 

41 towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 

42 pipelines, and an electrical switchyard. Construction materials could be delivered by a 

43 combination of rail spur, truck, and barge. Modifications may be required to deliver such 

44 materials; modifications could include new rail lines or access roads.

45 2.2.2.4 Combination Alternative (NGCC, Wind, and Solar)

46 In this section, the NRC staff describes the combination alternative to the continued operation of 

47 LSCS consisting of an NGCC facility constructed at an existing power plant site and operating in 
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1 conjunction with land-based wind farms and solar energy facilities, all of which would be located 

2 within the ROI. The NRC staff evaluates the environmental impacts from this alternative in 

3 Chapter 4.

4 To serve as an effective baseload power alternative to the LSCS reactors, this combination 

5 alternative must be capable of providing an equivalent amount of baseload power. For the 

6 purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar PV

7 facilities would comprise the combination alternative.

8 NGCC Portion of the Combination Alternative

9 To produce its required share of power (360 MWe), the NGCC portion, operating at an expected 

10 capacity factor of 85 percent (NETL 2007), would need to have a nameplate rating of 

11 approximately 425 MWe.

12 In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 

13 shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 

14 than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 

15 used for these “peaker plants” because natural gas combustion turbines can respond quickly; 

16 therefore, they tend to be used to meet short-term increases in electricity demand (EIA 2013d). 

17 A report prepared by CITI Research stated that gas-fired power plants can help overcome the 

18 intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 

19 gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 

20 combination alternative.

21 The NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would 

22 be constructed and installed at LSCS with a total net capacity of 360 MWe. The appearance of 

23 an NGCC unit would be similar to that of the full NGCC alternative considered in 

24 Section 2.2.2.3, although only one unit would be constructed. The NRC staff assumes that the 

25 NGCC portion of this alternative, which is assumed to be located at LSCS, would use existing 

26 electrical switchyards, substations, and transmission lines. Depending on the existing site 

27 conditions, it is possible that intake and discharge structures of the existing cooling system

28 could continue in service but would be connected to a new closed-cycle cooling system. For the 

29 purposes of this analysis, the NRC staff assumes that the NGCC portion of the combination 

30 would use mechanical draft cooling towers.

31 Wind Portion of the Combination Alternative

32 The NRC staff assumes that the wind-generated power from this combination alternative would 

33 come from land-based wind farms, which would be located in the ROI within the States of 

34 Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming 

35 a capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 

36 FWS 2013).

37 The American Wind Energy Association reports a total of more than 67,000 MW of installed 

38 wind energy capacity nationwide as of June 30, 2015 (DOE 2015). As of June 2015, Texas is 

39 by far the leader in installed land-based capacity with 15,635 MW. Two States in the ROI have 

40 the third and fifth largest installed capacity: Iowa with 5,708 MW, followed by Illinois with 

41 3,667 MW (DOE 2015). The installed wind capacity in the ROI has been increasing annually by 

42 1,000 MWe to 2,500 MWe in each of the past 8 years, for a total of over 13,000 MWe of 

43 additional wind capacity from 2007 to 2014 (DOE 2015). Therefore, the NRC staff considers 

44 6,042 MW of wind energy to be a reasonable amount by the time the LSCS licenses expire in 

45 2022 and 2023. As is the case with other renewable energy sources, the feasibility of wind 

46 resources serving as alternative baseload power is dependent on the location (relative to 

47 expected load centers), value, accessibility, and constancy of the resource. Wind energy must 
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1 be converted to electricity at or near the point where it is extracted, and there are limited energy 

2 storage opportunities available to overcome the intermittency and variability of wind resources. 

3 At the current stage of wind energy technology development, wind resources in wind power 

4 class 3 and higher are suitable for most utility scale applications (NREL 2014a). Wind power 

5 class 3 is defined as having a wind speed of 15.7 miles per hour (7.0 meters per second) and a 

6 wind density of 500 watts per square meter at 164 ft (50 m) (NREL 2014a). Each State in the 

7 ROI, other than Kentucky, has wind resources meeting this power class, with the highest 

8 concentrations occurring in Iowa and Illinois (NREL 2015a).

9 Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 2010. The size 

10 of turbine most frequently installed in the United States in recent years is the 1.5-MW turbine 

11 (WAPA and FWS 2013). For the purposes of this analysis, the NRC staff assumes wind 

12 turbines with a capacity of 1.79 MW. The capacity factors of land-based wind farms are lower 

13 than offshore wind farms (WAPA and FWS 2013). For the wind portion of the combination 

14 alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an estimated 

15 total net capacity of 1,813 MWe. Wind turbines must be well separated from each other to 

16 avoid interferences to wind flowing through the wind farm, resulting in wind farms requiring 

17 substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 1.2 ha) of 

18 land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and amount of 

19 land required between each turbine, approximately 3,376 turbines and 3,376 to 10,127 ac 

20 (1,366 to 4,098 ha) would be required for the wind portion of the combination alternative.

21 Wind energy’s intermittency affects its viability and value as a baseload power source. 

22 However, the variability of wind-generated electricity can be lessened if the proposed wind 

23 farms were located at a large distance from one another and were operated as interconnected 

24 wind farms, an aggregate controlled from a central point. Distance separation ensures that the 

25 two wind farms will not simultaneously experience the same climate, and power will likely be 

26 produced at some of the wind farms at any given time (Archer and Jacobson 2007).

27 Solar Photovoltaic Portion of the Combination Alternative

28 The solar portion of the combination alternative would be generated through one or more solar 

29 PV energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the solar 

30 energy facilities would need a collective nameplate rating of 1,193 MWe. Solar PV technologies 

31 could be installed on building roofs at existing residential, commercial, or industrial sites or at 

32 larger standalone solar facilities.

33 Nationwide, growth in large solar PV facilities (greater than 5 MW) has resulted in an increase 

34 from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it is 

35 estimated that more than 11,000 MW of large solar PV projects have signed power purchase 

36 agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 50 MW or 

37 greater, although most are located in the southwestern United States (Mendelsohn et al. 2012). 

38 As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have renewable 

39 energy legislation that includes requirements for solar PV technology. Missouri’s renewable 

40 portfolio standard includes a provision specifying that 2 percent of the renewable portfolio 

41 standard requirement must be met by solar energy by 2021. Illinois’ renewable portfolio 

42 standard specifies that solar PV must comprise 6 percent of the annual requirement for 

43 compliance year 2015–2016 and thereafter. As of 2012, only 33 MW of solar energy capacity

44 had been installed in the ROI (EIA 2014c).

45 Solar PV resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter per day 

(kWh/m2 46 /day). The most viable solar resources are located in Missouri, Iowa, and southern 

47 Illinois and Indiana (NREL 2015b). Economically viable solar resources are considered to be 

6.75 kWh/m2 48 /day and greater (BLM and DOE 2010). As is the case with wind energy sources, 
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1 the feasibility of solar energy resources serving as alternative baseload power is dependent on 

2 the location, value, accessibility, and constancy of the resource. Solar PV uses solar panels to 

3 convert solar radiation into usable electricity. Solar cells are formed into solar panels that can 

4 then be linked into PV arrays to generate electricity. The electricity generated can be stored, 

5 used directly, fed into a large electricity grid, or combined with other electricity generators as a 

6 hybrid plant. Solar PV can generate electricity whenever there is sunlight, regardless of 

7 whether the sun is directly shining on solar panels. Therefore, solar PV technologies do not 

8 need to directly face and track the sun, which has allowed solar PV systems to have broader 

9 geographical use than concentrated solar power (Ardani and Margolis 2011). Because the ROI 

10 contains average solar PV resources and because solar PV is a commercially available option 

11 for providing electrical generating capacity, the NRC staff considers the construction of solar PV

12 facilities to be a reasonable alternative to license renewal when combined with wind and NGCC.

13 For the purposes of this analysis, the NRC staff assumes solar PV facilities with a capacity 

14 factor of 19 percent (Ardani and Margolis 2011). Solar PV facilities may require 6.2 ac (2.5 ha)

15 of land per megawatt (NRC 2013). Although not all of this land would be cleared of vegetation 

16 and permanently impacted, it represents the land enclosed in the total site boundary of the solar 

17 facility (Ong et al. 2013). For the solar portion of this combination alternative, approximately 

18 7,397 ac (2,993 ha) would be required to support an installed net capacity of 227 MWe. In this 

19 analysis, the NRC staff does not speculate on the number and size of individual solar facilities, 

20 nor their locations within the ROI. However, as stated above, some of the output could be 

21 realized by solar PV installations on building roofs at existing residential, commercial, or 

22 industrial sites or at larger standalone solar facilities. To the extent that rooftop or 

23 building-integrated solar PV installations remain popular, land impacts would be relatively minor. 

24 Solar PV systems do not require water for cooling purposes, but a small amount of water is 

25 needed to clean the panels and for potable water for the workforce. Impacts identified in the 

26 U.S. Department of the Interior Bureau of Land Management (BLM) and DOE’s Solar Energy 

27 Programmatic Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012) provide 

28 information used in the analyses presented in the impact sections in Chapter 4.

29 2.2.2.5 Purchased Power Alternative

30 In this section, the NRC staff describes purchased power as an alternative to the continued 

31 operation of LSCS.

32 The impacts from purchased power would depend substantially on the generation technologies 

33 used to supply the purchased power. Impacts from operation of other electricity generators 

34 would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for LSCS

35 would be required in northern Illinois and could come from anywhere within Illinois or adjoining 

36 states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 

37 geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 

38 staff considers purchased power to be a feasible source of baseload power to replace LSCS by 

39 the time the licenses expire in 2022 and 2023.

40 Purchased power would likely come from the most common types of electricity generation within 

41 the ROI: coal, natural gas, nuclear, and wind. All these power sources are discussed as 

42 alternatives to license renewal of LSCS and are identified in Sections 2.2.2.2 to 2.2.2.4. 

43 Construction and operational impacts from these sources of electricity generation are 

44 considered in Chapter 4. Purchased power may require new transmission lines (which may 

45 require new construction) and may also rely on older and less-efficient power plants operating at 

46 higher capacities than they currently operate or on new facilities that would be constructed. 

47 During operations, impacts from nuclear, coal-fired, and natural gas-fired plants and from wind
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1 and solar energy projects would be similar to those described under the new nuclear, coal, 

2 natural gas, and combination alternatives described in Chapter 4 for all resource areas.

3 2.3 Alternatives Considered but Dismissed

4 Alternatives to LSCS license renewal that were considered and eliminated from detailed study 

5 are presented in this section. These alternatives were eliminated because of technical resource 

6 availability or current commercial limitations. Many of these limitations would continue to exist 

7 when the current LSCS licenses expire.

8 2.3.1 Energy Conservation and Energy Efficiency 

9 Energy conservation can include reducing energy demand through behavioral changes or 

10 altering the shape of the electricity load and usually does not require the addition of new 

11 generating capacity. Conservation and energy efficiency programs are more broadly referred to 

12 as demand-side management.

13 Conservation and energy efficiency programs can be initiated by a utility, transmission 

14 operators, the state, or other load-serving entities. The State of Illinois’ renewable portfolio 

15 standard includes an energy efficiency portfolio standard that requires utilities to reduce electric 

16 usage by 2 percent of demand by 2015 (DSIRE 2015a), which is equivalent to 4 million MWh, 

17 only 20 percent of the amount that would be required to offset LSCS’s current electrical 

18 generation.

19 In general, residential electricity consumers have been responsible for the majority of peak load 

20 reductions, and participation in most programs is voluntary. Therefore, the existence of a 

21 program does not guarantee that reductions in electricity demand would occur. The GEIS

22 concludes that, although the energy conservation or energy efficiency potential in the 

23 United States is substantial, there are likely no cases where an energy efficiency or 

24 conservation program has been implemented expressly to replace or offset a large baseload 

25 generation station (NRC 2013). Although significant energy savings are possible in the ROI 

26 through demand-side management and energy efficiency programs, conservation and energy 

27 efficiency programs are not likely to replace LSCS as a standalone alternative; therefore, the 

28 NRC staff does not consider conservation and energy efficiency to be a reasonable alternative 

29 to license renewal.

30 2.3.2 Solar

31 Solar power, including solar PV and concentrated solar power technologies, produce power 

32 generated from sunlight. PVs convert sunlight directly into electricity using solar cells made 

33 from silicon or cadmium telluride. Concentrating solar power uses heat from the sun to boil 

34 water and produce steam to drive a turbine connected to a generator to produce electricity 

35 (NREL 2014b). To be considered a viable alternative, a solar alternative must replace the 

36 amount of electricity LSCS provides. Assuming a capacity factor of 19 percent (Ardani and 

37 Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 

38 energy facilities in the seven-State ROI.

39 In 2012, 33 MW of solar energy capacity was installed in the ROI (EIA 2014c). The DOE’s 

40 National Renewable Energy Laboratory (NREL) reports that the States in the ROI receive solar 

insolation of 4.0 to 5.0 kWh/m2 41 /day, which is considered low to average (NREL 2015b). For 

utility-scale development, insolation levels below 6.5 kWh/m2 42 /day are not considered 

43 economically viable given current technologies (BLM and DOE 2010). There is more potential 

44 for solar development using local PV applications, such as rooftop solar panels, than through 
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1 utility-scale solar facilities. In addition, a solar facility can only generate electricity when the sun 

2 is shining. Energy storage can be used to overcome intermittency for concentrating solar power 

3 facilities; however, current and foreseeable storage technologies that have been paired with 

4 solar power facilities have a much smaller capacity than would be necessary to replace LSCS. 

5 Taking all of the factors above into account, it is unlikely that solar PV or concentrated solar 

6 power technologies could serve as baseload power in the ROI to replace LSCS’s current 

7 electricity output. Given the modest levels of solar energy available throughout the ROI, the 

8 lack of substantial installed solar capacity in the ROI and the weather-dependent intermittency 

9 of solar power, the NRC staff concludes that a solar power energy facility in the ROI would not 

10 be a reasonable alternative to license renewal. The NRC staff described an alternative of solar 

11 power in combination with wind and an NGCC plant in Section 2.2.2.4.

12 2.3.3 Wind

13 Two States in the ROI have the third and fifth largest installed capacity in the Nation: Iowa with 

14 5,708 MW, followed by Illinois with 3,667 MW (DOE 2015). The installed wind capacity in the 

15 ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 8 years, for 

16 a total of over 13,000 MWe of additional wind capacity from 2007 to 2014 (DOE 2015). All of 

17 the wind energy facilities and the electricity generation from wind currently being produced in 

18 the ROI are land based. To be considered a viable alternative, a wind alternative must replace 

19 the amount of electricity LSCS provides. Assuming a capacity factor of 30 percent for 

20 land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 

21 would need to be generated by some combination of land-based and offshore wind energy 

22 facilities in the seven-State ROI.

23 As is the case with other renewable energy sources, the feasibility of wind resources serving as 

24 alternative baseload power is dependent on the location (relative to expected load centers), 

25 value, accessibility, and constancy of the resource. Wind energy must be converted to 

26 electricity at or near the point where it is extracted, and there are limited energy storage 

27 opportunities available to overcome the intermittency and variability of wind resource availability. 

28 Although wind power is intermittent and although individual facilities are unable to provide 

29 baseload power, it has been proposed that multiple interconnected wind installations separated 

30 by long distances could theoretically function as a virtual power plant and could provide 

31 baseload power since individual facilities would be exposed to different weather and wind 

32 conditions. To date, however, no states or utilities operate arrays of wind installations as virtual 

33 power plants.

34 Given the amount of wind capacity necessary to replace LSCS and the intermittency of wind 

35 power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 

36 the NRC staff also concludes that, when used in combination with other technologies with 

37 inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 

38 described such a possible combination alternative in Section 2.2.2.4.

39 2.3.3.1 Offshore Wind

40 The United States does not have any offshore wind farms in operation; however, approximately 

41 20 projects representing more than 2,000 MW of capacity are in the planning and permitting 

42 process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 

43 Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 

44 depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 

45 Ram 2010).

46 Although wind data suggest a potential for offshore wind farms in the Great Lakes, project costs 

47 likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 
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1 (Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 

2 300 percent higher than land-based systems. In addition, based on current prices for wind 

3 turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 

4 above the current production costs from existing power generation facilities. In addition to cost, 

5 other barriers include the immature status of the technology, limited resource area, and high

6 risks and uncertainty (Tidball et al. 2010). Because no offshore wind capacity yet exists in 

7 either the Great Lakes or on the Atlantic Coast and because none appears likely to exist on a 

8 large commercial scale in the Great Lakes by 2022 (given the current state of development), the 

9 NRC staff finds that offshore wind will not be a reasonable alternative to LSCS. 

10 2.3.3.2 Wind Power with Storage

11 Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 

12 facilities, compressed air energy storage (CAES) is the technology most suited for storage of 

13 large amounts of energy. In CAES systems, electricity generated during low-demand periods 

14 can be stored by using a compressor to pressurize and store air; during high-demand periods, 

15 the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE report 

16 analyzed various power-generation sources, including wind, coupled with CAES systems 

17 (Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 

18 high voltage transmission, and a market for wholesale electric power and (2) availability of 

19 geology and wind resources. The results show that, within the ROI, the potential exists for 

20 one CAES site in northwestern Iowa. Without detailed wind-speed data, specific site 

21 information, and detailed information on the energy-storage capacity of the potential CAES site, 

22 estimating how much wind capacity would be necessary and determining whether it could 

23 provide for an all-wind alternative would be difficult. Furthermore, the NRC staff is not aware of 

24 a CAES project coupled with wind generation that is providing baseload power. Therefore, the 

25 NRC staff concludes that the use of CAES in combination with wind turbines to replace the 

26 LSCS power plant is unlikely.

27 2.3.3.3 Conclusion

28 Despite the relatively high reliability demonstrated by modern turbines, the recent technological 

29 advancements in turbine design and wind farm operation, and wind energy’s dramatic market 

30 penetrations of recent years, empirical data on wind farm capacity factors and wind energy’s 

31 limited ability to store power for delayed production of electricity cause the NRC staff to 

32 conclude that wind energy—on shore, off shore, or a combination thereof—could not serve as a 

33 discrete alternative to the baseload power supplied by the LSCS reactors. However, the NRC 

34 staff also concludes that, when used in combination with other technologies with inherently 

35 higher capacity factors, wind energy can provide a viable alternative. The NRC staff described 

36 such a possible combination alternative in Section 2.2.2.4.

37 2.3.4 Biomass

38 Biomass resources used for biomass-fired generation include agricultural residues, animal 

39 manure, wood wastes from forestry and industry, residues from food and paper industries, 

40 municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 

41 biomass-fired generation for baseload power depends on the geographic distribution, available 

42 quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 

43 NRC staff assumed that biomass would be combusted for power generation in the electricity 

44 sector. Biomass is also used for space heating in residential and commercial buildings and can 

45 be converted to a liquid form for use in transportation fuels (Haq undated).

46 In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 

47 could operate with capacity factors between 70 and 80 percent (NRC 2013). Although the ROI 
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1 currently produces electricity from biomass fuels, the plants operating within the ROI generated 

2 less than 1 percent of the total power generation in 2011 (EIA 2014b). Based on the relatively 

3 low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 

4 the construction of several new biomass plants, could increase capacity by adding 2,327 MWe

5 of electricity from biomass-fired generation by the time LSCS’s licenses expire in 2022 and 

6 2023.

7 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 

8 used for biomass conversion would be similar to fossil fuel plants, including the direct 

9 combustion of biomass in a boiler to produce steam (NRC 2013). Biomass generation is 

10 generally more cost-effective when co-fired with coal plants (IEA 2007). Biomass-fired 

11 generation plants generally are small and can reach capacities of 50 MWe, which means that 

12 more than 40 new facilities would be required before the LSCS licenses expire. After 

13 reevaluating current technologies, the NRC staff finds biomass-fired alternatives as still unable 

14 to reliably replace the LSCS capacity. For this reason, the NRC staff does not consider 

15 biomass to be a reasonable alternative to LSCS license renewal.

16 2.3.5 Hydroelectric

17 Hydroelectric power uses the force of water to turn turbines that spin a generator to produce 

18 electricity. In a run-of-the-river system, the force of a river current provides the force to create 

19 the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 

20 created by dams and is released as needed to generate electricity.

21 The DOE’s Idaho National Environmental Engineering Laboratory (now Idaho National 

22 Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 

23 hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 

24 institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 

25 cultural, historical, and geological values, (2) Federal and state land use, and (3) legal 

26 protection issues, such as wild and scenic legislation and threatened or endangered fish and 

27 wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 

28 do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 

29 (ORNL 2012). These nonpowered dams serve various purposes, such as providing water 

30 supply to inland navigation.

31 The EIA reported that the States comprising the ROI generated 2,262 MW of electricity from 

32 hydroelectric power in 2012 (EIA 2014c). In order to replace LSCS’s current output, 

33 hydroelectric generation across the ROI would need to double by 2022. Although there is 

34 potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 

35 that the maximum levels of development would occur across the entire ROI by the time LSCS’s 

36 licenses expire in 2022 and 2023 because the generating capacity of hydroelectric power is 

37 projected to continue to decrease through 2040 (EIA 2013b). Given the decrease in projected 

38 power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 

39 power to be a reasonable alternative to license renewal.

40 2.3.6 Wave and Ocean Energy

41 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 

42 for potential renewable energy generation. Four major technologies may be suitable to harness 

43 wave energy: terminator devices that range from 500 kilowatts to 2 MW, attenuators, point 

44 absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 

45 floating buoys to convert wave motion into mechanical energy, driving a generator to produce 

46 electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 
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1 surface; waves then enter a tube and compress air that is used to drive a generator that 

2 produces electricity (NRC 2013). Some designs are undergoing demonstration testing at 

3 commercial scales, but none are currently used to provide baseload power (BOEM undated).

4 The Great Lakes do not experience large tides, and there is limited energy output for wave 

5 technologies in the Great Lakes. The Electric Power Research Institute (EPRI) published a 

6 document that assessed ocean wave energy resources in the United States. The Great Lakes 

7 were not included in the analysis, suggesting that the resource potential is not great enough to 

8 use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 

9 infancy of the technologies in the Great Lakes support the NRC staff’s conclusion that wave and 

10 ocean energy technologies are not feasible substitutes for LSCS.

11 2.3.7 Fuel Cells

12 Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 

13 fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 

14 only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide

15 (depending on hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 

16 hydrocarbon resources. Natural gas is a typical hydrogen source.

17 Fuel cells are not economically or technologically competitive with other alternatives for 

18 electricity generation. EIA projects that fuel cells may cost $6,835 per installed kilowatt (total 

19 overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 

20 analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 

21 (approximately 10 MWe). Replacing the power LSCS provides would be extremely costly; it 

22 would require the construction of approximately 230 units and modifications to the existing 

23 transmission system. Given the immature status of fuel cell technology and high cost, the NRC 

24 staff does not consider fuel cells to be a reasonable alternative to LSCS license renewal.

25 2.3.8 Delayed Retirement

26 A delayed retirement alternative would consider deferring the retirement of generating facilities 

27 in Illinois and its six adjoining states that include MISO and PJM RTOs.

28 To maintain reliable operations, electric systems must be able to meet peak load requirements. 

29 To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013). 

30 The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 

31 requirement of 17.4 percent. However, recent EPA regulations may lead to increased coal plant 

32 retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 

33 retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 

34 below the reserve margin requirement (MISO 2011).

35 PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 

36 regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 

37 major population centers within the PJM region in the near future (Ott 2013a). Because the 

38 current generation mix has not resulted in the long-term commitment of generation needed for 

39 reliability, generation retirements that have occurred with short notice have created 

40 unanticipated reliability problems for PJM (Ott 2013a).

41 The EIA expects that more coal plant retirements will occur before 2016 than those previously 

42 predicted. These accelerated retirements are driven by low natural gas prices, slow growth in 

43 electricity demand, and the requirements of the Mercury and Air Toxics Standards that will 

44 require significant reductions in plant emissions (EIA 2014a, EPA 2015). Exelon also expects 

45 increased generation retirements for a variety of reasons, including increased operating costs 
Alternatives Including the Proposed Action

2-22

1 for older facilities, increased environmental regulations and competition, and decreased load 

2 (Exelon undated). As generators are required to adhere to future regulations, some power 

3 plants may opt for early retirement of older units rather than incur the cost for compliance. 

4 Exelon has further stated that some of their nuclear fleet may be retired early because of low 

5 wholesale energy prices and current energy policy (Associated Press 2015). Because of the 

6 uncertain regulatory environment and concerns expressed by MISO and PJM concerning the 

7 retirement pace of coal power plants, the NRC staff does not consider delayed retirement to be 

8 a reasonable alternative to LSCS license renewal.

9 2.3.9 Geothermal

10 Geothermal technologies extract the heat contained in geologic formations to produce steam to 

11 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 

12 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 

13 a potential source of baseload electric power. However, the feasibility of geothermal power 

14 generation to provide baseload power depends on the regional quality and accessibility of 

15 geothermal resources. Utility-scale geothermal energy generation requires geothermal 

16 reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 

17 300 kilowatts electric to 50 MWe and greater (TEEIC undated). Geothermal resources are 

18 concentrated in the western United States. Specifically, these resources are found in Alaska, 

19 Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 

20 Washington, and Wyoming. In general, most assessments of geothermal resources have been 

21 concentrated on these western states (DOE 2013b; USGS 2008). Geothermal resources are 

22 used in the ROI for heating and cooling purposes, but no electricity is currently being produced 

23 from geothermal resources in the ROI (EIA 2014c). Given the low resource potential in the ROI, 

24 the NRC staff does not consider geothermal to be a reasonable alternative to license renewal.

25 2.3.10 Municipal Solid Waste

26 Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 

27 heat, electricity, or fuel through combustion (EPA 2014b). The three types of combustion 

28 technologies include mass burning, modular systems, and refuse-derived fuel systems 

29 (EPA 2014a). Mass burning is the method used most frequently in the United States. The heat 

30 released from combustion is used to convert water to steam, which is used to drive a turbine 

31 generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 

32 captured through a filtering system (EPA 2014a). As of 2010, approximately 

33 86 waste-to-energy plants are in operation in 25 states, processing more than 28 million tons of 

34 waste per year (EPA 2014b). These waste-to-energy plants have an aggregate capacity of 

35 2,720 MWe, and although some plants have expanded to handle additional waste and produce 

36 more energy, no new plants have been built in the United States since 1995 (EPA 2014b). The 

37 average waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can 

38 operate at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste 

39 recovery facility that produces steam; Iowa has one waste-to-energy facility that produces 

40 10 MW of electricity; Michigan has three facilities that produce 89.7 MW of electricity; and 

41 Wisconsin has two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 

42 2010, the ROI had a municipal solid waste generating capacity of 132 MW. More than 

43 46 average-sized plants would be necessary to provide the same level of output as LSCS, 

44 almost doubling the national waste-to-energy generation.

45 The decision to burn municipal waste to generate energy is usually driven by the need for an 

46 alternative to landfills rather than energy considerations. Given the improbability that additional 

47 stable supplies of municipal solid waste would be available to support approximately 46 new
Alternatives Including the Proposed Action

2-23

1 facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 

2 municipal solid waste combustion to be a reasonable alternative to LSCS license renewal.

3 2.3.11 Petroleum

4 In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014c).

5 The variable costs of oil-fired generation tend to be greater than those of the nuclear or 

6 coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 

7 natural gas-fired generation. The high cost of oil has resulted in a steady decline in its use for 

8 electricity generation (EIA 2013a). Given the high cost of oil and the small generating capacity 

9 from oil-fired power plants in the ROI, the NRC staff does not consider oil-fired generation a 

10 reasonable alternative to LSCS license renewal.

11 2.3.12 Supercritical Pulverized Coal

12 In general, SCPC power plants are feasible, commercially available options for providing 

13 electrical generating capacity. Baseload coal units have proven their reliability and can sustain

14 capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 

15 that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 

16 to spin one or more turbines to generate electricity. Among the technologies available, 

17 pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 

18 for new coal-fired plants given their high operating temperatures and pressures that increase 

19 thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 

20 reducing environmental impacts (NETL undated).

21 As described in Section 2.2.3, EPA has signed a final rule for carbon pollution that would apply 

22 to new fossil fuel-fired power plants, including SCPC facilities (80 FR 64661–65120). The 

23 action establishes performance standards and has identified a CCS system as a method of 

24 emission reduction. The emission limit for these sources of 1,305 lb CO2/MWh, and any new 

25 coal-fired power plants could require CCS in order to achieve this emission limit.

26 In addition, given known technology and technological and demographic trends, EIA predicts 

27 that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 

28 (EIA 2013a). This does not consider the EPA rule described above but indicates a general 

29 trend away from coal-fired facilities in favor of natural gas-fired power plants due to falling 

30 natural gas prices. MISO projected that the EPA regulations could lead to increased coal plant 

31 retirements and estimated retirements between 3,000 MW to 12,600 MW, which could have a 

32 large impact on MISO’s reserve margin in the future (MISO 2011).

33 Although SCPC plants are currently the most widely used source of electricity generation within 

34 the ROI, given the potential for stringent air quality regulations and trends toward natural 

35 gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 

36 LSCS license renewal. Instead, the NRC staff describes an IGCC plant under the coal 

37 alternative in Section 2.2.2.2.

38 2.4 Comparison of Alternatives

39 In this chapter, the NRC staff considered the following alternatives to LSCS license renewal: 

40 new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 

41 natural gas, wind, and solar; and purchased power. The NRC also considered the no-action 

42 alternative and its effects. The impacts for all alternatives to LSCS license renewal are 

43 discussed in Chapter 4 and summarized in Table 2–2 below.
Alternatives Including the Proposed Action

2-24

1 The environmental impacts of the proposed action (issuing renewed LSCS operating licenses) 

2 would be SMALL for all impact categories. The environmental impacts from all other 

3 alternatives would be larger than the proposed license renewal, as shown in Table 2–2.

4 In conclusion, the environmentally preferred alternative is the granting of renewed licenses for 

5 LSCS. All other alternatives capable of meeting the needs currently served by LSCS entail 

6 potentially greater impacts than those of the proposed action of renewing the license for LSCS. 

7 To make up the lost power generation if a renewed license is not issued (the no-action 

8 alternative), one or a combination of alternatives would be implemented, all of which have 

9 greater impacts than the proposed action. Hence, the NRC staff concludes that the no-action 

10 alternative will have environmental impacts greater than or equal to those of the proposed 

11 license renewal action.
2-25

Table 2–2. Summary of Environmental Impacts of Proposed Action and Alternatives 1

Impact Area 

(Resource)

LSCS License 

Renewal 

(Proposed 

Action) No-Action

New Nuclear 

Alternative

IGCC 

Alternative

NGCC 

Alternative

Combina

Alternati

(NGCC, W

and Sola

Land Use and Visual Resources

Land Use SMALL SMALL SMALL TO 

MODERATE

SMALL TO 

LARGE

SMALL TO 

MODERATE

SMALL T

MODERA

Visual Resources SMALL SMALL SMALL TO 

MODERATE SMALL SMALL SMALL TLARGE 

Air Quality and Noise

Air Quality SMALL SMALL SMALL MODERATE MODERATE SMALL 

Noise SMALL SMALL SMALL SMALL TO 

MODERATE SMALL SMALL TMODERA

Geologic Environment SMALL SMALL SMALL SMALL SMALL SMALL 

Water Resources

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 T

MODERA

Aquatic Resources SMALL to 

MODERATE1 SMALL SMALL SMALL to MODERATE SMALL SMALL 

Special Status Species 

& Habitats NO EFFECT SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOT

Historic and 

Cultural Resources SEE NOTE3 SMALL SMALL SMALL SMALL SMALL TLARGE

Socioeconomics

Socioeconomics SMALL SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

LARGE SMALL 
2-26

Impact Area 

(Resource)

LSCS License 

Renewal 

(Proposed 

Action) No-Action

New Nuclear 

Alternative

IGCC 

Alternative

NGCC 

Alternative

Combina

Alternati

(NGCC, W

and Sola

Transportation SMALL SMALL SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL TO 

LARGE

SMALL T

MODERA

Human Health SMALL SMALL SMALL SMALL SMALL SMALL 

Environmental Justice SEE NOTE4 SEE NOTE5 SEE NOTE6 SEE NOTE6 SEE NOTE6 SEE NOT

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 = Natio

Places, APE = area of potential effect, CRMP = Cultural Response Management Plan, and IHPA = Illinois Historic Preservation Agen

(1) Thermal impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources in the c

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 habita

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) the fa

renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource assessment, lic

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 minorit

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 that this 

disproportionately high and adverse human health and environmental effects on minority and low-income populations. However, this 

depend on the location, plant design, and operational characteristics of the alternative. Therefore, the NRC staff cannot determine wh

would result in disproportionately high and adverse human health and environmental effects on minority and low-income populations.
Alternatives Including the Proposed Action

2-27

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35 U.S. Projects Having Commercial Potential.” October 2013. Available at 

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39 Coal Plant. 4 p. Available at <http://www.netl.doe.gov/KMD/cds/disk50/

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

43 Volumes 1 and 2. May 31, 1996. 1,204 p. ADAMS Nos. ML040690705 and ML040690738.
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3 Decommissioning of Nuclear Power Reactors. NUREG–0586, Volumes 1 and 2.

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5 ML023500228, and ML023500295.

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7 an Early Site Permit (ESP) at the Vogtle Electric Generating Plant Site. Washington, DC: NRC. 

8 NUREG–1872, Volumes 1 and 2. August 2008. 1,242 p. Available at 

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12 Applications for New Nuclear Power Reactors. NUREG/BR–0468. December 2009. 110 p. 

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17 Final Report. Washington, DC: NRC. NUREG–1947. March 2011. 568 p. ADAMS 

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21 Volumes 1, 2, and 3. June 30, 2013. 1,535 p. ADAMS Nos. ML13106A241, ML13106A242, 

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45 31 August 2015).
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7 Pennsylvania: PJM Interconnection, LLC. June 20, 2013. 9 p. Available at 

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13 and Direct Use Geothermal Energy Generation.” Available at 

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28 31 August 2015).

3-1

1 3.0 AFFECTED ENVIRONMENT

2 In this supplemental environmental impact statement (SEIS), the “affected environment” is the 

3 environment that currently exists at and around LaSalle County Station, Units 1 and 2 (LSCS). 

4 Because existing conditions are at least partially the result of past construction and operation at 

5 the plant, the impacts of these past and ongoing actions and a discussion on how they have 

6 shaped the environment are presented here. The facility and its operation are described in 

7 Section 3.1. The affected environment is presented in Sections 3.2 to 3.13.

8 3.1 Description of Nuclear Power Plant Facility and Operation

9 LSCS is a two unit nuclear power plant located in LaSalle County, Illinois. It began commercial 

10 operation in January 1984 (Unit 1) and October 1984 (Unit 2). Generally, the U.S. Nuclear 

11 Regulatory Commission (NRC) staff drew information about LSCS’s facilities and operation from 

12 the Exelon Generation Company, LLC (Exelon), Environmental Report (ER) (Exelon 2014a).

13 3.1.1 External Appearance and Setting

14 The LSCS site is approximately 82 driving miles (mi) (132 kilometers (km)) southwest of O’Hare 

15 International Airport in Chicago, Illinois, and approximately 26 mi (42 km) west of Exelon’s 

16 Braidwood Generating Station in Braceville, Illinois. Interstate Highway 80 is 8 mi (13 km) north 

17 of the site. Figure 3–1 presents the 50-mi (80-km) area around LSCS.

18 The LSCS site is located in a rural and agricultural setting. However, the surroundings are 

19 dominated by many wind turbines. Each wind turbine is 389 feet (ft) (119 meters (m)) tall (which 

20 includes the length of one of its three 126.5-ft (38.5-m) rotator blades). The town of Seneca lies 

21 6 mi (10 km) northeast of LSCS. The town of Marseilles lies 7 mi (11 km) north-northwest of 

22 LSCS. The Illinois River is 5 mi (8 km) north of LSCS. The Chicago, Rock Island and Pacific 

23 Railroad, which runs parallel to, and slightly north of, the Illinois River, is the closest railroad line 

24 in this area. A 6-mi (10-km) rail spur connects LSCS to the Atchison, Topeka, and Santa Fe 

25 Railroad south of the site (Exelon 2014a). Figure 3–2 presents the 6-mi (10-km) area around 

26 LSCS.

27 The LSCS site is approximately 3,776 acres (ac) (1,528 hectares (ha)) of which approximately 

28 2,058 ac (833 ha) are the cooling pond. Underground pipelines approximately 3.5 mi (5.6 km) 

29 long connect the cooling pond to the Illinois River, which is the source of the plant’s makeup 

30 water and the receiving body of water for plant discharges. This pipeline corridor right-of-way

31 intersects the eastern portion of the Marseilles State Fish and Wildlife Area, which is managed 

32 by the Illinois Department of Natural Resources (IDNR) for hunting and wildlife habitat. Country 

33 Road 6 (also known as North 21st Road) provides access to LSCS and runs along the site’s 

34 southern boundary (Exelon 2014a). Figure 3–3 presents the LSCS site layout.

35 The LSCS site’s main structures include two reactor buildings, an auxiliary building (which 

36 houses the control room), a turbine building, a diesel generator building, a switchyard, a training

37 building, an interim radioactive waste (radwaste) storage facility, a radwaste building, sewage 

38 and wastewater treatment facilities, and an independent spent fuel storage installation (ISFSI). 

39 The site’s tallest structure is a 400-ft (122-m) meteorological tower. The area of the LSCS site 

40 that is completely enclosed by physical barriers and that allows access only at designated 

41 control points is called the protected area. A physical protection program at the LSCS site 

42 includes surveillance, observation, and monitoring within the protected area (Exelon 2014a).

43 Figure 3–4 presents the LSCS plant features.
Affected Environment

3-2

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

2 Source: Exelon 2014a
Affected Environment

3-3

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

2 Source: Exelon 2014a
Affected Environment

3-4

1 Figure 3–3. LSCS Site Layout

2 Source: Exelon 2014a
Affected Environment

3-5

1 Figure 3–4. LSCS Plant Features

2 Source: Exelon 2014a
Affected Environment

3-6

1 3.1.2 Nuclear Reactor Systems

2 The nuclear reactor for each of the two LSCS units is a General Electric boiling water reactor

3 (BWR/5) with Mark II containment. Each LSCS reactor is licensed to produce core power of 

4 3,546 megawatts thermal. The annual mean net electrical power capacity for LSCS is 

5 2,327 megawatts electric. LSCS uses a 2,058-ac (833-ha) diked cooling pond for core cooling 

6 and withdraws makeup water from, and discharges to, the Illinois River (Exelon 2014a).

7 LSCS operates using low-enriched uranium dioxide fuel with enrichment not exceeding a 

8 nominal 5.0 percent by weight of uranium-235 and has been historically operated within a 

9 maximum analyzed fuel burnup rate of 62,000 megawatt-days per metric ton of 

10 uranium (MWd/MTU). In its ER, Exelon stated that, during some future fuel cycles, it expects 

11 the peak fuel burnup rate to exceed 62,000 MWd/MTU in some part-length fuel rods. 

12 Addendum 1 to Volume 1 of NUREG–1437, Generic Environmental Impact Statement for 

13 License Renewal of Nuclear Power Plants (GEIS) (NRC 1999), states that the environmental 

14 impacts would be small for transporting spent fuel enriched with up to 5-percent uranium-235 

15 with an average burnup for the peak rod of up to 62,000 MWd/MTU. It also states that, if peak 

16 fuel burnup is projected to exceed 62,000 MWd/MTU, license renewal applicants must submit 

17 an assessment of the implications for the environmental impacts. Exelon submitted an 

18 assessment of the environmental impacts of transporting spent fuel enriched with an average 

19 burnup for the peak rod exceeding 62,000 MWd/MTU in Section 4.13 of its ER. Appendix G of 

20 this document provides the NRC staff’s analysis of these projected environmental impacts. 

21 Refueling outages for LSCS, Units 1 and 2, are on a staggered 24-month schedule 

22 (Exelon 2014a).

23 3.1.3 Cooling and Auxiliary Water Systems

24 LSCS uses a closed-cycle, recirculating cooling system that includes an artificial cooling pond 

25 for heat dissipation. In this type of closed-cycle system, the cooling pond serves as the primary 

26 source of water to cool plant components and as the primary receiving body for excess heat. 

27 In BWRs like those used at LSCS, steam is produced directly in each reactor vessel. The 

28 steam passes through moisture separators and steam dryers and then flows to the turbine. 

29 Such systems contain only two heat transfer (exchange) loops. The primary loop transports the 

30 steam from the reactor vessel directly to the turbine, which generates electricity. The secondary 

31 cooling loop removes excess heat from the primary loop in the main condenser. From the 

32 condenser, the primary condensate is returned as feedwater to the reactor, and the secondary 

33 cooling loop removes the excess heat (NRC 2013). At LSCS, condenser cooling water is 

34 discharged directly to the cooling pond, where the heat is dissipated through mixing and 

35 evaporation (Exelon 2014a).

36 Cooling water that is not otherwise lost from the pond through evaporation or seepage or that is 

37 consumed in the process is recirculated from the cooling pond through the condenser systems 

38 in a continuous loop. In addition, a portion of the water in the cooling pond is discharged as 

39 blowdown on a near continuously basis under normal conditions. (Blowdown is water that is 

40 rinsed from the cooling system (i.e., cooling pond) to remove impurities that may degrade plant 

41 performance.) Total dissolved solids are the primary constituents of concern to prevent scale 

42 buildup on plant components. 

43 All water lost from the recirculating system must be replaced with fresh water; this water is 

44 referred to as makeup water (Exelon 2014a; NRC 2013). Makeup water for the onsite cooling 

45 pond is withdrawn from, and blowdown is discharged to, the Illinois River, which lies 3.5 mi 

46 (5.6 km) north of LSCS’s cooling pond. The intake and blowdown pipelines are routed through 
Affected Environment

3-7

1 a common right-of-way corridor. Figure 3–5 provides a basic schematic diagram of a 

2 closed-cycle, recirculating cooling system that uses a cooling pond.

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

4 Source: Modified from NRC 2013, Figure 3.1–4

5 Groundwater is also used by LSCS for potable water, sanitary water, and demineralized water 

6 makeup systems. 

7 Unless otherwise cited, the NRC primarily drew information about LSCS’s cooling and auxiliary 

8 water systems from Exelon’s ER (Exelon 2014a, 2015b) and its Updated Final Safety Analysis 

9 Report (UFSAR) (Exelon 2014b). The NRC staff visited the facilities cited herein during the 

10 May 2015 environmental site audit (NRC 2015b). Descriptions of the individual plant cooling 

11 and auxiliary systems and components that interact with the environment are provided below.

12 Cooling Pond and Ultimate Heat Sink. Water for the circulating water system (CWS) for 

13 condenser cooling water and for the plant service water system are supplied directly from the 

14 cooling pond. 

15 The LSCS cooling pond is an engineered impoundment encompassing 2,058 ac (833 ha) with 

16 an average depth of 15 ft (4.7 m) (NRC 1978) (Figure 3–6). The pond has an elevation of 700 ft 

17 (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 18 )) of water. 

19 This impoundment was formed by constructing earthen dikes to enclose the north, east, and 

20 south sides of the pond; the natural levee of the Illinois River forms the fourth side. Engineered 

21 fill consisting of silty-clay, taken from borrow areas within the pond basin, was used in the 

22 construction of these peripheral dikes. A perimeter drainage ditch designed to intercept runoff

23 and to capture and direct seepage toward surface drainages and away from the dikes flanks the 

24 pond’s dikes (Exelon 2014b). 

25 Integral to the pond’s construction are three internal baffle or finger dikes (i.e., earthen berms), 

26 that total 22,623 ft (6,895 m) in length. These structures direct the flow of water from the 

27 discharge canal and through the pond to ensure that the coolest water is available for use by 

28 LSCS (Exelon 2014b) (Figure 3–6). The average residence time for water in the cooling pond is 

29 5.5 days (NRC 1978). 
Affected Environment

3-8

1 The peripheral dike system that encloses the cooling pond includes a 300-ft- (91-m)-wide 

2 auxiliary spillway structure. The spillway is located northwest of the main plant complex and is 

3 adjacent to the discharge canal. The structure is capable of passing a volume of 

4 1,069,000 gallons per minute (gpm) (2,380 cubic feet per second (cfs) or 67.2 meters per 

5 second (m/s)) of water associated with the probable maximum water level. Discharge from the 

6 structure flows north to South Kickapoo Creek, a tributary to the Illinois River (Exelon 2014b). 

7 A dedicated portion of the cooling pond located immediately adjacent to the LSCS intake canal 

8 serves as the plant’s ultimate heat sink (UHS). It is also known as the core standby cooling 

9 system (CSCS) pond and directly supplies the CSCS equipment cooling water system, as 

10 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 11 ) of water. This volume of water is sufficient 

12 to supply 30 days of cooling water following safe shutdown from normal operating or accident

13 conditions. The CSCS pond can function even if the perimeter dikes of the cooling pond are 

14 breached (Exelon 2014b).

15 Illinois River Water Makeup System. Cooling pond makeup water is withdrawn via the river 

16 screen house located on the south bank of the Illinois River at Illinois River Mile (RM) 249.5 

17 (River Kilometer (RKm) 401.5) (Figure 3–6). The river screen house is situated approximately 

18 3.5 mi (5.6 km) north of the cooling pond. The structure is designed to withstand the 100-year 

19 flood of the Illinois River (Exelon 2014b).

20 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 21 /s)). Two pumps are normally operated 

22 at all times to meet cooling pond makeup demands, with the third serving as a backup. 

23 However, when reduced evaporation demands allow (winter months), the pump discharge ball 

24 valves are closed to 30 degrees (one-third open) (Exelon 2015c). 

25 River water is first drawn through an intake flume in the bottom of the river and then into a 

26 72-ft-- (22-m)-wide funnel inlet basin with concrete dam located 24 ft (7 m) from the shoreline 

27 frontage of the river screen house. The inlet is protected by a floating log boom to deflect river 

28 debris. From the inlet, water then enters the intake forebay of the screen house and passes first 

29 through two adjacent bar grills and then through vertical traveling screens with 3/8-inch (in.)

30 (0.95-centimeter (cm)) openings before entering the pumps (Exelon 2014a, 2015a). The bar 

31 grills are galvanized steel and measure 3/8 in. (0.95 cm) thick and 4 in. (10 cm) wide. The 

32 narrow dimension of each bar is oriented perpendicular to the incoming water flow, and the 

33 centerlines of the narrow dimension of adjacent bars are spaced 3 in. (7.6 cm) apart 

34 (Exelon 2015c).

35 Water velocity in the river intake channel is reported as ranging from 0.3 to 0.5 feet per second 

36 (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 

37 pumps operating. Flow velocity at the travelling screens ranges from about 0.5 to 0.9 fps 

38 (0.15 to 0.3 m/s) with one and two makeup pumps in full operation, respectively (NRC 1978; 

39 Exelon 2014a). In NRC’s Final Environmental Statement for the operating license of LSCS, the 

40 NRC staff estimated that the intake velocity at the face of the traveling screens would be 0.5 fps 

41 (0.2 m/s) 93 percent of the time and 1.0 fps (0.3 m/s) the remaining 7 percent of the time 

42 (NRC 1978). Exelon has not performed any operational studies to further characterize intake 

43 flow velocities (Exelon 2015c). Based on the assessment the NRC performed for LSCS’s 

44 operating license (NRC 1978), the velocity at the face of the traveling screens would typically be 

45 within the 0.5-fps (0.15-m/s) intake velocity now recommended by the U.S. Environmental 

46 Protection Agency (EPA) for protection of aquatic organisms (Volume 69 of the Federal 

47 Register, page 41576 (69 FR 41576)), although the velocity may be closer to 1.0 fps (0.3m/s) 

48 during certain periods during operations.
Affected Environment

3-9

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

2 Sources: Modified from Exelon 2014a, 2015b
Affected Environment

3-10

1 A backwash system removes debris from the river intake traveling screens, and trash rakes 

2 remove debris from bar grills. The backwash system can be set to operate in automatic or 

3 manual mode, but the system is normally left in automatic mode unless high debris loading 

4 requires manual cleaning. In automatic mode, cleaning is initiated when the measured 

5 differential water level across the screens reaches 4 in. (10 cm). With a differential water level 

6 of 6 in. (15 cm), the system switches to fast speed. A differential level in excess of 16 in. 

7 (40 cm) for at least 15 seconds will cause the associated makeup pumps to trip to prevent 

8 cavitation damage. Manual mode with either a slow or fast speed setting may be used during 

9 periods of high debris loading (Exelon 2015c). 

10 Collected debris, including any impinged biota, is deposited in a trash basket located outside the 

11 river screen house, with the debris ultimately disposed of in an offsite permitted landfill. The 

12 river screen house is not equipped with a fish return system. Screen backwash and other 

13 intermittent discharges from the screen house are discharged to the Illinois River through a 

14 National Pollutant Discharge Elimination System (NPDES)-permitted outfall (Outfall 002). The 

15 intake forebay of the facility has a floating oil boom to prevent any oil leaks from the screen 

16 house from entering the river. Section 3.5.1.3 of this SEIS presents additional information on 

17 water quality and LSCS’s NPDES permit. 

18 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 19 /s), which is equivalent to 129.6 million 

gallons per day (mgd) (491,000 cubic meters per day (m3 20 /day)). Normal peak makeup 

21 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 22 /day). Surface water use is detailed in Section 3.5.1.2. 

23 From the river screen house, intake water is pumped south to the northern end of the LSCS

24 cooling pond through a 60-in. (152-cm) pipeline. Upon reaching the pond, the water is 

25 conveyed into the pond through a reinforced concrete discharge structure located on the north 

26 side of the pond’s discharge canal. The structure is designed to prevent erosion of the cooling 

27 pond dike (Exelon 2014b) (see Figure 3–6). 

28 The river intake pipeline is equipped with air and vacuum relief valves along its course to help 

29 guard against pressure surges and other conditions that sometimes occur due to elevation 

30 changes along its routing. Nevertheless, the makeup pipeline, which is not a safety-related 

31 structure, has experienced a number of breaks resulting in flooding and erosion of areas 

32 surrounding the break. The most recent such break occurred on January 23, 2014. Exelon

33 reported the break to both the Illinois Environmental Protection Agency (IEPA) and EPA 

34 Region V in accordance with the reporting provisions of Exelon’s NPDES permit 

35 (Exelon 2015c).

36 To address issues associated with pipeline breaks, Exelon has performed maintenance, 

37 including replacing relief valves, and has installed instrumentation on the intake traveling 

38 screens to alert the LSCS control room operators to abnormal conditions. Exelon has also 

39 modified operating and response procedures and has implemented plans and procedures to 

40 prevent and quickly respond to any breaks. For example, operational procedures have been 

41 modified to include checks on pipeline integrity and to ensure necessary parts are maintained to 

42 replace a section of pipeline should a break occur (Exelon 2014a, 2015a). 

43 CWS and Blowdown Discharge. The CWS provides cooling water to the main condensers. In 

44 addition to the condensers, the system includes the cooling pond, lake screen house, circulating 

45 water pumps, piping, valves, and related equipment. The system normally supplies water to the 

46 main condensers at temperatures ranging from 32 °F to a maximum of 100 °F (0 to 37.8 °C). 

47 However, operating license technical specifications (TS) limit the temperature of the cooling 
Affected Environment

3-11

1 water supplied to the facility from the UHS portion of the cooling pond to 101.25 °F (38.5 °C) 

2 (Exelon 2014b).

The main condenser of each unit requires 616,500 gpm (1,373 cfs or 38.8 m3 3 /s), or 888 mgd 

(3.36 million m3 4 ) of circulating water flow to remove waste heat at 100-percent load. Cooling 

5 water is withdrawn from the cooling pond through the lake screen house, which is located at the 

6 west end of the intake canal (Figure 3–6). The lake screen house contains six circulating water 

7 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 8 /s) (Exelon 2015c), with two 

9 pumps normally in operation per unit to supply water to the condensers. Water first enters the 

10 intake forebays after passing through bar grills and traveling screens with 3/8-in. (0.95-cm) 

11 openings. Trash rakes prevent larger debris and aquatic biota from entering the system. The 

12 design water intake velocity at the screens is approximately 2.2 fps (0.7 m/s), assuming clean 

13 screens. Debris removed from the traveling screens by the screen backwash system and from 

14 the bar grills by trash rakes is collected in a trash basket and disposed of in an offsite permitted 

15 landfill. Similar to the river intake backwash system, the circulating water backwash system can 

16 be operated in either automatic or manual mode. When in automatic mode with a differential 

17 water level across the screens ranging between 0 and 6 in. (0 to 15 cm), a timer initiates a 

18 3-minute wash cycle every 12 to 14 hours. With a differential level rising to between 6 and 

19 10 in. (15 to 25 cm), a continuous backwash cycle starts at slow speed. The fast setting is 

20 triggered with a differential water level exceeding 10 in. (25 cm). Manual mode may be used 

21 during fish runs or other periods of high debris intake (Exelon 2015c). Like the river screen 

22 house, the lake screen house has no fish return system (Exelon 2014a, 2014b). 

23 From the lake screen house, water is pumped through the main condenser of each unit. 

24 A chemical feed system, located in facilities adjacent to the lake screen house, injects biocide

25 and other chemical treatments to reduce biofouling, silting, and scale buildup in the condenser 

26 systems. After passing through the unit condensers, heated circulating water is returned to the 

27 cooling pond through the discharge canal. The nominal (design) temperature rise in the 

28 circulating water passing through the main condensers is approximately 26.7 °F (10 °C) 

29 (Exelon 2014b). 

30 As previously stated, a series of parallel dikes in the cooling pond direct and slow the rate of 

31 movement of the returned cooling water through the pond to facilitate residence time cooling 

32 processes so that the coolest water is available for uptake again at the lake screen house. 

33 This heat dissipation is necessary so that cooling pond blowdown to the Illinois River meets 

34 temperature limitations and mixing zone requirements under the Illinois thermal water quality 

35 standards (35 IAC 302) and Special Condition 3 of Exelon’s NPDES Permit No. IL0048151 

36 (IEPA 2013). The permit also authorizes the discharge of various other effluent streams to the 

37 cooling pond in addition to condenser cooling water, as further described in Section 3.5.1.3 of 

38 this SEIS.

39 Blowdown combined with other comingled effluent streams flows through an open channel 

40 originating at the west shore of the cooling pond (UHS portion) and then northwest to a spillway 

41 adjacent to the LSCS discharge canal. This combined effluent stream can include processed 

42 liquid radioactive waste (radwaste), which may be discharged on a batch basis directly into the 

43 cooling pond blowdown line at a maximum rate of 45 gpm (0.17 cubic meters per minute), as 

44 further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Nevertheless, the blowdown 

45 line is equipped with a radiation monitor that will automatically isolate the radwaste discharge 

46 line in the event of a high-radiation signal (Exelon 2014b). 

47 The blowdown spillway connects to a 66-in. (168-cm) diameter pipeline through which the 

48 collected blowdown travels underground via gravity flow. The pipeline discharges into an 
Affected Environment

3-12

1 approximately 500-ft- (150-m)-long discharge structure consisting of a plunge pool and rip-raped 

2 lined swale that connects with the Illinois River at RM 249.4 (RKm 401) and just upstream of the 

3 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 4 /s). However, 

5 motor-operated values at both the river and lake ends of the discharge line can be used to 

6 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 7 /s) or less with a target annual average of 30,000 gpm (67 cfs or 

1.89 m3 8 /s) (Exelon 2014a, 2014b). The blowdown discharge point is regulated under LSCS’s 

9 NPDES permit as Outfall 001 (see Section 3.5.1.3). 

10 Because the blowdown pipeline functions under gravity flow, it is less susceptible to surges and 

11 breakage than the river intake pipeline. It is also equipped with air and vacuum relief valves. 

12 Nevertheless, breaks do occur. The most recent such break occurred on July 13, 2012. Exelon

13 reported the break to both the IEPA and EPA Region V. As discussed above for the makeup 

14 pipeline, Exelon has implemented a program to reduce the frequency of breaks and their 

15 impacts on operations and the environment (Exelon 2015c). 

16 Plant Service Water System. The service water system provides cooling water for various 

17 nonsafety-related auxiliary systems and components, including cooling water for the turbine 

18 generator; various air conditioning condensers; and the fuel pool, turbine building, and reactor

19 building heat exchangers. It also supplies water for the lake screen house traveling screen 

20 backwash system and the radwaste system, and it is used to fill the fire protection system and 

21 serves as a backup fire water supply. Service water is normally supplied by four pumps, with a 

22 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 23 /s). The pumps take suction from the lake screen house intake 

24 service water tunnel and discharge into a common header. Automatic backwash strainers 

25 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 26 /s). These pumps are 

27 powered by an emergency diesel generator and are used to meet minimum flow requirements 

28 during a loss of offsite power. The service water is also treated by the chemical feed system to 

29 guard against biofouling, scale buildup, corrosion, and silting. Chemical injection occurs directly 

30 to the service water tunnel feed lines. All service water return flows are discharged back to the 

31 cooling pond (Exelon 2014a, 2014b). 

32 Fire Protection Water System. The cooling pond is the source of fire protection water for the 

33 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 34 /s) jockey pumps normally keep the system 

pressurized. If a system demand occurs, a 225-gpm (0.50-cfs or 0.014-m3 35 /s) intermediate 

36 pump is activated. If the demands of the intermediate pump are exceeded, the first of two 

37 diesel-driven pumps are automatically engaged. These pumps, each with a capacity of 

2,500 gpm (51 cfs or 1.44 m3 38 /s), are located in the lake screen house and take suction directly 

39 from the service water tunnel (Exelon 2014b). 

40 Core Standby Cooling System. This system is equivalent in purpose to the essential service 

41 water systems at other nuclear power plants and provides cooling water for the purpose of 

42 cooling safety-related equipment necessary for safe shutdown of the reactors. This equipment 

43 includes the residual heat removal heat exchangers, pump seal coolers, and emergency diesel 

44 generators; the system also provides emergency spent fuel pool makeup water and a source of 

45 water for containment flooding for post-accident recovery. The CSCS withdraws cooling pond 

46 water from the UHS portion of the cooling pond (as discussed earlier) via the lake screen house 

47 service water tunnel. The water is chemically treated by the chemical feed system as previously 

48 described. As a safeguard against blockage of the traveling screens ahead of the service water 

49 channel, the system has a 54-in. (137-cm) bypass line that can be opened to directly supply 
Affected Environment

3-13

1 CSCS water. All pumps and strainers for conveying emergency cooling water are located in 

2 watertight spaces within the basements of the various plant buildings (Exelon 2014a, 2014b). 

3 Potable Water System. LSCS uses groundwater from two deep wells (Nos. 1 and 2) to supply 

4 potable (drinking) water, sanitary water, and raw makeup water for the demineralized water 

5 system. The wells were installed during plant construction with completion depths of 1,629 ft 

6 (497 m) and 1,620 ft (494 m), respectively (Exelon 2014a). Each well has a pump capacity of 

7 300 gpm (1.14 cubic meters per minute) (Exelon 2014b). Water is stored in a 350,000-gallon 

(gal) (1,325-m3 8 ) storage tank before distribution. The plant supply wells and LSCS’s 

9 groundwater use are further discussed in Section 3.5.2.2.

10 3.1.4 Radioactive Waste Management Systems

11 As part of normal operations and as a result of equipment repairs and replacements due to 

12 normal maintenance activities, nuclear power plants routinely generate both radioactive and 

13 nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes. 

14 There is also a class of waste, called mixed waste that is both radioactive and hazardous. The 

15 systems used to manage (i.e., treat, store, and dispose of) these wastes are described in this 

16 section. Waste minimization and pollution prevention measures commonly employed at nuclear 

17 power plants are also discussed in this section.

18 All nuclear plants were licensed with the expectation that they would release very limited 

19 quantities of radioactive material to both the air and water during normal operation. However, 

20 NRC regulations require that gaseous and liquid radioactive releases from nuclear power plants 

21 must meet radiation dose-based limits specified in Title 10 of the Code of Federal Regulations

22 (10 CFR) Part 20, and the as low as is reasonably achievable (ALARA) criteria in Appendix I to 

23 10 CFR Part 50. Regulatory limits are placed on the radiation dose that members of the public 

24 can receive from radioactive effluents released by a nuclear power plant. All nuclear power 

25 plants use radioactive waste management systems to control and monitor radioactive wastes.

26 LSCS uses liquid, gaseous, and solid waste processing systems to collect and process, as 

27 needed, radioactive materials produced as a by-product of plant operations. The liquid and 

28 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 

29 discharge into the environment. This is to ensure that the dose to members of the public from 

30 radioactive effluents is reduced to levels that are ALARA in accordance with NRC’s regulations. 

31 The radioactive material removed from the effluents is converted into a solid form for eventual 

32 disposal at a licensed radioactive disposal facility.

33 Exelon has a radiological environmental monitoring program (REMP) to assess the radiological 

34 impact, if any, to the public and the environment from radioactive effluents released during 

35 operations at LSCS. The REMP measures the aquatic, terrestrial, and atmospheric 

36 environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 

37 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 

38 material, including radon) (Teledyne 2015).

39 LSCS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 

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

41 effluents. These methods are used to ensure that radioactive material discharges from the plant 

42 meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 

43 the REMP (Exelon 2013d).

44 3.1.4.1 Radioactive Liquid Waste Management

45 LSCS Units 1 and 2 share a common liquid radioactive waste system (LRWS). The LRWS 

46 collects, monitors, and processes any potentially radioactive liquid wastes produced in the plant. 
Affected Environment

3-14

1 The LRWS also recycles as much processed liquid waste as can be accommodated within the 

2 LSCS water balance. Although LSCS tries to limit any radioactive releases via the liquid 

3 pathway, discharges from the system are authorized and may occur if treated waste water is not 

4 needed for other plant uses. The LRWS is designed so that any liquid radioactive waste 

5 discharged from the site will have radioactive nuclide concentrations below the limits specified in 

6 10 CFR Part 20 and Appendix I to10 CFR Part 50.

7 Processing of liquids in the LRWS results in a clean product stream and a reject stream. The 

8 clean product stream returns water for use by the main plant systems via the condensate 

9 storage tanks if the water quality is found acceptable and if the plant has the need for the 

10 makeup water. Water in the reject stream is processed for disposal in the solid radioactive 

11 waste system. Unused treated waste water can be sent to a discharge tank and held until a 

12 discharge batch accumulates. Before any release of a discharge batch, it would be sampled 

13 and treated if necessary to ensure radionuclide concentrations and resulting radiation doses to 

14 LSCS personnel and the general public comply with NRC regulations in 10 CFR Part 20 and 

15 Appendix I to 10 CFR Part 50. The LWRS sends discharge batches directly into the cooling 

16 pond blowdown line. 

17 The LRWS consists of a waste processing subsystem, a floor drain processing subsystem, a 

18 chemical waste subsystem, and a sludge subsystem. All subsystems are shared by LSCS

19 Units 1 and 2. A vendor-provided liquid waste treatment system is also available to supplement 

20 the LRWS if needed.

21 The waste processing subsystem collects and processes water from sources such as 

22 equipment drains. This water is treated by settling, filtration, and demineralization. After 

23 treatment and sampling, the water is returned for reuse through the condensate storage tanks. 

24 The floor drain processing subsystem collects and processes water from the floor drain 

25 systems. After treatment and sampling, the water is returned for reuse through the condensate 

26 storage tanks. The chemical waste subsystem collects and processes water from areas like the 

27 laboratory drains and the radwaste building sump. After treatment and sampling, plant 

28 procedures are used to determine where the processed water goes, which may include 

29 discharge. The sludge subsystem is not a processing stream, but rather a group of tanks and 

30 associated pumps that serve as an interface between the LRWS and the solid radioactive waste 

31 handling system. After radioactive contaminants have been removed from the LRWS, 

32 concentrated, and treated or held up to allow radioactive decay if necessary, they are 

33 transferred to the solid radioactive waste system for processing, temporary storage, and 

34 shipment for disposal.

35 The use of these radioactive waste systems and the procedural requirements in the ODCM 

36 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 

37 dose standards.

38 Dose estimates for members of the public are calculated based on radioactive liquid effluent 

39 release data and aquatic transport models. Exelon’s annual radiological effluent release report 

40 contains the radioactive liquid effluents release data from LSCS and the resultant calculated 

41 doses. The NRC staff reviewed 5 years of radioactive effluent release data: 2010 through 2014 

42 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year period provides a data set that covers a 

43 broad range of activities that occur at a nuclear power plant, such as refueling outages, routine 

44 operation, and maintenance activities that can affect the generation of radioactive effluents. 

45 LSCS did not have any radioactive liquid effluent releases over the period of 2010 through 

46 2014. 

47 Since LSCS had no radioactive liquid effluent releases for the period of 2010 through 2014, its

48 radioactive liquid effluent control program showed that radiation doses to members of the public 
Affected Environment

3-15

1 were controlled within the NRC’s and EPA’s radiation protection standards contained in 

2 Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190. Also, since LSCS had no 

3 radioactive liquid effluent releases for the period of 2010 through 2014, no adverse trends were 

4 observed in the dose levels.

5 Routine plant refueling and maintenance activities currently performed will continue during the 

6 license renewal term. Based on the past performance of the radioactive waste system to 

7 maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 

8 during the license renewal term.

9 3.1.4.2 Radioactive Gaseous Waste Management 

10 LSCS Units 1 and 2 share a common gaseous radioactive waste system (GRWS) with a 

11 common vent stack located on the roof of the containment building between the two units. The 

12 GRWS is designed to process and control radioactive gases and minimize the amount of 

13 radioactive gaseous material released into the environment. The gaseous radioactive wastes 

14 released consist primarily of xenon, argon, iodine, tritium, and carbon. The steam in a BWR 

15 plant such as LSCS contains impurities in the form of radioactive gases that are continuously 

16 removed during plant operation from the main condenser by an air ejector. This process is the 

17 major source of radioactive gases generated by LSCS (Exelon 2014a). The GRWS removes 

18 some radioactive gases and delays the release of other radioactive gases by adsorption on 

19 charcoal beds to allow time for radioactive decay. As a final step, the gaseous waste stream 

20 passes through a high efficiency particulate air filter, and is discharged through the common 

21 vent stack. Other plant facilities that are potential sources of radioactive gas emissions include 

22 the primary containment, the secondary containments (reactor buildings), the turbine buildings, 

23 and the radwaste building. The ventilation systems in each of these facilities have filtration and 

24 treatment systems that the air passes through before being discharged through the vent stack 

25 (Exelon 2014a).

26 The use of these radioactive waste systems and the procedural requirements in the ODCM 

27 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 

28 dose standards.

29 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 

30 release data and atmospheric transport models. Exelon’s annual radioactive effluent release 

31 report contains a detailed presentation of the radioactive gaseous effluents released from LSCS

32 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 

33 release data: 2010 through 2014 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year 

34 period provides a data set that covers a broad range of activities that occur at a nuclear power 

35 plant, such as refueling outages, nonrefueling outage years, routine operation, and maintenance 

36 activities that can affect the generation of radioactive effluents. The NRC staff compared the 

37 data against NRC dose limits and looked for indication of adverse trends (i.e., increasing dose 

38 levels) over the period of 2010 through 2014. Since the radioactive gaseous effluents are 

39 released from a common vent stack shared by both Unit 1 and Unit 2, the resultant calculated 

40 doses presented in the effluent release are divided in half to evaluate compliance with the 

41 Appendix I to 10 CFR Part 50 dose criteria. The following summarizes the calculated doses 

42 from radioactive gaseous effluents released from LSCS Units 1 and 2 during 2014:

43 Unit 1

44 • 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 45 −4 milligray (mGy), which is well below 

46 the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.
Affected Environment

3-16

1 • The air dose at the site boundary from beta radiation in gaseous effluents from LSCS

was 1.10×10−3 mrad (1.10×10 2 −5 mGy), which is well below the 20 mrad (0.2 mGy) 

3 dose criterion in Appendix I to 10 CFR Part 50.

4 • 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 5 −3 millisievert (mSv)), 

6 which is well below the 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR 

7 Part 50.

8 Unit 2

9 • The air dose at the site boundary from gamma radiation in gaseous effluents from 

LSCS was 2.36×10−2 mrad (2.36×10 10 −4 mGy), which is well below the 10 mrad 

11 (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

12 • The air dose at the site boundary from beta radiation in gaseous effluents from LSCS

was 1.10×10−3 mrad (1.10×10 13 −5 mGy), which is well below the 20 mrad (0.2 mGy) 

14 dose criterion in Appendix I to 10 CFR Part 50.

15 • 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 16 −3 mSv), which is well below the 

17 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.

18 The NRC staff’s review of LSCS’s radioactive gaseous effluent control program showed that 

19 radiation doses to members of the public were controlled within NRC’s and EPA’s radiation 

20 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 

21 40 CFR Part 190. No adverse trends were observed in the dose levels.

22 Routine plant refueling and maintenance activities currently performed will continue during the 

23 license renewal term. Based on the past performance of the radioactive waste system to 

24 maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 

25 expected during the license renewal term.

26 3.1.4.3 Radioactive Solid Waste Management

27 LSCS Units 1 and 2 share a common solid radioactive waste system (SRWS). The SRWS 

28 receives, dewaters, solidifies, packages, handles, and provides temporary storage facilities for 

29 all radioactive wet solid wastes prior to offsite shipment and disposal in accordance with NRC 

30 regulations in 10 CFR Parts 61 and 71. It also receives, decontaminates, compacts 

31 (as necessary), and provides temporary storage facilities for all radioactive dry wastes prior to 

32 offsite shipment and disposal (Exelon 2014a). Transportation of the radioactive solid waste is 

33 governed by the U.S. Department of Transportation regulations in 49 CFR Parts 171 to 178.

34 LSCS disposes of solid radioactive waste at facilities in Utah and Texas. LSCS also utilizes 

35 offsite vendor services in Tennessee for dry active waste processing, including compaction, 

36 incineration, thermal processing, and sorting of the dry active waste.

37 LSCS Units 1 and 2 have a shared Interim Radwaste Storage Facility (IRSF) with the capacity 

38 to hold 270 containers of Class B and Class C (Class B/C) low-level radioactive wastes in two 

39 layers of 135 spots each. In 2011, LSCS Units 1 and 2 both received license amendments to 

40 allow their IRSF to store Class B/C waste from Braidwood, Byron, and Clinton Stations in 

41 addition to the wastes generated at LSCS. Exelon states that LSCS has sufficient excess 

42 storage capacity to accommodate extended storage of the Class B/C wastes generated by all 

43 four Exelon stations. Also, LSCS can ship Class B/C wastes for treatment and disposal to the 

44 Waste Control Specialists facility in Texas to reduce the demand for any extended onsite 
Affected Environment

3-17

1 storage of those wastes. Therefore, storage capacity for low-level radioactive wastes should be 

2 sufficient for the length of the license renewal term. (Exelon 2014a)

3 LSCS infrequently generates small quantities of mixed waste (waste having both a hazardous 

4 component and radioactive component). The IEPA regulates the hazardous component of the 

5 waste and the Illinois Emergency Management Agency Division of Nuclear Safety and the NRC 

6 regulate the radioactive component. When generated, mixed wastes are accumulated in the 

7 Mixed Waste Storage Building before transport to a licensed offsite facility for treatment and 

8 disposal (Exelon 2014a).

9 LSCS has contracts to send its low-level waste (LLW) to two licensed LLW disposal sites: 

10 EnergySolutions in Clive, Utah, and Waste Control Specialists in Andrews, Texas. LSCS also 

11 sends certain wastes to Toxco Materials Management Center in Oak Ridge, Tennessee, and 

12 EnergySolutions in Oak Ridge, Tennessee for processing before disposal.

13 In 2014, 30 LLW shipments were made from LSCS for processing and disposal to the 

14 EnergySolutions Clive facility in Clive, Utah, the EnergySolutions Bear Creek facility in Oak 

15 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 16

(4.34×104 cubic feet and 1.34×101 curies (4.95×10 17 5 megabecquerels)), respectively 

18 (Exelon 2015b). Routine plant operation, refueling outages, and maintenance activities that 

19 generate radioactive solid waste will continue during the license renewal term. Radioactive 

20 solid waste is expected to be generated and shipped off site for disposal during the license 

21 renewal term.

22 3.1.4.4 Radioactive Waste Storage

23 Low-level radioactive waste (LLRW) is stored temporarily onsite before being shipped offsite for 

24 disposal at a licensed LLRW disposal facility. Exelon (2014a) stated that LSCS has sufficient 

25 capability to store Class B/C LLRW from Braidwood, Byron, and Clinton Stations in addition to 

26 LSCS Class B/C waste in the IRSF (Exelon 2014a). 

27 LSCS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 

28 storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 

29 approved dry cask storage containers onsite. The installation and monitoring of this facility is 

30 governed by NRC requirements in 10 CFR Part 72, “Licensing requirements for the independent 

31 storage of spent nuclear fuel, high-level radioactive waste, and reactor-related Greater than 

32 class C waste.” The LSCS ISFSI will remain in place until the U.S. Department of Energy takes 

33 possession of the spent fuel and removes it from the site for permanent disposal or processing. 

34 Spent fuel transfers to the ISFSI began in 2010 when fuel from the spent fuel pool was placed 

35 in casks and transferred to the ISFSI storage pad. As of December 2014, there are 16 dry 

36 casks containing spent fuel on the ISFSI storage pad (Exelon 2015b).

37 3.1.4.5 Radiological Environmental Monitoring Program

38 Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 

39 environment from operations at LSCS.

40 The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 

41 radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 

42 groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 

43 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 

44 material, including radon). 

45 In addition to the REMP, LSCS has an onsite ground water protection program designed to 

46 monitor the onsite plant environment for detection of leaks from plant systems and pipes 
Affected Environment

3-18

1 containing radioactive liquid (Teledyne 2015). Information on the groundwater protection 

2 program is contained in Section 3.5.2 of this document.

3 The NRC staff reviewed 5 years of annual radiological environmental monitoring data: 

4 2010 through 2014 (Teledyne 2011, 2012, 2013, 2014, 2015). A 5-year period provides a data 

5 set that covers a broad range of activities that occur at a nuclear power plant, such as refueling 

6 outages, routine operation, and maintenance activities that can affect the generation and 

7 release of radioactive effluents into the environment. The NRC staff looked for indication of 

8 adverse trends (i.e., buildup of radioactivity levels) over the period of 2010 through 2014.

9 The NRC staff’s review of Exelon’s data showed no indication of an adverse trend in 

10 radioactivity levels in the environment. The data showed that there was no measurable impact 

11 to the environment from operations at LSCS. 

12 3.1.5 Nonradioactive Waste Management Systems

13 Like any other industrial facility, nuclear power plants generate wastes that are not 

14 contaminated with either radionuclides or hazardous chemicals.

15 LSCS has a nonradioactive waste management program to handle its nonradioactive hazardous 

16 and nonhazardous wastes. The waste is managed in accordance with Exelon’s procedures. 

17 Listed below is a summary of the types of waste materials generated and managed at LSCS.

18 • LSCS is a small quantity hazardous waste generator; however, hazardous wastes

19 are managed according to large quantity generator standards. LSCS has contracts

20 in place to transfer hazardous waste to licensed offsite treatment and disposal

21 facilities.

22 • LSCS’s nonhazardous wastes include potentially infectious medical waste (PIMW),

23 waste/used oil, grease, antifreeze, adhesives, and other petroleum-based liquids.

24 PIMW is generated at a health facility onsite and can include used and unused

25 hypodermic needles and syringes, as well as items contaminated with human blood.

26 PIMW is considered a unique special waste category in Illinois and transportation

27 and disposal of this waste is regulated under the Illinois Administrative Code (IAC)

28 Title 35, Sections 1420 through 1422 and 1450, (35 IAC 1420-1422, 1450).

29 • Universal wastes, such as batteries and mercury-containing lamps are managed in

30 accordance with 35 IAC 733 standards. Other wastes, such as, oils, metals, paper,

31 and other recyclables are managed according to Exelon procedures and Illinois

32 regulations.

33 Exelon operates an onsite sewage treatment plant. Sewage treatment effluent is discharged to 

34 the LSCS cooling pond. Nonradioactive industrial wastewater is also processed at the 

35 treatment plant and the treated effluent is discharged into the cooling pond. Cooling pond 

36 blowdown is discharged to the Illinois River under NPDES permit IL0048151 (Exelon 2014a).

37 3.1.6 Utility and Transportation Infrastructure

38 The utility and transportation infrastructure at nuclear power plants typically interfaces with 

39 public infrastructure systems available in the region. Such infrastructure includes utilities, 

40 including suppliers of electricity, fuel, and water, as well as roads and railroads that provide 

41 access to the site. The following sections briefly describe the existing utility and transportation 

42 infrastructure at LSCS. 
Affected Environment

3-19

1 3.1.6.1 Electricity

2 Nuclear power plants generate electricity for other users; however, they also use electricity to 

3 operate. Offsite power sources provide power to engineered safety features and emergency 

4 equipment in the event of a malfunction or interruption of power generation at the plant. 

5 Independent backup power sources provide power in the event that power is interrupted from 

6 both the plant and offsite power sources.

7 At LSCS, connections to the Commonwealth Edison Company (ComEd) 345-kilovolt (kV) 

8 system at the onsite switchyard provide offsite power sources for essential safety systems and 

9 emergency equipment (Exelon 2014g). The switchyard is arranged in a double ring bus such 

10 that offsite power to both units cannot be lost due to any single failure (Exelon 2014g). In the 

11 event of total loss of auxiliary power from offsite sources, onsite diesel generators serve as an 

12 independent source of power for safe shutdown (Exelon 2014g). LSCS has six diesel 

13 generators (three for each nuclear unit) that can each provide up to 4.16 kV of power, which is 

14 ample capacity to supply all power required for the safe shutdown of both units in the event of a 

15 total loss of offsite power (Exelon 2014g).

16 3.1.6.2 Fuel

17 The LSCS nuclear units are operated using low-enriched uranium dioxide fuel with enrichment 

18 not exceeding 5 percent by weight of uranium-235. At any given time, the LSCS units contain 

19 approximately 140 metric tons (MT) (308,600 pounds) of uranium fuel (Exelon 2015e). Exelon 

20 replaces about 36 percent of that fuel at each refueling, which occurs on a staggered 24-month 

21 cycle (Exelon 2014a). Fresh (i.e., unirradiated) fuel is brought to the site and stored onsite in 

22 the LSCS new fuel storage facility prior to installation in the reactor cores (Exelon 2014g). 

23 Exelon stores spent fuel in a spent fuel pool and an ISFSI. Nuclear fuel and radioactive waste 

24 systems are further described in Section 3.1.4.

25 In addition to nuclear fuel, LSCS requires diesel fuel to operate the emergency diesel power 

26 generators. To meet emergency demands, Exelon stockpiles diesel fuel and gasoline on the 

27 site. In total, Exelon stores 204,080 gal (772,530 liters) of diesel fuel and gasoline for a variety 

28 of uses, including emergency diesel generators, diesel fire pumps, and plant vehicles 

29 (Exelon 2015e).

30 3.1.6.3 Water

31 In addition to cooling and auxiliary water (described in Section 3.1.3), nuclear power plants 

32 require potable water for sanitary and everyday uses by personnel (e.g., drinking, showering, 

33 cleaning, laundry, toilets, and eye washes). At LSCS, two deep wells supply the site with 

34 potable water. Water pumped from the wells is routed to an onsite vendor trailer, which 

35 deionizes the water and routes the water to a 1.3-million-liter (350,000-gal) storage tank. Water 

36 drawn from the storage tank may be used in either the demineralized water makeup system or 

37 the potable and sanitary water system. Water withdrawn for use in the potable water system 

38 undergoes chlorination prior to entering the system. LSCS withdraws approximately 98 liters 

39 per minute (L/min) (26 gpm) from the wells for potable water uses. (Exelon 2014a)

40 3.1.6.4 Transportation Systems

41 All nuclear power plants are served by controlled access roads. In addition to roads, many

42 plants also have railroad connections for moving heavy equipment and other materials. Some 

43 plants that are located on navigable waters, such as rivers, Great Lakes, or oceans, have 

44 facilities to receive and ship loads on barges.

45 At LSCS, County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road,

46 provides access to the site from the southern boundary. Major roads in the area include State 
Affected Environment

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1 Route 170 (SR-170), which lies 0.8 km (0.5 mi) east of the site, and Interstate 80 (I-80), which 

2 lies 13 km (8 mi) north of the site. Section 3.10.6 describes local transportation systems, 

3 including roadway access, in more detail.

4 Two major railway systems provide service near the LSCS site: the CSX Railroad runs parallel 

5 to and slightly north of the Illinois River, and a 10-km (6-mi) rail spur connects LSCS to the 

6 Atchison, Topeka, and Santa Fe Railroad south of the site. Exelon uses a portion of the onsite 

7 rail spur to transport spent fuel casks to the onsite storage area, but the spur has not been used 

8 to deliver equipment or materials to the site from external sources in many years. 

9 (Exelon 2015f)

10 LSCS lies south of the Marseilles Pool in the reach of the Illinois River between the Marseilles 

11 Lock and Dam at Marseilles, Illinois, and the Dresden Lock and Dam south of Channahon, 

12 Illinois (Exelon 2014a). These lock and dam sites are part of the Illinois Waterway, which flows 

13 from Chicago, Illinois, to St. Louis, Missouri, and is composed of seven water systems: Illinois 

14 River, Des Plaines River, Chicago Sanitary and Shipping Canal, South Branch Chicago River, 

15 Cal-Sag Channel, Little Calumet River, and the Calumet River (USACE 2012). Much of the 

16 barge traffic in this area is dominated by transportation of agricultural products (grains, corn, 

17 and soybeans) and other commodities, such as cement and concrete (USACE 2012). 

18 Exelon (2015g) does not own or maintain a barge slip for LSCS and does not otherwise receive 

19 or ship equipment for LSCS by barge.

20 Major airports in the vicinity of LSCS include Chicago Midway International Airport, Chicago 

21 O’Hare International Airport, and Central Illinois Regional Airport, which lie approximately 93 km 

22 (58 mi) northeast, 100 km (60 mi) north-northeast, and 110 km (70 mi) south of the site, 

23 respectively. Additionally, Illinois Valley Regional Airport in Peru, Illinois, serves LaSalle 

24 County, and eight private airports in the county accommodate smaller cargo, passenger, and 

25 private aircraft (LaSalle County 2014).

26 3.1.6.5 Power Transmission Systems

27 ComEd owns and operates the 345-kV onsite switchyard that connects LSCS with the regional 

28 electric grid. From the switchyard, a total of six transmission lines extend to four substations. 

29 Two 345-kV lines travel 66 km (41 mi) north from the site to the Plano substation east of Plano, 

30 Illinois. Two 345-kV lines travel 100 km (62 mi) northeast to Braidwood Station, Units 1 and 2, 

31 in Braceville, Illinois. Two 138-kV lines are connected to the switchyard through a 345/138-kV 

32 transformer. One of the 138-kV line extends 27 km (17 mi) to Mazon, Illinois, and the other 

33 138-kV line extends 40 km (25 mi) to Streator, Illinois (AEC 1973; NRC 1978; Exelon 2015h).

34 For license renewal, the NRC (2013) evaluates as part of the proposed action the continued 

35 operation of those transmission lines that connect the nuclear power plant to the substation 

36 where electricity is fed into the regional power distribution system and transmission lines that 

37 supply power to the nuclear plant from the grid. Exelon (2015h) has determined that the four 

38 electrical connections between the main plant and the LSCS switchyard are in scope for the 

39 license renewal environmental review. These connections extend a distance of 1,300 ft (400 m) 

40 across flat, primarily gravel laydown areas and paved roads (Exelon 2015h). Because 

41 redundant offsite power is provided to LSCS through the LSCS substation, no offsite 

42 transmission lines supply power to the nuclear plant from the grid (Exelon 2015h). All of the 

43 in-scope transmission lines lie within the owner-controlled and industrial-use area of the site.

44 3.1.7 Nuclear Power Plant Operations and Maintenance

45 Maintenance activities conducted at LSCS include inspection, testing, and surveillance to 

46 maintain the current licensing basis of the facility and to ensure compliance with environmental 
Affected Environment

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1 and safety requirements. Various programs and activities currently exist at LSCS to maintain, 

2 inspect, test, and monitor the performance of facility equipment. These maintenance activities 

3 include inspection requirements for reactor vessel materials, boiler and pressure vessel 

4 inservice inspection and testing, and maintenance of water chemistry.

5 Additional programs include those carried out to meet TS surveillance requirements, those 

6 implemented in response to the NRC generic communications, and various periodic 

7 maintenance, testing, and inspection procedures. LSCS must periodically discontinue the 

8 production of electricity for outages supporting refueling, periodic in-service inspection and 

9 testing, and maintenance activities. The LSCS reactor units are on staggered 24-month 

10 refueling cycles (Exelon 2014a).

11 3.2 Land Use and Visual Resources

12 3.2.1 Land Use

13 3.2.1.1 Onsite Land Use

14 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 

15 Illinois (Exelon 2015p). The site lies 8 km (5 mi) south of the Illinois River, about 10 km (6 mi) 

16 southwest of Seneca, Illinois, and 120 km (75 mi) southwest of downtown Chicago.

17 (Exelon 2014a)

18 A cooling pond occupies the western side of the site and accounts for about half of the site area. 

19 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 

20 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac). This 

21 industrial area is surrounded by about 142 ha (350 ac) of undeveloped natural areas, including 

22 grassland, old field, scrub-scrub, and small forested fragments (Exelon 2015p).

23 On the southwest shore of the cooling pond, the IDNR operates the LaSalle Fish Hatchery 

24 under a lease agreement with Exelon. The hatchery encompasses approximately 18 ha (45 ac) 

25 and includes several small buildings and 16 fish-rearing pools (Exelon 2014a).

26 A 5.6-km (3.5-mi) corridor for the makeup and blowdown pipelines—which travel underground 

27 from the Illinois River screen house south to the cooling pond—contains woodlands, pastures, 

28 and wetlands as well as mowed and maintained right-of-way for a portion of the 

29 LaSalle-to-Plano 345-kV transmission line (Exelon 2014a).

30 Table 3–1 lists site land uses, and Figure 3–3 depicts the site layout. Sections 3.1 and 3.6 

31 describe the developed and natural areas of the site in more detail, respectively.

32 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
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3-22

Land Use Area (in acres)(a) Percent

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

1 3.2.1.2 Coastal Zone

2 In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.; 

3 CZMA) to encourage and assist States and territories in developing management programs that 

4 preserve, protect, develop, and, where possible, restore the resources of the coastal zone 

5 (i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 

6 may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 

7 Great Lakes waters). Individual states are responsible for developing a Federally approved 

8 Coastal Management Plan and implementing a coastal management program in accordance 

9 with such a plan. In Illinois, the IDNR administers the coastal management program.

10 Section 307(c)(3)(A) of the CZMA requires that applicants for Federal permits whose proposed 

11 activities could reasonably affect coastal zones certify to the licensing agency (here, the NRC) 

12 that the proposed activity would be consistent with the state’s coastal management program. 

13 The regulations that implement the CZMA indicate that this requirement is applicable to renewal 

14 of Federal licenses for actions not previously reviewed by the state (15 CFR 930.51(b)(1)). 

15 LSCS is outside of the boundary of the Illinois coastal zone (IDNR 2011b, 2015c). Accordingly, 

16 a consistency determination is not required for the proposed LSCS license renewal.

17 3.2.1.3 Offsite Land Use

18 Within a 10-km (6-mi) radius of the LSCS site, most lands are contained within LaSalle County; 

19 however, this radius also includes a small area of land in Grundy County to the east. Land use 

20 in this area is primarily agricultural. Cropland or pastures border the LSCS site to the east, 

21 south, and west. The Illinois River lies to the north of the site, and the bluffs overlooking the 

22 Illinois River are mostly forested. The river’s south bank floodplain includes agricultural fields 

23 and woodlots, while the north bank is more developed and includes parts of the incorporated 

24 towns of Seneca and Marseilles. The majority of land cover (about 70 percent) within 10 km 

25 (6 mi) is used for crop cultivation. Deciduous forest accounts for about 12 percent of land cover, 

26 and the remaining 18 percent is composed of various land cover types, including open water, 
Affected Environment

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1 developed land, wetlands, and grasslands. Table 3–2 characterizes the land uses within a 

2 10-km (6-mi) radius of LSCS.

3 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

4 The IDNR manages three areas for public use and recreation within 10 km (6 mi) of LSCS. The 

5 LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling pond that is 

6 managed by the IDNR and open to the public for fishing and other recreational purposes 

7 (Exelon 2014a). The Marseilles State Fish & Wildlife Area is approximately 2.4 km (1.5 mi) 

8 north of the LSCS site. The IDNR (2015e) manages this 1,032-ha (2,550-acre) tract of 

9 predominantly wooded land for wildlife habitat and hunting. Illini State Park lies approximately 

10 10 km (6 mi) northwest of LSCS on the south bank of the Illinois River and encompasses 

11 206 ha (510 ac) (Exelon 2014a).

12 LaSalle County, in which LSCS is located, is a predominantly agricultural county; 85 percent of 

the county’s 1,135 square miles (m2 13 ) (294,000 ha or 726,400 ac) are in agricultural production 

14 (LaSalle County 2014). Much of the county’s agricultural lands were formerly prairie. LaSalle 

15 County’s major agricultural crops include corn, soybeans, and its major livestock commodities 

16 include cattle and calves, hogs and pigs, and sheep and lambs (LaSalle County 2014). The 

17 LaSalle County Comprehensive Plan (LaSalle County 2014) anticipates that the county will 

18 experience a slight (4 percent) increase in population over the next 15 years and reach an 

19 estimated 141,615 people by 2030. The county plans to manage its land resources in a manner 

20 that will preserve prime farmland and to encourage continued urban growth in areas where 

21 public infrastructure and services already exist so that farmland, open spaces, and natural and 

22 cultural resources are preserved.
Affected Environment

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1 3.2.2 Visual Resources

2 As described in the previous section, the LSCS site is located in a predominantly agricultural 

3 region. The site’s grade elevation is approximately 216 m (710 ft) above MSL, which is the 

4 highest point within a 3-km (5-mi) radius. The site’s generating facilities were built 60 m (200 ft) 

5 above the Illinois River floodplain elevation, which ranges from 152 to 155 m (500 to 510 ft) 

6 above mean sea level. The tallest structures on the LSCS site are the meteorological tower and 

7 the station vent stack, which are 122 m (400 ft) tall and 113 m (370 ft) tall, respectively. The 

8 vent stack is painted with thick white and red horizontal stripes. The largest and most visible 

9 buildings on the site are the reactor and turbine buildings, which are 56 m (185 ft) and 41 m 

10 (134 ft) tall, respectively (Exelon 2014a).

11 To the west and the southwest, the Grand Ridge Energy Center wind farm is situated on slightly 

12 higher ground (221 to 227 m (725 to 750 ft) above MSL) on a north-south ridgeline. A second 

13 wind farm, Top Crop I, is sited south and east of the Grand Ridge Energy Center. Wind turbines 

14 at these facilities stand 118.5 m (389 ft) tall and have rotor blades that are 38.5 m (126.5 ft) 

15 long. These two facilities’ 134 wind turbines dominate the viewscape in the vicinity of LSCS. 

16 (Exelon 2014a)

17 From most vantage points, the wind turbines are more noticeable than the LSCS buildings or 

18 facilities. A motorist travelling north on Highway 170 from Ranson, Illinois, to Seneca, Illinois,

19 would see wind turbines to the west, south, and east until the motorist crested the bluffs of the 

20 Illinois River at an elevation of about 200 m (650 ft) above MSL. The motorist would then lose 

21 sight of the turbines at the highway bridge that crosses the Illinois River, at which point the 

22 road’s elevation descends to approximately 152 m (500 ft) (Exelon 2014a).

23 3.3 Meteorology, Air Quality, and Noise

24 3.3.1 Meteorology and Climatology

25 LSCS is located in LaSalle County in northeastern Illinois, approximately 70 mi (113 km) 

26 southwest of Chicago and 35 mi (56 km) southwest of Joliet, Illinois. The regional climate is 

27 continental with cold winters; warm summers; and frequent short fluctuations in temperature, 

28 humidity, cloudiness, and wind direction (NCDC 2004). During fall, winter, and spring, the polar 

29 jet stream is located near or over northeastern Illinois, which causes large-scale synoptic storms 

30 to move through the area bringing precipitation, winds, and often dramatic temperature changes 

31 (NCDC 2004). Temperature and precipitation conditions vary widely throughout Illinois and 

32 between years. A wide range of temperature extremes is common in this region 

33 (NCDC 2015a). Tornadoes, thunderstorms, hail, and heat and cold waves are common in the 

34 State, and flooding is the most damaging weather-related hazard in Illinois (NCDC 2004).

35 The NRC staff obtained climatological data collected at the Peoria, Illinois, airport station 

36 (KPIA), which is located approximately 62 mi (100 km) from LSCS. Additionally, LSCS 

37 maintains a meteorological monitoring program that includes a 400-ft (122-m) meteorological 

38 tower located approximately 0.5 mi (0.8 km) southeast of the reactor buildings. The tower 

39 measures wind direction, wind speed, temperature, and precipitation. Data from these stations 

40 were used to characterize the region’s climate and are presented below.

41 The prevailing wind direction, for the 1981 through 2010 timeframe, at the KPIA station was 

42 from the south-southwest (NCDC 2015a). The mean annual wind speed for the 1981 through 

43 2010 timeframe is 8.4 miles per hour (mph) (13.5 kilometers per hour (kph)), and the mean 

44 monthly wind speed ranges from 6.0 mph (9.7 kph) in August to 10.2 mph (16.4 kph) in March. 

45 The annual predominant wind direction from the meteorological tower at LSCS for the 
Affected Environment

3-25

1 2010 through 2014 timeframe was from the south-southwest direction (for 2011 and 2012) and 

2 from the west-northwest direction (for 2010, 2013, and 2014) (Exelon 2015j). The mean annual 

3 wind speed at LSCS for the 2010 through 2014 timeframe is 10.4 mph (16.7 kph) 

4 (Exelon 2015j).

5 The mean annual temperature for the 1985 through 2014 period of record at the KPIA station is 

6 51.9 °F (11.1 °C), with a mean monthly temperature ranging from a low of 25.2 °F (-3.7 °C) in 

7 January to a high of 75.8 °F (24.3 °C) in July (NCDC 2015a). The hottest year over the period 

8 of record was in 2012, and coolest was in 1996. The mean annual temperature for the 2010 

9 through 2014 timeframe at LSCS is 50.7 °F (10.3 °C), with a mean monthly temperature ranging 

10 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).

11 The mean total annual liquid precipitation for the 1985 through 2014 period of record measured 

12 at the KPIA station is 35.9 in. (91.2 cm). The wettest year for the period of record is 55.35 in. 

13 (140.6 cm) in 1990 (NCDC 2015a); the driest year from the same period is 22.16 in. (56.2 cm) in 

14 1988 (NCDC 2015a). Monthly precipitation amounts tend to be evenly distributed throughout 

15 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 

16 (NCDC 2015a). The mean total annual precipitation measurements taken at LSCS’s 

17 meteorological tower for the 2010 through 2014 timeframe is 29.83 in. (75.8 cm). Average 

18 monthly precipitation ranges from a low of 0.93 in. (2.4 cm) in January to a high of 5.89 in. 

19 (14.9 cm) in June (Exelon 2015j).

20 LaSalle County, where LSCS is located, experiences severe weather events, such as 

21 tornadoes, floods, and hail. For the 1950 through 2014 period of record, the following events 

22 have been recorded (NCDC 2015b):

23 • 40 tornado events,

24 • 26 flash floods events,

25 • 131 hail events, and

26 • 4 blizzard events.

27 3.3.2 Air Quality

28 Under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.), EPA has set 

29 primary and secondary National Ambient Air Quality Standards (NAAQS) (40 CFR Part 50) for 

30 six common criteria pollutants to protect sensitive populations and the environment. Primary 

31 standards specify maximum ambient concentration levels of the criteria pollutants aimed at 

32 providing public health protection, including protecting the health of sensitive populations, such 

33 as asthmatics, children, and the elderly. Secondary standards specify maximum ambient 

34 concentration levels of the criteria pollutants aimed at providing public welfare protection, 

35 including protection against decreased visibility and damage to animals, crops, vegetation, and 

36 buildings. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen 

37 dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). Particulate matter 

38 is further categorized by size—PM10 (aerodynamic diameter of 10 micrometers (μm) or less) 

39 and PM2.5 (aerodynamic diameter of 2.5 μm or less). Table 3–3 identifies the NAAQS for the six 

40 common criteria pollutants.
Affected Environment

3-26

1 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

2 EPA designates areas of “attainment” and “nonattainment” with respect to the NAAQS. Areas 

3 that have insufficient data to determine designation status are denoted as “unclassifiable.” 

4 Areas that were once in nonattainment, but are now in attainment, are called “maintenance” 

5 areas; these areas are under a 10-year monitoring plan to maintain the attainment designation 

6 status. States have primary responsibility for ensuring attainment and maintenance of the 

7 NAAQS. Under Section 110 of the CAA and related provisions, states are to submit, for EPA 

8 approval, State Implementation Plans that provide for the timely attainment and maintenance of 

9 the NAAQS.

10 Air quality designations are generally made at the county level. For the purpose of planning and 

11 maintaining ambient air quality with respect to the NAAQS, EPA has developed air quality 

12 control regions (AQCRs), which are intrastate or interstate areas that share a common airshed 

13 (40 CFR Part 81). LSCS is located in LaSalle County, Illinois. This County, along with an 

14 additional five neighboring Counties (Bureau, Lee, Marshall, Putnam, and Stark Counties) in 

15 Illinois compose the North Central Illinois Intrastate AQCR (40 CFR 81.262). With regard to the 

16 NAAQS criteria pollutants, LaSalle County is designated as an attainment area for all NAAQS 

17 (40 CFR 81.314). The nearest designated nonattainment area is Grundy County, for the 8-hour 

18 ozone 2008 standard. The nearest designated maintenance area is Grundy County for the 

19 PM2.5 1997 standard. Grundy County is adjacent to LaSalle County, approximately 4 mi (6 km) 

20 from LSCS. Although Grundy County is adjacent to LaSalle County, it is not part of the same 

21 AQCR that LaSalle County belongs to.

22 Illinois air pollution control rules are issued under Title 35 of the IAC. Air emission sources at 

23 LSCS are regulated under a Federally Enforceable State Operating Permit (FESOP) (Permit 

24 No. 099802AAA, issued in December 2000) issued by the IEPA (IEPA 2000). A source is 
Affected Environment

3-27

1 eligible for a FESOP (also known as “synthetic minor” air permit) if the potential to emit from the 

2 source triggers CAA permit program requirements but if maximum actual emissions are below, 

3 or can be restricted to remain below, major source thresholds. LSCS’s FESOP permit was 

4 issued in December 2000, and expired in December 2005. In accordance with 35 IAC Part 201 

5 and the Illinois Environmental Protection Act of 1970 (415 Illinois Compiled Statute (ILCS) 5/39), 

6 Exelon submitted a renewal application for the FESOP permit (on July 15, 2005) to the IEPA 

7 90 days before the expiration of the permit; therefore, the conditions of the FESOP are 

8 administratively extended. On April 7, 2015, the IEPA issued a draft FESOP permit for LSCS 

9 for public review and comment (IEPA 2015).

10 Permitted sources at LSCS include five diesel-fired generators, a gasoline storage tank, and 

11 gasoline dispensing facilities. The LSCS FESOP permit limits nitrogen oxides, carbon 

12 monoxide, particulate matter, volatile organic compounds, and/or the sulfur dioxide emissions 

13 from the diesel generators and storage tank, as well as the fuel consumption of the diesel 

14 generators and gasoline of the fuel storage tank. LSCS has been in compliance with the 

15 requirements established in its FESOP permit, and there have been no reported violations in the 

16 past 5 years (Exelon 2015k; EPA 2015b). Emissions from permitted sources at LSCS are 

17 presented in Table 3–4. LSCS also has additional air emission sources that are exempt from 

18 permitting requirements, but it must still comply with applicable environmental laws and

19 regulations. These air emission sources include diesel pumps and generators that are less than 

20 600 horsepower and that are intended to be used during emergency circumstances and only 

21 operated during routine surveillance and testing (Exelon 2015j). Air emissions for LaSalle 

22 County in 2011 for carbon monoxide, nitrogen oxides, sulfur dioxide, particulate matter less than 

23 10 μm, and particulate matter less than 2.5 μm were 1,213 tons, 2,308 tons, 611 tons, 832 tons, 

24 and 483 tons, respectively (EPA 2011). LSCS permitted annual emissions are less than 

25 1 percent of the total 2011 emissions for LaSalle County. 

Table 3–4. LSCS Air Emissions (MT/year)(a) 26

Pollutant 2008 2009 2010 2011 2012 2013

CO 1.10 1.76 1.65 1.52 2.01 1.9

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 2014, 2015k

27 On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases

28 (GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 

29 (CO2e) per year in the United States (74 FR 56260). Most small facilities across all sectors of 

30 the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 

31 to EPA. On June 3, 2010, EPA issued the Prevention of Significant Deterioration (PSD) and 
Affected Environment

3-28

1 Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 2011, operating permits 

2 issued to major sources of GHGs under the PSD or Title V Federal permit programs must 

3 contain provisions requiring the use of best available control technology to limit the emissions of 

4 GHGs if those sources would be subject to PSD or Title V permitting requirements because of 

5 their non-GHG pollutant emission potentials and because their estimated GHG emissions are at 

6 least 75,000 tons per year of CO2e. As discussed above, LSCS is a synthetic minor source, 

7 and, as shown in Table 3–4, GHG emissions from sources at LSCS are below the GHG 

8 Mandatory Reporting (40 CFR Part 98) and Tailoring Rule thresholds. Section 4.15 of this SEIS

9 further discusses GHG emissions.

10 EPA issued the Regional Haze Rule (RHR) to improve and protect visibility in national parks 

11 and wilderness areas from haze, which is caused by numerous, diverse sources located across 

12 a broad region (40 CFR 51.308-309). Specifically, Subpart D of 40 CFR Part 81 lists mandatory 

13 Class I Federal Areas where visibility is an important value. The Regional Haze Rule requires 

14 states to develop State Implementation Plans to reduce visibility impairment at Class I Federal 

15 areas. The nearest Class I Federal area for visibility protection is the Mingo National Wildlife 

16 Refuge, which is approximately 306 mi (492 km) southwest of the LSCS site. EPA recommends 

17 that emission sources located within 62 mi (100 km) of a Class I area be modeled to consider 

18 adverse impacts (EPA 1992). Considering the distance to the nearest Class I area and the 

19 minor nature of air emissions from the site, there is little likelihood that ongoing activities at 

20 LSCS adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) 

21 in any of the Class I areas.

22 3.3.3 Noise

23 Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 

24 in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 

25 to a reference level equal to a normal person’s threshold of hearing. Most people barely notice 

26 a difference of 3 dB or less (FHA 2011). Another characteristic of sound is frequency or pitch. 

27 Noise may be composed of many frequencies, but the human ear does not hear very low or 

28 very high frequencies. To represent noise as closely as possible to the noise levels people 

29 experience, sounds are measured using a frequency weighting scheme known as the A scale. 

30 Sound levels measured on this A scale are given in units of A-weighted decibels (dBA). Table 

31 3–5 presents common noise sources and their respective noise levels. Noise levels can 

32 become annoying at 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 

33 10 dBA sounds twice as loud (EPA 1981).

34 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

Blender 80–90

Ambulance siren, jet plane 120

Source: CHC undated
Affected Environment

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1 Several different terms are commonly used to describe sounds that vary in intensity over time. 

2 The equivalent sound intensity level (Leq) represents the average sound intensity level over a 

3 specified interval, often 1 hour. The day-night average sound intensity level (LDN) is a single 

4 value calculated from an hourly Leq over a 24-hour period, with the addition of 10 dBA to sound 

5 levels from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 

6 nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded “n” percent of the 

7 time during a given period. For example, L90, is the sound level exceeded 90 percent of the 

8 time and is considered the background level.

There are no Federal regulations1 9 for public exposures to noise (EPA 2015c). The EPA 

10 recommends day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for 

11 outdoors in residential areas (EPA 1974). However, these are not standards. The Federal 

12 Housing Administration has established noise assessment guidelines for housing projects and 

13 finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014). 

14 Sections 25 and 27 of the Illinois Environmental Protection Act of 1970 (Chapter 415) 

15 established the authority to create noise regulations. The actual noise regulations are found in 

16 the IAC (Title 35, Subtitle H). These noise regulations have allowable octave-band sound levels 

17 according to emitting and receiving land class (Class A, B, and C) and time of day.

18 Major offsite noise sources in the vicinity of LSCS include vehicles, wind turbines, and 

19 agricultural equipment/machinery (Exelon 2015l). Common noise sources from nuclear power 

20 plant operations include transformers, loudspeakers, cooling towers, auxiliary equipment, and 

21 worker vehicles (NRC 2013). Major noise sources at LSCS include pumps, turbine building 

22 supply and exhaust fans, sirens, generators, transformers, and loudspeakers (Exelon 2015m). 

23 However, most of these noise sources are inside buildings, at approximately a 980-ft (300-m) 

24 distance from the site boundary, and/or are intermittent. The nearest resident is approximately 

25 0.7 mi (1.1 km) from the reactor buildings (Exelon 2014a). Exelon has not received any noise 

26 complaints from residents in the vicinity of LSCS (Exelon 2014a). Additional noise sensitive 

27 receptors nearby include the LaSalle Lake State Fish and Wildlife Area and Marseilles State 

28 Fish and Wildlife Area. LSCS is subject to, and in compliance with, Illinois noise pollution 

29 control regulations (Exelon 2015c, 2015m).

30 3.4 Geologic Environment

31 This section describes the current geologic environment of the LSCS site and vicinity, including 

32 landforms, geology, soils, and seismic conditions.

33 3.4.1 Physiography and Geology

34 The site is located in an area that contains glacially deposited sediments overlying a bedrock 

35 surface. These deposits formed during successive periods of glaciation. The power block and 

36 the cooling pond are located on a glacial moraine (a depositional landform directly deposited by 

37 a glacier). This area has a flat gently rolling topography. The river screen house is located 

38 north of both the power block and cooling pond on the flat-lying river valley of the Illinois River. 

39 The river valley is approximately 3.5 mi (5.6 km) north of the site and is topographically 

40 separated from the glacial moraine by the bluffs along the Illinois River. The bluffs along the 

41 Illinois River are dissected by stream valleys that cut into the glacial sediments and drain north 

 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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1 to the Illinois River. The maximum topographic relief between the site and the river is 

2 approximately 255 ft (78 m) (Exelon 2014a; USDA 2008) (Figure 3–7).

3 In the area of the power block and the cooling pond, the land is covered by a 4- to 8-ft (1.2- to 

4 2.4-m) layer of Richland Loess. The loess consists of windblown silt that has been weathered

5 to slightly clayey silt. The Richland Loess is underlain by the Wedron Silty-Clay Till. The till was 

6 directly deposited by glacial activity. It consists of unsorted silt and clay sedimentary deposits. 

7 In localized areas, the till also contains scattered, disconnected bodies of sand and gravel. In 

8 the area of the plant buildings and cooling pond, the Wedron Silty-Clay Till ranges in thickness 

9 from 120 to 140 ft (37 to 43 m). Moving north from the plant buildings and the cooling pond to 

10 the river, the Wedron Silty-Clay Till decreases in thickness until it disappears near the Illinois 

11 River (Figure 3–8) (Exelon 2014a).

12 Below the LSCS site, the Wedron Silty-Clay Till is underlain by bedrock. The topography of the 

13 bedrock reflects the surface of the land before glaciation. This topography is now buried by 

14 glacially deposited sediments. The site is located between two bedrock valleys that are filled 

15 with the Wedron Silty-Clay Till and some alluvial sand and gravel deposits from ancient streams 

16 that flowed through the bedrock valleys before they were completely buried. One alluvium-filled 

17 buried valley runs east-west and is located between the plant facility and the Illinois River Bluff, 

18 and one valley is located south of the plant facility and trends northwest and southeast 

19 (Exelon 2014a, 2014c) (Figure 3–9).

20 The underlying bedrock consists of 4,500 ft (1,371 m) of dolomite, sandstone, and shale rock. 

21 In turn, these rocks are underlain by granites and metamorphic rocks to a great depth. The 

22 Pennsylvanian aged Carbondale Formation forms the top of the bedrock surface over most of 

23 the site area. It is composed of alternating strata of shale, sandstone, clay, coal, limestone, and 

24 siltstone (Exelon 2014a).

25 LaSalle County contains a number of geologic resources of economic importance. The County 

26 is one of a handful of locations that can easily access the St. Peter Sandstone Formation. The 

27 unique characteristics of this sandstone make it valuable for a number of commercial uses, 

28 including glass, sand filters, sand molding, and abrasives. It is also in high demand for the 

29 extraction of oil and gas using conventional horizontal drilling and shale fracking techniques. 

30 LaSalle County also contains commercial deposits of gravel and limestone. Limestone and 

31 gravel are used in concrete, agricultural limestone, and road surfaces. Clay is mined in the 

32 county to manufacture bricks, drain tile, and dinnerware. Coal is no longer mined in the County 

33 but historically was mined in bluffs along the Illinois River and around Streator, Illinois 

34 (Ataner and Butler 2013; LaSalle County 2014; USDA 2008).

35 The LSCS site is underlain by coal seams, limestone beds, and the St. Peter Sandstone. 

36 However, they lie too deep beneath the land surface to be economically accessed. No oil and 

37 gas deposits have been identified beneath the site.

38 3.4.2 Soils

39 Eighty-five percent of the soil in LaSalle County is designated as prime farmland, and 9 percent 

40 is farmland of State importance (Exelon 2014a). Within the site boundary, almost all the soil is 

41 either silty loam or silty clay loam and is designated as prime farmland or farmland of State 

42 importance (Exelon 2014a; USDA 2008, 2015b).

43 Following initial construction of the facility, areas surrounding LSCS were graded to control 

44 runoff and to minimize erosion. Many areas were revegetated to support this effort

45 (Exelon 2014a).
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1 Figure 3–7. Site Physiography, LSCS Vicinity

2 Source: NRC Generated
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1 Figure 3–8. North-South Geologic Cross Section, LSCS Vicinity

2 (Elevation Exaggerated)

3 Source: Modified from Exelon 2014a
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1 Figure 3–9. Bedrock Topography and Buried Valleys, LSCS Vicinity

2 Source: Modified from Exelon 2014e
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1 3.4.3 Seismic Setting

2 The site is located in an area of Illinois that might experience slight damage from earthquakes

3 (FEMA 2015; Mid-America Earthquake Center 2009). A number of earthquakes (USGS 2013a, 

4 2013b, 2013c) have originated within Illinois, including the following:

5 • On May 26, 1909, a large earthquake knocked over many chimneys in Aurora and 

6 swayed buildings in Chicago.

7 • On July 18, 1909, an earthquake knocked down chimneys in Petersburg.

8 • On August 14, 1965, a sharp local earthquake knocked down chimneys in Elco, 

9 Unity, Olive Branch, and Olmstead.

10 • On November 9, 1968, a magnitude 5.3 earthquake was felt over the entire State of 

11 Illinois and in 22 other states.

12 Dozens of earthquakes originating outside Illinois have been felt inside the State without 

13 causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 

14 Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. Illinois can be affected by two 

15 major seismic zones, the Wabash Valley Seismic Zone and the New Madrid Seismic Zone. The 

16 Wabash Valley Zone lies between southeastern Illinois and southwestern Indiana about 322 mi 

17 (518 km) from the site. The New Madrid Seismic Zone is about 300 mi (483 km) from the site in 

18 southern Illinois, Missouri, Kentucky, and Tennessee. Of these two seismic zones, the New 

19 Madrid Seismic Zone is capable of producing very powerful earthquakes. If a large magnitude 

20 earthquake occurs in the New Madrid Seismic Zone, major damage could be experienced in 

21 southern Illinois (Missouri Department of Natural Resources 2013; USGS 2009).

22 The NRC requires every nuclear power plant to be designed for site-specific ground motions 

23 that are appropriate for its location. Nuclear power plants, including LSCS, Units 1 and 2, are 

24 designed and built to withstand site-specific ground motion based on their location and nearby 

25 earthquake activity. For LSCS, this includes earthquakes originating in either the Wabash 

26 Valley Zone or the New Madrid Seismic Zone (Exelon 2014a). The seismic design basis is 

27 established during the initial siting process using site-specific seismic hazard assessments. For 

28 each nuclear power plant site, applicants estimate a design-basis ground motion based on 

29 earthquake sources, wave propagations, and site responses; this estimate is then accounted for 

30 in the design of the plant. In this way, nuclear power plants are designed to withstand the 

31 maximum credible earthquake for a given site. Because methods of assessing seismic hazards 

32 evolve over time and the scientific understanding of earthquake hazards improve (NRC 2014c),

33 the NRC’s understanding of the seismic hazard for a given nuclear power plant may change 

34 over time. As new seismic information becomes available, the NRC evaluates the new 

35 information to determine whether changes are needed at existing plants or to NRC regulations. 

36 The NRC’s evaluation of the impact of seismic activity on a nuclear power plant is an ongoing 

37 process that is separate from the license renewal process.

38 On December 23, 2011, the Consolidated Appropriations Act (Public Law 112–074) was signed 

39 into law. Section 402 of the law directs the NRC to require reactor licensees to re-evaluate the 

40 seismic hazard at their sites against current applicable Commission requirements and 

41 thereafter, when appropriate, as determined by the Commission (NRC 2012). In 2012, the NRC 

42 required all licensees to re-evaluate the seismic hazards at their sites using updated seismic 

43 information and present-day regulatory guidance and methodologies (NRC 2012). The purpose 

44 of that request was to gather information to update the seismic hazards analysis to enable the 

45 NRC staff to determine whether individual site licenses should be modified, suspended, or 

46 revoked (NRC 2014a). On March 31, 2014, Exelon responded to this request and provided its 
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3-35

1 Seismic Hazard and Screening Report (SHSR) for LSCS (Exelon 2014d). On April 21, 2015,

2 the NRC staff issued an assessment (NRC 2015a) documenting its review of the Seismic 

3 Hazard and Screening Report. The NRC staff concluded that Exelon met the intent of the 

4 guidance for determining the re-evaluated seismic hazard and that it had provided an 

5 acceptable response to the request. In addition, the NRC staff directed Exelon to perform 

6 further seismic evaluations for NRC review.

7 3.5 Water Resources

8 3.5.1 Surface Water Resources

9 This section describes the current surface water resources within and near LSCS.

10 NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants

11 (GEIS) (NRC 2013), states that surface water encompasses all water bodies that occur above 

12 the ground surface, including rivers, streams, lakes, ponds, and man-made reservoirs or 

13 impoundments.

14 3.5.1.1 Surface Water Hydrology

15 The major surface water body in the region is the Illinois River, located approximately 4 mi 

16 (6.4 km) to the north of the LSCS main plant complex (see Figure 3–2). The LSCS site is 

17 situated within the lowermost portion of the Upper Illinois River Basin, which includes the 

10,949- mi2 (28,369-square-kilometer (km2 18 )) drainage area upstream from Ottawa, Illinois 

19 (Figure 3–10). The Illinois River is formed from the confluence of the Kankakee and Des 

20 Plaines Rivers at a point approximately 10 mi (16 km) east of Morris, Illinois. The main stem of 

21 the Illinois River is joined by the Fox River at Ottawa (Arnold et al. 1999; USGS 1998).

22 The Illinois River is also central to the Illinois Waterway, which provides for navigation from Lake 

23 Michigan to the Mississippi River and on to the Gulf of Mexico. The origins of this waterway 

24 began with the construction of canals from the lake to the Chicago and Illinois Rivers, beginning 

25 in the 1830s. Construction of the formal Illinois Waterway began in 1919 with the State of 

26 Illinois leading efforts in the upper part of the river basin and the U.S. Army Corps of Engineers

27 (USACE) in the lower part. Today, the Illinois Waterway includes part of the Chicago River, the 

28 Chicago Sanitary and Ship Canal, the Des Plaines River, and the Illinois River. Navigation is 

29 made possible by a series of eight major locks and dams and associated navigation pools along 

30 the Illinois River and its tributaries. Each pool is named for the dam downstream of each pool

31 (Exelon 2014a; Talkington 1991). Along its length, the waterway contains a navigation channel 

32 at least 9 ft (2.7 m) deep and 300 ft (91 m) wide (Talkington 1991). In the vicinity of LSCS, at 

33 normal pool elevation, the river has a depth of 12 ft (3.7 m) and a width of 800 ft (244 m)

34 (Exelon 2014a).

35 LSCS is located along the Marseilles Pool portion of the Illinois River. The Marseilles Lock and 

36 Dam at Illinois RM 247 (RKm 397.5) is approximately 2.4 mi (3.9 km) downstream of the LSCS 

37 intake and discharge structures near RM 249.5 (RKm 401.5) (see Section 3.1.3). However, the 

38 lock itself is located a further 2.5 mi (4.0 km) downstream of the dam on a bypass canal 

39 (Marseilles Canal) (USACE 2014). The Dresden Island Lock and Dam is 22 mi (35 km) 

40 upstream of the LSCS intake structure at RM 271.5 (RKm 437) (Exelon 2014a). The Marseilles 

41 Dam is 24 ft (7.3 m) high, and the Dresden Dam is 22 ft (6.7 m) high (Talkington 1991).

42 In total, the main stem of the Illinois River flows for approximately 270 mi (439 km) through 

43 Illinois and ultimately discharges into the Mississippi River at Grafton, Illinois (Exelon 2014a; 

44 USGS 1994; Talkington 1991). However, when accounting for the other components of the 

45 Illinois Waterway, the total length of the river system is 327 mi (526 km) (Talkington 1991).
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1 The U.S. Geological Survey (USGS) maintains a gaging station on the Illinois River at 

2 Marseilles, Illinois (Station 05543500) and RM 246.5 (RKm 396.7). This station is 

3 approximately 3 mi (4.8 km) downstream from the LSCS river screen house intake and nearby 

4 discharge structure near RM 249.4 (RKm 401). The gaging station is also 0.5 mi (0.8 km) 

5 downstream of the Marseilles Dam and 6.9 mi (11 km) upstream from the confluence of the Fox 

6 River with the main stem of the Illinois River (Exelon 2014a; USGS 1999b, USGS 2015). 

7 The mean annual discharge measured at the USGS gage at Marseilles for water years 1920 

through 2014 is 10,750 cfs (304 m3 8 /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 9 /s) for the 

10 period of record (USGS 2015). The 90 percent exceedance flow is an indicator value of 

11 hydrologic drought. It signifies a rate of streamflow that is equaled or exceeded 90 percent of 

12 the time, as compared to the average flow for the period of record. Based on average monthly 

13 flow over the period of record at the station, November is the low-flow month, and April is the 

14 high-flow month for the Marseilles Pool (USGS 2015).

15 Tributaries to the Illinois River in the immediate vicinity of LSCS include South Kickapoo Creek, 

16 Spring Brook, Deadly Run, Armstrong Run, and Hog Run (Figure 3–11). These headwater 

17 streams and manmade ditches drain the glacial upland on which LSCS is located and generally 

18 flow north toward the dissected bluffs of the river and across the river valley and into the Illinois 

19 River. The most extensive of these nearby tributaries is South Kickapoo Creek. With its 

20 headwaters on the northwest side of the LSCS property, this stream receives stormwater runoff,

21 cooling pond dike seepage collected by the LSCS perimeter drainage ditch, and overflow from 

22 the cooling pond auxiliary spillway (see Figures 3–3 and 3–5). The main channel of South 

23 Kickapoo Creek flows north to northwest from LSCS, with the main channel discharging to the 

24 Illinois River at a point approximately 3.5 mi (5.6 km) northwest of the LSCS cooling pond and 

25 approximately 0.4 mi (0.6 km) downstream of the LSCS blowdown discharge structure 

26 (Exelon 2014a).

27 On the northeast perimeter of the cooling pond is Armstrong Run. Armstrong Run previously 

28 drained much of the area that is now occupied by LSCS before plant construction. Like many of 

29 the manmade drainage channels (called “runs”) in the region, it was constructed to convey 

30 drainage collected by agricultural drain tile systems (NRC 1978). Armstrong Run now receives 

31 runoff and seepage collected from the northeast end of the peripheral dike drainage ditch. 

32 It discharges to the Illinois River at a point approximately 3.2 RM (5.1 RKm) northeast of the 

33 cooling pond and about 4.5 RM (7.2 RKm) upstream of the river screen house (Exelon 2014a).

34 As further described in Section 3.1.3, the dominant surface water feature within the LSCS site 

35 and vicinity is the 2,058- ac (833- ha) cooling pond (Figure 3–5). Other surface water features 

36 on the LSCS plant site include two stormwater management ponds (North and South Storm 

37 Water Ponds), two sewage treatment lagoons, and a collection of hatchery ponds as 

38 summarized below. The NRC staff visited the facilities cited herein during the May 2015 

39 environmental site audit (NRC 2015b).

40 The North and South Storm Water Ponds are located west of the LSCS main plant complex and 

41 receive stormwater runoff from the protected area, serving the north and south zones of the 

42 plant, respectively. Within the site, a system of ditches, storm drains, culverts, and underground 

43 storm sewers collect runoff and drainage from the protected area and convey much of it to 

44 either of the two ponds. Uncontaminated runoff from the north zone of the plant is conveyed to 

45 the North Storm Water Pond, with some runoff sources first passing through the Unit 2 oil-water

46 separator. A portion of the switchyard also drains toward the north zone, although most of the 

47 switchyard drains east to the cooling pond.
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1 Figure 3–10. The Upper Illinois River Basin and Drainage Basin Boundaries

2 Source: Modified from Arnold et al. 1999
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1 Figure 3–11. LSCS Surface Water and Related Water Resource Features

2 Source: Modified from Exelon 2014a, 2015b
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1 Most runoff from the south zone enters the smaller South Storm Water Pond; this pond then 

2 discharges to the cooling pond discharge canal through internal Outfall H01. Before entering 

3 the pond, some flows first pass through the Unit 1 oil-water separator. The south pond also 

4 receives runoff from the firing range. Areas of the plant site to the northwest and south of the 

5 developed plant complex do not drain to the ponds but instead are drained by existing surface 

6 stream segments and ditches (Exelon 2014a, 2014c).

7 Stormwater management and pollution control at LSCS is subject to Exelon’s Storm Water 

8 Pollution Prevention Plan (SWPPP) (Exelon 2013e), which Exelon has implemented in 

9 accordance with Special Condition 8 of the site’s NPDES permit (IEPA 2013). The SWPPP 

10 applies to industrial stormwater runoff from the site, which is not otherwise process-related and 

11 not captured and processed by LSCS’s wastewater treatment facilities. It describes the best 

12 management practices, controls, inspection, and monitoring requirements, and the associated 

13 implementing procedures and personnel responsibilities for reducing pollutants in stormwater 

14 discharge and for ensuring compliance with the terms and conditions of the site NPDES permit 

15 (Exelon 2013e).

16 Two open sewage treatment lagoons provide primary and secondary treatment for LSCS’s

17 sanitary effluent. These lagoons are geotextile-lined impoundments and are located to the north 

18 of the main plant complex adjacent to LSCS’s sewage treatment plant (as shown in 

19 Figure 3–3). Together, the NRC staff estimates the two impoundments cover an area of about 

20 1.6 ac (0.65 ha). After filtration and final disinfection in the sewage treatment plant, the final 

21 effluent from the treatment system is discharged into the cooling pond via NPDES internal 

22 Outfall B01 (Exelon 2014a, 2014c).

23 A cluster of 16 small fish-rearing ponds is located on the southwest shore of the cooling pond 

24 (see Figures 3–3 and 3–5). The NRC staff estimates that the ponds total approximately 29 ac 

25 (12 ha) of open water. These ponds comprise the LaSalle Fish Hatchery operated by the IDNR

26 on plant property and subject to a lease agreement with Exelon. The hatchery uses the cooling 

27 pond as a makeup water source. Runoff and drainage from the hatchery ponds flow back to the 

28 cooling pond and are ultimately subject to LSCS’s NPDES permit provisions 

29 (Exelon 2014a, 2014c). The LSCS site’s NPDES permit is further discussed in Section 3.5.1.3.

30 LSCS is not susceptible to riverine flooding because it is located upland and away from the 

31 Illinois River.

32 The grade elevation at the plant site is 710 ft (216 m) above MSL, and the floor elevation of the 

33 LSCS facilities is 710.5 ft (217 m) above MSL. The plant floor lies at an elevation that is 188 ft 

34 (57 m) above the level of a postulated probable maximum flood on the Illinois River 

35 (Exelon 2014a, 2014g). Although the river screen house is not a safety-related structure, it is 

36 designed to withstand the 100-year flood on the Illinois River. Its loss would not impact the 

37 ability to safely shut down the plant as water could still be drawn from the cooling pond and from 

38 the UHS portion of the cooling pond, as described in Section 3.1.3 of the SEIS (Exelon 2014a, 

39 2014g).

40 Furthermore, a failure of the peripheral dike system enclosing the cooling pond would not flood 

41 the power plant area because the onsite topography would cause cooling pond water to flow 

42 north and away from the plant following the existing drainage network (Exelon 2014a, 2014g).

43 3.5.1.2 Surface Water Use

44 LSCS withdraws surface water from the Illinois River as makeup water for the plant’s cooling 

45 pond. The cooling pond provides water for the plant’s circulating water, service water, and 

46 essential cooling water systems. Cooling tower blowdown and other permitted effluent streams 

47 are discharged back to the Illinois River via the plant’s primary NPDES outfall (Outfall 001) at a 
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1 point located about 900 ft (270 m) downstream from LSCS’s river intake structure and 

2 associated river screen house.

3 The maximum (nominal) surface water withdrawal rate for LSCS, Units 1 and 2, is 90,000 gpm 

(200 cfs or 5.66 m3 4 /s). This is equivalent to 129.6 million gallons per day (mgd) 

(491,000 m3 5 /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 6 /s) or 86.4 mgd 

(327,000 m3 7 /day). This rate assumes a two-pump operation with valves open at 100 percent. 

8 The third makeup pump located in the river screen house normally serves as a backup

9 (see Section 3.1.3).

10 The NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that document 

11 the volume of surface water withdrawn from, and discharged back to, the Illinois River during 

12 the period 2009 to 2013 (Table 3–6). Based on these data, LSCS surface water withdrawals 

13 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 14 /s or

15 67.8 mgd). Return discharges (blowdown) to the Illinois River have averaged 13,046 mgy 

(49.4 million m3 16 /yr), which is equivalent to an average discharge rate of about 55.3 cfs 

(1.56 m3 17 /s or 35.7 mgd). The difference between withdraw and discharge (i.e., approximately 

49.7 cfs (1.40 m3 18 /s)) generally reflects process consumptive use or other losses, evaporative 

19 losses, and presumably seepage from the cooling pond. In total, these data indicate a 

20 consumptive use rate averaging 47 percent.

21 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, 2014d

22 LSCS’s surface water withdrawals and consumptive water use are not subject to any water 

23 allocation or related permitting requirements at the present time. In 2006, the Governor of 

24 Illinois issued an executive order establishing a Statewide program for State and regional water 

25 supply planning and management, which included the development and approval of regional 

26 plans in designated Priority Water Quantity Planning Areas (State of Illinois 2006). LaSalle 

27 County, where LSCS is located, is not included within any of the three designated planning 

28 areas (Exelon 2014a; ISWS 2015a). Nevertheless, as referenced above, Exelon reports its 

29 surface water withdrawals to the State of Illinois under the State Illinois Water Inventory 

30 Program (Exelon 2014a; ISWS 2015b). Reporting is required in accordance with the Illinois 

31 Water Use Act of 1983 (525 ILCS 45) and its 2010 amendments. The general purpose and 

32 intent of the Act is “to establish a means of reviewing potential water conflicts before damage to 
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1 any person is incurred and to establish a rule for mitigating water shortage conflicts.” The 

2 2010 amendments to the Illinois Water Use Act added high-capacity intakes as subject to the 

3 Act’s water use reporting provisions. Such intakes are surface water intakes on a property in 

4 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 5 ) during any 24-hour period (525 ILCS 45).

6 Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 

7 cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 

8 Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 

9 and associated procedures to mitigate the impacts of summer drought and/or high river 

10 temperature and river low-flow conditions. Depending on predefined conditions set forth in the 

11 plan and implementing procedures, such actions may include a combination of monitoring and 

12 modeling of river intake and mixing zone temperatures; manipulation of the water level of the 

13 cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 

14 cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the TS

15 limits on condenser inlet temperature from the cooling pond (Exelon 2014a, 2015c).

16 Two other industrial facilities withdraw water from the Marseilles Pool of the Illinois River in the 

17 vicinity of LSCS (Figure 3–5) and are listed in the Illinois Water Inventory Program. These are 

18 Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. The volume of water withdrawn 

19 by these commercial facilities is not publicly available (Exelon 2014a). Because they are 

20 included in the State’s inventory, the NRC staff presumes that each facility withdraws in excess 

of 100,000 gpd (380 m3 21 ). Both are also currently subject to NPDES individual permits 

22 (i.e., Permits IL0001708 and IL0036463). Based on reported return discharges to the Illinois 

23 River, it is estimated that Agrium’s surface water withdrawals are on the order of 5 mgd 

(18,900 m3 24 ) (EPA 2015a).

25 The public water supply systems in the vicinity of LSCS (i.e., the city of Marseilles and the 

26 village of Seneca) do not withdraw water from the Illinois River but instead rely upon 

27 groundwater-supplied systems (Exelon 2014a) (see Section 3.5.2.2).

28 Surface water withdrawals within the Marseilles Pool have shown no significant effects on water 

29 availability to date (Exelon 2014a).

30 3.5.1.3 Surface Water Quality and Effluents

31 The Illinois Pollution Control Board (IPCB), a sister agency to the IEPA, promulgates water 

32 quality standards in the State. Two Sections of Title 35 of the IAC (35 IAC 302 and 35 IAC 303) 

33 contain the standards applicable to lakes and streams. Procedures that must be followed in 

34 using water quality standards to set NPDES permit limits appear in Section 309 (35 IAC 309).

35 Designated uses prescribed by 35 IAC 303 are those uses specified in water quality standards 

36 for each lake, river, stream, and groundwater resource. In designating uses for a waterbody, 

37 the IPCB considers the use and value of the waterbody for public water supply; propagation of 

38 fish, shellfish, and wildlife; and recreational, agricultural, industrial, and navigational purposes.

39 The main stem of the Illinois River is designated a “general use water” by the IPCB. Waters in 

40 the general use category must meet water quality standards protective of aquatic life, wildlife, 

41 agricultural use, and secondary contact use, as well as most industrial uses and aesthetic

42 quality (35 IAC 303.201). These standards pertain to pH; phosphorus; dissolved oxygen;

43 radioactivity (gross beta, strontium-90, and radium-226 and -228); various chemical constituents 

44 (metals and organic compounds); fecal coliform; and other toxic substances. In addition, a 

45 segment of the main stem of the Illinois River within LaSalle and Grundy Counties, and 

46 encompassing the entire Marseilles Pool on which LSCS is located, is afforded “enhanced 

47 dissolved oxygen protection.” Dissolved oxygen levels must be not less than 5.0 milligrams per 
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1 liter at any time during March through July and not less than 4.0 milligrams per liter at any time 

2 during August through February (35 IAC 302.206).

3 Over the last 150 years, water quality within the whole of the Illinois River Basin has historically 

4 suffered from rapid population growth; urbanization; and industrial development, including the 

5 conversion of prairie, wetlands, and forests. This change resulted in the discharge of untreated 

6 and inadequately treated sewage, the discharge of industrial pollutants and refuse, runoff of 

7 agricultural chemicals and sediments, and the alteration of the natural river hydrology due to 

8 navigation and flood control projects (Exelon 2014a; Talkington 1991).

9 Over the last 50 years, substantial improvements in water quality have occurred because of

10 municipal and industrial waste treatment and management efforts to address both point and 

11 nonpoint pollutant sources. Ongoing water quality concerns within the upper Illinois River Basin 

12 include the atmospheric deposition of pesticides and trace metals; endocrine disrupting 

13 compounds in surface and groundwater; nutrient enrichment of surface and groundwater; the 

14 transport and fate of pesticides, trace elements, and volatile organic compounds in surface and 

15 ground water; and the effects of urbanization on biodiversity, habitat, and water quality 

16 (USGS 1998).

17 Section 303(d) of the Federal Water Pollution Control Act (i.e., Clean Water Act of 1977, as 

18 amended (CWA) (33 U.S.C. 1251 et seq.)) requires the State of Illinois and other states to 

19 identify all “impaired” waters for which effluent limitations and pollution control activities are not 

20 sufficient to attain water quality standards in such waters. The Section 303(d) list includes those 

21 water quality-limited stream segments that require the development of total maximum daily 

22 loads (TMDLs) to ensure future compliance with water quality standards. The TMDLs specify 

23 the maximum amount of a pollutant that a waterbody can receive and still meet water quality 

24 standards. Once established, TMDLs are typically implemented through watershed-based 

25 programs administered by the State, primarily through the NPDES permit program and 

26 associated point and nonpoint source water quality improvement plans and associated best 

27 management practices. The IEPA has classified a 30.1-mi- (48.4-km)-long segment (IL_D-23) 

28 of the Illinois River between Morris and Ottawa, Illinois, that includes the LSCS site as impaired. 

29 This segment is listed as impaired because it does not meet designated uses for fish 

30 consumption due to polychlorinated biphenyls (PCBs) and mercury contamination. It is also 

31 impaired for primary contact recreation use due to fecal coliform bacteria (IEPA 2014b). Special 

32 Condition 13 of the NPDES permit for LSCS prohibits the discharge of PCBs in plant effluents 

33 (IEPA 2013). The river segment is classified as fully supporting its designated use for aquatic 

34 life. IEPA has assigned a medium priority for the development of TMDLs for segment IL_D-23

35 (IEPA 2014b).

36 As for other streams and runs in the vicinity of LSCS, IEPA (2014b) designates them as 

37 Category 3, which are waters for which no use-support determination can be made due to 

38 insufficient available data and/or information.

39 The LSCS cooling pond is included in the IEPA’s CWA Section 314 inventory of lakes and has 

40 also been designated as Category 3 (IEPA 2014b). However, LSCS’s cooling pond is defined 

41 by the State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 

42 definition, the cooling pond is not waters of the State under 35 IAC 301.440. Likewise, as 

43 defined in 40 CFR 230.3, pursuant to the Federal CWA, “waste treatment systems, including 

44 treatment ponds or lagoons designed to meet the requirements of the Clean Water Act” are 

45 explicitly excluded from the definition of “waters of the United States.” Therefore, the cooling 

46 pond is not subject to State or Federal water quality standards.

47 To operate a nuclear power plant, licensees must comply with the CWA, including associated 

48 requirements imposed by EPA or the state as part of the NPDES permitting system under
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1 Section 402 of the CWA, as well as state water quality certification requirements under 

2 Section 401 of the CWA. The EPA or the state, not the NRC, sets the limits for effluents and 

3 operational parameters in plant-specific NPDES permits. Nuclear power plants cannot operate 

4 without a valid NPDES permit and a current CWA Section 401 Water Quality Certification. The

5 EPA has delegated responsibility to the State of Illinois for the administration of the NPDES 

6 program in Illinois. NPDES permits are issued by the IEPA on a 5-year cycle.

7 LSCS is authorized to discharge various wastewater (effluent) streams, including cooling pond 

8 blowdown and stormwater under NPDES Permit IL0048151, reissued on July 5, 2013; the 

9 current permit expires on July 31, 2018 (Exelon 2014a; IEPA 2013). The permit specifies the 

10 discharge standards and monitoring requirements for effluent chemical and thermal quality 

11 through the plant’s outfalls to the Illinois River, as summarized in Figure 3–7. The location of 

12 the LSCS’s primary outfall (001) to the Illinois River is shown in Figure 3–5.

13 Table 3–7. National Pollutant Discharge Elimination

14 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

I01(b,f,g) Intermittent Reverse Osmosis System Reject Water and Greensand Filter 

Backwash
Affected Environment

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Outfall

Average Flow 

Rate (mgd)(a) Description

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

1 As indicated in Table 3–7, the NPDES permit for LSCS requires Exelon to monitor and sample 

2 site effluents for various parameters in accordance with applicable effluent limits. Monitoring 

3 results are reported in monthly Discharge Monitoring Reports (DMRs) submitted to the State. 

4 The NRC staff reviewed the DMRs submitted by Exelon to the IEPA for the period 2010 through 

5 2014. This review encompassed the results of recorded maximum cooling pond blowdown 

6 temperatures to the Illinois River and associated calculations of river mixing zone temperatures 

7 as reported in the DMRs for the past 5 years (2010 through 2014) and as compiled by Exelon 

8 (Exelon 2015c). Based on the NRC’s staff review and Exelon’s responses to the NRC’s 

9 requests for additional information, LSCS has received no notices of violation associated with 

10 NPDES permitted discharges during the 2010 through 2014 time period. Nonetheless, Exelon 

11 recorded several unusual occurrences in its DMR reports. These included reports of a makeup 

12 pipeline line failure on January 29, 2010; a blowdown line failure on July 13, 2012; a makeup 

13 pipeline line failure on January 25, 2013; a blowdown line air release valve failure on 
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3-45

1 February 8, 2013; a makeup pipeline failure on May 21, 2013; and a makeup pipeline failure on 

2 January 23, 2014 (Exelon 2015c).

3 The DMR submittals also document actions taken to comply with provisional variances granted 

4 by the IEPA to Exelon with respect to LSCS’s effluent discharges to the Illinois River and 

5 associated river mixing zone temperature limits. Specifically, these variances 

6 (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 

7 March, July, and August 2012, respectively, due to unusual weather conditions and associated 

8 high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 

9 meet the requirements of Special Condition 3 of LSCS’s NPDES permit. This limits the number 

10 of temperature excursion hours to 1 percent (87.6 hours) of the hours in a 12-month period,

11 ending with any month (see footnote d in Table 3–7). During the variance period(s), Exelon was 

12 required, in part, to continuously monitor both the discharge and receiving water temperatures 

13 and visually inspect all discharge areas at least three times each day to assess the impact on 

14 aquatic life. These thermal discharge excursions were not found to have any impact on aquatic 

15 life (Exelon 2015c).

16 An applicant (in this case, Exelon) for a Federal license to conduct activities that may cause a 

17 discharge of regulated pollutants into navigable waters of the United States is required by 

18 Section 401 of the CWA to provide the licensing agency (in this case, the NRC) with water 

19 quality certification from the state (in this case, the State of Illinois). This certification implies 

20 that discharges from the project or facility to be licensed will comply with CWA requirements and 

21 will not cause or contribute to a violation of state water quality standards. If the applicant has 

22 not received Section 401 certification, the NRC cannot issue a renewed license unless that state 

23 has waived the requirement. The NRC recognizes that some NPDES-delegated states explicitly 

24 integrate their 401 certification process with NPDES permit issuance. However, LSCS’s 

25 NPDES permit does not explicitly convey water quality certification under CWA Section 401.

26 By letter dated February 4, 2014, Exelon submitted an application to the IEPA Bureau of Water

27 that requested certification from the IEPA that renewal of Exelon’s NRC operating licenses for 

28 LSCS would not violate State water quality standards (Exelon 2014h). The IEPA Division of 

29 Water Pollution Control issued a letter to the NRC, and copied Exelon, which provides

30 Section 401 water quality certification for renewal of the operating licenses for LSCS. The 

31 certification was issued with the condition that Exelon shall be responsible for obtaining NPDES

32 permits required for wastewater or stormwater discharges to waters of the State (IEPA 2014c). 

33 As previously stated in this section, NRC licensees must comply with the CWA, including 

34 associated requirements imposed by EPA or the state, as part of the NPDES permitting system 

35 under CWA Section 402. The NRC staff concludes that the IEPA’s response provides the 

36 necessary certification pursuant to CWA Section 401.

37 To maintain LSCS’s surface water intake system on Marseilles Pool of the Illinois River, Exelon

38 conducts occasional maintenance dredging at the river screen house (Exelon 2014a). The 

39 need for maintenance dredging at the river screen house forebay is periodically evaluated in 

40 accordance with an Exelon operating procedure. Currently, needed dredging is conducted 

41 under a USACE Section 10 permit, which is issued pursuant to the Rivers and Harbors 

42 Appropriation Act of 1899 (33 U.S.C. 403) (USACE 2006). Dredging was most recently 

43 conducted in October 2013 in compliance with the provisions of the permit. Less than 100 cubic 

yards (76 m3 44 ) of sediment was removed, and the material was dewatered and placed out of the 

45 floodplain near the screen house. Future maintenance dredging will be conducted as needed 

46 and with the necessary permits. Exelon does not expect to perform any dredging in the vicinity 

47 of the LSCS discharge channel during the license renewal term and does not anticipate the 

48 need to conduct any fill activities (Exelon 2015c).
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1 3.5.2 Groundwater Resources

2 This section describes the current groundwater resources at the LSCS site and in the vicinity.

3 3.5.2.1 Site Description and Hydrogeology

4 The site is characterized by five hydrogeologic units. By increasing depth, they are as follows:

5 • the Alluvial Aquifer,

6 • the Glacial Drift Aquitard,

7 • the Buried Bedrock Valley Aquifers,

8 • the Pennsylvanian Aquitard, and

9 • the Cambrian-Ordovician Aquifer System.

10 The hydrogeologic characteristics of these units are summarized in Figure 3–12. 

11 Alluvial (stream) deposits are found beneath, and extend along each side of, the Illinois River. 

12 These deposits form the Alluvial Aquifer that lays on top of the bedrock (the Pennsylvanian 

13 Aquitard) (Figure 3–8). The river functions as a hydrologic boundary, which prevents 

14 groundwater within the Alluvial Aquifer from flowing from one side of the river to the other. The 

15 Alluvial Aquifer is generally 2 to 4 ft (0.6 to 1.2 m) thick, is located in the vicinity of the river 

16 screen house, and ranges from 3,500 to 4,800 ft (1,067 to 1,463 m) in width. Yields in the 

17 Alluvial Aquifer are restricted by the limited areal extent and thickness of the sand and gravel 

18 deposits that make up the aquifer. Small dependable yields suitable for domestic purposes are 

19 only locally available. The aquifer receives recharge primarily by precipitation and from the 

20 river. Well yields from the Alluvial Aquifer in the vicinity of the river screen house are most likely 

21 adequate only for domestic use (Exelon 2014a).

22 The Glacial Drift Aquitard is made up of the Richland Loess and the Wedron Silty-Clay Till 

23 (see Section 3.4.1). The aquitard largely consists of silty-clay till (unsorted sediment containing 

24 a range of grain sizes) with very low permeability. In the area of the plant buildings, the Glacial 

25 Drift Aquitard is over 200 ft (61 m) thick (CRA 2006). Any extractable groundwater in this 

26 aquitard is produced from thin discontinuous sand and gravel pockets that are recharged by the 

27 slow infiltration of precipitation through the silty-clay till. The volume of groundwater produced 

28 from these pockets is limited so that it is primarily used as a source of water for domestic or 

29 farm activities (Exelon 2014a).

30 As discussed in Section 3.4.1, the site is located between two buried bedrock valleys that 

31 contain alluvial deposits of sandy gravels and gravelly sands with lesser amounts of silt and clay 

32 in scattered thin layers. These alluvial deposits are overlain and merge with the Wedron 

33 Silty-Clay Till. They are recharged by the slow infiltration of precipitation through the thick 

34 overlying Glacial Drift Aquitard. Therefore, the volume of groundwater that can be produced 

35 from the Buried Bedrock Valley Aquifers is limited to supplying water for domestic or farm 

36 activities (Exelon 2014a).

37 The Pennsylvanian Aquitard forms the bedrock. It consists of alternating beds of shale, 

38 siltstone, underclay, sandstone, limestone, coal, and many gradational layers. Low permeability

39 shale and siltstone comprise more than 90 percent of the aquitard. In the area of the plant 

40 buildings, the Pennsylvanian Aquitard is approximately 176 ft (54 m) thick. Groundwater in the 

41 aquitard occurs under artesian conditions. Wells finished in the aquitard get water primarily 

42 from thin sandstone and limestone beds within the aquitard, which are recharged by seepage 

43 through the overlying shales and through the silty-clay till of the Glacial Drift Aquitard. In 

44 general, the sandstone and limestone beds within the aquitard can only supply enough water for 
Affected Environment

3-47

1 domestic or farm use because well yields are commonly less than 36 L/min (10 gpm) 

2 (Exelon 2014a).

3 Figure 3–12. LSCS Site Hydrogeologic Units

4 Source: Modified from Exelon 2014a
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1 The Pennsylvanian Aquitard is underlain by the Cambrian-Ordovician Aquifer, which is an 

2 important aquifer in the region. Beneath the site, this aquifer is composed of the following strata 

3 (listed from shallowest to deepest):

4 • Platteville Group,

5 • Glenwood—St. Peter Sandstone,

6 • Potosi Dolomite,

7 • Franconia Formation,

8 • Ironton Sandstone, and

9 • Galesville Sandstone.

10 At the site, the Cambrian-Ordovician Aquifer is approximately 1,090 ft (469 m) thick. Although 

11 numerous alternating layers of sandstones, limestone, and dolomites impart a heterogeneous 

12 character to the system, these units are hydraulically connected and behave as a single aquifer 

13 (Exelon 2014a). The Cambrian-Ordovician Aquifer is the most important supplier of public 

14 water in the region.

15 The Cambrian-Ordovician Aquifer is underlain by 450 ft (137 m) of the Eau Claire Formation 

16 Aquitard, which is underlain by 2,500 ft (762 m) of the Mt. Simon Aquifer. The Mt. Simon 

17 Aquifer is underlain by granitic and metamorphic rock.

18 In addition to the hydrogeologic units previously described, the plant area is directly underlain by 

19 engineered granular fill that has been placed on top of the Wedron Silty-Clay Till. The 

20 engineered granular fill underlies and surrounds the plant buildings and structures. It is 

21 composed of sand and gravel and silty clay and contains groundwater that is recharged by local 

22 precipitation. Because the underlying Wedron Silty-Clay Till has a very low permeability, 

23 groundwater in the granular fill flows laterally eastward until it discharges into the intake canal, 

24 or it flows laterally and discharges to the stormwater ponds and the discharge canal to the west 

25 (CRA 2006) (Figures 3–12 and 3–13).

26 3.5.2.2 Groundwater Use

27 LaSalle County has an adequate supply of groundwater to meet current needs for industrial, 

28 municipal, and domestic purposes. Regionally, the most abundant groundwater supplies are 

29 obtained from the Cambrian-Ordovician Aquifer (LaSalle County 2014).

30 At the site, water for potable usage is obtained from two cased onsite wells completed into the 

31 Cambrian-Ordovician Aquifer. These wells were installed in 1972 and 1974 in the area of the 

32 plant buildings. They were drilled to a depth of 1,620 and 1,629 ft (494 and 496 m) and cased 

33 to a depth of 921 and 989 ft (281 and 301 m) (Exelon 2014a, 2014f; ISGS 2015). Together the 

34 two wells withdraw groundwater at an average rate of 26.1 gpm (98.7 L/min) (Exelon 2014a). 
Affected Environment

3-49

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

2 Source: Modified from Exelon 2014a
Affected Environment

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1 Figure 3–14. LSCS Hydrogeologic Cross-Section

2 (Elevation Exaggerated)

3 Source: Modified from CRA 2006
Affected Environment

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1 Within 10 mi (16 km) of the LSCS site, almost all water used for public water supplies is 

2 obtained from the Cambrian-Ordovician Aquifer. However, the Village of Ransom withdraws

3 water from both the Cambrian-Ordovician Aquifer and from permeable zones in the 

4 Pennsylvanian Aquitard, and the Village of Grand Ridge obtains water from the Buried Bedrock 

5 Valley Aquifers. People in small communities within 10 mi (16 km) of the LSCS site that are not 

6 served by a public water supply system obtain water from individual wells in the glacial drift, the 

7 Pennsylvanian strata, or the upper portion of the Cambrian-Ordovician Aquifer (Exelon 2014a).

8 3.5.2.3 Groundwater Quality

9 In general, the quality of groundwater in the Alluvial Aquifer, the Glacial Drift Aquitard, the 

10 Buried Bedrock Valley Aquifers, the Pennsylvanian Aquitard, and the Cambrian-Ordovician 

11 Aquifer is suitable for public use and consumption. A search of Illinois State Geological Survey 

12 water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant 

13 buildings. With the exception of one well completed in the Pennsylvanian Aquitard, all these 

14 wells withdraw water from the Cambrian-Ordovician Aquifer (ISGS 2015).

15 In 1985, a condensate line broke in the area east-southeast of the LSCS reactor building. 

16 Tritium was detected near the broken line in groundwater near the surface. The line was 

17 repaired soon after it broke. In 1986, the highest tritium concentrations detected in the 

18 groundwater was approximately 11,000 picocuries per liter (pCi/L). Tritium concentrations in the 

19 groundwater near the broken line have declined to the point that, since 2007, tritium 

20 concentrations in the groundwater have been below the lower limit of detection (Exelon 2014a; 

21 Exelon Nuclear 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015).

22 In September 2001, a spill of water from a recycled condensate storage tank resulted in tritium

23 contamination into groundwater near the land surface. Tritium concentrations in the 

24 groundwater ranged from 766 to 1,280 pCi/L in 2006 (Exelon 2014a; Exelon Nuclear 2007). 

25 These concentrations are well below the EPA Maximum Contaminant Level for tritium of 

26 20,000 pCi/L. In 2014, tritium concentrations in the groundwater had further decreased below 

27 the lower limit of detection (Exelon Nuclear 2015).

28 Another leak from a recycled condensate tank was identified in 2010. The tank is located near 

29 the plant buildings and is underlain by 10 ft (3 m) of engineered granular fill. In turn, the fill is 

30 underlain by the Wedron Silty-Clay Till. Soon after the leak was detected, the tank was drained 

31 and repaired. The leak contaminated groundwater in engineered granular fill with condensate 

32 water that contained tritium. Contamination in the engineered granular fill is being addressed 

33 through natural monitored attenuation and by active remediation. Exelon is pumping 

34 contaminated groundwater from both a well and a French drain installed in the engineered 

35 granular fill and then discharging the recovered water into the cooling pond where it is greatly 

36 diluted to below the lower limit of detection (Exelon 2014a). Exelon has been monitoring the 

37 cleanup of the engineered granular fill using monitor wells. In June 2015, samples from all of

38 the monitor wells recorded tritium concentrations below the EPA Maximum Contaminant Level 

39 for tritium of 20,000 pCi/L (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015; Exelon 2015a, 

40 2015c). Although the engineered granular fill has been contaminated with tritium and is being 

41 cleaned up, it is not an aquifer. No aquifers are known to have been contaminated by 

42 inadvertent releases of radionuclides to groundwater.

43 One “nonradiological” release to groundwater occurred in 1999 when an oil tank was discovered 

44 to have leaked. The spill was remediated, and on February 9, 2005, IEPA issued a letter of “No 

45 Further Remediation” for the cleanup activities (Exelon 2014a).
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1 3.6 Terrestrial Resources

2 3.6.1 LSCS Ecoregion

3 LSCS lies within the Illinois/Indiana Prairies Level IV Ecoregion. This ecoregion encompasses 

19,557 mi2 (50,652 km2 4 ) in eastern and central Illinois and western Indiana (Woods et al. 2006). 

5 It is composed of vast glaciated, flat to rolling plains with terminal and recessional moraines, 

6 prairie potholes, and old lake beds. Historically, tallgrass prairie covered the majority of the land 

7 surface. Oak-hickory forests were common on moraines and floodplains, and marshes and wet 

8 prairies occurred in poorly drained areas. Beginning in the 19th century, agricultural land began 

9 to replace the natural vegetation, and it is now the dominant land type (Woods et al. 2006). 

10 Prairie remnants lack many natural ecosystem functions due to their small size, and areas of 

11 prairie restoration often lack forbs (broad-leaved herbs other than grass) or are overly 

12 dominated by big bluestem (Andropogon gerardii) (a grass) or Indiangrass (Sorghastrum 

13 nutans) (IDNR 2005). Historically, forests were dominated by oak (Quercus spp.), hickory 

14 (Carya spp.), elm (Ulmus spp.), ash (Fraxinus spp.), beech (Fagus spp.), and maple (Acer spp.) 

15 species (CEC 2008). Remaining forests are highly fragmented and are experiencing species 

16 composition shifts to sugar maple (A. saccharum) and other mesophytic species (IDNR 2005). 

17 This shift is in part due to fire suppression, which has favored species that do not rely on 

18 periodic fires as part of their life cycle (IDNR 2005). Many wetland areas have been drained for 

19 row crops, and agriculture now accounts for over 75 percent of land use within this ecoregion 

20 (IDNR 2005).

21 Table 3–8 lists representative wildlife for this ecoregion, as well as species that the Illinois 

22 Department of Natural Resources (IDNR) considers to be “critical” to the conservation and 

23 restoration of the region’s native habitats; species that are indicative of ecosystem health 

24 (known as “indicator species”); and species that are native to the region, but are now extirpated 

25 or imperiled.

26 The IDNR maintains the Illinois Wildlife Action Plan (IDNR 2005), which addresses native 

27 habitat and species decline and contains a statewide conservation plan.

28 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)
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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)

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

1 3.6.2 LSCS Site Surveys, Studies, and Reports

2 A number of vegetation and wildlife surveys have been conducted on the LSCS site beginning 

3 with baseline surveys prior to LSCS construction in the early 1970s. This section summarizes 

4 these surveys in chronological order.

5 Baseline Terrestrial Surveys (1971–1972)

6 In July and December 1971, and April, July, and October 1972, baseline ecological studies were 

7 conducted at the LSCS site. The 1971 studies were primarily qualitative, and the 1972 studies 

8 gathered quantitative data on vegetation, mammals, birds, reptiles, and invertebrates present on 

9 the LSCS site. The ER for operation of LSCS (ComEd 1977) describes these studies and the 

10 associated results in detail.

11 Final Environmental Statement for Construction (1973)

12 In February 1973, the U.S. Atomic Energy Commission (AEC), the NRC’s predecessor agency, 

13 issued a Final Environmental Statement that evaluated the construction of LSCS (FES-C) 

14 (AEC 1973). Although no specific studies were conducted to support the preparation of the 
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1 FES-C, the report briefly summarizes the terrestrial wildlife and habitats on the site, including 

2 those that were altered or destroyed during the construction of the cooling pond.

3 Terrestrial Monitoring during LSCS Construction (1974–1978)

4 Following the commencement of LSCS construction, ComEd commissioned NALCO 

5 Environmental Sciences to conduct a 5-year monitoring program to evaluate the effects of 

6 temporary and permanent ecological disturbances related to construction from 1974 

7 through 1978. The ER for operation of LSCS (ComEd 1977) describes the results of the first 

8 2 years of this monitoring.

9 Final Environmental Statement for Operation (1978)

10 In November 1978, the NRC issued a Final Environmental Statement that evaluated the 

11 operation of LSCS (FES-O) (NRC 1978). The report includes updates to the terrestrial habitat 

12 and wildlife information presented in the FES-C based on the 5 years of terrestrial monitoring 

13 conducted during LSCS construction.

14 Wildlife Habitat Council Vegetation and Wildlife Surveys (2007)

15 In September 2007, Wildlife Habitat Council (WHC) biologists performed a baseline habitat 

16 survey for the Wildlife at Work program. The survey results are documented in the LSCS

17 Wildlife Management Plan (Exelon 2013b).

18 LSCS Wildlife Habitat Team Monitoring (Ongoing)

19 The LSCS Wildlife Habitat Team conducts periodic wildlife surveys of the site in the spring 

20 (April), summer (July), and fall (September) to monitor changes in wildlife communities and to 

21 document any new species found on the site. Results of periodic surveys are collected in 

22 Exelon’s Wildlife Management Plan (Exelon 2013b).

23 3.6.3 LSCS Site

24 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 

25 Illinois. The cooling pond, generating facilities and associated infrastructure, and LaSalle Fish 

26 Hatchery occupy the majority (66 percent) of the site. The remaining areas are undeveloped 

27 and include the following terrestrial communities: forest, shrub-scrub, grassland, old-field, and 

28 wetlands.

29 A cooling pond occupies the western side of the site and accounts for about half of the site area. 

30 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 

31 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac)

32 (Exelon 2015p). This industrial area is surrounded by about 142 ha (350 ac) of undeveloped

33 natural areas, including grassland, old field, schub-scrub, and small forested fragments 

34 (Exelon 2015p).

35 3.6.3.1 Vegetation

36 Because the majority of the LSCS site is developed or occupied by the cooling pond, only small 

37 areas of terrestrial habitat occur on the site. An open grassy area lies between the cooling pond 

38 and the site’s industrial area. This area is bounded on the north by the discharge canal and on 

39 the south by the property boundary. Another grassy area lies to the southwest of the industrial 

40 area. These two areas have a few scattered trees (Exelon 2014a).

41 The makeup and blowdown pipeline corridor extends north from the cooling pond to the Illinois 

42 River and supports upland habitats, including shrub-scrub, forest, grassland, and old-fields, and 

43 scattered wetlands. Common tree species in the upland forest areas, which comprise the 
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1 majority of the corridor, include white oak (Quercus alba), red oak (Q. rubra), shagbark hickory 

2 (Carya ovata), sugar maple, hop hornbeam (Ostrya virginiana), hawthorn (Crataegus spp.), 

3 black cherry (Prunus serotina), and American elm (Ulmus americana) (Exelon 2014a). The 

4 corridor widens as it approaches the Illinois River where it contains several small freshwater 

5 emergent and freshwater forested/scrub wetlands. These wetlands are discussed in 

6 Section 3.6.5.2.

7 3.6.3.2 Wildlife

8 Mammals

9 During the baseline terrestrial surveys in 1971 and 1972, 29 species of mammals were recorded 

10 on the LSCS site. The most commonly observed mammals included raccoon (Procyon lotor), 

11 mink (Mustela vison), red fox (Vulpes fulva), gray fox (Urocyon cinereoargenteus), gray squirrel 

12 (Sciurus carolinensis), fox squirrel (Sciurus niger), beaver (Castor canadensis), muskrat 

13 (Ondatra zibethicus), eastern cottontail (Sylvilagus floridanus), and white-tailed deer 

14 (ComEd 1977). During the 2007 WHC baseline inventory of the LSCS site, coyote (Canis 

15 latrans), beaver, opossum (Didelphis virginiana), groundhog (Marmota monax), striped skunk 

16 (Mephitis mephitis), white-tailed deer, and gray squirrel were observed on the site (Exelon

17 2013b).

18 Birds

19 During the baseline terrestrial surveys in 1971 and 1972, 129 species of birds were recorded on 

20 or near the LSCS site. Of these, 41 are considered permanent residents, 45 are summer 

21 residents, 13 are winter residents, and 21 are transients (ComEd 1977). Permanent residents 

22 included mallard (Anas platyrhynchos), black duck (A. rubripes), red-tailed hawk (Buteo 

23 jamaicensis), red-shouldered hawk (Buteo lineatus), bald eagle (Haliaeetus leucocephalus), 

24 bobwhite (Colinus virginianus), ring-necked pheasant (Phasianus colchicus), killdeer 

25 (Charadrius vociferus), rock dove (Columba livia), mourning dove (Zenaida macroura), great 

26 horned owl (Bubo virginianus), short-eared owl (Asio flammeus), saw-whet owl (Aegolius 

27 acadicus), northern flicker (Colaptes auratus), red-bellied woodpecker (Melanerpes carolinus), 

28 red-headed woodpecker (M. erythrocephalus), horned lark (Eremophila alpestris), blue jay 

29 (Cyanocitta cristata), American crow (Corvus brachyrhynchos), black-capped chickadee 

30 (Poecile atricapillus), northern mockingbird (Mimus polyglottos), eastern bluebird (Sialia sialis), 

31 cedar waxwing (Bombycilla cedrorum), loggerhead shrike (Lanius ludovicianus), starling 

32 (Sturnus vulgaris), and house sparrow (Passer domesticus) (ComEd 1977). During the 2007 

33 WHC baseline inventory of the LSCS site, 15 species of birds were observed, all of which had 

34 been previously recorded as occurring on the site during baseline surveys (Exelon 2013b).

35 Reptiles and Amphibians

36 No reptiles or amphibians were collected on the LSCS site in the 1971 baseline surveys 

37 (ComEd 1977). In 1972, two Eastern plains garter snakes (Thamnophis radix radix) were 

38 observed in pastureland near an intermittent stream (ComEd 1977). The 2007 WHC baseline 

39 inventory did not include reptiles or amphibians.

40 3.6.4 LSCS Wildlife Management Plan

41 The LSCS Wildlife Management Plan (Exelon 2013b) outlines the goals and projects of LSCS’s 

42 Wildlife at Work program. Some of the plan’s past and planned wildlife habitat enhancement 

43 and conservation activities at the LSCS site include:

44 • planting native vegetation, including swamp white oak (Quercus bicolor) near the 

45 cooling pond,
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1 • controlling invasive common reed (Phragmites australis) near the cooling pond,

2 • enhancing existing habitat for grassland nesting birds through seeding, mowing, and 

3 controlled burns,

4 • maintaining nesting boxes for eastern bluebirds, and

5 • installing osprey (Pandion haliaetus) platforms near the cooling pond 

6 (Exelon 2014a).

7 Exelon (2015n), as a corporation, has been a member of the WHC since 2005, and Exelon first 

8 received WHC certification for its Wildlife at Work program at LSCS in November 2011.

9 3.6.5 Important Species and Habitats

10 3.6.5.1 Important Species

11 State-Listed Species

12 The Illinois Endangered Species Protection Act of 1972, as amended, makes illegal the transfer, 

13 sale, and possession of species (including skins and products) listed by the State as 

14 endangered or threatened. The Act establishes an Endangered Species Protection Board, 

15 which maintains a list of endangered and threatened species and advises the IDNR on the 

16 conservation of those species.

17 Within LaSalle County, the IDNR’s (2014b) Natural Heritage Database indicates that

18 28 State-listed terrestrial species (19 plants, 3 birds, 2 reptiles, 2 mammals, 1 insect, and 

19 1 amphibian) occur in the county (see Table 3–9). In September 2013, Exelon generated an 

20 IDNR Ecological Compliance Assessment Tool (EcoCAT) report that used Illinois Natural 

21 Heritage Database information to further refine the list of State-listed species that could occur 

22 on the LaSalle site and that could potentially be affected by the proposed license renewal. The 

23 EcoCAT report is included in Appendix C of the applicant’s ER (Exelon 2014a). The report 

24 indicates that there are no terrestrial State-listed species on or near the LSCS site that may be 

25 affected by the proposed license renewal. In a May 2014 letter to Exelon, the IDNR (2014c) 

26 confirmed that the EcoCAT report was accurate, and in its letter, the IDNR mentioned no 

27 records of State-listed terrestrial species on or near the site. Federally protected species are 

28 discussed in Section 3.8.

29 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
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Common Name Species Name Status(a)

Mammals

gray bat(b) Myotis grisescens SE

Indiana bat(b) Myotis sodalis SE

Plants

American brooklime Veronica americana SE

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

1 Although not listed as occurring in LaSalle County by the IDNR, Exelon (2014a) reports that it 

2 has observed the State-threatened peregrine falcon (Falco peregrinus) on the LSCS site. A pair 

3 of peregrine falcons nested on the roof of the auxiliary building several years ago. Exelon 

4 (2014a) personnel have not observed peregrine falcon nesting in recent years, but personnel 
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1 occasionally observe peregrines in flight on the site. The FES-O (NRC 1978) notes the 

2 observance of a single peregrine falcon in November 1972 in an offsite woodland.

3 Bald Eagles

4 The bald eagle is protected under the Bald and Golden Eagle Protection Act (16 USC 668 

5 et seq.). This Federal act prohibits anyone from taking or disturbing bald eagles or golden 

6 eagles (Aquila chrysaetos), including their nests or eggs, without a U.S. Fish and Wildlife 

7 Service (FWS)-issued permit. The bald eagle was observed near the LSCS site in April 1972, 

8 on the river’s north-facing bluffs (ComEd 1977; NRC 1978). However, Exelon (2014a) is not 

9 aware of bald eagle observations at the site in recent years.

10 3.6.5.2 Important Habitats

11 Illinois Natural Areas Inventory Sites

12 In its Illinois Natural Areas Inventory (INAI), the IDNR (2014a) identifies 28 LaSalle County sites 

13 as Category I (“high quality natural community and natural community restorations”), Category II 

14 (“specific suitable habitat for state-listed species or state-listed species relocations”), 

15 Category III (“State-dedicated Nature Preserves, Land and Water Reserves, & Natural Heritage 

16 Landmarks”), or a combination of the three categories. The 2013 EcoCAT report (contained in 

17 Appendix D of the applicant’s ER (Exelon 2014a)) indicates that one of these sites with 

18 terrestrial habitat lies near the LSCS site: Marseilles Hill Prairie.

19 The Marseilles Hill Prairie (INAI Site No. 1520) lies 3 mi (4.8 km) north of the LSCS main site 

20 boundary (Exelon 2015o). It is 39.71 ac (16.07 ha) in size and managed by the IDNR (2014a) 

21 to conserve prairie habitat. The IDNR (2014a) designates this INAI site as Category I.

22 State Parks and Wildlife Areas

23 The IDNR manages three areas for State parks or wildlife areas within 10 km (6 mi) of LSCS: 

24 LaSalle Lake State Fish & Wildlife Area, Marseilles State Fish & Wildlife Area, and Illini State 

25 Park. The LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling 

26 pond that is managed by the IDNR and open to the public for fishing and other recreational 

27 purposes (Exelon 2014a). The Marseilles State Fish & Wildlife Area is open to seasonal 

28 hunting of turkey (Meleagris gallopavo), pheasant, quail, dove, deer, rabbit, squirrel, and coyote 

29 (IDNR 2015e). Illini State Park provides habitat for a number deciduous trees, including hickory, 

30 ash (Fraxinus spp.), walnut (Juglans spp.), elm, cottonwood (Populus deltoids), oak, and maple, 

31 as well as white-tailed deer, eastern gray squirrels, opossums, beavers, raccoon, groundhogs, 

32 and a variety of waterfowl and songbirds (IDNR 2015b).

33 Wetlands

34 The National Wetlands Inventory Wetlands Mapper identifies eight small areas of freshwater 

35 emergent wetland and freshwater forested/scrub wetland on the LSCS site near the Illinois 

36 River that total about 10 ac (4 ha) (FWS 2015e). Common tree species in the freshwater 

37 forested/scrub wetland include American elm, black cherry, white oak, red oak, black oak, 

38 shagbark hickory, bitternut hickory (Carya cordiformis), hackberry (Celtis occidentalis), elm, 

39 willow (Salix spp.), and sycamore (Platanus occidentalis) (Exelon 2014a). The freshwater 

40 emergent wetlands contain cattail (Typha spp.), horsetail (Equisetum spp.), and other 

41 herbaceous vegetation (Exelon 2014a).

42 Managed Prairie Habitat

43 In partnership with Pheasants Forever, Inc., Exelon (2014a) actively manages 4 ha (10 ac) of 

44 native prairie to the west of the cooling pond.
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1 3.6.6 Invasive and Non-Native Species

2 The invasive common reed inhabits parts of the cooling pond, particularly along the pond’s 

3 western edge. In 2007, as part of its Wildlife at Work program, Exelon (2014a) began an effort 

4 to eradicate the species through mechanical harvesting and application of aquatic-safe 

5 herbicides.

6 3.7 Aquatic Resources

7 The aquatic communities of interest for the LSCS site occur in the Illinois River and in the site’s 

8 artificial cooling pond. The Illinois River lies 5 mi (8 km) north of the site. It supplies makeup 

9 water to LSCS’s cooling system and receives cooling system blowdown. The cooling pond is 

10 the site’s main source of cooling water and is the plant’s UHS. Section 3.1.3 describes the 

11 cooling system in detail, and Section 3.5.1 describes the surface water characteristics of the

12 Illinois River and the cooling pond.

13 The sections below describe the two main aquatic ecosystems at the LSCS site, the Illinois 

14 River and the LSCS cooling pond (see Sections 3.7.1 and 3.7.2, respectively). In addition, 

15 Section 3.7.3 describes State-listed species and important habitats and Section 3.7.4 describes 

16 non-native species. 

17 3.7.1 Illinois River

18 The Illinois River begins southwest of Chicago, at the confluence of the Des Plaines and 

19 Kankakee Rivers. It flows south until it reaches the Mississippi River north of St. Louis, 

20 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 21 ) from Illinois, Wisconsin, 

22 and Indiana (IDNR 2011a). Major tributaries include the Des Plaines, Fox, Kankakee, 

23 Vermilion, Mackinaw, Sangamon, Spoon, and La Moine rivers.

24 Prior to the 1800s, the Illinois River Basin was comprised of prairie savannas and oak-hickory 

25 forests. The river provided diverse aquatic habitats including backwater lakes, side channels, 

26 and a narrow main channel (USGS 1999a). The rapid expansion of agricultural activities 

27 throughout the 1800s and early 1900s converted wet and mesic (relatively well drained)

28 floodplain prairies to crop lands. This land use conversion resulted in increased erosion, 

29 sediment loading, and nutrient and herbicide transport to the Illinois River. Beginning in the 

30 1900s, several efforts occurred to divert water from Lake Michigan and construct navigation 

31 dams or levees to increase the navigability of the Illinois River to the Mississippi River and 

32 provide a navigable passage from Chicago (Lake Michigan) to the Gulf of Mexico (USGS 

33 1999a). As the population in Chicago continued to grow, sewage disposal and toxic waste 

34 disposal further contributed to the degradation of aquatic habitat in the Illinois River (Parker 

35 2014). By the 1960s, the biodiversity of fish within the upper Illinois River was low and 

36 freshwater mussels were nearly absent (Sietman et al. 2001). Pollution tolerant, non-native 

37 common carp (Cyprinus carpio) and goldfish (Carassius auratus) dominated fish populations 

38 (Parker 2014). Since the passage of the CWA in 1974, water quality within the Illinois River has 

39 improved and more diverse fish assemblages inhabit the upper Illinois River (Parker 2014). 

40 Similarly, freshwater mussels have recolonized portions of the upper Illinois River since the 

41 1980s (Sietman et al. 2001). 

42 Currently, a series of locks and dams along the Illinois River continue to limit habitat connectivity 

43 and fish passage along the Illinois River. Four of the locks and dams (Thomas J. O’Brien, 

44 Lockport, Brandon Road, and Dresden Island) are upstream of LSCS and four (Marseilles, 

45 Starved Rock, Peoria, and LaGrange) are downstream (USACE 1998). The closest locks and 
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1 dams to LSCS include the Dresden Island Lock and Dam, 22 mi (26 km) upstream of the LSCS 

2 intake, and the Marseilles Lock and Dam, 2.4 mi (3.5 km) downstream of the LSCS discharge

3 (USACE 1998; Exelon 2015c). 

4 In 2005, IEPA most recently classified the water quality within the Illinois River as “fair,” which 

5 means that the water quality has been impaired, and the water body meets the needs of a 

6 designated use most of the time (IDNR 2011a). Current factors that continue to contribute to 

7 the degradation of the Illinois River include the increase in invasive fish, accumulated 

8 sediments, continued sedimentation, and agricultural chemical runoff (USGS 1999a; 

9 Parker et al. 2005). 

10 3.7.1.1 Aquatic Communities in the Illinois River

11 Plankton

12 Plankton are small organisms that float or drift in rivers and other water bodies. Plankton is a 

13 primary food source for many whales, fish, and other animals, and consists of bacteria, 

14 protozoans, certain algae, tiny crustaceans such as copepods, and many other organisms.

15 ComEd, the previous owner of LSCS, conducted surveys for plankton within the Illinois River 

16 both upstream and downstream of the LSCS discharge and river intake structures. ComEd

17 initially sampled plankton prior to operations, from August 1972 through January 1973, and 

18 again during construction, from February 1974 through November 1976. These studies are 

19 summarized in the Final Environmental Statement for Operations of LSCS (NRC 1978). 

20 Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 

21 one base of aquatic food webs by producing biomass from inorganic compounds and sunlight. 

22 As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 

23 recycling of nutrients and minerals.

24 Diatoms were the most abundant phytoplankton in the Illinois River near LSCS in the 1970s, 

25 and reached peak densities in August (NRC 1978). The most common diatom genera included 

26 Cyclotella, Melosira, and Stephanodiscus. The NRC staff noted that many of the diatoms

27 collected in preoperational studies were pollution tolerant (NRC 1978). Other phytoplankton 

28 followed similar trends with primary production peaking in August and dipping in winter months. 

29 The NRC staff is not aware of any additional phytoplankton surveys that have been conducted 

30 in the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.

31 Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past often called 

32 “blue-green algae”), heterotrophic microbes, other small organisms, and detritus that attach to 

33 submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 

34 source of nutrients to many bottom-feeding organisms.

35 During ComEd’s initial study prior to construction, diatom densities upstream of the LSCS

36 discharge and intake areas accounted for 75 percent of the total periphyton density in 

37 August 1972 and 100 percent in January 1973. The next dominant taxa was green algae, which 

38 accounted for 7 percent of the total periphyton density in 1972 and none of the total periphyton 

39 density in 1973. Downstream of the LSCS discharge and intake, diatom densities accounted for 

40 94 percent of the total periphyton density in August 1972 and 92 percent in January 1973, while 

41 the green algae accounted for 1 percent in 1972 and none in 1973 (NRC 1978). Diatoms were 

42 the dominant periphyton group during the warmer months (May, August, and November), 

43 whereas green algae was dominant during February from 1974 to 1976 (NRC 1978). Dominant 

44 diatom genera included Cyclotella, Navicula, and Nitzschia; dominant green algae genera 

45 included Stigeoclonium, Cladophora, Rhizoclonium, and Ulothrix (NRC 1978).
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1 The NRC staff is not aware of any additional periphyton surveys that have been conducted in 

2 the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.

3 Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water column 

4 and include ichthyoplankton (fish eggs and larvae) with no or limited swimming ability and larvae 

5 of benthic invertebrates. Zooplankton are important trophic links between primary producers 

6 (e.g., phytoplankton and periphyton) and carnivores (e.g., fish). 

7 During preoperational studies, copepods and rotifers dominated zooplankton samples both prior 

8 to and during construction (NRC 1978). Dominant copepod genera included Cyclops and 

9 Eucyclops, and dominant rotifer genera included Asplanchna, Brachionus, Filinia, Notholca, 

10 Polyarthra, and Synchaeta (NRC 1978). Peak densities for both copepods and rotifers 

11 generally occurred in August, and minimum densities generally occurred in February.

12 In 2014, EA Engineering, Science, and Technology, Inc. (EA) (2015) collected icthyoplankton 

13 samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 

14 samples using 0.5-m (1.6-ft) conical plankton nets with 505-μm mesh suspended from the 

15 forebay bridge in front of the river intake (see Figure 3–15). EA (2015) collected samples during 

16 the 2014 spawning season, from late April through August, when icthyoplankton densities would 

17 likely be highest. 
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1 Figure 3–15. Icthyoplankton Sampling Location at the LSCS River Intake Structure

2 Key: LSCS: LaSalle County Station; RSH: River Screen House

3 Source: EA (2015)

4 EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 

5 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 

6 combined comprised 79 percent of the number of organisms within ichthyoplankton sample. 

7 EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was 

8 not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. 

9 The most common taxa by life stage included Ictiobinae (buffalo fish) yolk-sac larvae 

10 (24 percent), cyprinidae (carps and minnows) yolk-sac larvae (23 percent), and common carp 

11 yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent 

12 of the icthyoplankton samples (EA 2015). 

13 Benthic Macroinvertebrates

14 Benthic macroinvertebrates include aquatic annelids (e.g., aquatic worms or oligochaetes, 

15 leeches), mollusks, crustaceans, and insect larvae that inhabit aquatic sediments and 

16 submerged surfaces. They accelerate detrital decomposition and nutrient cycling, and serve as 
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1 a food source for fish and other aquatic biota. ComEd, Exelon, and their contractors sampled 

2 benthic invertebrates during three time periods: preoperational studies from February through 

3 November, 1972 through 1976 (as summarized in NRC 1978); a 1999 study in response to low 

4 flow and high air temperatures (EA 2000); and a 2013 study in preparation for Exelon’s license 

5 renewal application (EA 2014). 

6 During the preoperational and the 2013 study, ComEd and Exelon sampled benthic 

7 macroinvertebrates at one location upstream of the river intake and blowdown discharge

8 (location 1), at one location immediately downstream of the blowdown discharge (location 2), 

9 and at two locations further downstream of the blowdown discharge (locations 3 and 4) (Figure 

10 3–16). ComEd and Exelon sampled each location with a Hester-Dendy artificial substrate 

11 sampler and a Ponar grab sampler (NRC 1978; EA 2014).

12 In 1999, Exelon also collected benthos using a Ponar grab at one site upstream and one site 

13 downstream of the blowdown discharge, similar to the sampling sites for the preoperational and 

14 2013 study. In addition, EA collected benthos using a Ponar grab at a second downstream site 

15 that was further downstream than South Kickapoo Creek (EA 2000).

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

17 Source: EA 2014

18 Collections during preoperational studies resulted in the identification of 143 taxa (NRC 1978). 

19 Chironomidae and Oligochaeta were the most dominant groups. The most common 

20 oligochaete genera were Limnodrilus and Nais. The most abundant chironomid genera 

21 included Cryptochironomous, Dicrotendipes, Procladius, Cricotopus, and Orthocladius.

22 EA (2000) collected a total of 34 taxa from Ponar grab samples. Chironomidae and Oligochaeta 

23 were the most taxa-rich groups, with 12 taxa each. EA (2000) determined that the dominant

24 taxa at all sampling sites are considered tolerant to poor water quality. Both total richness and 

25 the number of Ephemeroptera, Plecoptera, and Trichoptera species, which are considered 

26 intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) 

27 compared to upstream (location 1) of the intake and discharge structures. 
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1 EA (2014) collected a total of 61 taxa from the Hester-Dendy artificial substrate collections. 

2 Chironomidae was the most taxa rich group with 21 taxa followed by Ephemeroptera and Bivalvia, 

3 with 8 taxa each. The dominant taxa from the Hester-Dendy collections included the following 

4 insect larvae: Dicrotendipes modestus (a non-biting midge), Maccaffertium integrum (a mayfly), 

5 Cyrnellus fraternus (a caddisfly), and Dicrotendipes neomodestus. Among the 10 most dominant 

6 taxa for the Hester-Dendy artificial substrate samples, only one taxon is considered tolerant of 

7 environmental degradation, Glyptotendipes (IEPA 1987; EA 2014). The remaining taxa are 

8 considered facultative to slightly intolerant to poor water quality (IEPA 1987; EA 2014).

9 For the Ponar grab samples, Chironomidae was the most taxa rich group with 15 taxa, followed 

10 by 8 Bivalvia and 4 Ephemeroptera taxa. EA (2014) observed the highest taxa richness at 

11 locations 1 and 3 (20 to 29 taxa) as compared to locations 2 and 4 (16 to 27 taxa). Species 

12 richness among pollution sensitive Ephemeroptera, Plecoptera, and Trichoptera was similar 

13 among all locations, ranging from three to five taxa (EA 2014). At all sampling sites, EA (2014) 

14 observed dominant taxa that were relatively tolerant to poor water quality as well as dominant 

15 taxa that were relatively intolerant or facultative to poor water quality.

16 Fish

17 ComEd, Exelon, and their contractors sampled fish near LSCS during three time periods: 

18 preoperational studies from May through November, 1972 through 1976 (as summarized in 

19 NRC 1978); a post-operational study in response to low flow and high air temperatures in July 

20 through October, 1999 (EA 2000); and a post-operational study in August 2013 in preparation

21 for Exelon’s license renewal application (EA 2014). 

22 During both the preoperational and 2013 study, Exelon sampled fish at one location upstream of 

23 the river intake and blowdown discharge (location 1) and at two locations downstream of the 

24 blowdown discharge (locations 2 and 5), one of which was South Kickapoo Creek

25 (Figure 3–16). Exelon sampled fish at each sampling site by electrofishing in a downstream 

26 direction for 500 m (1,640 ft). In addition, Exelon seined for fish along the shoreline at all three 

27 locations using a 25-ft (8-m) long by 6-ft (2-m) deep seine with 0.19- in. (0.48-cm) mesh. 

28 Exelon hauled the seine along 15 m (49 ft) of shoreline in a downstream direction.

29 In 1999, EA also electrofished at one site upstream and one site downstream of the blowdown 

30 discharge, similar to the sampling sites for the preoperational and 2013 study. In addition, EA 

31 electrofished at second downstream site that was further downstream than South Kickapoo 

32 Creek (EA 2000). 

33 All three studies looked for external parasites or other abnormalities. EA (2000 and 2014) 

34 specifically examined all fish for external DELT (deformities, erosions, lesions, or tumors)

35 anomalies.

36 During the preoperational monitoring period, NRC (1978) determined that the most dominant 

37 species included emerald shiner (Notropis atherinoides), gizzard shad (Dorosoma cepedianum), 

38 common carp, green sunfish (Lepomis cyanellus), bluntnose minnow (Pimephales notatus), and 

39 white sucker (Catostomus commersonii) (see Table 3–10). Prior to operations, downstream 

40 collection stations generally had lower species abundance and higher species diversity than 

41 upstream stations (NRC 1978). The NRC (1978) concluded that the low species abundance 

42 and diversity, low condition factors, and the degree of external parasitism and physical damage 

43 of the fishes in this area of the Illinois River were indicative of a poor quality aquatic 

44 environment. Barge traffic, habitat alteration, and heavy pollution loads contributed significantly 

45 to the poor water quality in the Illinois River near LSCS, which primarily supported populations 

46 of pollution-tolerant fish in the 1970s (NRC 1978).
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1 During the 1999 survey, EA (2000) collected 27 species and 1 hybrid for a total of 960 fish. The 

2 most commonly collected fish species included gizzard shad (24 percent), smallmouth buffalo 

3 (Ictiobus bubalus) (12 percent), spotfin shiner (Cyprinella spiloptera) (10 percent), green sunfish 

4 (9 percent) and bluegill (Lepomis macrochirus) (8 percent) (Table 3–10). EA (2000) observed a 

5 total of 63 fish (6.6 percent of the catch) with DELT anomalies. Channel catfish (Ictalurus 

6 punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest 

7 DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin 

8 erosion (52 percent) and deformities (38 percent). 

9 During the 2013 study, EA (2014) collected 12 fish species for a total of 1,295 fish. The most 

10 commonly collected species during electrofishing included gizzard shad (48 percent), spotfin 

11 shiner (16.5 percent), smallmouth buffalo (6 percent), golden redhorse (Moxostoma erythrurum) 

12 (5 percent), smallmouth bass (Micropterus dolomieu) (4 percent), and freshwater drum 

13 (4 percent; EA 2014) (Table 3–10). Gizzard shad dominated samples both upstream and 

14 downstream of the intake and discharge (EA 2014). The most commonly collected species 

15 during seining surveys included emerald shiner (83 percent), spotfin shiner (9.5 percent), 

16 bluntnose minnow (2 percent), and sand shiner (Notropis stramineus) (2 percent) (EA 2014) 

17 (Table 3–10). Emerald shiner dominated samples both upstream and downstream of the intake 

18 and discharge (EA 2014). EA (2014) observed DELT anomalies on 2 of the 1,295 fish collected 

19 (0.2 percent), both of which were eroded fins on freshwater drum. EA (2014) did not observe 

20 any external parasites or other abnormalities. 

21 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

Catostomidae

Catostomus commersoni white sucker X

Ictiobus bubalus smallmouth buffalo X X

Micropterus dolomieu smallmouth bass X

Moxostoma erythrurum golden redhorse X

Atherinopsidae

Labidesthes sicculus brook silverside X

Clupeidae

Dorosoma cepedianum gizzard shad X X X
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Species Common Name

Commonly Collected Species(d)

1974-1976(a) 1999(b) 2013(c)

Sciaenidae

Aplodinotus grunniens freshwater drum X

(a) NRC 1978

(b) EA 2000

(c) EA 2014

(d) X= one of the sixth 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 sixth most commonly collected species.

Sources: NRC 1978; EA 2000, 2014

1 Common carp and white sucker were commonly collected during preoperational studies but 

2 were not commonly collected during the 1999 or 2013 study. Ohio EPA (1987) classifies both of 

3 these species as pollution tolerant. Brook silverside (Labidesthes sicculus), freshwater drum, 

4 sand shiner, smallmouth bass, smallmouth buffalo, golden redhorse, and bluegill were among 

5 the commonly collected species in the 1999 or 2013 studies but were not commonly collected in 

6 the preoperational studies. Five of these seven species (brook silverside, sand shiner, 

7 smallmouth bass, golden redhorse, and bluegill) are native species that are sensitive to declines 

8 in water quality or habitat degradation (Lerczak 1996; Smith 2002).

9 These results are consistent with other fish surveys (Lerczak 1996; McClelland et al. 2012) 

10 within the upper Illinois River that since the mid-1950s through 1990s and the 2000s, show a 

11 decline in fish species that are tolerant of poor water quality and an increase in fish species that 

12 are sensitive to habitat degradation. For example, Lerczak (1996) examined fish population 

13 data from the Illinois Natural History Survey (INHS), which began monitoring fish populations in 

14 the Illinois River in 1957. Since 1957, INHS conducted annual electrofishing surveys at set 

15 locations throughout the entire Illinois River, including sampling locations approximately 1 RM 

16 downstream of the LSCS river intake, within the vicinity of the LSCS river intake, and 11 RM 

17 upstream of the LSCS river intake. Within the upper 50 mi (80 km) of the Illinois River, which 

18 includes LSCS, Lerczak (1996) concluded that common carp, which is pollution tolerant, has 

19 become less common while bluegill, which is intolerant to degraded habitats, has become more 

20 common. For example, in the 1960s, INHS captured an average of 35 common carp per hour 

21 as compared to 6 common carp per hour in the 1990s. Bluegill increased from averages of less 

22 than 1 per hour in the 1960s to 12 per hour in the 1990s. Lerczak (1996) also noted that in the 

23 1990s, fish communities were more evenly distributed among a greater number of species than 

24 in the 1960s. For example, in 1962 and 1963, four species comprised 95 percent of all catches: 

25 gizzard shad, emerald shiner, common carp, and goldfish—a species with pollution tolerance 

26 similar to common carp. In 1995, 10 species comprised 95 percent of all catches including 

27 several species that are sensitive to habitat degradation, such as the bluegill, largemouth bass 

28 (Micropterus salmoides), and several species of small minnows.

29 McClellan et al. (2012) also examined fish populations during three time periods from 1957 

30 through 2009 based on INHS data. Table 3–11 describes the species that contributed to 

31 approximately 90 percent of all electrofishing catches in the Illinois River (McClelland 

32 et al. 2012). The NRC staff further classified fish as either pollution tolerant or intolerant. In 

33 addition, the NRC staff determined whether McClelland reported increases or decreases in the 

34 relative abundance of each species over time. The NRC staff notes that these general trends 

35 were not assessed using regression analyses or other statistical analyses. The most common 
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1 species during the 1957 through 1969 surveys (common carp, gizzard shad, emerald shiner, 

2 and goldfish) are considered pollution tolerant species and the relative abundance of these 

3 species has generally declined over time. All pollution intolerant species listed in 

4 Table 3–11 have generally increased overtime. These data suggest that water quality within the 

5 Illinois River has improved over time, allowing species that are pollution sensitive to increase in 

6 relative abundance. 

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

8 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 - - ↓

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

9 3.7.2 LSCS Cooling Pond

10 As described in Section 3.5, the 2,058-ac (833-ha) cooling pond was created in 1978 by 

11 pumping water from the Illinois River into the excavated pond. Exelon leases a large portion of 

12 the LSCS cooling pond to the IDNR, which maintains the LSCS cooling pond as an outdoor 
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1 recreation area for public use and fishing. IDNR has actively managed the LSCS cooling pond 

2 since 1984 (Exelon 2014a). For example, IDNR surveys the cooling pond each year and 

3 determines which fish to stock based on fishermen preferences, fish abundance, different 

4 species’ tolerance to warm waters, predator and prey dynamics, and other factors (Exelon 2002, 

5 2014a, 2015a). The cooling pond can be characterized as a highly managed ecosystem in 

6 which IDNR fish stocking and other human activities primarily influence the species composition 

7 and population dynamics. 

8 3.7.2.1 Aquatic Community in the Cooling Pond

9 IDNR stocks the LSCS cooling pond each year. In 1981, IDNR’s fish hatchery located adjacent 

10 to the cooling pond started operations, at which point IDNR started stocking the cooling pond 

11 with species from the hatchery (EA 2002). Initially, IDNR stocked the LSCS cooling pond with 

12 largemouth bass and bluegill (EA 2002).

13 Currently, commonly stocked species include largemouth bass, smallmouth bass, black crappie 

14 (Pomoxis nigromaculatus), white crappie (Pomoxis annularis), channel catfish, blue catfish 

15 (Ictalurus furcatus), striped bass hybrid (Morone saxatilis x M. chrysops), walleye (Sander 

16 vitreus), and bluegill (See Table 3–12; Exelon 2002 and 2015a). Because of the high water 

17 temperatures experienced in the summer months, introductions of warm-water species, such as 

18 largemouth bass and blue catfish, have been more successful than introductions of cool-water 

19 species, such as walleye and tiger muskellunge. 

20 In addition to the stocked species, gizzard shad and threadfin shad (Dorosoma petenense)—

21 together called “shad”—also occur in the cooling pond. Shad are not recreationally fished, and 

22 IDNR does not currently stock these fish. IDNR stocks some recreationally fished species that 

23 consume shad (e.g., catfish and striped bass) in part to limit the size of shad populations 

24 (Exelon 2002).

25 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 and 2015
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1 3.7.2.2 Cooling Pond Fish Kill Events

2 LSCS has had four reportable fish kills in the cooling pond since 2001, including fish kills in 

3 July 2001, June 2005, June 2009, and August 2010 (Exelon 2014a, 2015a). The temperature in 

4 the cooling pond during these events ranged from 93 °F (33.9 °C) to 101°F (38.3 °C) 

5 (Exelon 2001, 2009, 2010). In addition, several smaller non-reportable fish kills have occurred 

6 when the cooling pond was 95 °F (35 °C) or above (Exelon 2015c). Exelon attributes these fish 

7 kills to high cooling pond temperatures as a result of high summer temperatures combined with 

8 low winds and high humidity, as described below (Exelon 2001, 2009, 2010). 

9 The largest fish kill occurred in July 2001 when IDNR reported approximately 94,500 dead fish 

10 due to high temperatures that peaked at 98.2 °F (36.9 °C) (Exelon 2001). IDNR found the 

11 maximum temperature in the cooling pond discharge canal to be 120 °F (48.9 °C) and dissolved 

12 oxygen levels to range from 6.2 to 18.8 parts per million. The majority of dead fish (96 percent) 

13 were gizzard shad (90,800) (Exelon 2001). IDNR identified other dead fish to include 

14 1,279 carp, 1,143 smallmouth buffalo, 610 freshwater drum, 345 channel catfish, 238 striped 

15 bass hybrid, 93 smallmouth bass, 24 walleye, 13 bluegill, 12 white bass (Morone chrysops), 

16 6 yellow bullhead catfish (Ameiurus natalis), and 4 yellow bass (M. mississippiensis) 

17 (Exelon 2001). 

18 In a June 2005 fish kill, IDNR counted 1,515 dead fish, including 1,439 striped bass hybrids 

19 (95 percent), 36 smallmouth bass (2 percent), 20 walleye (1 percent),11 channel catfish (less 

20 than 1 percent), 4 blue catfish (less than 1 percent), 3 yellow bass (less than 1 percent), and 

21 2 sauger (less than 1 percent) (Exelon 2015c). The LSCS cooling pond peaked at 95 °F (35 °C) 

22 during the fish kill (Exelon 2015c). 

23 In the June 2009 fish kill, 3,000 to 4,000 gizzard shad comprised 99 percent of the dead fish 

24 shad (Exelon 2009). Exelon (2009) also observed 26 smallmouth bass, 4 striped bass, and 

25 4 walleye. Immediately prior to and during the fish kill, the LSCS cooling pond increased 10 °F 

26 from 83 °F (28 °C) on June 20 to 93 °F (34 °C) on June 23. 

27 In the August 2010 fish kill, IDNR concluded that over 90 percent of the dead fish were small 

28 threadfin and gizzard shad less than 3 in. (8 cm) long (Exelon 2010). IDNR also observed dead 

29 carp, striped bass hybrids, walleye, and smallmouth bass (Exelon 2010). The LSCS cooling 

30 pond peaked at 101.3 °F (38.5 °C) the day before the fish kill.

31 3.7.3 Important Species and Habitats

32 3.7.3.1 State-Listed Species

33 IDNR lists 35 fish and 26 mussel species as State-endangered or threatened (IDNR 2015a). Of

34 these, IDNR (2014b) indicates that 7 species (5 fish, 2 mussels) occur in LaSalle County (see 

35 Table 3–13).
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1 Table 3–13. State-Listed Aquatic Species with the Potential To Occur in La Salle 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

(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, 2015a

2 Banded killifish. Banded killifish occur in clear glacial lakes, streams, or tributaries, often near 

3 vegetation (Nyboer et al. 2006). This fish forms small schools near the surface of weedy lakes 

4 (Nyboer et al. 2006). In recent years, this species has been documented in the Illinois River 

5 (McClelland and Sass 2007; McClelland et al. 2012). In 2006, the INHS collected two banded 

6 killifish at RM 241.5 in the Starved Rock Pool sampling area, approximately 8 RM (13 Rkm) 

7 downstream of the LSCS river intake (McClelland and Sass 2007). However, from 1993 

8 through 2012, the INHS did not observe banded killifish in the Marseilles Pool sampling area, 

9 which included sampling locations approximately 1 RM (1.6 Rkm) downstream of the LSCS river 

10 intake, within the vicinity of the LSCS river intake, and 11 RM (18 Rkm) upstream of the LSCS 

11 river intake (Fritts 2013). 

12 In 2014, EA (2015) collected a juvenile banded killifish during an impingement and entrainment

13 study at the LSCS river intake. In response to this collection, Exelon noted that EA Engineering 

14 intends to request a scientific collector’s permit report from IDNR. This species was not 

15 collected during preoperational surveys (NRC 1978) or during operational studies in 1999 and 

16 2013 (EA 2000, 2014).

17 River Redhorse. The river redhorse inhabits large river systems, including impoundments and 

18 pools, in areas of moderate to swift current and clean gravel substrate (NatureServe 2014a). 

19 Barbour et al. (1999) classify this species as an insectivore that is intolerant of pollution and 

20 other environmental stressors. INHS electrofishing surveys that began in 1957 have 

21 documented this species in the Illinois River (McClelland and Sass 2007). However, from 1993 
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1 through 2012, INHS did not observe river redhorse in the Marseilles Pool sampling area, which 

2 included sampling locations approximately 1 RM (1.6 RKm) downstream of the LSCS river 

3 intake, within the vicinity of the LSCS river intake, and 11 RM (18 RKm) upstream of the LSCS 

4 river intake (Fritts 2013). The river redhorse was not collected during preoperational surveys 

5 (NRC 1978) or operational surveys in 1999 and 2013 (EA 2000, 2014). From 2013 through 

6 2015, EA (2015) conducted an impingement and entrainment study near the LSCS river intake. 

7 Although EA (2015) collected several Moxostoma fish that were not identified to species, EA 

8 (2015) concluded that these species were most likely the more common Moxostoma spp., such 

9 as shorthead, golden, silver, and black redhorse, given that these common species were 

10 conclusively identified during the study. 

11 Greater Redhorse. The greater redhorse inhabits lakes and large rivers with sandy to rocky 

12 pools (Nyboer et al. 2006). This fish was considered extirpated in Illinois until it was observed in 

13 the upper Illinois River basin in 1985 (Nyboer et al. 2006). IDNR (2014) recorded three 

14 observations of this species in LaSalle County, most recently in July 2004. This species is rare

15 in the Illinois River, and INHS did not observe this species from 1957 through 2006 at any 

16 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 

17 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 

18 (EA 2000, 2014), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from

19 1993 through 2012 (Fritts 2013). From 2013 through 2015, EA (2015) conducted an 

20 impingement and entrainment study near the LSCS river intake. Although EA (2015) collected 

21 several Moxostoma fish that were not identified to species, EA (2015) concluded that these 

22 species were most likely the more common Moxostoma spp., such as shorthead, golden, silver, 

23 and black redhorse given that these common species were conclusively identified during the 

24 study. 

25 Blacknose shiner. The blacknose shiner inhabits clear vegetated lakes, and pools and runs of 

26 clear streams (Nyboer et al. 2006). Increased turbidity and decreases in aquatic vegetation 

27 have contributed to the decline of this species (Nyboer et al. 2006). IDNR (2014) recorded two 

28 observations of this species in LaSalle County, most recently in October 2013. This species is 

29 rare in the Illinois River and INHS did not observe this species from 1957 through 2006 at any 

30 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 

31 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 

32 (EA 2000, 2014), an impingement and entrainment study at the LSCS river intake from 2013 

33 through 2015 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling 

34 area from 1993 through 2012 (Fritts 2013).

35 Weed shiner. In Illinois, the weed shiner inhabits clear sand-bottom creeks with some 

36 submerged vegetation (Nyboer et al. 2006). IDNR (2014) recorded one observation of this 

37 species in LaSalle County, most recently in October 2013. This species is rare in the Illinois 

38 River and INHS did not observe this species from 1957 through 2006 at any sampling station in 

39 the Illinois River (McClelland and Sass 2007). This species was not collected during 

40 preoperational surveys (NRC 1978), operational studies in 1999 and 2013 (EA 2000, 2014), an 

41 impingement and entrainment study at the LSCS river intake from 2013 through 2015 

42 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 1993 

43 through 2012 (Fritts 2013).

44 Slippershell. The slippershell is a freshwater mussel that inhabits small to medium sized 

45 streams where it is usually found buried in sandy substrates in shallow water

46 (Nyboer et al. 2006). IDNR (2014) recorded five observations of this species in LaSalle County, 

47 most recently in October 2013. In 1994, 1995, and 1999, Sietman et al. (2001) conducted 

48 freshwater mussel surveys in the Illinois River from RM 232.0 to 271.2 (RKm 373 to 436), 

49 including the Starved Rock and Marseilles Pools sampling areas. Sietman et al. (2001) did not 
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1 collect this species during the surveys. Similarly, this species was not observed in 2013 when 

2 IDNR collected 14,850 live mussels, representing 23 species, near the Marseilles Dam after a 

3 boating accident (Kanter 2013). This species was not collected during LSCS preoperational 

4 surveys (NRC 1978), operational studies in 2013 (EA 2014), or during impingement and 

5 entrainment studies at the LSCS river intake from 2013 through 2015 (EA 2015).

6 Spike. The spike is a freshwater mussel that inhabits shoals of medium streams to large 

7 rivers, reservoirs, and lakes with sand and gravel substrates (Minnesota DNR 2014). It is 

8 distributed throughout the eastern United States, the Mississippi River system, and portions of 

9 the Great Lakes (NatureServe 2014b). IDNR (2014) recorded one observation of this species in 

10 LaSalle County in August 2010. This species was not collected during LSCS preoperational 

11 surveys (NRC 1978); the freshwater mussel survey from RM 232.0 to 271.2 in 1994, 1995, and 

12 1999 (Sietman et al. 2001); IDNR’s collection of mussels near the Marseilles Dam in 2013 

13 (Kanter 2013); operational studies in 2013 (EA 2014); or during impingement and entrainment

14 studies at the LSCS river intake from 2013 through 2015 (EA 2015).

15 3.7.3.2 Important Habitats

16 LaSalle Lake State Fish and Wildlife Area is part of the 2,058 ac (833 ha) cooling pond. As 

17 described above in Section 3.7.2, IDNR manages this area for public boating and fishing.

18 The Marseilles State Fish and Wildlife Area occurs approximately 1.5 mi (2.4 km) north of the 

19 LSCS site and the makeup and blowdown pipeline corridor right-of-way crosses the eastern 

20 portion of the area. The Marseilles State Fish and Wildlife Area is a 1,032-ha (2,550-ac) area 

21 managed by IDNR for hunting and wildlife habitat (IDNR 2015d). It is a joint-use area with the 

22 Illinois Department of Military Affairs, and periodically used by the Illinois National Guard for 

23 training (IDNR 2015d). 

24 3.7.4 Non-Native Species

25 Several non-native species, including the common carp, goldfish, and Asian carps 

26 (Hypophthalmichthys spp.), have been introduced into the Illinois River (McClelland et al. 2012). 

27 Common carp and goldfish have been present in the vicinity of LSCS prior to operations

28 (McClelland et al. 2012; Exelon 2014a). Both species dominated non-native fish collections in 

29 INHS’s long term monitoring surveys from 1957 and 1985 (McClelland et al. 2012). Common 

30 carp and goldfish are tolerant of degraded aquatic habitats and can tolerate low levels of 

31 dissolved oxygen and high water turbidity. 

32 Beginning in 1985, the number of non-native fish observed in the Illinois River increased 

33 (McClelland et al. 2012). Species documented in the Illinois River since 1985 include grass 

34 carp (Ctenopharyngodon idella), bighead carp (Hypophthalmycthys nobilis), silver carp 

35 (Hypophthalmycthys molitrix), round goby (Neogobius melanostomus), white perch (Morone 

36 americana), and the white perch-yellow bass hybrid (M. americana x M. mississippiensis) 

37 (McClelland et al. 2012). 

38 In addition to fish, Exelon has documented the occurrence of invertebrate non-native species 

39 near the river intake, the cooling pond intake, and within the cooling system. Bryozoans are 

40 aquatic invertebrates that grow into large sessile colonies. Zebra mussels are native to the 

41 Black and Caspian Seas, and have invaded Europe and North America. These organisms can 

42 cause biofouling of LSCS’s underwater piping systems or water intakes. In 1996, Exelon 

43 discovered bryozoans at the cooling pond screen house and removed the colony by using a 

44 continuous chlorination treatment. In 2010, Exelon observed the bryozoan Plumatella reticulata 

45 in the Unit 1 cooling water system and unidentified bryozoans at the river intake and in the 

46 cooling pond (HDR 2011). Within the past 5 years, Exelon has continued to regularly observe 
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1 bryozoan colonies and zebra mussels at both the river intake and the cooling pond intake, and 

2 limits the growth of these organisms by using biocides (HDR 2012, 2013, 2014; Exelon 2014a). 

3 When necessary, Exelon also follows procedures to remove zebra mussels manually.

4 3.8 Federally Protected Species and Habitats

5 Because NRC’s issuance of a renewed license for power plants is a Federal action, the NRC’s 

6 National Environmental Policy Act (NEPA) process considers species and habitats that are 

7 protected under Federal acts and possibly affected by license renewal. Federal acts that 

8 protect species and habitats possibly affected by the renewal of a nuclear plant license include 

9 the Endangered Species Act of 1973, as amended (ESA); the Bald and Golden Eagle 

10 Protection Act of 1940, as amended; the Migratory Bird Treaty Act of 1918, as amended; the 

11 Magnuson-Stevens Fishery Conservation and Management Act, as amended (MSA); and the 

12 Marine Mammal Protection Act of 1972, as amended. Of these, the NRC has direct 

13 responsibilities only under the ESA and MSA. No species protected under the MSA, which 

14 protects habitat for certain marine and anadromous fish species, occur near LSCS. Species 

15 protected under the ESA are discussed in this section, and species protected under other 

16 Federal acts where the NRC has no direct responsibilities and under State acts are discussed in 

17 Section 3.6 for terrestrial resources and Section 3.7 for aquatic resources.

18 Section 7(a)(2) of the ESA states that each Federal agency shall, in consultation with the 

19 Secretary (Secretary of Commerce or Secretary of the Interior), insure that any action 

20 authorized, funded, or carried out by that agency is not likely to jeopardize the continued 

21 existence of a listed species or result in the destruction or adverse modification of designated 

22 critical habitat. In fulfilling these requirements, each agency is to use the best scientific and 

23 commercial data available. Section 7 of the ESA sets out the consultation process, which is 

24 further implemented by regulation (50 CFR Part 402). The ESA makes it unlawful for a person 

25 to take a listed animal without a permit, where “take” under the ESA is defined as “to harass, 

26 harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such 

27 conduct.” Through regulations, the term “harm” is defined as “an act which actually kills or 

28 injures wildlife.” Such an act may include significant habitat modification or degradation where it 

29 actually kills or injures wildlife by significantly impairing essential behavioral patterns, including 

30 breeding, feeding or sheltering (50 CFR 17.3). Listed plants are not protected from take, 

31 although collecting or maliciously harming them on Federal land is illegal.

32 The FWS and the National Marine Fisheries Service jointly administer the ESA. The FWS 

33 manages the protection of and recovery efforts for listed terrestrial and freshwater species, and 

34 the National Marine Fisheries Service manages the protection of and recovery efforts for listed 

35 marine and anadromous species, of which none occur in the Illinois River near LSCS.

36 3.8.1 Action Area

37 The ESA regulations at 50 CFR 402.02 define “action area” to mean all areas to be affected 

38 directly or indirectly by the Federal action and not merely the immediate area involved in the 

39 action. The action area essentially bounds the analysis of ESA-protected species because 

40 species that occur within the action area may be affected by the Federal action, while species 

41 that do not occur within the action area would likely not be affected by the Federal action. The 

42 NRC staff recognizes that, although the action area is stationary, Federally listed species can 

43 move in and out of the action area. For instance, a migratory fish species could occur in the 

44 action area periodically and then travel to freshwater streams to spawn. Similarly, a flowering 

45 plant known to occur near, but outside of, the action area could appear within the action area 

46 over time if its seeds are carried into the action area by wind, water, or animals. Thus, in its 
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1 analysis, the NRC staff considers not only those species known to occur directly within the 

2 action area but also those species that may passively or actively move into the action area. The 

3 NRC staff then considers whether the life history of each species makes the species likely to 

4 move into the action area where it could be affected by the proposed LSCS license renewal. 

5 Depending on habitat requirements, migration patterns, or other biological or physical 

6 requirements, different species may require different action areas.

7 The LSCS site occupies about 1,528 ha (3,776 ac) in Marseilles, La Salle County, Illinois 

8 (Exelon 2015p), about 8 km (5 mi) south of the Illinois River (Exelon 2014a). A cooling pond on 

9 the eastern side of the site accounts for about half of the site area. A 5.6-km (3.5-mi) corridor 

10 for the makeup and blowdown pipelines—which travel underground from the Illinois River 

11 screen house south to the cooling pond—connects the cooling pond with the Illinois River, from 

12 which LSCS withdraws makeup water and discharges blowdown (Exelon 2014a). The intake 

13 structure on the Illinois River has bar grills, traveling screens with 3/8 in. (9.5 mm) openings, 

14 and no fish return system (Exelon 2014a). 

15 For Federally protected terrestrial species, the action area is the site, including the water intake 

16 and discharge pipe ROW, and areas immediately around the site that could include natural 

17 populations affected by plant operations. Within the action area, Federally listed terrestrial 

18 species could experience impacts such as habitat disturbance associated with transmission 

19 lines, exposure to radionuclides, and other direct and indirect impacts associated with station, 

20 cooling system, and in-scope transmission line operation and maintenance (NRC 2013).

21 For Federally protected aquatic species, the action area is the site and the Illinois River in the 

22 area affected by water withdrawal and discharge as well as the range of any species affected by 

23 water withdrawal and discharge. The license renewal of nuclear plants action can affect 

24 Federally listed aquatic species in several ways, such as impingement or entrainment of 

25 individuals into the cooling system, alteration of the riverine environment through water level 

26 reductions, changes in dissolved oxygen, gas supersaturation, eutrophication, thermal 

27 discharges from cooling system operation, habitat loss or alteration from dredging, and 

28 exposure to radionuclides (NRC 2013a).

29 3.8.2 Federally Protected Species and Habitats Considered

30 Exelon’s ER (2014a) documents correspondence between Exelon and the FWS about the 

31 effects of the proposed LSCS license renewal on Federally listed species. In July 2014, the 

32 FWS concurred with Exelon’s March 2014 conclusion that license renewal would not adversely 

33 affect any Federally listed species and noted that Exelon should consider an additional species: 

34 Northern long-eared bat, a proposed species known to occur in the plant vicinity. In 

35 August 2014, Exelon submitted a biological evaluation including the northern long-eared bat, 

36 and the FWS concurred with Exelon’s conclusion that license renewal would not affect any 

37 Federally listed species. Exelon (2014a, Appendix D) includes copies of this correspondence.

38 In late February 2015, NRC staff filled in an online form for an updated protected species list for 

39 LSCS on FWS’s Environmental Conservation Online System, Information for Planning and

40 Conservation. The FWS (2015b) responded with a list of threatened and endangered species

41 that may be affected by the LSCS license renewal. In October 2015, the NRC staff checked the 

42 FWS (2015a) online Illinois County distribution of listed species for updates. Exelon (2014a) 

43 reports that “no federally listed species have been observed on the LSCS property.” Terrestrial 

44 and wildlife studies conducted by Exelon associated with LSCS that may have discovered and 

45 reported Federally listed species are described in Section 3.6.2 of this SEIS.

46 Exelon commissioned several aquatic monitoring studies in the past, and none of them reported 

47 Federally listed species in the Illinois River near LSCS. EA (2000) reported the results of a 
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1 1999 monitoring study at three locations in the Illinois River upstream and downstream of the 

2 LSCS intake and discharge in late summer. Fish were sampled by electrofishing and seining 

3 and benthic macroinvertebrates by Ponar grab. The physical condition of fish put the study area 

4 in the poorest category using Ohio criteria, and a benthic macroinvertebrate (macrobenthos) 

5 community indicative of poor conditions was present. No Federally listed threatened or 

6 endangered species were observed.

7 EA (2014) reported results of fish and macrobenthos monitoring above and below LSCS in 

8 summer 2013 and compared results with past studies. Fish were sampled by electrofishing and 

9 seining and benthic macroinvertebrates by Ponar grab, kick net samplers, and artificial 

10 substrate samplers. No Federally listed threatened or endangered species were observed. 

11 EA (2015) reported results of impingement sampling from April 2014 through March 2015 and 

12 entrainment sampling in April through August 2014. No Federally listed fish or shellfish species 

13 were observed in entrainment or impingement samples.

14 Table 3–14 shows Federally listed species that may occur in LaSalle County near LSCS and 

15 habitat notes. Descriptions of the species follow.

16 Table 3–14. Federally Listed Species and Designated Habitat in La Salle 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

17 Sheepnose Mussel (Plethobasus cyphyus). The FWS listed the sheepnose mussel (also called 

18 just sheepnose) as endangered on March 13, 2012, with an effective date of April 12, 2012, but 

19 could not designate critical habitat at that time (77 FR 14914). The sheepnose mussel is a 

20 freshwater mussel in the family Unionidae. According to Parmalee and Bogan (1998), adult 
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1 mussels may reach 11 to 12 cm (4.3 to 4.8 in.) in length. Adult mussels are found partially or 

2 completely buried in the substrate. They are suspension feeders and eat bacteria, algae, 

3 microscopic animals, and detritus (77 FR 14914). Sheepnose is found in large rivers in gravel 

4 or mixed sand and gravel (INHS 2013). Further, in unimpounded rivers, sheepnose mussels 

5 can be found in less than 0.6 m (2 ft) of water and in relatively fast currents. In reservoirs, 

6 sheepnose mussels occupy depths of 3.6 to 4.6 m (12 to 15 ft) (Parmalee and Bogan 1998), 

7 though they have also been reported at depths exceeding 6 m (20 ft) (77 FR 14914). 

8 Sheepnose mussels are long-lived and can live nearly 100 to 200 years (FWS 2013b).

9 Like other unionids, sheepnose has an unusual life cycle. After fertilization, the eggs live in 

10 special gill chambers of the females and develop into microscopic larvae called glochidia. 

11 Females brood the glochidia. When the glochidia are ready, the female expels the glochidia, 

12 which then must attach to the host fish’s gills or fins to complete development by enclosing 

13 themselves in a cyst (encysting). They drop off the host fish as newly transformed juveniles. 

14 The sauger (Sander canadensis) is the only known natural host for sheepnose mussel 

15 glochidia. The FWS (77 FR 14914) reports that in laboratory studies, sheepnose glochidia 

16 have successfully transformed on several other species, including fathead minnow (Pimephales 

17 promelas), creek chub (Semotilus atromaculatus), central stoneroller (Campostoma anomalum), 

18 and brook stickleback (Culaea inconstans), although interactions between these species and 

19 sheepnose may be rare and infrequent in nature due to habitat preferences. The FWS (2015c) 

20 identifies golden shiner (Notemigonus crysoleucas) as another possible host species.

21 The sheepnose mussel is found across the Southeast and the Midwest, although it has been 

22 eliminated from about two-thirds of its range. Today, the sheepnose mussel is found in 

23 Alabama, Illinois, Indiana, Iowa, Kentucky, Minnesota, Mississippi, Missouri, Ohio, 

24 Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.

25 In a study for Exelon, EA (2014) sampled fish, benthic invertebrates, and physical and chemical 

26 parameters during summer 2013 in the Illinois River both upstream and downstream of LSCS

27 and compared the results to past studies for LSCS in 1974 through 1978 and 1999. EA 

28 sampled fish using electrofishing and seines and benthic invertebrates using artificial substrate 

29 samples and a grab sampler. EA found no threatened or endangered fish or macroinvertebrate 

30 species, including endangered mussels, near LSCS in this study or in past studies. 

31 Exelon (2014a) reports not observing any Federally listed species at LSCS.

32 Decurrent False Aster (Boltonia decurrens). Decurrent false aster is a flowering perennial plant 

33 in the aster family. The aster-like flowers appear from the tall (typically about 1.5 m (60 in.) or 

34 more), bushy plants from August to October, and the flower rays range in color from white to 

35 pale violet. “Decurrent” refers to leaf stem bases that run down along the stem where they 

36 attach. Decurrent false aster lives in the wet prairies in disturbed alluvial ground and open 

37 shores of floodplain forests along the Illinois and Mississippi Rivers, and historically ranged from 

38 LaSalle, Illinois, downstream to St. Louis, Missouri, on the Mississippi River. In 1988, the FWS

39 proposed to list the species as threatened (53 FR 5598) because it found only 12 extant 

40 populations remaining in 5 Illinois counties and one Missouri County. In addition, destruction 

41 and modification of the floodplain forest along the Illinois and Mississippi Rivers due to wetland 

42 drainage and agricultural expansion threatened survival of the species. In November 1988, the 

43 FWS determined the decurrent false aster to be a threatened species under the ESA but did not 

44 designate critical habitat (53 FR 45858). At that time, the FWS thought the species to be 

45 extirpated from 13 counties in Illinois and 3 counties in Missouri. Twelve remaining extant 

46 populations were located along the Illinois River in Morgan, Schuyler, Fulton, and Marshall 

47 Counties; one population along the Mississippi River in St. Clair County; and two populations in 

48 St. Charles County, Missouri. It was often found in disturbed alluvial soil where the forest 

49 overstory and understory are open due to frequent flooding. It prefers moist, sandy areas 
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1 around natural lakes in the Illinois River floodplain, but these areas now receive 2 or 3 in. (5 to 

2 7.5 cm) of silt per year due to extensive row crop agricultural practices and numerous levee 

3 systems that increase the amount of silt deposited on river banks during floods, and the silt 

4 prevents seed germination. 

5 The FWS initiated 5-year status reviews of decurrent false aster in 1990 and 2011, requested 

6 new information on the species, and found no reason to change the ESA threatened status. In 

7 its Recovery Plan that incorporated new information, FWS (1990) reported 18 known 

8 populations for this species in Illinois and 2 in Missouri, although not all were self-sustaining. In 

9 its 2012 5-year Review, FWS (2012b) found that research since the Recovery Plan indicated 

10 that this species may best be described as a metapopulation (a group of spatially separated 

11 populations of the same species that interact at some level) that colonizes and disappears from 

12 available habitat patches. In a metapopulation, as local populations fluctuate in size, they 

13 become vulnerable to extinction during periods when their numbers are low, and the regional 

14 persistence of the species depends on the existence of a metapopulation. Elimination of much 

15 of the metapopulation structure can increase the chance of regional extinction of the species.

16 The plant’s abundance appears to fluctuate widely in response to annual changes in site 

17 conditions and the dynamic Illinois River hydrology. In a metapopulation model of decurrent 

18 false aster (Smith et al. 2005), flood pulses characterized by spring floods and midsummer 

19 periods of low water maintain subpopulations and help establish new sub-populations. The 

20 flood pulses provide necessary disturbance and reduce competition to facilitate the colonization 

21 of habitats. Impoundment of the Illinois River and periodic prolonged high water events during 

22 the growing season have reduced available habitat and contributed to the species’ decline. The 

23 FWS has not reported extant populations in LaSalle County and Exelon (2014a) reports no 

24 threatened or endangered species on the LSCS site.

25 Eastern Prairie Fringed Orchid (Platanthera leucophaea). The eastern prairie fringed orchid is 

26 1 of at least 200 North American orchid species and is a perennial herb. Plants are about 8 to 

27 40 in. (0.2 to 1 m) tall. An upright leafy stem carries a flower cluster called an inflorescence. 

28 The 3- to 8-in. (76- to 200-cm) lance-shaped leaves sheath the stem. Each plant has one single 

29 flower spike composed of 5 to 40 creamy white flowers, and the blossoms often rise just above 

30 the height of the surrounding grasses and sedges. Blooming occurs in late June and early July. 

31 Night-flying hawkmoths (family Sphingidae) pollinate the nocturnally fragrant flowers 

32 (FWS 2013a).

33 This species typically inhabits tallgrass prairies east of the Mississippi River that have 

34 calcareous silt loam soils and calcareous wetlands with open portions of fends, sedge 

35 meadows, marshes, and bogs. While once numerous and widespread, populations have 

36 declined with the disappearance of eastern prairies by conversion of habitat for crop fields, 

37 grazing, intensive and continuous hay mowing, drainage, and related human uses. Other 

38 reasons for the decline include succession to woody vegetation, competition from non-native 

39 species, and over-collection. Remaining populations tend to be small, unprotected, and 

40 unmanaged. The FWS designated the eastern prairie fringed orchid as an endangered species

41 in 1989 (54 FR 39857) and in 2012 initiated a 5-year status review of the listing (77 FR 38762). 

42 The FWS did not designate critical habitat for this species. Exelon (2014a) reports not 

43 observing any Federally listed species on the LaSalle site.

44 Leafy Prairie-Clover (Delea foliosa). The FWS listed the leafy prairie-clover as endangered 

45 throughout its range in 1991 (56 FR 19953), when it was known to be present only in two sites 

46 in Alabama, nine sites in Tennessee, and three sites in Illinois. The FWS did not designate 

47 critical habitat for leafy prairie-clover. The species is perennial and a member of the pea family 

48 (Fabaceae). The plants grow erect stems about 0.5-m (1.5-ft) tall, on the end of which grow 
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1 small purple flowers in dense spikes. Flowering begins in August, and seeds ripen in early 

2 October, after which the above-ground portion of the plant dies while the below-ground portion 

3 survives the winter (56 FR 19953).

4 This plant is typically found in dry prairies, often in dolomitic soils. In Illinois, leafy prairie-clover 

5 was originally known from six counties in the northeastern part of the State, but by 1991 only 

6 three populations were known in the State, all in Will County in prairie remnants along the 

7 Des Plaines River (56 FR 19953). The U.S. Forest Service (USFS) (undated a) lists the 

8 reasons for its decline as plant and habitat loss from inundation by dams, road work, and 

9 right-of-way management, including herbicide effects; botanical and horticultural collection; 

10 off-road vehicle impacts to plants and habitat; predation by deer and rabbits; encroachment of 

11 woody plants; and severe drought. Its habitat is being lost as dolomite prairies are being 

12 converted to industrial, commercial, and residential uses (USFS undated b). Recovery efforts 

13 by a partnership of the FWS (Chicago Field Office), the USFS, the Forest Preserve District of 

14 Will County, the Department of the Army (Joliet Training Area), the IDNR, the Forest Preserve 

15 District of Kane County, and Midewin National Tallgrass Prairie are underway in northeastern 

16 Illinois (USFS undated b). Exelon (2014a) reports not observing any Federally listed species on 

17 the LSCS site.

18 Indiana Bat (Myotis sodalis). The FWS listed the Indiana bat as endangered in 1967 

19 (32 FR 4001). The FWS designated critical habitat for the Indiana bat in 1976 (41 FR 41914) to 

20 include 11 caves and 2 mines in six states, including a cave in LaSalle County, Illinois. The 

21 Indiana bat is an insectivorous, migratory bat that inhabits the central portion of the Eastern 

22 United States and hibernates colonially in caves and mines. The decline of Indiana bats is 

23 attributed to urban expansion, habitat loss and degradation, human-caused disturbance of 

24 caves or mines, insecticide poisoning, and white-nose syndrome (WNS) (FWS 2011; 

25 Pruitt and TeWinkel 2007).

26 During summer months, reproductive female bats tend to roost in colonies under slabs of 

27 peeling tree bark or cracks within trees in forest fragments, often near agricultural areas 

28 (Pruitt and TeWinkel 2007). Colonies may also inhabit closed-canopy, bottomland deciduous 

29 forest; riparian habitats; wooded wetlands and floodplains; and upland communities 

30 (Pruitt and TeWinkel 2007). Maternity colonies typically consist of 60 to 80 adult females 

31 (Whitaker and Brack 2002). Colonies occupy multiple trees for roosting and rearing young 

32 (Watrous et al. 2006) and, once established, usually return to the same areas each year 

33 (Pruitt and TeWinkel 2007). Nonreproductive females and males do not roost in colonies during 

34 the summer; they may remain near the hibernacula or migrate to summer habitat 

35 (Pruitt and TeWinkel 2007). A hibernaculum is an area where bats gather and hibernate in 

36 winter. High-quality summer habitat includes mature forest stands containing open 

37 subcanopies, multiple moderate- to high-quality snags, and trees with exfoliating bark 

38 (Farmer et al. 2002). In summer, bats forage for insects along forest edges, riparian areas, and 

39 in semi-open forested habitats. In the winter, Indiana bats rely on caves for hibernation. The 

40 species prefers hibernacula in areas with karst (limestone, dolomite, and gypsum), although it 

41 may also use other cave-like locations, such as mines.

42 The Indiana Bat Recovery Plan (Pruitt and TeWinkel 2007) indicates that Indiana bats are 

43 distributed across 36 of the 102 counties in Illinois. Twenty-two winter hibernacula (16 extant, 

44 4 of uncertain status, and 2 historic) are located throughout these counties. Additionally, 

45 29 extant maternity colonies occur in Illinois, and adult males, nonreproductive females, or both

46 have been captured during summer surveys within 26 of the 36 counties. For 2011, the 

47 FWS (2009) estimated that Illinois’s total population of Indiana bats was 54,095 individuals. 

48 According to more recent estimates, the Illinois population of Indiana bats has increased by 
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1 almost 2,000 over in 2011 to 55,956 individuals (FWS 2012a). Exelon (2014a) reports not 

2 observing any Federally listed species on the LSCS site.

3 Northern Long-Eared Bat (Myotis septentrionalis). In December 2013, the FWS (78 FR 72058) 

4 found that listing of the northern long-eared bat as an endangered species under the ESA was 

5 warranted. Earlier in October 2013, the FWS (78 FR 61046) had found that it could not 

6 determine critical habitat for this species. The FWS listed the northern long-eared bat as 

7 threatened throughout its range on April 2, 2015 (80 FR 17974). The following information is 

8 from those listing documents. The northern long-eared bat is a medium-sized bat species with 

9 average adult body weights of 5 to 8 grams (0.2 to 0.3 ounces), adult body lengths between 

10 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 

11 is typically brown, darker on top than below. The range includes much of the eastern and north 

12 central United States (it occurs in 39 states) and all Canadian provinces west to the southern 

13 Yukon Territory and eastern British Columbia. Throughout the majority of this range, however, it 

14 is patchily distributed, and historically it was less common in the southern and western part of its 

15 range than in the northern portion. The bats gather and hibernate in winter typically in mines 

16 and caves, where they are now usually found only in low numbers. They migrate out of the 

17 hibernacula in summer, when they forage at night and roost during daylight in small numbers in 

18 live and dead trees and change roosts often. Their diet includes moths, flies, leafhoppers, 

19 caddisflies, and beetles, although the diet differs geographically and seasonally, and an 

20 individual can consume 3,000 insects each night. Mating occurs in the autumn and birthing in 

21 May or June. Mature forests are an important habitat type for northern long-eared bats, 

22 although they occasionally act as forager over forest clearings and along roads. The northern 

23 long-eared bat has experienced a sharp decline, estimated at approximately 99 percent from 

24 hibernaculum data, in the northeastern portion of its range due to the recent emergence of a 

25 fungal disease known as WNS (currently called Geomycetes destructans), and the FWS 

26 expects similar declines in the western part of its range as this disease spreads. The 

27 FWS (2013c) confirmed the existence of WNS in northern long-eared and little brown bats from 

28 LaSalle and Monroe Counties, Illinois. Human activities that threaten this species include 

29 constructing physical barriers at cave accesses and destruction of habitat through mining, 

30 flooding, vandalism, development, timber harvest, and other activities. Exelon (2014a) reports 

31 not observing any Federally listed species on the LSCS site.

32 Summary of the Occurrence of Listed Species within the Action Area. The six species listed in 

33 Table 3–14 are under the FWS’s jurisdiction within LaSalle County, although the information is 

34 not specific to the LSCS site. For the six species identified for LaSalle County, the NRC staff 

35 did not identify any within the action area after review of the ER (Exelon 2014a), a site visit that 

36 included discussions with site staff and review of onsite documents, and published and online 

37 sources. Sections 3.6 Terrestrial Resources and 3.7 Aquatic Resources summarize the 

38 ecological surveys performed on and near the LSCS site that would detect protected species. 

39 Exelon (2014a) reports not observing any Federally listed species on the LSCS site.

40 3.9 Historic and Cultural Resources

41 This section discusses the cultural background and the known historic and cultural resources

42 found on or near LSCS. The discussion is based on a review of historic and cultural resource 

43 surveys and other background information on the region surrounding LSCS. In addition, a 

44 records search was performed via the Illinois Historic Preservation Agency to obtain the most 

45 updated information about historic and cultural resources in the region. 

46 The Area of Potential Effect (APE) is the area at the LSCS power plant site, the transmission 

47 lines up to the first substation, and immediate environs that may be affected by the license 
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1 renewal decision and land-disturbing activities associated with continued reactor operations. 

2 For this analysis, the first substation (345 kV LSCS switchyard) is located on the LSCS site 

3 (Exelon 2014a). The APE may extend beyond the immediate environs in instances where 

4 land-disturbing maintenance and operations activities during the license renewal term or 

5 refurbishment activities could potentially have an effect. In the case of LSCS, the APE includes 

6 the corridor between the cooling pond and the Illinois River containing the makeup and 

7 blowdown water pipelines within the site boundary. These pipelines traverse a distance of 

8 approximately 5.6 km (3.5 mi) from the cooling pond to the Illinois River. See Figure 3–3.

9 3.9.1 Cultural Background

10 Human occupation near the LSCS site is generally characterized according to the following 

11 chronological sequence (Pauketat 1993):

12 • Paleo-Indian Period (12,000 – 10,000 before present (BP)),

13 • Archaic Period (10,000 – 3,000 BP),

14 • Woodland Period (3,000 – 1,100 BP),

15 • Mississippian Period (1,100 – 400 BP (ca. A.D. 900 – 1600)), and

16 • Protohistoric/Historic Period (400 – present (ca. A.D. 1600 – present)).

17 Paleo-Indian Period (12,000 – 10,000 B.P.). The earliest evidence of people living in Illinois 

18 dates to the Paleo-Indian Period. Paleo-Indian sites are generally found upland or on river 

19 terraces and are characterized by specific types of projectile points (i.e., fluted Clovis and 

20 Folsom points) and stone tools such as gravers, scrapers or large blades. These artifacts often

21 occur in association with mastodon remains, suggesting a reliance on megafauna 

22 (e.g., mammoth, ground sloth, and saber-tooth tiger) for subsistence along with plants, small 

23 game, birds, and amphibians. Social organization consisted of small, highly nomadic bands of 

24 hunter-gathers, leaving Paleo-Indian sites with little detailed archaeological information 

25 (Neusius and Gross 2007; Pauketat 1993).

26 Archaic Period (10,000 – 3,000 B.P.). The Archaic Period was a time of major climatic shifts as 

27 colder environments transitioned to warmer environments similar to modern conditions. In 

28 response to this shift, new technologies and subsistence strategies were developed during this 

29 time. The Archaic Period is often divided into early, middle, and late subperiods. The Early 

30 Archaic Period is characterized by a shift from nomadic to sedentary settlement patterns, with 

31 central base camps located on river terraces and smaller hunting camps located in upland 

32 areas. This subperiod also shows an increased reliance on wild plant foods, small game, and 

33 aquatic resources. The Middle Archaic Period is characterized by an increased number of 

34 settlement sites on high stream terraces, which may reflect population increases. While 

35 subsistence and settlement patterns remained fairly similar to the Early Archaic Period, artifact 

36 assemblages suggest increased exploitation of aquatic resources as well as new artifacts such 

37 as pecked and ground stone tools used for intensive processing of nuts; banner stones that 

38 signaled the innovation of a new projectile technology called the atlatl or spear-thrower; and 

39 grooved axes. The Late Archaic Period is characterized by an increase in the number and size 

40 of settlement sites, which indicates an increase in population and a more sedentary lifestyle. 

41 New features of Late Archaic artifact assemblages, such as crude ceramic vessels, represent a 

42 shift towards increased reliance on horticulture as a subsistence strategy, although hunting and 

43 gathering would have continued (Fagan 2005; Neusius and Gross 2007; Pauketat 1993).

44 Woodland Period (3,000 – 1,100 B.P.). The Woodland Period is also often divided into early, 

45 middle, and late periods. However, the distinction between the early and middle period is not 
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1 fixed. The Woodland Period is marked by an increase in more permanent settlements, changes 

2 in burial practices, increased cultivation of plants such as sunflowers and cucurbits 

3 (e.g., squashes, gourds, melons), and a rise in the manufacture and use of pottery 

4 (Fagan 2005). During the Middle Woodland Period, the large and complex Hopewell Culture 

5 emerged in the northeastern and Midwestern United States, including Illinois. This culture is 

6 characterized by settlement in villages, increased reliance on intensive horticulture, burial 

7 mounds, and long distance trade networks. These long distance networks allowed the trade of 

8 exotic materials, such as marine shells from the Gulf Coast, obsidian from the Rocky Mountains, 

9 copper from Lake Superior, and mica from the Appalachian Mountains far outside their 

10 immediate locations. Evidence of the Illinois Hopewell culture is found primarily in the bluffs and 

11 floodplains of the Illinois River Valley. The burial mounds of this period often included central 

12 features, lined with logs, and filled with grave goods. Different burial treatments within the 

13 mounds point to social stratification within society, but through sex and age rather than 

14 hereditary lineage (Neusius and Gross 2007). The Late Woodland Period is characterized by 

15 an increase in settlement sites, which suggests (a) a rise in population, or (b) a change in 

16 settlement patterns from large, centralized village sites to smaller, dispersed habitation sites, or 

17 both (Fagan 2005).

18 Mississippian Period (1,100 – 400 B.P. (ca. A.D. 900 – 1600)). The Mississippian Period is 

19 characterized by major changes in settlement, subsistence patterns, and social structure. Large 

20 highly centralized chiefdoms with permanent settlements sites supported by numerous satellite 

21 villages emerged during this period. The platform mound, a new ceremonial earthen mound 

22 appeared in association with these permanent settlements. Platform mounds, burial mounds, 

23 and defensive structures, such as moats and palisades, were often constructed in clusters in 

24 settlements of this period and were common in the larger river valleys of the Midwest. 

25 Mississippian Period subsistence relied heavily on maize agriculture, as well as hunting and 

26 gathering. Long distance trading increased and craft specialists produced highly specialized 

27 lithic and ceramic artifacts, beadwork and shell pendants (Fagan 2005). Examples of 

28 Mississippian Period occupation within LaSalle County is the Starved Rock State Park area. 

29 Starved Rock is a 1,065 ha (2,632 ac) area along the south bank of the Illinois River between 

30 the towns of LaSalle and Ottawa, Illinois. Mississippian period artifacts have been found in 

31 some 62 sites in the region surrounding Starved Rock State Park with 16 sites recorded in the 

32 park itself (DOI 1998).

33 Protohistoric/Historic Period (A.D. 1600 – Present). The end of the Mississippian Period is 

34 characterized by severe social, political, and demographic changes that resulted from indirect 

35 and direct contact with Europeans. In particular, it is believed that the introduction of European 

36 infectious diseases such as smallpox, typhoid, and influenza severely decimated Native 

37 American populations, which had no immunity to these diseases. The spread of these 

38 diseases, which were fatal to large numbers of Native Americans, resulted in the widespread 

39 abandonment of villages and a concurrent collapse of Native American socioeconomic 

40 networks, such that by the time of widespread European contact and settlement, the 

41 Mississippian chiefdoms were gone (Fagan 2005). During the historic period, Illinois was 

42 primarily populated with a confederation of tribes known as the Illinois, or Illiniwek, and the 

43 Miami tribe. During the 1700s and early 1800s, new tribes migrated to Illinois, including the 

44 Iroquois, Fox (Mesquakie), Ioway, Kickapoo, Mascouten, Piankashaw, Potawatomi, Sauk, 

45 Shawnee, Wea, and Winnebago. Competition for resources led to sporadic war among the 

46 Illinois, surrounding tribes, and European immigrants to the area for approximately the next 

47 120 years (ISM 2002). In approximately 1673, French explorers traveled along the Mississippi 

48 River and up the Illinois River to present-day LaSalle County. Robert Cavalier, also known as 

49 Louis de La Salle, made the first European settlement in LaSalle County. French influence in 

50 the Illinois territory began to wane by the mid-1700s due to being ejected from the area by the 
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1 British. Illinois became part of the Northwestern Territory at the close of the American 

2 Revolution. LaSalle County was organized by the Illinois legislature during the 1830–1831 

3 legislative session (Baldwin 1877). The State of Illinois joined the Union in 1818. The area 

4 surrounding the LSCS site has principally been used for agriculture and coal mining from this 

5 period onward (Exelon 2014a).

6 3.9.2 Historic and Cultural Resources

7 LSCS historic and cultural resources include prehistoric era and historic era archaeological

8 sites, historic districts, and buildings, as well as any site, structure, or object that may be 

9 considered eligible for listing on the National Register of Historic Places (NRHP). Historic and 

10 cultural resources also include traditional cultural properties that are important to a living 

11 community of people for maintaining their culture. “Historic property” is the legal term for a 

12 historic or cultural resource that is eligible for listing on the NRHP.

13 A review of databases maintained by the National Park Service (NPS) indicates that there are 

14 31 properties listed in the NRHP within LaSalle County, including three that have been 

15 designated as National Historic Landmarks (DOI 2015). These historic properties reflect the 

16 historic cultural contexts for the LSCS property and include Starved Rock State Park, and 

17 structures and districts dating from the mid-18th through mid-20th centuries. None of the 

18 historic properties is located within the boundaries of the LSCS property (DOI 2015). The 

19 closest NRHP site is the Illinois and Michigan Canal (NR200462), approximately 5 mi (8 km) to 

20 the north of the plant.

21 A number of surveys of the LSCS site were conducted between 1972 and 1994. In 1972, a 

22 Phase I archaeological survey was done by the Illinois Archaeological Survey of the LSCS 

23 site—originally known as the Collins Generating Station. Five sites were discovered on LSCS 

24 property. However, these sites were not recorded or evaluated because, in 1972, isolated finds 

25 were not recognized as sites and therefore not evaluated. Three of the sites were assigned 

26 Illinois Archaeological Survey accession numbers—LS00207, LS00208, and LS00209. The 

27 1972 survey concluded that construction of the LSCS would not significantly affect 

28 archaeological resources (Exelon 2014a). These findings were accepted by the NRC in its Final 

29 Environmental Statement for LSCS issued in 1978 (NRC 1978). In 1993, the Illinois 

30 Department of Military Affairs did a survey to support the siting of a military training area 

31 immediately northwest of LSCS. This survey found 48 archaeological sites, one of which is 

32 located on the LSCS site—LS00514. This site was also determined not to be NRHP eligible 

33 (Exelon 2014a).

34 The NRC staff searched the Illinois State Archaeological Site Files, a database maintained by 

35 the Illinois State Historic Preservation Officer, and identified the LSCS sites listed in the 

36 1972 and 1993 surveys as well as one additional site—LS00527—which was determined to be 

37 NRHP ineligible. No other cultural resources within the current confines of the LSCS site were 

38 identified (NRC 2015c).

39 3.10 Socioeconomics

40 This section describes current socioeconomic factors that have the potential to be directly or 

41 indirectly affected by changes in operations at LSCS. LSCS, and the communities that support 

42 it, can be described as a dynamic socioeconomic system. The communities supply the people, 

43 goods, and services required to operate the nuclear power plant. Power plant operations, in 

44 turn, supply wages and benefits for people and dollar expenditures for goods and services. The 

45 measure of a community’s ability to support LSCS operations depends on its ability to respond 

46 to changing environmental, social, economic, and demographic conditions.
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1 3.10.1 Power Plant Employment and Expenditures

2 The socioeconomics region of influence (ROI) is defined by the areas where LSCS employees 

3 and their families reside, spend their income, and use their benefits, thus affecting the economic 

4 conditions of the region. Exelon employs a permanent workforce of approximately 

5 890 employees and 30 long-term contract employees (Exelon 2014a). Approximately 

6 83 percent of LSCS employees reside in a three-county area in northeastern Illinois in Grundy, 

7 LaSalle, and Will Counties. Most of the remaining 17 percent of the workforce are spread 

8 among 23 other counties in Illinois, with numbers ranging from 1 to 40 employees per county 

9 (Exelon 2014a). Given the residential locations of LSCS employees, the most significant effects 

10 of plant operations are likely to occur in Grundy, LaSalle, and Will Counties.

11 Table 3–15 summarizes the LSCS workforce geographic distribution. The focus of the 

12 socioeconomic impact analysis in this SEIS is, therefore, on the impacts of continued LSCS 

13 operations on these three counties, also termed the ROI.

14 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 2014

15 Exelon purchases goods and services to facilitate LSCS operations. While specialized 

16 equipment and services are procured from a wider region, some proportion of the goods and 

17 services used in plant operations are acquired from within the ROI. These transactions fuel a 

18 portion of the local economy, as jobs are provided and additional local purchases are made by 

19 plant suppliers.

20 The LSCS units are on staggered 24-month refueling cycles lasting approximately 25 days 

21 each. During refueling outages, site employment typically increases by an additional 

22 800 temporary workers (Exelon 2014a). Approximately 75 to 80 percent of the outage workers 

23 are permanent residents of the ROI. The remaining 20 to 25 percent stay in Morris, Ottawa, or 

24 Joliet, Illinois (Exelon 2014a).

25 3.10.2 Regional Economic Characteristics

26 This section presents information on employment and income in the LSCS socioeconomic ROI. 

27 Grundy and LaSalle counties are predominantly rural with agricultural and forested land 

28 comprising the majority (90 percent) of the land use in the county. Conversely, Will County is 

29 more urban with developed land comprising about 34 percent of total land area in the county 

30 (USDA 2015a).
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1 3.10.2.1 Employment and Income

2 From 2010 to 2014, the labor force in the LSCS ROI decreased approximately 0.8 percent to 

3 approximately 440,000. However, the number of employed persons increased by about 

4 3.4 percent, to approximately 406,000. Consequently, the number of unemployed people in the 

5 ROI decreased by 33.6 percent, by approximately 17,000 persons to approximately 33,000, or 

6 about 7.6 percent of the current workforce—down from 11.3 percent in 2010 (BLS 2015).

7 According to the U.S. Census Bureau’s (USCB’s) 2014 “American Community Survey 1-Year 

8 Estimates” for LaSalle and Will Counties and 2009-2013 “American Community Survey 5-Year 

9 Estimates” for Grundy County, the educational, health, and social services industry represented 

10 the largest employment sector in the socioeconomic ROI (22.8 percent) followed by 

11 manufacturing and retail (both at 12 percent) (USCB 2015a). A list of employment by industry in 

12 each county of the ROI is provided in Table 3–16.

13 Table 3–16. Employment by Industry in the LSCS ROI

14 (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

15 Major employers in LaSalle County, the county in which LSCS is located, are listed in 

16 Table 3–17. Exelon is shown as the largest employer in the county.
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1 Table 3–17. Major Employers in LaSalle County in 2009

Employer Number of Employees

Exelon Generation 890

OSF, Saint Elizabeth Medical Center 730

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

2 Estimated income information for the LSCS ROI is presented in Table 3–18. According to the 

3 USCB’s 2014 American Community Survey 1-year estimates, 10.5 percent of families and 

4 14.4 percent of individuals in Illinois were living below the Federal poverty threshold and the 

5 median household and per capita income for Illinois was $57,444 and $30,417, respectively 

6 (USCB 2015b). In the socioeconomic ROI, people living in LaSalle County had median 

7 household and per capita incomes below the State average. The median household and per 

8 capita income average in LaSalle County was $50,432 and $25,129, respectively, with 

9 9.6 percent of families and 13.3 percent of individuals living below the poverty level. 

10 Conversely, Will County had a higher median household and per capita income average 

11 ($74,828 and $32,148, respectively) and a lower percentage of families (6.3 percent) and 

12 individuals (7.9 percent) living below the official poverty level. According to the USCB’s 

13 “2011-2013 American Community Survey 3-Year Estimates,” Grundy County also had higher 

14 median household and per capita income averages ($63,978 and $28,465, respectively) and 

15 lower percentages of families (7.2 percent) and individuals (9.4 percent) living below the poverty 

16 level than the State of Illinois and LaSalle County (USCB 2015b).

17 Table 3–18. Estimated Income Information for the LSCS ROI

18 (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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1 3.10.2.2 Unemployment

2 According to the USCB’s 2014 American Community Survey estimates, the unemployment 

3 rates in LaSalle County and the State of Illinois were 8.1 and 10.5 percent, respectively. 

4 Comparatively, the Will County unemployment rate during this same time period was 

5 6.0 percent. According to the USCB’s 2013 American Community Survey 3-year estimates, the 

6 unemployment rates in Grundy County was 9.6 percent (USCB 2015c).

7 3.10.3 Demographic Characteristics

8 According to the 2010 Census, an estimated 103,000 people lived within 20 mi (32 km) of 

9 LSCS, which equates to a population density of approximately 81 persons per square mile 

(persons/mi2 10 ) (CAPS 2014). This translates to a Category 3, “least sparse” population density 

using the GEIS measure of sparseness (60 to 120 persons/mi 11 2 within 20 mi). An estimated 

12 1,926,000 people live within 50 mi (80 km) of LSCS with a population density of approximately 

245 persons/mi2 13 (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/mi 14 2 within 

15 50 mi). Therefore, LSCS is located in a high population area based on the GEIS sparseness 

16 and proximity matrix.

17 Table 3–19 shows population projections and percent growth from 1980 to 2060 in the 

18 three-county LSCS ROI. The ROI population continues to increase over the past two decades 

19 (2000 and 2010). Based on forecasts, the population is expected to continue these trends at 

20 moderate to high rates. Population projections for years 2020 and 2040 shown in the table 

21 were developed for the Illinois Department of Transportation.

22 Table 3–19. Population and Percent Growth in LSCS ROI Counties 1980–2010, 2014 

23 (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.

24 The 2010 Census demographic profile of the three-county ROI population is presented in Table 

25 3–20. According to the 2010 Census, minorities (race and ethnicity combined) comprised 

26 28.6 percent of the total three-county population. The largest minority populations in the ROI 
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1 were Hispanic or Latino of any race (14.1 percent) and Black or African American (9.2 percent) 

2 (USCB 2015e).

3 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

4 According to the USCB’s 2014 and 2013 American Community Survey estimates, since 2010 

5 minority populations in the ROI were estimated to have increased by approximately 

6 17,700 persons and now comprise 30.5 percent of the ROI population (see Table 3–21). The 

7 largest increase occurred in the Hispanic or Latino population (nearly 8,900 persons since 2010, 

8 an increase of 7.5 percent). The next largest increase in minority population was Asian, an 

9 increase of approximately 5,800 persons or 18.5 percent from 2010 (USCB 2015f).

10 Table 3–21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County)

Grundy(a) 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(a) 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

(a) 2011-2013 “American Community Survey 3-Year Estimates.”

Source: USCB 2015f

1 3.10.3.1 Transient Population

2 Within 50 mi (80 km) of LSCS, colleges and recreational opportunities attract daily and seasonal 

3 visitors who create a demand for temporary housing and services. In 2015, approximately 

4 57,000 students attended colleges and universities within 50 mi (80 km) of LSCS 

5 (NCES 2015a).

6 Based on “2009-2013 American Community Survey 5-Year Estimates,” approximately 

7 23,000 seasonal housing units are located within 50 mi (80 km) of LSCS. Of those, 1,785 were 

8 located in the LSCS ROI. Table 3–22 presents information about seasonal housing for the 

9 counties located all or partly within 50 mi (80 km) of LSCS.

10 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

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

1 3.10.3.2 Migrant Farm Workers

2 Migrant farm workers are individuals whose employment requires travel to harvest agricultural 

3 crops. These workers may or may not have a permanent residence. Some migrant workers 

4 follow the harvesting of crops, particularly fruit, throughout rural areas of the United States. 

5 Others may be permanent residents living near LSCS and travel from farm to farm harvesting 

6 crops.

7 Migrant workers may be members of minority or low-income populations. Because they travel 

8 and can spend a significant amount of time in an area without being actual residents, migrant 

9 workers may be unavailable for counting by census takers. If uncounted, these minority and 

10 low-income workers would be “underrepresented” in the decennial Census population counts.

11 In the 2002 Census of Agriculture, farm operators were asked for the first time whether or not 

12 they hired migrant workers—defined as a farm worker whose employment required travel—to 

13 do work that prevented the migrant workers from returning to their permanent place of residence 

14 the same day. The Census is conducted every 5 years and results in a comprehensive 

15 compilation of agricultural production data for every county in the nation.

16 Information about migrant and temporary labor (working less than 150 days) was collected in 

17 the 2012 Census of Agriculture. Table 3–23 supplies information about migrant and temporary 

18 farm labor within 50 mi (80 km) of LSCS. According to the 2012 Census, approximately 

19 12,000 farm workers were hired to work for less than 150 days and were employed on 

20 5,563 farms within 50 mi (80 km) of LSCS. The county with the highest number of temporary 

21 farm workers (1,101) on 253 farms was DeKalb County, Illinois (NASS 2015).
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1 Table 3–23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 

2 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)

3 A total of 71 farms, in the 50-mi (80 km) radius of the LSCS, reported hiring migrant workers in 

4 the 2012 Census. Kankakee County, Illinois, reported the most farms with migrant farm labor 

5 (17 farms) (NASS 2015).

6 3.10.4 Housing and Community Services

7 This section presents information regarding housing and local public services, including 

8 education and water supply.
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1 3.10.4.1 Housing

2 Table 3–24 lists the total number of occupied and vacant housing units, vacancy rates, and 

3 median value in the ROI. Based on USCB’s 2014 American Community Survey estimates, 

4 there were nearly 310,000 housing units in the ROI, of which nearly 285,000 were occupied. 

5 The median values of owner-occupied housing units in the ROI range from $121,700 in LaSalle 

6 County to $209,400 in Will County. The vacancy rate also varied considerably between the 

7 three counties, from 6.6 percent in Will County to 13.9 percent in LaSalle County 

8 (USCB 2015h).

9 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

10 3.10.4.2 Education

11 Grundy County has 12 public school districts with 24 public schools and approximately 

12 13,000 students during the 2013-2014 school year. LaSalle County, the county in which LSCS

13 is located, has 26 public school districts with 47 public schools and approximately 

14 17,000 students during the 2013-2014 school year. Will County has 30 public school districts 

15 with 171 public schools and approximately 117,000 students during the 2013-2014 school year 

16 (NCES 2015b). 

17 3.10.4.3 Public Water Supply

18 The City of LaSalle pumps and treats groundwater. The city's water treatment and distribution

19 system serves the City of LaSalle. The City of LaSalle treatment plant has a treatment capacity 

20 of approximately 500,000 gallons per day. Water and wastewater treatment services are 

21 provided by a number of townships and municipalities in LaSalle County which service 

22 residential, commercial, and industrial customers. Other residents within the county are served 

23 by private, onsite well and wastewater disposal systems.

24 Table 3–25 lists the largest public water suppliers in Grundy, LaSalle, and Will Counties and 

25 provides water source and population served for those suppliers. Most of the major public water 

26 suppliers in Grundy, LaSalle, and Will Counties obtain their supplies from groundwater. 

27 Currently, there is excess capacity in every major public water system in the three counties.
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1 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
Affected Environment

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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 2015e

1 3.10.5 Tax Revenues

2 Exelon pays taxes on LSCS property to LaSalle County, public schools, libraries, townships, 

3 districts, and other taxing authorities. Property taxes paid by Exelon for LSCS for the years of 

4 2007 through 2013 are listed in Table 3–26. As shown in the table, total property tax payments 

5 for the reported years fluctuated from year to year. 

6 Property taxes paid on LSCS are based partially on settlement agreements for the valuation of 

7 the power block, with the remaining land taxed on the assessment of fair market value, as 

8 established by Illinois State tax law. Power block tax payments have been approximately 

9 98 percent of the total tax payment. Settlement agreements in 1999 and 2006 covered the 

10 years 2000 through 2004 and 2005 through 2008, respectively. Negotiations for the next 

11 settlement agreement began in 2009 and was not completed until mid-2013. Consequently, 

12 without the settlement agreement, the LaSalle County tax assessor increased the assessed 

13 value of the LSCS power block, which resulted in sharply increased tax payments by Exelon. 

14 As shown in Table 3–26, tax payments more than doubled in 2009 in keeping with the increased 

15 assessment of the power block made by the County Assessor, as affirmed or amended on 

16 appeal by the LaSalle County Board of Review. Based on independent appraisals, Exelon 

17 appealed the assessments for tax years 2009 through 2012 to the Illinois Property Tax Appeal 

18 Board because the company did not believe the assessments accurately reflected the value of 

19 the LSCS power block. In July 2013, Exelon and all taxing bodies agreed to a new long-term 

20 settlement agreement that sets the Equalized Assessed Value of the LSCS power block for the 

21 next 7 years, starting with the 2013 tax year. The settlement agreement was fully executed and 

22 approved by the Court for the 13th Judicial District in LaSalle County, Illinois, in February 2014. 

23 At the request of all parties, the Property Tax Appeal Board dismissed the appeals with 

24 prejudice in May 2014 (Exelon 2014a).

25 Exelon intends to negotiate additional tax settlement agreements during the license renewal 

26 term, as it helps the company and taxing authorities plan for future income revenue and 

27 expenditures (Exelon 2014a).

28 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
Affected Environment

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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) 3,033,333,333 22,490,721

(a) Under settlement agreement.

(b) Set by Board of Review.

NA=Not available.

Source: Exelon 2014a, 2015c

1 Taxes paid in 2013 to local taxing bodies constitute between 94 percent and less than 1 percent 

2 of the total levy for any individual taxing body, as shown in Table 3–27. Tax payments under 

3 any new settlement agreement would likely continue at similar percentages (Exelon 2014a). 

4 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 2014a
Affected Environment

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1 In addition, Exelon makes annual payments to the Illinois Emergency Preparedness Agency for 

2 LSCS. These annual payments are listed in Table 3–28. Smaller amounts are paid on an 

3 intermittent and voluntary basis to local emergency management agencies and government 

4 agencies that participate in emergency management activities. 

5 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 2014a

6 Exelon anticipates no change in State or local tax laws, rates or assessments that would result 

7 in notable future increases or decreases in property taxes or other payments to State or local 

8 governments with respect to LSCS during the license renewal term. However, new property tax 

9 settlement agreements could result in higher property tax assessments and higher property tax 

10 payments. 

11 3.10.6 Local Transportation

12 The region surrounding LSCS has a highly developed roadway network. Interstate 80 (I-80) 

13 runs east and west approximately 8 mi (13 km) north of LSCS. Interstate 55 runs northeast to 

14 southwest approximately 15 mi (24 km) east of LSCS. US-51/I-39 runs north and south 

15 approximately 21 mi (35 km) west of LSCS. Interstate 80 and I-55 provide access to the LSCS 

16 site from Chicago to the northeast.

17 County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, runs parallel to 

18 LSCS’s southern boundary and provides access to the LSCS site. State Highway 170 is 0.5 mi 

19 (0.8 km) east of the site and County Road 30, also known as East 25th Road, is slightly west of

20 the site. The Chicago, Rock Island & Pacific Railroad is the closest railroad line to LSCS. It 

21 runs parallel to and slightly north of the Illinois River. A 6 mi (10 km) rail spur connects LSCS to 

22 the Atchison, Topeka, and Santa Fe Railroad south of the site (Exelon 2014a).

23 Table 3–29 lists commuting routes to the LSCS site and average annual daily traffic volume 

24 values. The average annual daily traffic values represent traffic volumes for a 24-hour period 

25 factored by both the day of the week and the month of the year.

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

27 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
Affected Environment

3-96

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

1 3.11 Human Health

2 3.11.1 Radiological Exposure and Risk

3 As required by NRC regulation 10 CFR 20.1101, Exelon has a radiation protection program 

4 designed to protect onsite personnel, including employees, contractor employees, visitors, and 

5 offsite members of the public from radiation and radioactive material generated at LSCS. 

6 The radiation protection program is extensive and includes, but is not limited to the following:

7 • Organization and Administration (i.e., a Radiation Protection Manager who is

8 responsible for the program and having trained and qualified workers),

9 • Implementing procedures,

10 • ALARA Program to minimize dose to workers and members of the public,

11 • Dosimetry Program (i.e., measure radiation dose of plant workers),

12 • Radiological Controls (i.e., protective clothing, shielding, filters, respiratory

13 equipment, and individual work permits with specific radiological requirements),

14 • Radiation Area Entry and Exit Controls (i.e., locked or barricaded doors, interlocks,

15 local and remote alarms, personnel contamination monitoring stations),

16 • Posting of Radiation Hazards (i.e., signs and notices alerting plant personnel of

17 potential hazards),

18 • Record Keeping and Reporting (i.e., documentation of worker dose and radiation

19 survey data),
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1 • Radiation Safety Training (i.e., classroom training and use of mockups to simulate 

2 complex work assignments),

3 • Radioactive Effluent Monitoring Management (i.e., control and monitor radioactive

4 liquid and gaseous effluents released into the environment),

5 • Radioactive Environmental Monitoring (i.e., sampling and analysis of environmental

6 media, such as air, water, vegetation, food crops, direct radiation, and milk to

7 measure the levels of radioactive material in the environment that may impact human

8 health), and

9 • Radiological Waste Management (i.e., control, monitor, process, and dispose of

10 radioactive solid waste).

11 Regarding the radiation exposure to LSCS personnel, the NRC staff reviewed the data 

12 contained in NUREG–0713, “Occupational Radiation Exposure at Commercial Nuclear Power 

13 Reactors and Other Facilities 2012: Forty-Fifth Annual Report” (NUREG–0713, Volume 34) 

14 (NRC 2014b). This report, which was the most recent available at the time of this review, 

15 summarizes the occupational exposure data through 2012 that are maintained in the NRC’s 

16 Radiation Exposure Information and Reporting System database. Nuclear power plants are 

17 required by 10 CFR 20.2206 to report their occupational exposure data to the NRC annually.

18 NUREG–0713 calculates a 3-year average collective dose per reactor for all nuclear power 

19 reactors licensed by the NRC. The 3-year average collective dose is one of the metrics that the 

20 NRC uses in the Reactor Oversight Program to evaluate the applicant’s ALARA program. 

21 Collective dose is the sum of the individual doses received by workers at a facility licensed to 

22 use radioactive material over a 1-year time period. There are no NRC or EPA standards for 

23 collective dose. Based on the data for operating BWRs like those at LSCS, the average annual 

24 collective dose per reactor was 133 person-rem. In comparison, LSCS had a reported annual 

25 collective dose per reactor of 158 person-rem.

26 In addition, as reported in NUREG–0713, for 2012, no worker at LSCS received an annual dose

27 greater than 2.0 rem (0.02 Sv), which is less than half of the NRC occupational dose limit of 

28 5.0 rem (0.05 Sv) in 10 CFR 20.1201.

29 3.11.2 Chemical Hazards

30 The use, storage, and discharge of chemicals, biocides, and sanitary wastes, as well as minor 

31 chemical spills are regulated by state and Federal environmental agencies. Chemical hazards 

32 to LSCS’s workers during the license renewal term are expected to be minimized by 

33 implementing good industrial hygiene practices as required by Federal and State regulations. 

34 Discharges of chemical and sanitary wastes are monitored and controlled as part of the LSCS’s 

35 NPDES permit IL0048151 to minimize impacts to the public and the environment 

36 (Exelon 2014a).

37 3.11.3 Microbiological Hazards

38 Nuclear plants such as LSCS that discharge thermal effluents to cooling ponds, lakes, canals, 

39 or rivers have the potential to promote the increased growth of thermophilic microorganisms, 

40 which could result in adverse health effects for plant workers and the public. Microorganisms of 

41 particular concern include several types of bacteria (Legionella spp., Salmonella spp., 

42 Shigella spp., thermophilic fungi, and Pseudomonas aeruginosa) and the free-living amoeba 

43 Naegleria fowleri. 
Affected Environment

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1 Nuclear plant workers can be exposed to Legionella spp. when performing maintenance 

2 activities on plant cooling systems if workers inhale cooling tower vapors because vapors are 

3 often within the optimum temperature range for Legionella growth. Plant personnel most likely 

4 to come in contact with Legionella aerosols would be workers who clean biofilms off of 

5 condenser tubes, cooling towers, and related system components or equipment. Exposure of 

6 the public to Legionella from nuclear plant operations is generally not a concern because 

7 Legionella exposure would be confined to a small area of the site within the protected area. 

8 LSCS does not have cooling towers so exposure of workers to Legionella is unlikely.

9 The public can be exposed to the thermophilic microorganisms Salmonella, Shigella, 

10 P. aeruginosa, and N. fowleri during swimming, boating, or other recreational uses of 

11 freshwater. If a nuclear plant’s thermal effluent enhances the growth of thermophilic 

12 microorganisms, recreational users could experience an elevated risk of exposure when using 

13 waters near the plant’s discharge. 

14 3.11.3.1 Thermophilic Microorganisms of Concern

15 Legionella is a genus of common warm water bacteria that occurs in lakes, ponds, and other 

16 surface waters, as well as some groundwater sources and soils. The bacteria are pathogenic to 

17 humans when aerosolized and inhaled into the lungs. Approximately 2 to 5 percent of those 

18 exposed in this way to Legionella develop an acute bacterial infection of the lower respiratory 

19 tract known as Legionnaires’ disease (Pearson 2003). Optimal growth occurs in stagnant 

20 surface waters with biofilms or slimes that range in temperature from 35 to 45 °C (95 to 113 °F), 

21 though the bacteria can persist in waters from 20 to 50 °C (68 to 122 °F) (Pearson 2003). 

22 Elderly and immunocompromised individuals are most susceptible to Legionnaires’ disease 

23 (Pearson 2003). According to data from the Centers for Disease Control and Prevention (CDC) 

24 (CDC 2011a) from 2000 through 2009, New England and Mid-Atlantic states generally had the 

25 highest number of reported legionellosis cases each year.

26 Approximately 2,000 serotypes of Salmonella spp. cause the bacterial infection salmonellosis in 

27 humans. Of these, the serotypes Typhimurium and Enteritidis are the most common in the 

28 United States (CDC 2010a). Salmonellosis is most common in summer months, and it is 

29 transmitted through contact with food, water, or animals contaminated with human or animal 

30 feces (CDC 2010a). The bacteria have an optimal growth temperature of 37 °C (98.6 °F) but 

31 can grow at temperatures ranging from 6 to 46 °C (43 to 115 °F) (Albrecht 2013a). Studies 

32 examining the persistence of Salmonella spp. outside of a host have found that Salmonella can 

33 survive for several months in water and in aquatic sediments (Moore et al. 2003).

34 Shigella is a genus of bacteria species that causes shigellosis (i.e., bacterial dysentery), which 

35 is spread through consuming fecal-contaminated food or water, by swimming in contaminated 

36 water, or by contact with an infected person through contaminated feces and unhygienic 

37 handling of food. Its optimum growth temperature is 37 °C (98.6 °F), though it can grow in water 

38 temperatures ranging from 10 to 40 °C (50 to 104 °F) (Albrecht 2013b). Shigellosis is most 

39 common in summer months and among toddlers age 2 to 4 who are not fully toilet trained and in 

40 childcare settings (CDC 2013e).

41 Pseudomonas aeruginosa is a free-living bacterium found in soil, water, sewage, plant surfaces 

42 and the skin of healthy individuals. It is most commonly linked to infections transmitted in 

43 healthcare settings. However, as a waterborne pathogen, it can cause ear infections 

44 (i.e., “swimmer’s ear”), eye infections, and skin rashes after exposure to contaminated hot tubs, 

45 swimming pools, or other recreational waters (CDC 2013a). Its optimum growth temperature is 

46 37 °C (98.6 °F), though it can grow at temperatures as high as 42 °C (107.6 °F) (Todar 2004). 

47 P. aeruginosa almost exclusively infects immunocompromised individuals or already injured or 

48 inflamed sites on the skin (Todar 2004).
Affected Environment

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1 Naegleria fowleri is a free-living amoeba that occurs in warm lakes, rivers, or hot springs. It is 

2 the causative agent of human primary amoebic meningoencephalitis (PAM). Infection occurs 

3 when contaminated freshwater enters the nose, and the amoeba migrates to brain tissue; the 

4 ensuing illness is usually fatal (CDC 2013b). N. fowleri grows best at higher temperatures up to 

5 46 °C (115 °F) (CDC 2013b), though it has also been isolated from thermally altered waters 

6 surrounding power plant discharges at temperatures ranging from 35 to 41 °C (95 to 105.8 °F) 

7 (Stevens et al. 1977).

8 3.11.3.2 Prevalence of Waterborne Diseases Associated with Recreational Waters

9 From 2002 through 2011, the CDC (2003, 2004a, 2005, 2006a, 2007, 2008a, 2009, 2010b, 

10 2011b, 2012) reported an average of 2,774 cases of Legionnaires’ disease per year, of which 

11 between 28 and 151 per year were reported from Illinois.

12 The Illinois Department of Public Health (IDPH) indicates that approximately 1,500 to 

13 2,000 cases of salmonellosis are reported in the State each year (IDPH 2009), and the 

14 overwhelming majority of salmonellosis cases are foodborne (CDC 2010a). The CDC reports 

15 biannually on waterborne disease outbreaks associated with recreational waters. A review of 

16 the past 10 available data years (1999 through 2008) of these reports indicates that no 

17 outbreaks or cases of waterborne Salmonella infection from recreational waters occurred in the 

18 United States during this timeframe (CDC 2002, 2004b, 2006b, 2008b, 2011c). From 2006 to 

19 2013, all CDC-reported salmonellosis outbreaks have been caused by contaminated produce, 

20 meats, or prepared foods or through contact with contaminated animals (CDC 2013d).

21 Approximately 1,300 confirmed cases of shigellosis are reported in Illinois each year 

22 (IDPH 2013). CDC reports (2002, 2004b, 2006b, 2008b, 2011c) indicate that less than a 

23 dozen shigellosis outbreaks have been attributed to lakes, reservoirs, and other recreational 

24 waters in the past 10 available data years (1999 through 2008). None of these cases was

25 in Illinois.

26 Infections attributed to Pseudomonas aeruginosa are most commonly contracted in pools, spas, 

27 and hot tubs. No cases of infection linked to contaminated recreational waters in the 

28 United States have been reported within the past 10 available data years (1999 through 2008) 

29 (CDC 2002, 2004b, 2006b, 2008b, 2011c).

30 The N. fowleri-caused disease, PAM, is rare in the United States. Since 1962, between zero 

31 and eight cases of PAM have been reported to the CDC annually, and no cases have been 

32 reported in Illinois (CDC 2013c).

33 3.11.4 Electromagnetic Fields

34 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

35 energized conductors or from induced charges in metallic structures has not been found to be a 

36 problem at most operating plants and generally is not expected to be a problem during the 

37 license renewal term. However, a site-specific review is required to determine the significance 

38 of the electric shock potential along the portions of the transmission lines that are within the 

39 scope of this SEIS.

40 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® 41 ) criteria, it was not possible to 

42 determine the significance of the electric shock potential (IEEE 2002). Evaluation of individual 

43 plant transmission lines is necessary because the issue of electric shock safety was not 

44 addressed in the licensing process for some plants. For other plants, land use in the vicinity of 

45 transmission lines may have changed, or power distribution companies may have chosen to 

46 upgrade line voltage. To comply with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an 
Affected Environment

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1 assessment of the impact of the proposed action on the potential shock hazard from the 

2 transmission lines if the transmission lines that were constructed for the specific purpose of 

3 connecting the plant to the transmission system do not meet the recommendations of the NESC 

4 for preventing electric shock from induced currents. The NRC uses the NESC criteria and the 

5 applicant’s adherence to those criteria during the current operating license as a baseline to 

6 assess the potential human health impact of the induced current from an applicant’s 

7 transmission lines. As discussed in the GEIS, the issue of electric shock is of small significance 

8 for transmission lines that are operated in adherence with the NESC criteria. 

9 As discussed in Section 3.1.6 of this SEIS, transmission lines that are within the scope of the 

10 NRC’s license renewal environmental review are limited to those transmission lines that connect 

11 the nuclear plant to the substation where electricity is fed into the regional distribution system 

12 and transmission lines that supply power to the nuclear plant from the grid (NRC 2013). 

13 As indicated by Exelon in its ER, no offsite transmission lines are in-scope for the environmental 

14 review for license renewal. The only transmission lines that are in scope for license renewal are 

15 onsite; the lines from the LSCS power block to the LSCS switchyard (Exelon 2014a). The 

16 public does not have access to this area and could not come into contact with these lines. 

17 Therefore, there is no potential shock hazard to members of the public from these transmission 

18 lines. As discussed in Section 3.11.5 of this SEIS, LSCS maintains an occupational safety 

19 program in accordance with the Occupational Safety & Health Administration regulations for its 

20 workers, which includes protection from acute electric shock.

21 3.11.5 Other Hazards

22 Two additional human health issues are addressed in this section: physical occupational 

23 hazards and electric shock hazards.

24 Nuclear power plants are industrial facilities that have many of the typical occupational hazards 

25 found at any other electric power generation facility. Workers at or around nuclear power plants 

26 would be involved in some electrical work, electric power line maintenance, repair work, and 

27 maintenance activities and exposed to some potentially hazardous physical conditions 

28 (e.g., falls, excessive heat, cold, noise, electric shock, and pressure). The issue of physical 

29 occupational hazards is generic to all nuclear power plants.

30 The Occupational Safety and Health Administration (OSHA) is responsible for developing and 

31 enforcing workplace safety regulations. OSHA was created by the Occupational Safety and 

32 Health Act of 1970 (29 USC 651 et seq.), which was enacted to safeguard the health of 

33 workers. With specific regard to nuclear power plants, plant conditions that result in an 

34 occupational risk, but do not affect the safety of licensed radioactive materials, are under the 

35 statutory authority of OSHA rather than the NRC as set forth in a Memorandum of 

36 Understanding (53 FR 43950) between the NRC and OSHA. Occupational hazards can be 

37 minimized when workers adhere to safety standards and use appropriate protective equipment; 

38 however, fatalities and injuries from accidents can still occur.

39 LSCS participates in the OSHA Voluntary Protection Program (VPP) (OSHA 2015a). The “VPP 

40 recognizes employers and workers in the private industry and federal agencies who have 

41 implemented effective safety and health management systems and maintain injury and illness 

42 rates below national Bureau of Labor Statistics averages for their respective industries. In the 

43 VPP, management, labor, and OSHA establish cooperative relationships at workplaces that 

44 have implemented a comprehensive safety and health management system. Approval into VPP 

45 is OSHA’s official recognition of the outstanding efforts of employers and employees who have 

46 achieved exemplary occupational safety and health” (OSHA 2015b). LSCS holds the “Star” 

47 rating in the VPP, which indicates “participants whose safety and health management systems 
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1 operate in a highly effective, self-sufficient manner and meet all VPP requirements. Star is the 

2 highest level of VPP participation” (OSHA 2008).

3 3.12 Environmental Justice

4 Under Executive Order (EO) 12898 (59 FR 7629), Federal agencies are responsible for 

5 identifying and addressing, as appropriate, disproportionately high and adverse human health 

6 and environmental impacts on minority and low-income populations. Independent agencies, 

7 such as the NRC, are not bound by the terms of EO 12898 but are, as stated in 

8 paragraph 6-604 of the EO, “requested to comply with the provisions of [the] order.” In 2004, 

9 the Commission issued a Policy Statement on the Treatment of Environmental Justice Matters 

10 in NRC Regulatory and Licensing Actions (69 FR 52040), which states, “The Commission is 

11 committed to the general goals set forth in EO 12898, and strives to meet those goals as part of 

12 its NEPA review process.” 

13 The Council on Environmental Quality (CEQ) provides the following information in 

14 Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 1997):

15 Disproportionately High and Adverse Human Health Effects. 

16 Adverse health effects are measured in risks and rates that could result in latent 

17 cancer fatalities, as well as other fatal or nonfatal adverse impacts on human 

18 health. Adverse health effects may include bodily impairment, infirmity, illness, or 

19 death. Disproportionately high and adverse human health effects occur when the 

20 risk or rate of exposure to an environmental hazard for a minority or low-income 

21 population is significant (as employed by NEPA) and appreciably exceeds the 

22 risk or exposure rate for the general population or for another appropriate 

23 comparison group (CEQ 1997).

24 Disproportionately High and Adverse Environmental Effects. 

25 A disproportionately high environmental impact that is significant (as employed 

26 by NEPA) refers to an impact or risk of an impact on the natural or physical 

27 environment in a low-income or minority community that appreciably exceeds the 

28 environmental impact on the larger community. Such effects may include 

29 ecological, cultural, human health, economic, or social impacts. An adverse 

30 environmental impact is an impact that is determined to be both harmful and 

31 significant (as employed by NEPA). In assessing cultural and aesthetic

32 environmental impacts, impacts that uniquely affect geographically dislocated or 

33 dispersed minority or low-income populations or American Indian tribes are 

34 considered (CEQ 1997).

35 The environmental justice analysis assesses the potential for disproportionately high and 

36 adverse human health or environmental effects on minority and low-income populations that 

37 could result from the operation of LSCS during the renewal term. In assessing the impacts, the 

38 following definitions of minority individuals and populations and low-income population were 

39 used (CEQ 1997):

40 Minority individuals

41 Individuals who identify themselves as members of the following population 

42 groups: Hispanic or Latino, American Indian or Alaska Native, Asian, Black or 

43 African American, Native Hawaiian or Other Pacific Islander, or two or more 

44 races, meaning individuals who identified themselves on a Census form as being 

45 a member of two or more races, for example, White and Asian.

46 Minority populations
Affected Environment

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1 Minority populations are identified when (1) the minority population of an affected 

2 area exceeds 50 percent or (2) the minority population percentage of the affected 

3 area is meaningfully greater than the minority population percentage in the 

4 general population or other appropriate unit of geographic analysis.

5 Low-income population

6 Low-income populations in an affected area are identified with the annual 

7 statistical poverty thresholds from the Census Bureau's Current Population 

8 Reports, Series P60, on Income and Poverty.

9 3.12.1 Minority Population

10 According to 2010 Census data, approximately 21 percent of the population residing within a 

11 50-mi (80-km) radius of LSCS identified themselves as minority individuals. The largest minority 

12 group was Hispanic or Latino (of any race) (9.7 percent), followed by Black or African American 

13 (6.4 percent) (USCB 2015e).

14 According to USCB’s (USCB’s) 2010 Census data, minority populations in the socioeconomic 

15 ROI (LaSalle, Grundy, and Will Counties) composed 28.6 percent of the total three-county 

16 population (see Table 3–20). Figure 3–17 shows predominantly minority population block 

17 groups, using 2010 Census data for race and ethnicity, within a 50-mi (80-km) radius of LSCS.

18 Census block groups were considered minority population block groups if the percentage of the 

19 minority population within any block group exceeded 21 percent (the percent of the minority 

20 population within the 50-mi radius of LSCS). A minority population exists if the percentage of 

21 the minority population within the block group is meaningfully greater than the minority 

22 population percentage in the 50-mi (80-km) radius. Approximately 400 of the census block 

23 groups located within the 50-mi (80-km) radius of LSCS have meaningfully greater minority 

24 populations.

25 As shown in Figure 3–17, minority population block groups (race and ethnicity) are mostly 

26 clustered near Chicago, Illinois. None of the block groups near to LSCS have meaningfully 

27 greater minority populations.

28 According to the USCB’s “2014 American Community Survey 1-Year Estimates,” since 2010, 

29 minority populations in the ROI increased by approximately 17,700 persons (an increase of 

30 7.4 percent) and now comprise 30.5 percent of the ROI population (see Table 2.10.3-3). The 

31 largest increases occurred in the Hispanic or Latino population (an increase of approximately 

32 8,900 persons or 7.5 percent) and Asian population (an increase of approximately 

33 5,800 persons or 18.5 percent) (USCB 2015b).

34 3.12.2 Low-Income Population

35 According to 2010 American Community Survey data, 9 percent of individuals residing within a 

36 50-mi (80-km) radius of LSCS were identified as living below the Federal poverty threshold in 

37 2010 (USCB 2015e). The 2010 Federal poverty threshold was $22,113 for a family of four.

38 Figure 3–18 shows the location of predominantly low-income population block groups within a 

39 50-mi (80 km) radius of LSCS. Census block groups were considered low-income population 

40 block groups if the percentage of individuals living below the Federal poverty threshold within 

41 any block group exceeded the percent of the individuals living below the Federal poverty 

42 threshold within the 50-mi radius of LSCS. Approximately 490 of the 1,269 census block groups 

43 located within the 50-mi (80-km) radius of LSCS have meaningfully greater low-income 

44 populations.
Affected Environment

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1 As shown in Figure 3–18, low-income population block groups are evenly distributed around 

2 LSCS. The LSCS site is not located in a low-income population block group. The nearest 

3 low-income population block group is located south and east of the block group containing 

4 LSCS.

5 According to the USCB’s “2014 American Community Survey 1-Year Estimates,” 10.5 percent 

6 of families and 14.4 percent of individuals in Illinois were living below the Federal poverty 

7 threshold and the median household and per capita incomes for Illinois was $57,444 and 

8 $30,417, respectively (USCB 2015b). In the socioeconomic ROI, people living in LaSalle 

9 County had median household and per capita incomes below the State average. The median 

10 household and per capita income averages in LaSalle County were $50,432 and $25,129, 

11 respectively, with 9.6 percent of families and 13.3 percent of individuals living below the poverty 

12 level. In comparison to the State of Illinois and LaSalle County, Will County had higher median 

13 household and per capita income averages ($74,828 and $32,148, respectively) and lower 

14 percentages of families (6.3 percent) and individuals (7.9 percent) living below the poverty level 

15 (USCB 2015b). According to the USCB’s “2011-2013 American Community Survey 3-Year 

16 Estimates,” Grundy County also had higher median household and per capita income averages 

17 ($63,978 and $28,465, respectively) and lower percentages of families (7.2 percent) and 

18 individuals (9.4 percent) living below the poverty level than the State of Illinois and LaSalle 

19 County (USCB 2015b).
Affected Environment

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

2 Source: USCB 2015e
Affected Environment

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

2 Source: USCB 2015e
Affected Environment

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1 3.13 Waste Management and Pollution Prevention

2 3.13.1 Radioactive Waste

3 As discussed in Section 3.1.4 of this SEIS, LSCS uses liquid, gaseous, and solid waste

4 processing systems to collect and treat, as needed, radioactive materials produced as a 

5 byproduct of plant operations. Radioactive materials in liquid and gaseous effluents are 

6 reduced prior to being released into the environment so that the resultant dose to members of 

7 the public from these effluents is well within NRC and EPA dose standards. Radionuclides that 

8 can be efficiently removed from the liquid and gaseous effluents prior to release are converted 

9 to a solid waste form for disposal in a licensed disposal facility.

10 3.13.2 Nonradioactive Waste

11 Waste minimization and pollution prevention are important elements of operations at all nuclear 

12 power plants. Licensees are required to consider pollution prevention measures as dictated by 

13 the Pollution Prevention Act (Public Law 101-508) and Resource Conservation and Recovery 

14 Act of 1976, as amended (Public Law 94-580) (NRC 2013).

15 As described in Section 3.1.5, LSCS has a nonradioactive waste management program to 

16 handle nonradioactive waste in accordance with Federal, State, and corporate regulations and 

17 procedures. LSCS has waste minimization measures in place, as verified during the site visit 

18 conducted by the NRC staff in May 2015. This program includes appropriate recycling, thereby 

19 effecting waste reduction.

20 LSCS has a Storm Water Pollution Prevention Plan (SWPPP) that identifies potential sources of 

21 pollution that may affect the quality of storm water discharges from each permitted outfall. The 

22 SWPPP also describes practices that are used to reduce pollutants in storm water discharges to 

23 assure compliance with the site’s NPDES permit. As part of LSCS’s Spill Prevention Control 

24 and Countermeasure Plan, measures are in place to monitor areas within the site that have the 

25 potential for spills of regulated substances, such as oil (Exelon 2014a).

26 3.14 References

27 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

28 protection against radiation.”

29 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

30 production and utilization facilities.”

31 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

32 protection regulations for domestic licensing and related regulatory functions.”

33 10 CFR Part 61. Code of Federal Regulations, Title 10, Energy, Part 61, “Licensing 

34 requirements for land disposal of radioactive waste.”

35 10 CFR Part 71. Code of Federal Regulations, Title 10, Energy, Part 71, “Packaging and 

36 transportation of radioactive material.”

37 10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, “Licensing 

38 requirements for the independent storage of spent nuclear fuel, high-level radioactive waste, 

39 and reactor-related Greater than Class C waste.”

40 15 CFR Part 930. Code of Federal Regulations, Title 15, Commerce and Foreign Trade, 

41 Part 930, “Federal consistency with approved coastal management programs.”
Affected Environment

3-107

1 40 CFR Part 50. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 

2 “National primary and secondary ambient air quality standards.”

3 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 50, 

4 “National Primary and Secondary Ambient Air Quality Standards,” Washington, DC. 

5 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 51, 

6 “Requirements for Preparation, Adoptions, and Submittal of Implementation Plans." 

7 Washington, D.C.

8 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

9 "Designation of areas for air quality planning purposes." 

10 40 CFR Part 98. Code of Federal Regulations, Title 40, Protection of Environment, Part 98, 

11 “Mandatory Greenhouse Gas Reporting”. 

12 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

13 “Environmental radiation protection standards for nuclear power operations.”

14 40 CFR Part 230. Code of Federal Regulations, Title 40, Protection of Environment, Part 230,

15 “Section 404(b)(1) Guidelines for Specification of Disposal Sites for Dredged or Fill Material.” 

16 49 CFR Parts 171–178. Code of Federal Regulations, Title 49, Transportation, Subchapter C—

17 Hazardous Materials Regulations and “Specifications for packagings.”

18 50 CFR 17.3. U.S. Fish and Wildlife Service. 2006. “Endangered and Threatened Wildlife and 

19 Plants; Definitions.”

20 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

21 “Interagency Cooperation—Endangered Species Act of 1973, as Amended.”

22 32 FR 4001. U.S. Fish and Wildlife Service. 1967. “Endangered Species.” Federal 

23 Register 32(48):4001. March 11, 1967.

24 41 FR 41914. U.S. Fish and Wildlife Service. 1976. “Endangered and Threatened Wildlife and 

25 Plants; Determination of Critical Habitat for American Crocodile, California Condor, Indiana Bat, 

26 and Florida Manatee.” Federal Register 41(187):41914–41916. September 24, 1976.

27 53 FR 43950. U.S. Department of Labor. “Memorandum of Understanding Between the 

28 Nuclear Regulatory Commission and the Occupational Safety and Health Administration; 

29 Worker Protection at NRC-licensed Facilities.” Federal Register 53 (210):43950-43952. 

30 October 31, 1988.

31 53 FR 5598. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 

32 Plants; Proposal to Determine Boltonia decurrens (Decurrent false aster) to be a Threatened a 

33 Threatened Species. Federal Register 53(37):5598-5602. February 25, 1988.

34 53 FR 45858. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 

35 Plants; Determination of Threatened Status for Boltonia decurrens (Decurrent False Aster). 

36 Federal Register 53(219):45858-45861. November 14, 1988.

37 54 FR 39857. U.S. Fish and Wildlife Service. 1989. Endangered and Threatened Wildlife and 

38 Plants; Determination of Threatened Status for Eastern and Western Prairie Fringed Orchids. 

39 Federal Register 54(187):29857-39863. September 28, 1989.

40 56 FR 19953. U.S. Fish and Wildlife Service. 1991. Endangered and Threatened Wildlife and

41 Plants; Dalea foliosa (Leafy Prairie-Clover) Determined to be Endangered. Federal Register

42 56(84):19953-19959. May 1, 1991. 
Affected Environment

3-108

1 59 FR 7629. Executive Order No. 12898. “Federal actions to address environmental justice in

2 minority populations and low-income populations.” Federal Register 59(32):7629–7634. 

3 February 16, 1994.

4 69 FR 52040. U.S. Nuclear Regulatory Commission. “Policy statement on the treatment of 

5 environmental justice matters in NRC regulatory and licensing actions.” Federal Register

6 69(163):52040–52048. August 24, 2004.

7 69 FR 41576. U.S. Environmental Protection Agency. “National Pollutant Discharge 

8 Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake 

9 Structures at Phase II Existing Facilities.” Federal Register 69(131):41576–41693. 

10 July 9, 2004.

11 74 FR 56260. Environmental Protection Agency. “Mandatory Reporting of Greenhouse 

12 Gases.” Federal Register 74(209): 56260-56519. October 30, 2009.

13 75 FR 31514. Environmental Protection Agency. “Prevention of Significant Deterioration and 

14 Title V Greenhouse Gas Tailoring Rule.” Federal Register 75(106):31514-31608.

15 77 FR 14914. U.S. Fish and Wildlife Service. “Endangered and Threatened Wildlife and Plants: 

16 Determination of Endangered Status for the Sheepnose and Spectaclecase Mussels 

17 Throughout Their Range.” Federal Register 77(49):14914-14949. March 13, 2012.

18 77 FR 38762. U.S. Fish and Wildlife Service. 2012. Endangered and Threatened Wildlife and 

19 Plants; 5-Year Status Reviews of Seven Listed Species. Federal Register

20 77(126):38762-38764. June 29, 2012.

21 78 FR 61046. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 

22 Plants; 12-Month Finding on a Petition To List the Eastern Small-Footed Bat and the Northern 

23 Long-Eared Bat as Endangered or Threatened Species; Listing the Northern Long-Eared Bat as 

24 an Endangered Species; Proposed Rule. Federal Register 78(194):61046-61080. 

25 October 2, 2013.

26 78 FR 72058. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 

27 Plants; Listing the Northern Long-Eared Bat as an Endangered Species. Federal Register

28 78(231):72058-72059. December 2, 2013.

29 80 FR 17974. U.S. Fish and Wildlife Service. “Endangered and Threatened Wildlife and 

30 Plants; Threatened Species Status for the Northern Long-Eared Bat with 4(d) Rule.” Federal 

31 Register 80(63):17974-8033. April 2, 2015.

32 35 IAC 1420.140(a). Illinois Administrative Code, Title 35, Environmental Protection, Part 1420, 

33 General Provisions, Section 140, Prohibitions.

34 35 IAC 201. Illinois Administrative Code, Title 35, Environmental Protection, "Subtitle B," Air 

35 Pollution Control Board Subchapter a, "Permits and General Provisions," Part 201 Permit and 

36 General Provisions.

37 35 IAC 301. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 

38 Pollution," Chapter I, "Pollution Control Board," Part 301, “Introduction.” Illinois Pollution Control 

39 Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations40 Title35.aspx> (accessed 21 August 2015).

41 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 

42 Pollution," Chapter I, "Pollution Control Board," Part 302, “Water Quality Standards.” Illinois 

43 Pollution Control Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPA

44 EnvironmentalRegulations-Title35.aspx> (accessed 21 August 2015).
Affected Environment

3-109

1 35 IAC 303. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, “Water 

2 Pollution,” Chapter I, “Pollution Control Board,” Part 303, “Water Use Designations and Site 

3 Specific Water Quality Standards.” Illinois Pollution Control Board. Available at 

4 <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations-Title35.aspx> 

5 (accessed 21 August 2015).

6 35 IAC 309. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, “Water 

7 Pollution,” Chapter I, “Pollution Control Board,” Part 309, “Permits,” Subpart A, “NPDES

8 Permits.” Illinois Pollution Control Board. Available at <http://www.ipcb.state.il.us/SLR/

9 IPCBandIEPAEnvironmentalRegulations-Title35.aspx> (accessed 21 August 2015).

10 35 IAC 733. Illinois Administrative Code, Title 35, Environmental Protection, Part 733, 

11 Standards for Universal Waste Management. 

12 35 IAC 900, Illinois Administrative Code, Title 35, Environmental Protection, Subtitle H, “Noise,” 

13 Chapter I, "Pollution Control Board."

14 525 ILCS 45. Illinois Compiled Statutes. Chapter 525, “Conservation,” Act, “Water Use 

15 Act of 1983,” as amended. Available at <http://www.ilga.gov/legislation/ilcs/

16 ilcs3.asp?ActID=1743&ChapterID=44> (accessed 21 August 2015).

17 [AEC] U.S. Atomic Energy Commission. 1973. Final Environmental Statement Related to the 

18 LaSalle County Nuclear Station. February 1972. Washington, DC: AEC. 287 p. ADAMS 

19 No. ML15043A501.

20 Albrecht JA. 2013a. “University of Nebraska-Lincoln: UNL Food: Bacteria Causing Foodborne 

21 Illness: Salmonella.” Available at <http://food.unl.edu/web/safety/salmonella> (accessed 

22 23 October 2013).

23 Albrecht JA. 2013b. “University of Nebraska-Lincoln: UNL Food: Bacteria Causing Foodborne 

24 Illness: Shigella.” Available at <http://food.unl.edu/web/safety/shigella> (accessed 

25 23 October 2013).

26 Arnold TL, Sullivan DJ, Harris MA, Fitzpatrick FA, Scudder BC, Ruhl PM, Hanchar DW, Stewart 

27 JS. 1999. Environmental Setting of the Upper Illinois River Basin and Implications for Water 

28 Quality. Urbana, IL: U.S. Geological Survey, WRD. Water-Resources Investigations 

29 Report 98–4268. Available at <http://il.water.usgs.gov/nawqa/uirb/pubs/reports/WRIR_98-

30 4268.pdf> (accessed 21 August 2015).

31 Ataner S, Butler S. 2013. Geologic Field Trip to the Starved Rock State Park Area, LaSalle 

32 County, Illinois, Guidebook for the field trip held on October 6, 2013 in conjunction with the 50th 

33 Anniversary Annual Meeting of The Clay Minerals Society held at the University of Illinois at 

34 Urbana-Champaign. October 6, 2013. Available at 

35 <http://www.clays.org/annual%20meeting/50th_annual_meeting_website/docs/CMS13-Fieldtrip36 Guide-StarvedRock.pdf> (accessed 31 December 2014).

37 Bald and Golden Eagle Protection Act of 1940, as amended. 16 U.S.C. §668–668c.

38 Baldwin, E. 1877. History of LaSalle County Illinois: Its Topography, Geology, Botany, Natural 

39 History, History of the Mound Builders, Indian Tribes, French Explorations, and A Sketch of the 

40 Pioneer Settlers of Each Town to 1840, with an Appendix, Giving the Present Status of the 

41 County, Its Population, Resources, Manufactures, and Institutions. Chicago, IL: Rand McNally 

42 and Company, 552 p.
Affected Environment

3-110

1 Barbour MT, Gerritsen J, Snyder BD, Stribling JB. 1999. Rapid Bioassessment Protocols for 

2 Use in Streams and Wadeable Rivers: Periphyton, Benthic Macroinvertebrates, and Fish. 

3 Second Edition. Appendix C: Tolerance and Trophic Guilds of Selected Fish Species. 

4 Washington, DC: U.S. Environmental Protection Agency. EPA 841-B-99-002. Available at 

5 <http://water.epa.gov/scitech/monitoring/rsl/bioassessment/index.cfm> (accessed 3 April 2014).

6 [BLS] Bureau of Labor Statistics. 2015. “Local Area Unemployment Statistics.” July 1, 2015. 

7 Available at <http://www.bls.gov/data/> (accessed October 2015).

8 [CAPS] Circular Area Profiles. 2014. Missouri Census Data Center. Circular Area Profiles 

9 (CAPS) - Version 10C (Revision 4-24-14) Using Data from Summary File 1, 2010 Census. In a 

10 20-mile and 50-mile radius around LSCS (41.24555 Lat., 88.66826 Long). Available at 

11 <http://mcdc.missouri.edu/websas/caps10c.html> (accessed October 2015).

12 [CDC] Centers for Disease Control and Prevention. 2002. “Surveillance for 

13 Waterborne-Disease Outbreaks—United States, 1999–2000.” Morbidity and Mortality Weekly 

14 Report 51(8):1–28. November 22, 2002. Available at <http://www.cdc.gov/mmwr/

15 preview/mmwrhtml/ss5108a1.htm> (accessed 23 October 2013).

16 [CDC] Centers for Disease Control and Prevention. 2003. Summary of Notifiable Diseases—

17 United States, 2001. Morbidity and Mortality Weekly Report 50(53). Atlanta, GA: CDC. 

18 May 2, 2003. 136 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5053.pdf> (accessed 

19 22 October 2013).

20 [CDC] Centers for Disease Control and Prevention. 2004a. Summary of Notifiable Diseases—

21 United States, 2002. Morbidity and Mortality Weekly Report 51(53). Atlanta, GA: CDC. 

22 April 30, 2004. 88 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5153.pdf> (accessed 

23 22 October 2013).

24 [CDC] Centers for Disease Control and Prevention. 2004b. “Surveillance for 

25 Waterborne-Disease Outbreaks and Other Health Events Associated with Recreational Water—

26 United States, 2001–2002.” Morbidity and Mortality Weekly Report 53(8):1–22. 

27 October 22, 2004. Available at <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5308a1.htm> 

28 (accessed 23 October 2013).

29 [CDC] Centers for Disease Control and Prevention. 2005. Summary of Notifiable Diseases—

30 United States, 2003. Morbidity and Mortality Weekly Report 52(54). Atlanta, GA: CDC. 

31 April 22, 2005. 88 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5254.pdf> (accessed 

32 22 October 2013).

33 [CDC] Centers for Disease Control and Prevention. 2006a. Summary of Notifiable Diseases—

34 United States, 2004. Morbidity and Mortality Weekly Report 53(53). Atlanta, GA: CDC. 

35 June 16, 2006. 84 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5353.pdf> (accessed

36 22 October 2013).

37 [CDC] Centers for Disease Control and Prevention. 2006b. “Surveillance for Waterborne 

38 Disease and Outbreaks and Other Health Events Associated with Recreational Water—

39 United States, 2003–2004.” Morbidity and Mortality Weekly Report 55(12):1–24. 

40 December 22, 2006. Available at 

41 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5512a1.htm> (accessed 23 October 2013).

42 [CDC] Centers for Disease Control and Prevention. 2007. Summary of Notifiable Diseases—

43 United States, 2005. Morbidity and Mortality Weekly Report 54(53). Atlanta, GA: CDC. 

44 March 30, 2007. 96 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5453.pdf> 

45 (accessed 22 October 2013).
Affected Environment

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1 [CDC] Centers for Disease Control and Prevention. 2008a. Summary of Notifiable Diseases—

2 United States, 2006. Morbidity and Mortality Weekly Report 55(53). Atlanta, GA: CDC. 

3 March 21, 2008. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5553.pdf> 

4 (accessed 22 October 2013).

5 [CDC] Centers for Disease Control and Prevention. 2008b. “Surveillance for Waterborne 

6 Disease and Outbreaks Associated with Recreational Water Use and Other Aquatic 

7 Facility-Associated—United States, 2005-2006.” Morbidity and Mortality Weekly 

8 Report 57(9):1–29. September 9, 2008. Available at 

9 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5709a1.htm> (accessed 23 October 2013).

10 [CDC] Centers for Disease Control and Prevention. 2009. Summary of Notifiable Diseases—

11 United States, 2007. Morbidity and Mortality Weekly Report 56(53). Atlanta, GA: CDC. 

12 July 9, 2009. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5653.pdf> (accessed 

13 22 October 2013).

14 [CDC] Centers for Disease Control and Prevention. 2010a. “General Information on 

15 Salmonella.” April 5, 2012. Available at <http://www.cdc.gov/salmonella/general/> (accessed 

16 23 October 2013).

17 [CDC] Centers for Disease Control and Prevention. 2010b. Summary of Notifiable Diseases—

18 United States, 2008. Morbidity and Mortality Weekly Report 57(54). Atlanta, GA: CDC. 

19 June 25, 2010. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5754.pdf> 

20 (accessed 22 October 2013).

21 [CDC] Centers for Disease Control and Prevention. 2011a. “Legionellosis—United States, 

22 2000–2009.” Morbidity and Mortality Weekly Report 60(32):1083-1086. August 19, 2011. 

23 Available at <http://www.cdc.gov/mmwr/preview/mmwrhtml/mm6032a3.htm> (accessed 

24 23 October 2013).

25 [CDC] Centers for Disease Control and Prevention. 2011b. Summary of Notifiable Diseases—

26 United States, 2009. Morbidity and Mortality Weekly Report 58(53). Atlanta, GA: CDC. 

27 May 13, 2011. 104 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5853.pdf> 

28 (accessed 22 October 2013).

29 [CDC] Centers for Disease Control and Prevention. 2011c. “Surveillance for Waterborne 

30 Disease Outbreaks and Other Health Events Associated with Recreational Water—

31 United States, 2007–2008.” Morbidity and Mortality Weekly Report 60(12):1–32. 

32 September 23, 2011. Available at 

33 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss6012a1.htm?s_cid=ss6012a1_w> (accessed 

34 23 October 2013).

35 [CDC] Centers for Disease Control and Prevention. 2012. Summary of Notifiable Diseases—

36 United States, 2010. Morbidity and Mortality Weekly Report 59(53). Atlanta, GA: CDC. 

37 June 1, 2012. 116 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5953.pdf> (accessed 

38 22 October 2013).

39 [CDC] Centers for Disease Control and Prevention. 2013a. “Pseudomonas aeruginosa in 

40 Healthcare Settings—HAI.” Available at <http://www.cdc.gov/hai/organisms/

41 pseudomonas.html> (accessed 23 October 2013).

42 [CDC] Centers for Disease Control and Prevention. 2013b. “Naegleria fowleri—Primary 

43 Amebic Meningoencephalitis (PAM).” Available at <http://www.cdc.gov/parasites/naegleria/> 

44 (accessed 23 October 2013).
Affected Environment

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1 [CDC] Centers for Disease Control and Prevention. 2013c. “Naegleria fowleri—Sources of 

2 Infection—Number of Case-reports of Primary Amebic Meningoencephalitis by State of 

3 Exposure: United States, 1962–2012.” June 6, 2013. Available at 

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5 [CDC] Centers for Disease Control and Prevention. 2013d. “Reports of Selected Salmonella

6 Outbreak Investigations.” Available at <http://www.cdc.gov/salmonella/outbreaks.html> 

7 (accessed 23 October 2013).

8 [CDC] Centers for Disease Control and Prevention. 2013e. “Shigellosis: General 

9 Information—NCZVED.” May 14, 2013. Available at <http://www.cdc.gov/nczved/divisions/

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12 America: Toward a Common Perspective. Available at 

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17 National Environmental Policy Act. Available at 

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20 [CHC] Center for Hearing and Communication. undated. “Common Environmental Noise 

21 Levels Factsheet.” Available at <http://www.chchearing.org/noise-center-home/facts22 noise/common-environmental-noise-levels> (accessed 3 August 2015).

23 Clean Air Act of 1970. 42 U.S.C. §7401 et seq.

24 Coastal Zone Management Act of 1972. 16 U.S.C. §1451 et seq.

25 [ComEd] Commonwealth Edison Company. 1977. LaSalle County Station Environmental 

26 Report Operating License Stage. Volume 1. May 10, 1977. ADAMS Nos. ML15273A414 and 

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28 Consolidated Appropriations Act of 2012. Pub. L. No. 112–74, 402, 125 Stat. 786, 883 (2011), 

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31 Assessment LaSalle Generating Station Marseilles, Illinois, Revision 1. September 2006. 

32 ADAMS No. ML062760008.

33 [DOI] U.S. Department of the Interior, National Park Service. 1998. National Register of 

34 Historic Places, Multiple Property Documentation Form, Archaeological Sites of Starved Rock 

35 State Park (9,000–150 B.P.). Available at 

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39 28 August 2015).

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11 No. ML15273A204.

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

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30 Available at <http://www3.epa.gov/ttn/chief/net/2011inventory.html> (accessed 24 April 2015).

31 [EPA] U.S. Environmental Protection Agency. 2015a. “Envirofacts Search: PCS-ICIS.” [Permit 

32 Compliance System (PCS) and Integrated Compliance Information System (ICIS) databases]. 

33 Page updated June 24, 2014. Available at <http://www.epa.gov/enviro/facts/pcs34 icis/search.html> (accessed 31 August 2015).

35 [EPA] Environmental Protection Agency. 2015b. EPA, Enforcement and Compliance History 

36 Online, Exelon LaSalle County Station. Available at <http://echo.epa.gov/?redirect=echo> 

37 (accessed 22 April 2015).

38 [EPA] Environmental Protection Agency. 2015c. EPA History: Noise and the Noise Control 

39 Act. Available at <http://www2.epa.gov/aboutepa/epa-history-noise-and-noise-control-act> 

40 (accessed 15 July 2015).

41 [EPA] Environmental Protection Agency. 2015d. National Ambient Air Quality Standards. 

42 Available at <http://www.epa.gov/air/criteria.html> (accessed 10 July 2015).

43 [EPA] U.S. Environmental Protection Agency. 2015e. “Safe Drinking Water Information System 

44 (SDWIS),” County Search— Grundy, LaSalle and Will Counties, Illinois. Available at 

45 <http://www.epa.gov/enviro/facts/sdwis/search.html> (accessed October 2015).
Affected Environment

3-114

1 [ESPA] Illinois Compiled Statutes, Chapter 520, Wildlife, Part 10, “Illinois Endangered Species 

2 Protection Act.”

3 [Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 

4 Manager, LaSalle County Station to U.S. NRC, Document control Desk. Subject: 

5 Environmental Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle 

6 County Station. August 17, 2001. ADAMS No. ML012330070.

7 [Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 

8 Assurance Manager, LaSalle County Station to U.S. NRC, Document control Desk. Subject: 

9 Environmental Protection Plan and Operating Report Appendix B to Facility License No. NPF-11 

10 and NPF-18. April 29, 2002. ADAMS No. ML021330421.

11 [Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 

12 LaSalle County Station to U.S. NRC, Document control Desk. Subject: Environmental 

13 Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle County Station. 

14 July 22, 2009. ADAMS No. ML092040381.

15 [Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 

16 LaSalle County Station to U.S. NRC, Document control Desk. Subject: Environmental Non17 Routine Event Report for Exelon Generation Company, LLC—LaSalle County Station. 

18 August 25, 2010. ADAMS No. ML102371289.

19 [Exelon] Exelon Generation Co. LLC. 2011a. Illinois Water Inventory Program [LaSalle County 

20 Station report submitted to the Illinois State Water Survey for calendar year 2010]. ADAMS 

21 No. ML15195A385.

22 [Exelon] Exelon Generation Company, LLC. 2011b. LaSalle County Station, 2010 Radioactive 

23 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 26, 2011. ADAMS 

24 No. ML11124A101.

25 [Exelon] Exelon Generation Co. LLC. 2012a. Illinois Water Inventory Program [LaSalle County 

26 Station report submitted to the Illinois State Water Survey for calendar year 2011]. ADAMS 

27 No. ML15195A385. [RAI response SW-01]

28 [Exelon] Exelon Generation Company, LLC. 2012b. LaSalle County Station, 2011 Radioactive 

29 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 20, 2012. ADAMS 

30 No. ML12116A148.

31 [Exelon] Exelon Generation Co. LLC. 2013a. Illinois Water Inventory Program [LaSalle County 

32 Station report submitted to the Illinois State Water Survey for calendar year 2012]. ADAMS 

33 No. ML15195A385.

34 [Exelon] Exelon Generation Company, LLC. 2013b. LaSalle County Generating Station Wildlife 

35 Management Plan. ADAMS No. ML15273A416.

36 [Exelon] Exelon Generation Company, LLC. 2013c. LaSalle County Station, 2012 Radioactive 

37 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 26, 2013. ADAMS 

38 No. ML131280052.

39 [Exelon] Exelon Generation Company, LLC. 2013d. Offsite Dose Calculation Manual (ODCM). 

40 Revision 4. Marseilles, IL: Exelon Nuclear. CY-LA-170-301. April 2013. ADAMS 

41 No. ML13128A059.
Affected Environment

3-115

1 [Exelon] Exelon Generation Company, LLC. 2013e Storm Water Pollution Prevention Plan, 

2 LaSalle County Station, Marseilles, Illinois. June 2013. In Letter from M.P. Gallagher, Vice 

3 President, License Renewal Projects, to NRC Document Desk. Subject: Response to NRC 

4 Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 

5 Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. ADAMS 

6 No. ML15195A389. 

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

8 Operating License Renewal Stage LaSalle County Station, Unit 1 and Unit 2. Chicago, Illinois: 

9 Exelon. December 9, 2014. ADAMS Nos. ML14343A849, ML14343A883, and ML14343A897.

10 [Exelon] Exelon Generation Co. LLC. 2014b. Illinois Water Inventory Program [LaSalle County 

11 Station report submitted to the Illinois State Water Survey for calendar year 2013]. ADAMS 

12 No. ML15195A385. 

13 [Exelon] Exelon Generation Company, LLC. 2014c. LaSalle County Station, 2013 Radioactive 

14 Effluent Release Report. Marseilles, IL: Exelon Nuclear. May 1, 2014. ADAMS 

15 No. ML14121A217.

16 [Exelon] Exelon Generation Company, LLC. 2014d. LaSalle County Station, Units 1 and 2

17 Seismic Hazard and Screening Report. Chicago, Illinois: Exelon. March 31, 2014. ADAMS 

18 No. ML14091A013. 

19 [Exelon] Exelon Generation Company, LLC. 2014e. LaSalle, Units 1 and 2, Updated Final 

20 Safety Analysis Report, Revision 20, Chapter 2.0, Figure 2.5-19, Sheet 40 through 

21 Figure 2.5-92. Chicago, Illinois: Exelon. April 11, 2014. ADAMS No. ML14113A086. 

22 [Exelon] Exelon Generation Company, LLC. 2014f. LaSalle, Units 1 and 2, Updated Final 

23 Safety Analysis Report, Revision 20, Chapter 2.0—Site Characteristics. Chicago, Illinois: 

24 Exelon. April 11, 2014. ADAMS No. ML14113A084. 

25 [Exelon] Exelon Generation Company, LLC. 2014g. LaSalle County Station, Updated Final 

26 Safety Analysis Report, Revision 20. Chicago, Illinois: Exelon. April 11, 2014. ADAMS 

27 No. ML14113A099.

28 [Exelon] Exelon Generation Company, LLC. 2014h. Letter from M.P. Gallagher, Vice 

29 President, License Renewal Projects, to Illinois Environmental Protection Agency, Bureau of 

30 Water. Subject: Application for Clean Water Act Section 401 Certification associated with 

31 Renewal of LaSalle County Station Units 1 and 2 Operating Licenses. February 4, 2014. In: 

32 LaSalle County Station, Units 1 and 2, License Renewal Application, Appendix E, Applicant’s 

33 Environmental Report, Operating License Renewal Stage. ADAMS No. ML14343A897 

34 (Appendix B).

35 [Exelon] Exelon Generation Company, LLC. 2015a. Corrected LaSalle Groundwater Tritium 

36 Concentrations. Chicago, Illinois: Exelon. July 28, 2015. ADAMS No. ML15195A402. 

37 [Exelon] Exelon Generation Company, LLC. 2015b. LaSalle County Station, 2014 Radioactive 

38 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 30, 2015. ADAMS

39 No. ML15120A282.

40 [Exelon] Exelon Generation Company, LLC. 2015c. Letter from M.P. Gallagher, Vice 

41 President, License Renewal Projects, to the NRC Document Control Desk. Subject: Response 

42 to NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

43 Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. 

44 ADAMS No. ML15195A351. 
Affected Environment

3-116

1 [Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 

2 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

6 Review Requests for Additional Information. Response to Request for Additional Information 

7 LU-01. July 2, 2015. ADAMS No. ML15195A373.

8 [Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 

9 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

10 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

11 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

12 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

13 Review Requests for Additional Information. Response to Request for Additional Information 

14 LU-02. July 2, 2015. ADAMS No. ML15195A374.

15 [Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 

16 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

18 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

19 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

20 Review Requests for Additional Information. Response to Request for Additional Information 

21 LU-03. July 2, 2015. ADAMS No. ML15195A375.

22 [Exelon] Exelon Generation Company, LLC. 2015g. Letter from M.P. Gallagher, Vice President 

23 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

24 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

25 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

26 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

27 Review Requests for Additional Information. Response to Request for Additional Information 

28 LU-04. July 2, 2015. ADAMS No. ML15195A376.

29 [Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice President 

30 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

31 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

32 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

33 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

34 Review Requests for Additional Information. Response to Request for Additional Information 

35 LU-05. July 2, 2015. ADAMS No. ML15195A377.

36 [Exelon] Exelon Generation Company, LLC. 2015i. Letter from M.P. Gallagher, Vice President 

37 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

38 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

39 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

40 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

41 Review Requests for Additional Information. Response to Request for Additional Information 

42 LU-06. July 2, 2015. ADAMS No. ML15195A378.
Affected Environment

3-117

1 [Exelon] Exelon Generation Company, LLC. 2015j. Letter from M.P. Gallagher, Vice President 

2 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

6 Review Requests for Additional Information. Response to Request for Additional Information 

7 MA-01. July 2, 2015. ADAMS No. ML15195A344. 

8 [Exelon] Exelon Generation Company, LLC. 2015k. Letter from M.P. Gallagher, Vice President 

9 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

10 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

11 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

12 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

13 Review Requests for Additional Information. Response to Request for Additional Information 

14 MA-05. July 2, 2015. ADAMS No. ML15195A348. 

15 [Exelon] Exelon Generation Company, LLC. 2015l. Letter from M.P. Gallagher, Vice President 

16 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

18 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

19 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

20 Review Requests for Additional Information. Response to Request for Additional Information 

21 MA-09. July 2, 2015. ADAMS No. ML15195A353. 

22 [Exelon] Exelon Generation Company, LLC. 2015m. Letter from M.P. Gallagher, Vice 

23 President License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: 

24 Response to NRC Request for Additional Information, dated May 22, 2015, Regarding the 

25 LaSalle County Station, Units 1 and 2, License Renewal Application, Environmental Review. 

26 Enclosure B: LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal 

27 Environmental Review Requests for Additional Information. Response to Request for Additional 

28 Information MA-10. July 2, 2015. ADAMS No. ML15195A354. 

29 [Exelon] Exelon Generation Company, LLC. 2015n. Letter from M.P. Gallagher, Vice President 

30 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

31 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

32 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

33 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

34 Review Requests for Additional Information. Response to Request for Additional Information 

35 TE-02. July 2, 2015. ADAMS No. ML15195A380.

36 [Exelon] Exelon Generation Company, LLC. 2015o. Letter from M.P. Gallagher, Vice President 

37 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

38 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

39 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

40 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

41 Review Requests for Additional Information. Response to Request for Additional Information 

42 TE-03. July 2, 2015. ADAMS No. ML15195A381.

43 [Exelon] Exelon Generation Company, LLC. 2015p. Letter from M.P. Gallagher, Vice President 

44 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Revisions to 

45 LaSalle County Station, Units 1 and 2, License Renewal Application, Applicant's Environmental 

46 Report - Operating License Renewal Stage. July 31, 2015. ADAMS No. ML15212A259.
Affected Environment

3-118

1 Exelon Nuclear. 2007. LaSalle County Station Units 1 and 2, Annual Radiological 

2 Environmental Operating Report, 1 January Through 31 December 2006. May 2007. ADAMS 

3 No. ML071410244.

4 Exelon Nuclear. 2008. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

5 Report, Annual Radiological Environmental Operating Report, 1 January through 

6 31 December 2007. May 2008. ADAMS No. ML081420473.

7 Exelon Nuclear. 2009. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

8 Report, Annual Radiological Environmental Operating Report, 1 January through 

9 31 December 2008. May 2009. ADAMS No. ML091350485.

10 Exelon Nuclear. 2010. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

11 Report, Annual Radiological Environmental Operating Report, 1 January through 

12 31 December 2009. May 2010. ADAMS No. ML101320380.

13 Exelon Nuclear. 2011. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

14 Report, Annual Radiological Environmental Operating Report, 1 January through 

15 31 December 2010. May 2011. ADAMS No. ML111320602.

16 Exelon Nuclear. 2012. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

17 Report, Annual Radiological Environmental Operating Report, 1 January through 

18 31 December 2011. May 2012. ADAMS No. ML12130A420.

19 Exelon Nuclear. 2013. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

20 Report, Annual Radiological Environmental Operating Report, 1 January through 

21 31 December 2012. May 2013. ADAMS No. ML13136A007.

22 Exelon Nuclear. 2014. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

23 Report, Annual Radiological Environmental Operating Report, 1 January through 

24 31 December 2013. May 2014. ADAMS No. ML14135A214.

25 Exelon Nuclear. 2015. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

26 Report, Annual Radiological Environmental Operating Report, 1 January through 

27 31 December 2014. May 2015. ADAMS Nos. ML15141A195 and ML15141A219.

28 Fagan BM. 2005. Ancient North America. 4th ed. London: Thames & Hudson Ltd. 568 p.

29 Farmer A, Cade S, Staufer DF. 2002. Evaluation of Habitat Suitability Index Model. In: Kurta 

30 A, Kennedy J, editors. The Indiana Bat: Biology and Management of an Endangered Species. 

31 Austin, TX: Bat Conservation International. pp. 172–181.

32 Federal Water Pollution Control Act (Clean Water Act) of 1972, as amended. 

33 33 U.S.C. §1251 et seq. Rivers and Harbors Appropriation Act of 1899, as amended. 

34 33 U.S.C. §403 Section 10.

35 [FEMA] Federal Emergency Management Agency. 2015. Earthquake hazard maps available at 

36 <www.fema.gov/earthquake/earthquake-hazard-maps#0> (accessed 16 June 2015).

37 [FHA] Federal Highway Administration. 2011. Highway Traffic Noise Analysis and Abatement 

38 Policy and Guidance. Available at <https://www.fhwa.dot.gov/environment/noise/

39 regulations_and_guidance/polguide/polguide02.cfm> (accessed August 2015).

40 Fritts, MW. 2013. Email from M.W. Fritts, Illinois Natural History Survey, to P. Moore, Tetra 

41 Tech. Subject: RE: Request: Illinois River Reports. June 24, 2013. ADAMS No. 

42 ML15273A418.
Affected Environment

3-119

1 [FWS] U.S. Fish and Wildlife Service. 1990. Decurrent False Aster Recovery Plan. U.S. Fish 

2 and Wildlife Service, Twin Cities, Minnesota. 26 p. Available at 

3 <http://ecos.fws.gov/docs/recovery_plans/1990/900928c.pdf.> (accessed 28 August 2015). 

4 [FWS] U.S. Fish and Wildlife Service. 2009. Indiana Bat (Myotis sodalis) 5-Year Review: 

5 Summary and Evaluation. Midwest Region – Region 3. Available at 

6 <http://www.fws.gov/midwest/endangered/recovery/5yr_rev/pdf/INBA5Yr30Sept2009.pdf.> 

7 (accessed 28 August 2015). 

8 [FWS] U.S. Fish and Wildlife Service. 2011. A National Plan for Assisting States, Federal 

9 Agencies, and Tribes in Managing White-Nose Syndrome in Bats. Hadley, MA: FWS. 

10 May 2011. 21 p. Available at <http://static.whitenosesyndrome.org/sites/default/files/

11 white-nose_syndrome_national_plan_may_2011.pdf> (accessed 22 August 2013).

12 [FWS] U.S. Fish and Wildlife Service. 2012a. 2011 Rangewide Population Estimate for the 

13 Indiana Bat (Myotis sodalis) by USFWS Region. ADAMS No. ML14265A502.

14 [FWS] U.S. Fish and Wildlife Service. 2012b. Decurrent False Aster (Boltonia decurrens) 

15 5-Year Review: Summary and Evaluation 2012. Midwest Region. Available at 

16 <http://www.fws.gov/midwest/endangered/plants/5yrreviews/Boltonia5YrRev2012.pdf.> 

17 (accessed 28 August 2015). 

18 [FWS] U.S. Fish and Wildlife Service. 2013a. “USFWS: Eastern Prairie Fringed Orchid 

19 (Platanthera leucophaea) Fact Sheet.” July 9, 2013. Available at 

20 <http://www.fws.gov/midwest/endangered/plants/epfo.html> (accessed 18 December 2013). 

21 [FWS] U.S. Fish and Wildlife Service. 2013b. “USFWS: Endangered Species: Sheepnose 

22 Mussel (Plethobasus cyphyus).” January 3, 2013. Available at 

23 <http://www.fws.gov/midwest/endangered/clams/sheepnose/> (accessed 20 December 2013).

24 [FWS] U.S. Fish and Wildlife Service. 2013c. White-Nose Syndrome Confirmed in Illinois Bats: 

25 Illinois becomes 20th state in U.S. to confirm deadly disease in bats. Midwest Region. 

26 November 4, 2013. Available at <http://www.fws.gov/midwest/news/621.html.> (accessed 

27 1 September 2015). 

28 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 

29 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 

30 September 30, 2015. Available at <http://www.fws.gov/midwest/endangered/lists/illinois31 cty.html> (accessed 9 October 2015). 

32 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC. Subject: LaSalle 

33 Power Plant License Renewal. List of threatened and endangered species that may occur in 

34 your proposed project location, and/or may be affected by your proposed project. 

35 February 27, 2015. ADAMS ML15126A069.

36 [FWS] U.S. Fish and Wildlife Service. 2015c. Letter from L. Nelson, Regional Environmental 

37 Officer, FWS, to D. Wrona, NRC. May 8, 2015. ADAMS No. ML15131A004.

38 [FWS] U.S. Fish and Wildlife Service. 2015d. Letter from Rock Island Ecological Services 

39 Field Office, FWS, to NRC. Subject: List of threatened and endangered species that may occur 

40 in your proposed project location, and/or may be affected by your proposed project. 

41 February 27, 2015. ADAMS No. ML15126A069. 

42 [FWS] U.S. Fish and Wildlife Service. 2015e. National Wetlands Inventory Wetlands Mapper. 

43 Available at <http://www.fws.gov/wetlands/Data/Mapper.html> (accessed 10 March 2015).
Affected Environment

3-120

1 [HDR] HDR Engineering, Inc. 2010. Zebra Mussel Monitoring Program at LaSalle Nuclear 

2 Station, 2009. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2010. Woodstock, 

3 Illinois. ADAMS No. ML15273A421.

4 [HDR] HDR Engineering, Inc. 2011. Zebra Mussel Monitoring Program at LaSalle Nuclear 

5 Station, 2010. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2011. Woodstock, 

6 Illinois. ADAMS No. ML15273A422.

7 [HDR] HDR Engineering, Inc. 2012. Zebra Mussel Monitoring Program at LaSalle Nuclear 

8 Station, 2011. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2012. Woodstock, 

9 Illinois. ADAMS No. ML15273A440.

10 [HDR] HDR Engineering, Inc. 2013. Zebra Mussel Monitoring Program at LaSalle Nuclear 

11 Station, 2012. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2013. Woodstock, 

12 Illinois. ADAMS No. ML15273A441.

13 [HDR] HDR Engineering, Inc. 2014. Zebra Mussel Monitoring Program at LaSalle Nuclear 

14 Station, 2013. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2014. Woodstock, 

15 Illinois. ADAMS No. ML15273A442.

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17 Control. Available at <https://www.hudexchange.info/environmental-review/noise-abatement18 and-control/> (accessed 15 July 2015).

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20 Conservation Plan & Strategy. Version 1.0. July 11, 2005. 380 p. Available at 

21 <http://www.dnr.illinois.gov/conservation/IWAP/Documents/WildlifeActionPlanFinal.pdf> 

22 (accessed 9 March 2015).

23 [IDNR] Illinois Department of Natural Resources. 2007. Status of the Catfish Fishery. Illinois 

24 Department of Natural Resources, Division of Fisheries. March 2007. Available at 

25 <http://www.dnr.state.il.us/orc/fisheries/07/07%20catfish%20status%20report.pdf> (accessed 

26 21 May 2015).

27 [IDNR] Illinois Department of Natural Resources. 2009. Status of the Striped Bass/Hybrid 

28 Striped Bass Fishery. Illinois Department of Natural Resources, Division of Fisheries. 

29 March 2009. Available at 

30 <http://www.prairiestateoutdoors.com/images/uploads/2009_Striped_Bass_Status.pdf> 

31 (accessed 21 May 2015).

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33 Sheets. Illinois Department of Natural Resources, Aquatic Illinois, DNR158-6/12. Available at 

34 <http://dnr.state.il.us/education/aquatic/aquaticillinoisrivlakefactshts.pdf> (accessed 

35 10 September 2015).

36 [IDNR] Illinois Department of Natural Resources. 2011b. State of Illinois Coastal Management 

37 Program. Available at <http://www.dnr.illinois.gov/cmp/Documents/ICMPPD.pdf> (accessed 

38 6 March 2015).

39 [IDNR] Illinois Department of Natural Resources. 2014a. “Illinois Natural Areas Inventory (INAI) 

40 Sites.” October 2014. Available at <http://dnr.state.il.us/conservation/

41 naturalheritage/Documents/INAI_by_County.pdf> (accessed 10 March 2015).

42 [IDNR] Illinois Department of Natural Resources. 2014b. “Illinois Threatened and Endangered 

43 Species By County.” Updated October 2014. Available at 

44 <http://www.dnr.illinois.gov/ESPB/Documents/ET_by_County.pdf> (accessed 9 March 2015).
Affected Environment

3-121

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2 Assessment Section, to M.P. Gallagher, Vice President License Renewal, Exelon Nuclear. Re: 

3 Renewal of Facility Operating Licenses by the U.S. Nuclear Regulatory Commission (NRC) for 

4 LaSalle Generating Station, Units 1 and 2 - Correspondence dated March 7, 2014 County: 

5 LaSalle. May 22, 2014. In Appendix D of Exelon 2014a.

6 [IDNR] Illinois Department of Natural Resources. 2015a. Checklist of Illinois Endangered and 

7 Threatened Animals and Plants, Illinois Endangered Species Protection Board. May 19, 2015. 

8 Available at <http://www.dnr.illinois.gov/ESPB/Documents/2015_ChecklistFINAL_for_webpage

9 _051915.pdf> (accessed 15 October 2015).

10 [IDNR] Illinois Department of Natural Resources. 2015b. “Illini State Park.” Available at 

11 <http://dnr.state.il.us/lands/Landmgt/parks/i&m/east/illini/park.htm> (accessed 10 March 2015).

12 [IDNR] Illinois Department of Natural Resources. 2015c. “Illinois Coastal Management 

13 Program Boundaries.” Available at <http://www.dnr.illinois.gov/cmp/Pages/boundaries.aspx> 

14 (accessed 6 March 2015).

15 [IDNR] Illinois Department of Natural Resources. 2015d. Marseilles State Fish and Wildlife 

16 Area. Available at <http://dnr.state.il.us/lands/Landmgt/parks/r1/MARSEIL.HTM> (accessed 

17 15 October 2015).

18 [IDNR] Illinois Department of Natural Resources. 2015e. “Marseilles State Fish & Wildlife Area 

19 (Upland) Hunter Fact Sheet.” Available at 

20 <http://www.dnr.illinois.gov/hunting/FactSheets/Pages/MarseillesStateFishWildlifeAreaUpland.a

21 spx> (accessed 6 March 2015).

22 [IDNR and Exelon] Illinois Department of Natural Resources and Exelon Generation Company, 

23 LLC. 2014. IDNR and Exelon Meeting Notes, Review of Braidwood, Clinton and LaSalle, Lake 

24 Fishery and Land Management Plans. March 5, 2014. ADAMS No. ML15195A368.

25 [IDNR and Exelon] Illinois Department of Natural Resources and Exelon Generation Company, 

26 LLC. 2015. IDNR and Exelon Meeting Notes, Review of Braidwood, Clinton and LaSalle, Lake 

27 Fishery and Land Management Plans. March 4, 2015. ADAMS No. ML15195A368.

28 [IDPH] Illinois Department of Public Health. 2009. “Salmonella.” January 2009. Available at 

29 <http://www.idph.state.il.us/public/hb/hbsam.htm> (accessed 23 October 2013).

30 [IDPH] Illinois Department of Public Health. 2013. “Shigellosis Healthbeat.” Available at 

31 <http://www.idph.state.il.us/public/hb/hbshigellosis.htm> (accessed 23 October 2013).

32 [IDPH] Illinois Department of Public Health. 2014. Email from K. Marshall, IDPH, to N. Ranek, 

33 Exelon, Subject: RE: LaSalle County Station Units 1 and 2- Consultation about thermophilic 

34 organisms. February 19, 2014. ADAMS No. ML15273A445.

35 [IEPA] Illinois Environmental Protection Agency. 1987. Field and Laboratory Methods Manual: 

36 Section C, Macroinvertebrate Monitoring. IEPA. Springfield, IL. 55 p.

37 [IEPA] Illinois Environmental Protection Agency. 2000. Federally Enforceable State Operating 

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28 <http://www.umesc.usgs.gov/reports_publications/status_and_trends.html> (accessed 

29 21 October 2015).

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35 (accessed 5 September 2013).

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37 <http://earthquake.usgs.gov/earthquakes/states/illinois/history.php> (accessed 

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41 4 September 2013).

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44 4 September 2013).
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2 River at Marseilles, Illinois. Available at 

3 <http://waterdata.usgs.gov/nwis/inventory/?site_no=05543500&agency_cd=USGS> (accessed 

4 5 June 2015).

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6 Predicting minimum habitat characteristics for the Indiana bat in the Champlain Valley. The 

7 Journal of Wildlife Management 70(5):1228-1237.

8 Whitaker JO Jr, Brack V Jr. 2002. Distribution and summer ecology in Indiana. pp. 48–54. In: 

9 Kurta A, Kennedy J, editors. 2002. The Indiana Bat: Biology and Management of an 

10 Endangered Species. Austin, TX: Bat Conservation International. 253 p.

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19 9 March 2015).
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. In 

NUREG–0586, “Generic Environmental Impact Statement on Decommissioning of Nuclear

Facilities, Supplement 1,” the NRC (2002) concludes generically that land use during 

decommissioning activities would be SMALL. The GEIS (NRC 2013b) 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. The vent stack, reactor buildings, and 

turbine buildings, which create the largest visual impact, would eventually be dismantled, which 

would reduce the already SMALL impacts to visual resources that would occur during the 

proposed license renewal term. Thus, the NRC staff concludes that the impacts of the no-action 

alternative on visual resources would be SMALL.
Environmental Consequences and Mitigating Actions

4-3

4.2.3 New Nuclear Alternative

4.2.3.1 Land Use

The new nuclear alternative assumes that Exelon Generation Company, LLC (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, 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 
Environmental Consequences and Mitigating Actions

4-4 

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.

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 
Environmental Consequences and Mitigating Actions

4-5

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.

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 4.3.3.1. 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 6,749 ac (2,731 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 4.3.3.2 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 
Environmental Consequences and Mitigating Actions

4-6

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.

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 

transmission-line 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.
Environmental Consequences and Mitigating Actions

4-7

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

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 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 remain 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 
Environmental Consequences and Mitigating Actions

4-8

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. 

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),
Environmental Consequences and Mitigating Actions

4-9

• 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 

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 
Environmental Consequences and Mitigating Actions

4-10

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.

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 syngas (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 
Environmental Consequences and Mitigating Actions

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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 

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 

(FR 48208)) requires 28 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.
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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

(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. Furthermore, the IGCC alternative 

would be subject to carbon dioxide emission performance rate standards set forth in the Clean 

Power Plan aimed at reducing carbon pollution from power plants (80 FR 64661–65120).

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 new 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. Although the proposed rule has not been finalized, the IGCC alternative 

analysis includes an option for future implementation of CCS.

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.

 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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As result of the significant criteria air emissions, a major air 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.

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 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).
Environmental Consequences and Mitigating Actions

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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 

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).

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)—9.8 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 these 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 9.8 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 
Environmental Consequences and Mitigating Actions

4-15

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 

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 carbon dioxide emission performance rate standards set forth in the Clean 

Power Plan aimed at reducing carbon pollution from power plants (80 FR 64661–65120).

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.

On January 8, 2014, EPA issued a new proposal for GHG emissions from new fossil fuel-fired 

electric utility steam generating units (79 FR 1430). It also proposes standards of performance 

for natural gas-fired stationary combustion turbines based on modern, efficient NGCC 

technology as the best system of emission reduction.

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. 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 
Environmental Consequences and Mitigating Actions

4-16

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. 

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 
Environmental Consequences and Mitigating Actions

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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 

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.

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 360 MWe and a 

capacity factor of 0.85, the resulting estimated NGCC emissions are as follows:

• sulfur dioxide (SO2)—4.2 tons (3.8 MT) per year,

• nitrogen oxides (NOx)—90 tons (81 MT) per year,

• particulate matter (PM10)—6.5 tons (5.9 MT) per year,

• carbon monoxide (CO)—9.3 tons (8.4 MT) per year, and

• carbon dioxide equivalent (CO2e)—1.2 million tons (1.1 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.

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 
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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.

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 
Environmental Consequences and Mitigating Actions

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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 

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 discussions provided 

above. 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 
Environmental Consequences and Mitigating Actions

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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.

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, 
Environmental Consequences and Mitigating Actions

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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.

4.4.4 IGCC Alternative

For the coal 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 generation 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 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.
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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. 

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, 2015b), 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.

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 
Environmental Consequences and Mitigating Actions

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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) 

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 PCE Phosphate, Marseilles Operation. These facilities are discussed in 

Section 3.5.1.2 and shown in Figure 3–5.

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
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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.

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

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. Therefore, 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 
Environmental Consequences and Mitigating Actions

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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.

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 maximum of 750 milligrams per liter (mg/L), which is less than half the total dissolved solids 

concentration (1,709 mg/L) in water obtained from the Cambrian-Ordovician Aquifer. 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 
Environmental Consequences and Mitigating Actions

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(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, 

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 throughout plant 

shutdown and decommissioning. 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.
Environmental Consequences and Mitigating Actions

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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 

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, a State or regional permitting 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 
Environmental Consequences and Mitigating Actions

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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, 

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 coal 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 
Environmental Consequences and Mitigating Actions

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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 

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 
Environmental Consequences and Mitigating Actions

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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 

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.
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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.

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

For the generic (Category 1) terrestrial resource issues listed in Table 4–6, the NRC staff did not 

identify any new and significant information related to the generic (Category 1) issues listed 

above during the review of the applicant’s 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.

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 
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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 

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 
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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.

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 activities, 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.
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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, 

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). In NUREG–0586, the 

NRC (2002) concludes generically that impacts to terrestrial ecology during decommissioning

activities would be SMALL. The GEIS (NRC 2013d) notes that terrestrial resource 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 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.
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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.

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 4.13.3.2. 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 
Environmental Consequences and Mitigating Actions

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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.

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 4.13.3.2. 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 4.3.3.1. 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 6,749 ac (2,731 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 
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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 

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
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Issue GEIS Section Category

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

(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 GEIS concludes that the nine Category 1 issues listed in Table 4–7 would have a SMALL 

impact on aquatic resources during the license renewal term for all plants. For these issues, no 

additional plant-specific analysis is required unless new and significant information is identified. 

During its review, the NRC staff considered Exelon’s ER, aquatic surveys and studies 

performed at LSCS and in the Illinois River, and available scientific literature; participated in a 

site audit; and considered Federal and State agency and public comments received during the 

scoping process. The NRC staff did not identify any new and significant information related to 

any of the Category 1 issues. Therefore, no site-specific analysis is required for these issues, 

and there would be no impacts associated with these issues beyond those discussed in the 

GEIS.

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).
Environmental Consequences and Mitigating Actions

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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 

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, 2013b, 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
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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. 

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 
Environmental Consequences and Mitigating Actions

4-41

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 

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), 
Environmental Consequences and Mitigating Actions

4-42

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 

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 blue gill (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 
Environmental Consequences and Mitigating Actions

4-43

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, 

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 
Environmental Consequences and Mitigating Actions

4-44

rather than the Illinois River. The cooling pond system is similar to a closed-cycle cooling

system 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. 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.

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 
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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 

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, 2015b).

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.
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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 

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)]
Environmental Consequences and Mitigating Actions

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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. 

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 
Environmental Consequences and Mitigating Actions

4-48

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:

• 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 
Environmental Consequences and Mitigating Actions

4-49

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. 

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 3.7.4 

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). 
Environmental Consequences and Mitigating Actions

4-50

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). Similarly, in a status review of the cooling pond in 

2011, 2012, and in 2014, IDNR noted the decline in the threadfin shad population due to fish 

kills during each summer (Exelon 2015b). Shad populations generally recovered within 1 year 

after a kill occurred (Exelon 2002, 2015a) and loss of shad did not substantially affect the 

community dynamics within the cooling pond (Exelon 2010, 2015a). The NRC staff also did not 

identify any long-term or destabilizing changes from previous fish kills. 

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, EA concluded 

that the LSCS cooling pond has reached a point where fish kills should 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 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, 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 gizzard shad and threadfin shad. The increase in intensity 

and number of fish kills would not result in a significant impact because the cooling pond is a 

managed ecosystem where fish populations affected by fish kills generally recover within 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 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 
Environmental Consequences and Mitigating Actions

4-51

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). 

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 concluded that such fish kills have noticeable 

effects on threadfin and gizzard shad, based on a decreased population size following a fish kill. 

Fish kills are not destabilizing to shad populations because they tend to recover within 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 continue to occur 

during the license renewal term and would have noticeable effects on threadfin shad and 

gizzard shad, based on a decreased population size following a fish kill. Fish kills would not be 

destabilizing to shad populations because they tend to recover within a year. Therefore, the 

NRC staff concluded the impacts from heat shock would be MODERATE to gizzard shad and 

threadfin shad in the LSCS cooling pond. The applicant has proposed no mitigation to reduce 

the MODERATE environmental impacts associated with heat stress 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.
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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 

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 or cease to occur in the cooling pond.

NUREG–0586 (NRC 2002) concludes generically that impacts to aquatic ecology during 

decommissioning activities would be SMALL for facilities at which the decommissioning 
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4-53

activities would be limited to existing operational areas. In the case of LSCS, the NRC staff did 

not identify any effects that would have more than minor impacts on aquatic resources. 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.

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.

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 
Environmental Consequences and Mitigating Actions

4-54

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.

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.

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 
Environmental Consequences and Mitigating Actions

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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

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 
Environmental Consequences and Mitigating Actions

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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. 

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
Environmental Consequences and Mitigating Actions

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Group

Federally Listed 

Species Common Name

Federal 

Status(a) Determination

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.

Under the no-action alternative, the NRC would assess the need for ESA consultation if any 

activities associated with plant shutdown have the potential to affect a Federally listed species 

and if the activities meet the criteria in 50 CFR Part 402 for initiation of section 7 consultation.

The ESA forbids “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.” In the 

case of a take, ESA section 7 requires that the NRC initiate consultation with the FWS or 

NMFS. If consultation was initiated and then completed, the implementing regulations at 

50 CFR 402.16 also direct Federal agencies to reinitiate consultation in circumstances where 

(a) the incidental take limit in a biological opinion is exceeded, (b) new information reveals 

effects to Federally listed species or designated critical habitats that were not previously 

considered, (c) the action is modified in a manner that causes effects not previously considered, 

or (d) new species are listed or new critical habitat is designated that may be affected by the 

action. An ESA section 7 consultation could identify impacts on Federally listed species or 

critical habitat, require monitoring and mitigation to minimize such impacts, and provide a level 

of exempted takes. Regulations and guidance regarding the ESA section 7 consultation 

process are provided in 50 CFR Part 402 and in the Endangered Species Consultation 

Handbook (FWS and NMFS 1998).

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.
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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 

adversely affect any Federally listed species or adversely modify or destroy 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 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 

ESA-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 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 “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 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 ESA-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 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 “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 construction and operation of an 
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NGCC plant would be different than those described under 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. Because the 

types and magnitudes of adverse impacts to ESA-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 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 “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 operation of the NGCC portion of the combination alternative would be 

different than those described under 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 ESA-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 ESA-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 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 type, 

period, or 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,
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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. In the 

decommissioning GEIS, the NRC staff determined that, for all nuclear plant sites at which 

decommissioning does not anticipate disturbing lands beyond existing site boundaries, impacts 

to cultural resources would be SMALL. If disturbance beyond the operational areas is 

anticipated, the impacts may or may not be detectable or destabilizing, depending on 

site-specific conditions, and cannot be predicted generically. In those cases, the NRC staff 

concludes that, if disturbance beyond the operation areas is anticipated, the potential impacts 

may be SMALL, MODERATE, or LARGE and must be determined through site-specific analysis 

(NRC 2002). 

Title 10 of CFR Section 50.82 requires power reactor licensees to submit to the NRC a 

post-shutdown decommissioning activities report (PSDAR). The PSDAR is required to be 

submitted within 2 years following permanent cessation of operations and contains a description 

of planned decommissioning activities to be completed at that time. Until the PSDAR is 

submitted, the NRC staff does not know whether land disturbance will remain within the existing 

site boundary after the plant is shut down.

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 
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alternative is sited on the approximately 250 ac (101 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.

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 250 ac (101 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 
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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 

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.
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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 Part 51, applicable to LSCS during the license renewal term. 

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 
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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 

termination of nuclear plant operations (which may 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 
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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 

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 
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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 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.

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.
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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 

“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 three-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. 
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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.

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.
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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 

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 

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.

Whether or not there would be a 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 

Similarly, purchased power from existing power generating facilities would also 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 volumes could increase noticeably on local roads near the new power 

plant site during shift changes.
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Whether or not there would be a 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.

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 limits blowdown discharges to the river 

(Outfall 001) to a maximum rate of 45 gallons per minute (gpm) (0.17 m3 per minute (m3

/min)), 
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as further 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 2014; 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.

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 
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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.

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 
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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 evaluated SAMAs for the applicant’s plant in an 

environmental impact statement or related supplement or in an environmental assessment, 

10 CFR Part 51.53(c)(3)(ii)(L) requires license renewal applicants to consider alternatives to 

mitigate 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. Pursuant to 10 CFR Part 54, the only changes that 

the applicant must implement as part of the license renewal process are those that are identified 
Environmental Consequences and Mitigating Actions

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as being cost beneficial, that provide a significant reduction in total risk, and that are related to 

adequately managing the effects of aging during the period of extended operation.

Overview of SAMA Process

This section presents a summary of the SAMA evaluation for LSCS, as described in the ER 

(Exelon 2014a), additional requested information (Exelon 2015h), and the NRC staff’s review of 

those evaluations. 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 four 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 estimated how much each 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 cost and benefit of each remaining SAMA to determine 

whether it was cost beneficial (the benefits of the SAMA exceeded its cost).

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 (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 

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.
Environmental Consequences and Mitigating Actions

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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 1.1x10−8 4

Loss of Offsite Power 7.2x10−8 3

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
Environmental Consequences and Mitigating Actions

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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 

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;
Environmental Consequences and Mitigating Actions

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(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

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
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Release Mode Population Dose Risk(a) Offsite Economic Cost Risk

(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.

During this process, two SAMA candidates were screened out based on the excessive cost 

criterion. Table F.6–1 of the ER (Exelon 2014a) provides a description of each of the 

24 Phase II SAMA candidates, which was later changed3 to 25 Phase II SAMA candidates in 

Exelon’s revised analysis (Exelon 2015h).

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 

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.

 3 The results of a sensitivity analysis to determine the impact of a correction to the Level 2 model resulted in the 

retention of one of the Phase I SAMAs (SAMA 26), which was originally screened out. 
Environmental Consequences and Mitigating Actions

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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 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 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.
4-84

Table 4–16. LSCS Potentially Cost-Beneficial SAMAs(a) 1

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.

19—PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 

TO THE LPCS SYSTEM FOR LOCA MITIGATION 38 58 58 3.4M 
4-86

Individual SAMA and Assumptions

% Risk Reduction(b) Total Benefi

CDF Population 

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

Per

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

1
Environmental Consequences and Mitigating Actions

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1 Cost-Benefit Comparison

2 If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 

3 was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 

4 SAMA candidate was considered to be potentially cost beneficial. Table 4–16 presents the 

5 results of the cost-benefit evaluation. Exelon’s cost-benefit analysis identified 14 SAMA 

6 candidates determined to be potentially cost beneficial at the 95th percentile on an individual 

7 basis, as follows:

8 • SAMA 2: Automate suppression pool cooling.

9 • SAMA 3: Install passive vent path.

10 • SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation 

11 bypass switch.

12 • SAMA 5: Automate SBLC initiation.

13 • SAMA 8: Obtain a 480-V AC portable generator to supply the 125-V DC battery 

14 chargers and develop procedures for its use.

15 • SAMA 9: Develop flood zone-specific procedures.

16 • SAMA 10: Change the logic to close the turbine-driven feedwater pump discharge

17 valves when the pumps are not running.

18 • SAMA 14: Provide a portable DC source to support RCIC and SRV operation.

19 • SAMA 15: Tie RHRSW to the LPCS system for ISLOCA mitigation.

20 • SAMA 16: Provide portable fans for alternate room cooling in the core standby 

21 cooling system vaults.

22 • SAMA 18: Improve the connection between the fire protection and 

23 feedwater systems.

24 • SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for 

25 LOCA mitigation.

26 • SAMA 21: Install automatic ATWS level control system.

27 • SAMA 23: Enhance the fuel pool emergency makeup pump and connection.

28 When the planned installation of a hardened vent pipe is considered as the base case, the 

29 number of SAMA candidates considered to be potentially cost beneficial at the 95th percentile 

30 may be reduced. Because a new baseline is established following the implementation of a 

31 SAMA, which further influences the benefits provided by the remaining SAMA candidates, 

32 Exelon defined an optimal set to containing SAMAs that, if implemented, would render the 

33 remaining SAMAs to be not cost beneficial. Acknowledging Exelon’s commitment to install the 

34 hardened vent pipe (SAMA 1), additional modifications included in the optimal set are 

35 SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). Assessment of the optimal set 

36 was performed before Exelon generated revised results in response to the NRC staff’s RAIs 

37 (Exelon 2015h). Because Exelon did not take a priori credit for installation of the hardened vent 

38 pipe, revision to the optimal set assessment was not required. Exelon is referring the 

39 14 potentially cost-beneficial SAMAs from its revised analysis (Exelon 2015h) to the LSCS Plant 

40 Health Committee for further implementation considerations within the established plant 

41 procedural process, as indicated in Section 4.15 of the ER (Exelon 2014a).
Environmental Consequences and Mitigating Actions

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1 Conclusions

2 Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 

3 updated probabilistic safety assessment models, SAMA-related industry documentation, 

4 plant-specific enhancements, and its review of SAMA candidates from potential improvements 

5 primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 

6 SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 

7 been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 

8 costs and benefits associated with each of the 25 potential SAMAs. Exelon concluded that 

9 14 SAMA candidates were potentially cost beneficial at the 95th percentile (shown in 

10 Table 4–16). Exelon has decided to proceed with the modification to install a hardened vent 

11 pipe regardless of cost even though it is not cost beneficial. From a sensitivity analysis, no 

12 additional SAMA candidates were identified as potentially cost beneficial. Because the 

13 potentially cost-beneficial SAMAs do not relate to aging management during the period of 

14 extended operation, their implementation is not required as part of license renewal pursuant to 

15 10 CFR Part 54. Nevertheless, as stated in Section 4.15 of the ER (Exelon 2014a), Exelon 

16 indicated that the potentially cost-beneficial SAMAs are being referred to the LSCS Plant Health 

17 Committee for further implementation considerations within the established plant procedural 

18 process.

19 The NRC staff reviewed Exelon’s SAMA analysis and concludes that, based on the discussion 

20 in Appendix F of this document, the methods used and implementation of those methods were 

21 sound. On the basis of the applicant’s treatment of SAMA benefits and costs, the NRC staff 

22 finds that the SAMA evaluations performed by Exelon are reasonable and are sufficient for the 

23 license renewal submittal. The NRC staff concurs with Exelon’s conclusion that 14 SAMA 

24 candidates are potentially cost beneficial for LSCS and notes that Exelon’s assessment was 

25 based on generally conservative treatment of costs, benefits, and uncertainties. Based on the 

26 NRC staff’s review of Exelon’s SAMA evaluations, including Exelon’s response to the NRC 

27 staff’s RAIs, the NRC staff concludes that Exelon has adequately identified areas in which risk 

28 can be further reduced in a cost-beneficial manner through the implementation of the identified 

29 potentially cost-beneficial SAMAs. Given the potential for cost-beneficial risk reduction, the 

30 NRC staff agrees that further evaluation by Exelon of the 14 SAMA candidates identified by 

31 Exelon as being potentially cost beneficial is warranted.

32 The NRC staff also evaluated whether the identified potentially cost-beneficial SAMAs are 

33 subject to aging management. The evaluation considered any structures, systems, and 

34 components associated with these SAMAs that perform intended functions without moving parts 

35 or without a change in configuration or properties and that would not be subject to replacement 

36 based on a qualified life or specified time period. The NRC staff determined that the potentially 

37 cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the 

38 period of extended operation. Therefore, they do not need to be implemented as part of license 

39 renewal in accordance with 10 CFR Part 54.

40 4.11.2 No-Action Alternative

41 Human health risks would be smaller following plant shutdown. The two reactor units, which are 

42 currently operating within regulatory limits, would emit less gaseous, liquid, and solid radioactive 

43 material to the environment. In addition, following shutdown, the variety of potential accidents at 

44 the plant (radiological or industrial) would be reduced to a limited set associated with shutdown 

45 events and fuel handling and storage. In Section 4.11.1, the NRC staff concluded that the 

46 impacts of continued plant operation on human health would be SMALL, except for “chronic 

47 effects of electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. In 

48 Section 4.11.1.2, the NRC staff concluded that the impacts of accidents during operation were 
Environmental Consequences and Mitigating Actions

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1 SMALL. Therefore, as radioactive emissions to the environment decrease, and as the likelihood 

2 and types of accidents decrease following shutdown, the NRC staff concludes that the risk to 

3 human health following plant shutdown would be SMALL.

4 4.11.3 New Nuclear Alternative

5 Impacts on human health from construction of two new nuclear units would be similar to impacts 

6 associated with the construction of any major industrial facility. Compliance with worker 

7 protection rules would control those impacts on workers at acceptable levels. Impacts from 

8 construction on the general public would be minimal, since limiting active construction area 

9 access to authorized individuals is expected. Impacts on human health from the construction of 

10 two new nuclear units would be SMALL.

11 The human health effects from the operation of two new nuclear units would be similar to those 

12 of operating the two existing LSCS units. As presented in Section 4.11.1, impacts on human 

13 health from the operation of LSCS would be SMALL, except for “chronic effects of 

14 electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. Therefore, the impacts 

15 on human health from the operation of two new nuclear units would be SMALL.

16 4.11.4 IGCC Alternative

17 Impacts from construction on workers are expected to be similar to those experienced during 

18 construction of any major industrial facility. Impacts from construction of an IGCC facility are 

19 expected to be the same as those for construction of fossil fuel facilities. Construction would 

20 increase traffic on local roads, which could affect the health of the general public. Human health 

21 impacts would be the same for all facilities, whether located on greenfield sites or at an existing 

22 power plant. Personal protective equipment, training, and engineered barriers would protect the 

23 workforce (NRC 2013d). Therefore, the impacts on human health from the construction of an 

24 IGCC facility would be SMALL.

25 The IGCC alternative introduces worker risks from coal and limestone mining, worker and public 

26 risk from coal and lime/limestone transportation, worker and public risk from disposal of 

27 coal-combustion waste, and public risk from inhalation of stack emissions. In addition, human 

28 health risks are associated with the management and disposal of coal combustion waste. Coal 

29 combustion generates waste in the form of ash, and equipment for controlling air pollution 

30 captures additional ash and produces scrubber sludge, which must be managed as coal 

31 combustion waste. Human health risks may extend beyond the facility workforce to the public, 

32 depending on their proximity to the coal combustion waste storage and/or disposal facility. The 

33 character and the constituents of coal combustion waste depend on both the chemical 

34 composition of the source coal and the technology used to combust it. Generally, the primary 

35 sources of adverse consequences from coal combustion waste are from exposure to sulfur 

36 oxide and nitrogen oxide in air emissions and radioactive elements, such as uranium and 

37 thorium, as well as the heavy metals and hydrocarbon compounds contained in fly ash and 

38 bottom ash, and scrubber sludge (NRC 2013d).

39 Regulatory agencies, including EPA and state agencies, base air emission standards and 

40 requirements on human health impacts. These agencies also impose site-specific emission 

41 limits as needed to protect human health. Given the regulatory oversight exercised by EPA and 

42 state agencies, the NRC staff concludes that the human health impacts from radiological doses 

43 and inhaled toxins and particulates generated from the IGCC alternative would be SMALL 

44 (NRC 2013d).
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1 4.11.5 NGCC Alternative

2 Impacts on human health from construction of the NGCC alternative would be similar to effects 

3 associated with the construction of any major industrial facility. Compliance with worker 

4 protection rules would control those impacts on workers at acceptable levels. Impacts from 

5 construction on the general public would be minimal, since crews would limit active construction 

6 area access to authorized individuals. Based on the above, the NRC staff concludes that the 

7 impacts on human health from the construction of the NGCC alternative would be SMALL.

8 Impacts from the operation of an NGCC facility include public risk from inhalation of gaseous 

9 emissions. The risk may be attributable to nitrogen oxide emissions that contribute to ozone 

10 formation, which in turn contribute to health risk. Regulatory agencies, including the EPA and 

11 state agencies, base air emission standards and requirements on human health impacts. 

12 These agencies also impose site-specific emission limits as needed to protect human health. 

13 Given the regulatory oversight exercised by EPA and state agencies, the NRC staff concludes 

14 that the human health impacts from the NGCC alternative would be SMALL.

15 4.11.6 Combination Alternative (NGCC, Wind, Solar)

16 Impacts on human health from construction of a combination of NGCC, wind, and solar 

17 alternative would be similar to effects associated with the construction of any major industrial 

18 facility. Compliance with worker protection rules and personal protective equipment, training, 

19 and engineered barriers would protect the workforce (NRC 2013d). Impacts from construction 

20 on the general public would be minimal, since crews would limit active construction area access 

21 to authorized individuals. Based on the above, the NRC staff concludes that the Impacts on 

22 human health from the construction of the NGCC, wind, and solar alternative would be SMALL.

23 Operational hazards at an NGCC facility are discussed in Section 4.11.5.

24 Operational hazards at a wind facility for the workforce include working at heights, near rotating 

25 mechanical or electrically energized equipment, and in extreme weather. Potential impacts to 

26 workers and the public include ice thrown from rotor blades and broken blades thrown as a 

27 result of mechanical failure. Potential impacts also include EMF exposure, aviation safety 

28 (hazards), and exposure to noise and vibration from the rotating blades.

29 Operational hazards at a solar PV facility may involve exposure to airborne toxic metals 

30 (e.g., cadmium) and silicon if the PV cell loses its integrity from a fire. Workers could also inhale 

31 silicon dust if a PV cell were smashed by an object or from a fall to the ground. However, based 

32 on worker and environmental protection rules, it is expected that remediation of toxic material 

33 would occur. Such remediation would minimize the impact to workers and the environment.

34 Therefore, given the expected compliance with worker and environmental protection rules and 

35 the use of personal protective equipment, training, and engineered barriers, the NRC staff 

36 concludes that the potential human health impacts would be SMALL.

37 4.11.7 Purchased Power Alternative

38 Purchased power is expected to come from the types of electricity generation available within 

39 the ROI: coal, natural gas, nuclear, and wind. The human health impacts from the operation of 

40 these types of power plants are discussed in Sections 4.11.3, 4.11.4, 4.11.5, and 4.11.6. Based 

41 on the information in those sections, the NRC staff concludes that the human health impacts of 

42 the purchased power alternative using nuclear, coal, natural gas, wind, and solar would be 

43 SMALL.
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1 4.12 Environmental Justice

2 This section describes the potential human health and environmental effects of the proposed 

3 action (license renewal) and alternatives to the proposed action on minority and low-income 

4 populations. 

5 4.12.1 Proposed Action

6 Section 3.12 identifies minority and low-income populations living in the vicinity of LSCS. 

7 Table 4–17 identifies the environmental justice issue applicable to LSCS during the license 

8 renewal term. 

9 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

10 The NRC addresses environmental justice matters for license renewal by (1) identifying the 

11 location of minority and low-income populations that may be affected by the continued operation 

12 of the nuclear power plant during the license renewal term, (2) determining whether there would 

13 be any potential human health or environmental effects to these populations and special 

14 pathway receptors, and (3) determining if any of the effects may be disproportionately high and 

15 adverse. Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal 

16 adverse impacts on human health. Disproportionately high and adverse human health effects 

17 occur when the risk or rate of exposure to an environmental hazard for a minority or low-income 

18 population is significant and exceeds the risk or exposure rate for the general population or for 

19 another appropriate comparison group. Disproportionately high environmental effects refer to 

20 impacts or risks of impacts on the natural or physical environment in a minority or low-income 

21 community that are significant and appreciably exceed the environmental impact on the larger 

22 community. Such effects may include biological, cultural, economic, or social impacts.

23 Figures 3–17 and 3–18 show the location of predominantly minority and low-income population 

24 block groups residing within a 50-mi (80-km) radius of LSCS. This area of impact is consistent 

25 with the impact analysis for public and occupational health and safety, which also focuses on 

26 populations within a 50-mi (80-km) radius of the plant. Chapter 4 presents the assessment of 

27 environmental and human health impacts for each resource area. The analyses of impacts for 

28 all environmental resource areas indicated that the impact from license renewal would be 

29 SMALL.

30 Potential impacts on minority and low-income populations (including migrant workers or Native 

31 Americans) would mostly consist of socioeconomic and radiological effects; however, radiation 

32 doses from continued operations during the license renewal term are expected to continue at 

33 current levels, and they would remain within regulatory limits. Section 4.11.1.2 of this SEIS 

34 discusses the environmental impacts from postulated accidents that might occur during the 

35 license renewal term, which include both design basis and severe accidents. In both cases, the 

36 Commission has generically determined that impacts associated with DBAs are small because 

37 nuclear plants are designed and operated to successfully withstand such accidents, and the 

38 probability-weighted consequences of severe accidents are small.

39 Therefore, based on this information and the analysis of human health and environmental 

40 impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 
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1 adverse human health and environmental effects on minority and low-income populations from 

2 the continued operation of LSCS during the license renewal term.

3 As part of addressing environmental justice concerns associated with license renewal, the NRC 

4 staff also assessed the potential radiological risk to special population groups (such as migrant 

5 workers or Native Americans) from exposure to radioactive material received through their 

6 unique consumption practices and interaction with the environment, including subsistence 

7 consumption of fish and wildlife, native vegetation, surface waters, sediments, and local 

8 produce; absorption of contaminants in sediments through the skin; and inhalation of airborne 

9 radioactive material released from the plant during routine operation. This analysis is presented 

10 below.

11 Subsistence Consumption of Fish and Wildlife

12 The special pathway receptors analysis is an important part of the environmental justice

13 analysis because consumption patterns may reflect the traditional or cultural practices of 

14 minority and low-income populations in the area, such as migrant workers or Native Americans.

15 Section 4–4 of Executive Order 12898 (1994) directs Federal agencies, whenever practical and 

16 appropriate, to collect and analyze information about the consumption patterns of populations 

17 that rely principally on fish and/or wildlife for subsistence and to communicate the risks of these 

18 consumption patterns to the public. In this SEIS, the NRC considered whether there were any 

19 means for minority or low-income populations to be disproportionately affected by examining 

20 impacts on American Indian, Hispanics, migrant workers, and other traditional lifestyle special 

21 pathway receptors. The assessment of special pathways considered the levels of radiological 

22 and nonradiological contaminants in vegetation, crops, soils and sediments, groundwater, 

23 surface water, fish, and game animals on or near LSCS.

24 Radionuclides released to the atmosphere may deposit on soil and vegetation and, therefore, 

25 may eventually be incorporated into the human food chain. To assess the impact of LSCS

26 operations to humans from the ingestion pathway, samples of fish, milk, green leafy vegetables, 

27 surface water, sediment, and groundwater are collected and analyzed for radioactivity. The 

28 following describes Exelon’s radiological environmental monitoring program (REMP).

29 Exelon has an ongoing comprehensive REMP to assess the impact of LSCS operations on the 

30 environment. To assess the impact of nuclear power plant operations, samples are collected 

31 annually from the environment and analyzed for radioactivity. A plant effect would be indicated 

32 if the radioactive material detected in a sample were larger or higher than background levels. 

33 Two types of samples are collected. The first type, a control sample, is collected from areas 

34 that are beyond the influence of the nuclear power plant or any other nuclear facility. These 

35 samples are used as reference data to determine normal background levels of radiation in the 

36 environment. These samples are then compared with the second type of samples, indicator 

37 samples, collected near the nuclear power plant. Indicator samples are collected from areas 

38 where any contribution from the nuclear power plant will be at its highest concentration. These 

39 samples are then used to evaluate the contribution of nuclear power plant operations to 

40 radiation or radioactivity levels in the environment. An effect would be indicated if the 

41 radioactivity levels detected in an indicator sample were larger or higher than the control sample 

42 or background levels.

43 Samples were collected from the aquatic and terrestrial environment in the vicinity of LSCS in 

44 2014. The aquatic environment includes groundwater, surface water, fish, and river sediment. 

45 Aquatic monitoring results for 2014 of water, sediment, and fish showed only naturally occurring 

46 radioactivity and radioactivity associated with fallout from past atmospheric nuclear weapons 

47 testing and were consistent with levels measured prior to the operation of LSCS. No 
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1 radioactivity was detected greater than the minimum detectable activity in any aquatic sample 

2 during 2014, and no adverse long-term trends were identified in aquatic monitoring data 

3 (Exelon 2015a).

4 The terrestrial environment includes airborne particulates, milk, and food products (i.e., beets, 

5 kohlrabi, potatoes, Swiss chard, and kale). However, cow milk samples were not analyzed in 

6 2014, as the dairy herd was sold prior to the first sample in 2014 (Exelon 2015a). Terrestrial 

7 monitoring results for 2014 of groundwater and leafy garden vegetable samples, showed only 

8 naturally occurring radioactivity. The radioactivity levels detected were consistent with levels 

9 measured prior to the operation of LSCS. No radioactivity was detected greater than the 

10 minimum detectable activity in any terrestrial samples during 2014. The terrestrial monitoring 

11 data also showed no adverse trends in the terrestrial environment (Exelon 2015a).

12 Analyses performed on 1,393 samples collected from the environment at LSCS in 2014 showed 

13 no significant measurable radiological constituent above background levels. Overall, 

14 radioactivity levels detected in 2014 were consistent with previous levels, as well as radioactivity 

15 levels measured prior to the operation of LSCS. REMP sampling in 2014 did not identify any 

16 radioactivity above the minimum detectable activity (Exelon 2015a).

17 Based on the radiological environmental monitoring data from LSCS, the NRC staff finds that no 

18 disproportionately high and adverse human health impacts would be expected in special 

19 pathway receptor populations in the region as a result of subsistence consumption of water, 

20 local food, fish, and wildlife. Continued operation of LSCS would not have disproportionately 

21 high and adverse human health and environmental effects on these populations.

22 4.12.2 No-Action Alternative

23 This section evaluates the potential for disproportionately high and adverse human health and 

24 environmental effects on minority and low-income populations that could result from the 

25 no-action alternative. Impacts on minority and low-income populations would depend on the 

26 number of jobs and the amount of tax revenues lost by communities in the immediate vicinity of 

27 the power plant after LSCS ceases operations. Not renewing the operating licenses and 

28 terminating reactor operations would have a noticeable impact on socioeconomic conditions in 

29 the communities located near LSCS. The loss of jobs and income would have an immediate 

30 socioeconomic impact. Some, but not all, of the approximately 890 employees would begin to 

31 leave after reactor operations are terminated; and overall tax revenue generated by plant 

32 operations would be reduced. The reduction in tax revenue would decrease the availability of 

33 public services in LaSalle County. This could disproportionately affect minority and low-income 

34 populations that may have become dependent on these services. See also Appendix J of 

35 NUREG–0586, Supplement 1 (NRC 2002), for additional discussion of these impacts.

36 4.12.3 New Nuclear Alternative

37 This section evaluates the potential for disproportionately high and adverse human health and 

38 environmental effects on minority and low-income populations that could result from the 

39 construction and operation of a new nuclear power plant. Some of these potential effects have 

40 been identified in resource areas discussed in this SEIS. For example, increased demand for 

41 rental housing during replacement power plant construction could disproportionately affect 

42 low-income populations. Everyone living near the proposed power plant site could be affected 

43 by the construction and operation of a new nuclear power plant, including minority and 

44 low-income populations.
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1 Potential impacts to minority and low-income populations from the construction and operation of 

2 a new nuclear power plant at an existing nuclear power plant or retired coal plant site would 

3 mostly consist of environmental and socioeconomic effects (e.g., noise, dust, traffic, 

4 employment, and housing impacts). Noise and dust impacts from construction would be short

5 term and primarily limited to onsite activities. Minority and low-income populations residing 

6 along site access roads would be affected by increased commuter vehicle traffic during shift 

7 changes and truck traffic. However, these effects would be temporary during certain hours of 

8 the day and would not likely be high and adverse. Increased demand for rental housing during 

9 construction could affect low-income populations. However, given the proximity of some 

10 existing nuclear power plant or retired coal plant sites to metropolitan areas, construction 

11 workers could commute to the site, thereby reducing the potential demand for rental housing.

12 Potential impacts to minority and low-income populations from new nuclear power plant 

13 operations would mostly consist of radiological effects; however, radiation doses are expected 

14 to be well below regulatory limits. All people living near the new nuclear power plant would be 

15 exposed to the same potential effects from power plant operations, and permitted air emissions 

16 are expected to remain within regulatory standards.

17 Based on this information and the analysis of human health and environmental impacts 

18 presented in this SEIS, it is not likely that the construction and operation of a new nuclear power 

19 plant would have disproportionately high and adverse human health and environmental effects 

20 on minority and low-income populations. However, this determination would depend on the 

21 location, plant design, and operational characteristics of the new power plant. Therefore, the 

22 NRC staff cannot determine whether this alternative would result in disproportionately high and 

23 adverse human health and environmental effects on minority and low-income populations.

24 4.12.4 IGCC Alternative

25 This section evaluates the potential for disproportionately high and adverse human health and 

26 environmental effects on minority and low-income populations that could result from the 

27 construction and operation of a new IGCC power plant. Some of these potential effects have 

28 been identified in resource areas discussed in this SEIS. For example, increased demand for 

29 rental housing during replacement power plant construction could disproportionately affect 

30 low-income populations. Everyone living near the proposed power plant site could be affected 

31 by the construction and operation of a new IGCC power plant, including minority and 

32 low-income populations.

33 Potential impacts to minority and low-income populations from the construction and operation of 

34 a new IGCC plant at the LSCS site or at another existing power plant site would consist of 

35 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

36 impacts). Noise and dust impacts from construction would be short term and primarily limited to 

37 onsite activities. Minority and low-income populations residing along site access roads would 

38 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

39 However, these effects would be temporary during certain hours of the day and would not likely 

40 be high and adverse. Increased demand for rental housing during construction could affect 

41 low-income populations. However, given the proximity of some existing power plant sites to 

42 Chicago (LSCS site) and other metropolitan areas (at another existing power plant site), 

43 construction workers could commute to the site, thereby reducing the potential demand for 

44 rental housing.

45 Emissions from the IGCC plant during power plant operations could disproportionately affect 

46 minority and low-income populations. However, permitted air emissions are expected to remain 

47 within regulatory standards.
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1 Based on this information and the analysis of human health and environmental impacts 

2 presented in this SEIS, it is not likely that the construction and operation of a new IGCC plant 

3 would have disproportionately high and adverse human health and environmental effects on 

4 minority and low-income populations. However, this determination would depend on the 

5 location, plant design, and operational characteristics of the new power plant at the LSCS site or 

6 at another existing power plant site. Therefore, the NRC staff cannot determine whether this 

7 alternative would result in disproportionately high and adverse human health and environmental 

8 effects on minority and low-income populations.

9 4.12.5 NGCC Alternative 

10 This section evaluates the potential for disproportionately high and adverse human health and 

11 environmental effects on minority and low-income populations that could result from the 

12 construction and operation of a new NGCC plant. Some of these potential effects have been 

13 identified in resource areas discussed in this SEIS. For example, increased demand for rental 

14 housing during replacement power plant construction could disproportionately affect low-income 

15 populations. Everyone living near the proposed power plant site could be affected by the 

16 construction and operation of a new NGCC power plant, including minority and low-income 

17 populations.

18 Potential impacts to minority and low-income populations from the construction and operation of 

19 a new NGCC plant at the LSCS site would mostly consist of environmental and socioeconomic 

20 effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise and dust impacts 

21 from construction would be short term and primarily limited to onsite activities. Minority and 

22 low-income populations residing along site access roads would be affected by increased 

23 commuter vehicle traffic during shift changes and truck traffic. However, these effects would be 

24 temporary during certain hours of the day and would not likely be high and adverse. Increased 

25 demand for rental housing during construction could affect low-income populations in the vicinity 

26 of the LSCS site. However, given the proximity of LSCS to the Chicago metropolitan area, 

27 many construction workers could commute to the site, thereby reducing the potential demand 

28 for rental housing.

29 Emissions from the NGCC plant during power plant operations could disproportionately affect 

30 minority and low-income populations living in the vicinity of the new power plant. However, 

31 permitted air emissions are expected to remain within regulatory standards.

32 Based on this information and the analysis of human health and environmental impacts 

33 presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant 

34 would have disproportionately high and adverse human health and environmental effects on 

35 minority and low-income populations. However, this determination would depend on the 

36 location, plant design, and operational characteristics of the new power plant at LSCS. 

37 Therefore, the NRC staff cannot determine whether this alternative would result in 

38 disproportionately high and adverse human health and environmental effects on minority and 

39 low-income populations.

40 4.12.6 Combination Alternative (NGCC, Wind, Solar)

41 This section evaluates the potential for disproportionately high and adverse human health and 

42 environmental effects on minority and low-income populations that could result from the 

43 construction and operation of a combination of NGCC, wind, and solar PV electrical power 

44 generating activities. Some of these potential effects have been identified in resource areas 

45 discussed in this SEIS. For example, increased demand for rental housing during construction 

46 could disproportionately affect low-income populations. Everyone living near the new NGCC, 
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1 wind farms, and solar PV installations could be affected by construction activities and facility 

2 operations, including minority and low-income populations.

3 Potential impacts to minority and low-income populations from the construction and operation of 

4 a new NGCC plant, wind turbines, and solar PV installations would mostly consist of 

5 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

6 impacts). Noise and dust impacts from construction would be short term and primarily limited to 

7 onsite activities. Minority and low-income populations residing along site access roads would 

8 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

9 However, these effects would be temporary during certain hours of the day and would not likely 

10 be high and adverse. Increased demand for rental housing during construction could affect 

11 low-income populations. However, given the small number of construction workers and the 

12 possibility that many workers could commute to these construction sites, the potential need for 

13 rental housing would not be significant.

14 Minority and low-income populations living in close proximity to wind farm and solar PV power 

15 generating installations could be disproportionately affected by maintenance and operations 

16 activities. However, operational impacts from the wind turbines and solar PV installations would 

17 mostly be limited to noise and aesthetic effects.

18 Based on this information and the analysis of human health and environmental impacts 

19 presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant, 

20 wind farms, and solar PV installations would have disproportionately high and adverse human 

21 health and environmental effects on minority and low-income populations. However, this 

22 determination would depend on the location, plant design, and operational characteristics of 

23 these new power generating facilities. Therefore, the NRC staff cannot determine whether this 

24 alternative would result in disproportionately high and adverse human health and environmental 

25 effects on minority and low-income populations.

26 4.12.7 Purchased Power Alternative

27 This section evaluates the potential for disproportionately high and adverse human health and 

28 environmental effects on minority and low-income populations that could result from purchasing 

29 electric power. As previously discussed, such effects may include human health, biological, 

30 cultural, economic, or social impacts.

31 Purchased power from existing power generating facilities would not likely have any 

32 disproportionately high and adverse effects on minority populations, because there would be no 

33 change in power plant operations or workforce. However, low-income populations could be 

34 disproportionately affected by increased utility bills, due to the cost of purchased power, 

35 although programs are available to assist low-income families in paying for increased electrical 

36 costs.

37 If the amount of purchased power needed exceeds the available supply, new electric power 

38 generating facilities would be needed. Construction and operation of a new electrical power 

39 generating facility to supply purchased power could create new human health and 

40 environmental effects in communities located near the new facility. Everyone living near the 

41 new electric power generating facility could be affected by construction activities and facility 

42 operations, including minority and low-income populations.

43 Potential human health and environmental effects from constructing and operating a new power 

44 generating facility have been described in the previous sections. Operational impacts for all 

45 new power generating facilities would mostly be limited to noise, air emissions, and aesthetic

46 effects. Minority and low income populations could experience disproportionate human health 
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1 and environmental effects from the emissions from fossil-fueled power plants (e.g., increased 

2 asthma). However, any human health or environmental effects would depend on the location of 

3 the new power plant in relation to minority and low-income communities and the magnitude of 

4 the change in ambient air quality conditions. Also, permitted air emissions would be expected to 

5 remain within regulatory standards.

6 Based on this information and the analysis of human health and environmental impacts 

7 presented in this SEIS, it is not likely that purchasing electrical power from existing power 

8 generating facilities would have disproportionately high and adverse human health and 

9 environmental effects on minority and low-income populations. In addition, this determination 

10 would depend on whether a new electrical power generating facility were needed to supply 

11 purchased power. If a new power generating facility is needed, impacts to minority and 

12 low-income populations would depend on the location, plant design, and operational 

13 characteristics of these new power generating facilities. Therefore, the NRC staff cannot 

14 determine whether this alternative would result in disproportionately high and adverse human 

15 health and environmental effects on minority and low-income populations.

16 4.13 Waste Management

17 This section describes the potential impacts of the proposed action (license renewal) and 

18 alternatives to the proposed action on waste management and pollution prevention.

19 4.13.1 Proposed Action

20 Section 3.12 describes LSCS waste management and pollution prevention. Table 4–18 

21 identifies the waste management issues applicable to LSCS during the license renewal term. 

22 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

23 The NRC staff’s evaluation of the environmental impacts associated with spent nuclear fuel is 

24 addressed in two issues in Table 4–18, “Onsite storage of spent nuclear fuel” and “Offsite 

25 radiological impacts of spent nuclear fuel and high-level waste disposal.” The issue of onsite 

26 storage of spent nuclear fuel now incorporates the generic environmental impact determinations 

27 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 28 . 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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1 radiological impacts of spent nuclear fuel and high-level waste disposal are codified in 

2 Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51, and the technical feasibility of disposal 

3 in a geologic repository is discussed in NUREG–2157, “Generic Environmental Impact 

4 Statement for Continued Storage of Spent Nuclear Fuel, Volumes 1 and 2” (NRC 2014). 

5 The NRC staff did not identify any new and significant information related to waste management 

6 issues listed in Table 4–18 during its review of the applicant’s ER (Exelon 2014a), the site visit, 

7 or the scoping process. Therefore, there are no impacts related to these issues beyond those 

8 discussed in the GEIS (NRC 2013d) and NUREG–2157 (NRC 2014). During the license 

9 renewal term, for these Category 1 issues discussed in the GEIS, the NRC staff concludes that 

10 the impacts are SMALL.

11 4.13.2 No-Action Alternative

12 If the no-action alternative were implemented, LSCS would cease operation at the end of the 

13 term of the initial operating licenses, or sooner, and enter decommissioning. The plants, which 

14 are currently operating within regulatory limits, would generate less spent nuclear fuel and emit 

15 less gaseous and liquid radioactive effluents into the environment. In addition, following 

16 shutdown, the variety of potential accidents at the plants (radiological and industrial) would be 

17 reduced to a limited set associated with shutdown events and fuel handling and storage. In 

18 Section 4.14.2 of this SEIS, the NRC staff concludes that the impacts from decommissioning 

19 would be SMALL. Therefore, as radioactive emissions to the environment decrease, and the 

20 likelihood and variety of accidents decrease following shutdown and decommissioning, the NRC 

21 staff concludes that impacts from implementation of the no-action alternative would be SMALL.

22 4.13.3 New Nuclear Alternative

23 Construction-related debris would be generated during construction activities and would be 

24 recycled or disposed of in approved landfills.

25 During normal plant operations, routine plant maintenance, and cleaning activities would 

26 generate radioactive low-level waste, spent nuclear fuel, and high-level waste, as well as 

27 nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 

28 management at LSCS. Quantities of radioactive and nonradioactive waste generated by LSCS 

29 would be comparable to that generated by the two new nuclear plants.

30 According to the GEIS (NRC 2013d), the generation and management of solid radioactive and 

31 nonradioactive waste during the license renewal term are not expected to result in significant 

32 environmental impacts.

33 Based on this information, the waste impacts would be SMALL for the new nuclear alternative.

34 4.13.4 IGCC Alternative

35 Construction-related debris would be generated during plant construction activities and would 

36 be recycled or disposed of in approved landfills.

37 Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 

38 for controlling air pollution generates additional ash, spent selective catalytic reduction (SCR) 

39 catalyst, and scrubber sludge. The management and disposal of the large amounts of coal 

40 combustion waste is a significant part of the operation of a coal-fired power generating facility.

41 Although an IGCC facility is likely to use offsite disposal of coal combustion waste, some 

42 short-term storage of coal combustion waste (either in open piles or in surface impoundments) 
Environmental Consequences and Mitigating Actions

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1 is likely to take place on site, thus establishing the potential for leaching of toxic chemicals into 

2 the local environment.

3 The impacts of managing the substantial amounts of solid waste, especially fly ash and 

4 scrubber sludge, generated during operation of this alternative would be MODERATE 

5 (NRC 1996). The amount of the construction waste would be small compared to the amount of 

6 waste generated during the operational stage and much of it could be recycled (i.e., marketed 

7 for beneficial use). Therefore, the NRC staff concludes that the overall waste management 

8 impacts from construction of this alternative would be SMALL and from operation of this 

9 alternative would be MODERATE.

10 4.13.5 NGCC Alternative

11 Construction-related debris would be generated during plant construction activities, and would 

12 be recycled or disposed of in approved landfills.

13 Waste generation from NGCC technology would be minimal. The only significant waste 

14 generated at an NGCC power plant would be spent SCR catalyst, which is used to control 

15 nitrogen oxide emissions.

16 The spent catalyst would be regenerated or disposed of offsite. Other than the spent SCR 

17 catalyst, waste generation at an operating natural-gas-fired plant would be limited largely to 

18 typical operations and maintenance of nonhazardous waste. Overall, the NRC staff concludes 

19 that waste impacts from the NGCC alternative would be SMALL.

20 4.13.6 Combination Alternative (NGCC, Wind, Solar)

21 Construction-related debris would be generated during construction activities and would be 

22 recycled or disposed of in approved landfills.

23 Waste generation from NGCC technology is discussed in Section 4.13.5.

24 Waste generation from a combination of wind and solar PV alternatives would be minimal, 

25 consisting of debris from routine maintenance and the disposal of worn or broken parts. Based 

26 on this information, the NRC staff concludes that waste impacts from the construction and 

27 operation of a combination wind and solar PV alternative would be SMALL.

28 4.13.7 Purchased Power Alternative

29 The types of waste generated by the alternative electricity generation sources (i.e., coal, natural 

30 gas, nuclear, and wind) used in the purchased power alternative are discussed in 

31 Sections 4.13.3, 4.13.4, 4.13.5, and 4.13.6. Depending on types of power generation plants 

32 used to provide the electricity for the purchased power alternative, the NRC staff concludes that 

33 the waste management impacts would range from SMALL to MODERATE.

34 4.14 Evaluation of New and Potentially Significant Information

35 New and significant information must be new based on a review of the GEIS (NRC 2013d) and 

36 codified in Table B–1 of Appendix B to Subpart A of 10 CFR Part 51, and must bear on the 

37 proposed action or its impacts, presenting a seriously different picture of the impacts from those 

38 envisioned in the GEIS (i.e., impacts of greater severity than impacts considered in the GEIS, 

39 considering their intensity and context).

40 In accordance with 10 CFR 51.53(c), the ER that the applicant submits must provide an analysis 

41 of the Category 2 issues in Table B–1 of 10 CFR Part 51, Subpart A, Appendix B. Additionally, 
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1 it must discuss actions to mitigate any adverse impacts associated with the proposed action and 

2 environmental impacts of alternatives to the proposed action. In accordance with 

3 10 CFR 51.53(c)(3), the ER does not need to contain an analysis of any Category 1 issue 

4 unless there is new and significant information on a specific issue.

5 The NRC process for identifying new and significant information is described in NUREG–1555, 

6 Supplement 1, Standard Review Plans for Environmental Reviews for Nuclear Power Plants, 

7 Supplement 1: Operating License Renewal (NRC 2013f). The search for new information 

8 includes: 

9 • review of an applicant’s ER and the process for discovering and evaluating the 

10 significance of new information;

11 • review of public comments;

12 • review of environmental quality standards and regulations;

13 • coordination with Federal, state, and local environmental protection and resource 

14 agencies; and 

15 • review of technical literature. 

16 New information that the staff discovers is evaluated for significance using the criteria set forth 

17 in the GEIS. For Category 1 issues in which new and significant information is identified, 

18 reconsideration of the conclusions for those issues is limited in scope to assessment of the 

19 relevant new and significant information; the scope of the assessment does not include other 

20 facets of an issue that the new information does not affect.

21 The NRC staff reviewed the discussion of environmental impacts associated with operation 

22 during the renewal term in the GElS and has conducted its own independent review, including a 

23 public involvement process (e.g., public meetings) to identify new and significant issues for the 

24 LSCS license renewal application environmental review. The NRC staff has not identified new 

25 and significant information on environmental issues related to operation of LSCS during the 

26 renewal term. The NRC staff also determined that information provided during the public 

27 comment period did not identify any new issue that requires site-specific assessment.

28 The NRC staff did, however, find new, but not significant, information regarding the uranium fuel 

29 cycle issue, and this information is discussed in Section 4.15.1 and Appendix G of this SEIS.

30 4.15 Impacts Common to All Alternatives

31 This section describes the impacts that are considered common to all alternatives discussed in 

32 this SEIS, including the proposed action and replacement power alternatives. The continued 

33 operation of a nuclear power plant and replacement fossil fuel power plants both involve the 

34 mining, processing, and consumption of fuel, which results in comparative impacts 

35 (NRC 2013d). In addition, the termination of operations and the decommissioning of both a 

36 nuclear power plant and replacement fossil-fueled power plants, as well as GHG emissions, are 

37 discussed in the following sections.

38 4.15.1 Fuel Cycles

39 This section describes the environmental impacts associated with the fuel cycles of the 

40 proposed action and replacement power alternatives. Most replacement power alternatives 

41 employ a set of steps in the utilization of their fuel sources, which can include extraction, 
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1 transformation, transportation, and combustion. Emissions generally occur at each stage of the 

2 fuel cycle (NRC 2013d).

3 4.15.1.1 Uranium Fuel Cycle

4 The uranium fuel cycle issues applicable to LSCS are discussed below and listed in Table 4–19 

5 for Category 1 issues. Table B–1 of Appendix B to Subpart A of 10 CFR Part 51 contains more 

6 information on these issues.

7 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

8 The uranium fuel cycle includes uranium mining and milling, production of uranium hexafluoride, 

9 isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation of radioactive 

10 materials, and management of low-level wastes and high-level wastes related to uranium fuel 

11 cycle activities. The generic potential impacts of the radiological and nonradiological 

12 environmental impacts of the uranium fuel cycle and transportation of nuclear fuel and wastes 

13 are described in detail in NUREG–1437 (NRC 2013d).

14 The NRC staff did not identify any new and significant information related to the uranium fuel 

15 cycle issues “Offsite radiological impacts—individual impacts from other than the disposal of 

16 spent fuel and high level waste,” “Offsite radiological impacts—collective impacts from other 

17 than the disposal of spent fuel and high-level waste,” and “Nonradiological impacts of the 

18 uranium fuel cycle,” listed above in Table 4–19, during its review of the applicant’s ER 

19 (Exelon 2014a), the site visit, and the scoping process. Therefore, there are no impacts related 

20 to these issues beyond those discussed in the GEIS. For these Category 1 issues, the GEIS 

21 concludes that the impacts are SMALL, except for the issue, “Offsite radiological impacts—

22 collective impacts,” to which the NRC has not assigned an impact level. This issue assesses 

23 the 100-year radiation dose to the U.S. population (i.e., collective effects or collective dose) from 

24 radioactive effluent released as part of the uranium fuel cycle for a nuclear power plant during 

25 the license renewal term compared to the radiation dose from natural background exposure. It 

26 is a comparative assessment for which there is no regulatory standard to base an impact level.

27 The NRC staff did, however, find new information regarding the uranium fuel cycle issue 

28 “Transportation,” listed above in Table 4–19, in its review of the applicant’s ER. The NRC has 

29 generically determined, in its license renewal application reviews, that the environmental 

30 impacts of the transportation of fuel and radioactive wastes to and from nuclear power facilities 

31 are small for all reactors as long as certain specific conditions are met. The application for 

32 license renewal of LSCS stated that the specific conditions that allow the transportation impacts 

33 of spent fuel to be generically determined to be small may not be met for LSCS. Therefore, the 

34 NRC staff analyzed the environmental impacts of transporting spent fuel from LSCS in 

35 Appendix G of this SEIS. From this analysis, the NRC staff concludes that the environmental 

36 impacts of the transportation of spent fuel from LSCS would be consistent with the 
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1 environmental impacts associated with the transportation of fuel and radioactive wastes to and 

2 from current-generation reactors presented in Table S–4 of 10 CFR 51.52, and thus would be 

3 SMALL.

4 4.15.1.2 Replacement Power Plant Fuel Cycles

5 Fossil Fuel Energy Alternatives

6 Fuel cycle impacts for a fossil-fuel-fired plant result from the initial extraction of fuel, cleaning 

7 and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 

8 solid wastes from fuel combustion. These impacts are discussed in more detail in 

9 Section 4.12.1.2 of the GEIS (NRC 2013d) and can generally include:

10 • significant changes to land use and visual resources;

11 • impacts to air quality, including release of criteria pollutants, fugitive dust, VOCs, and 

12 coalbed methane in the atmosphere;

13 • noise impacts;

14 • geology and soil impacts due to land disturbances and mining;

15 • water resource impacts, including degradation of surface water and groundwater

16 quality;

17 • ecological impacts, including loss of habitat and wildlife disturbances;

18 • historic and cultural resources impacts within the mine footprint;

19 • socioeconomic impacts from employment of both the mining workforce and service 

20 and support industries;

21 • environmental justice impacts;

22 • health impacts to workers from exposure to airborne dust and methane gases; and

23 • generation of coal and industrial wastes.

24 New Nuclear Energy Alternatives

25 Uranium fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport 

26 of fuel to the facility, and management and ultimate disposal of spent fuel. The environmental 

27 impacts of the uranium fuel cycle are discussed above in Section 4.15.1.1.

28 Renewable Energy Alternatives

29 The “fuel cycle” for renewable energy facilities is difficult to define for technologies such as wind 

30 and solar because these natural resources exist regardless of any effort to harvest them for 

31 electricity production. Impacts from the presence or absence of these renewable energy 

32 technologies are often difficult to determine (NRC 2013d).

33 4.15.2 Terminating Power Plant Operations and Decommissioning

34 This section describes the environmental impacts associated with the termination of operations 

35 and the decommissioning of a nuclear power plant and replacement power alternatives. All 

36 operating power plants will terminate operations and be decommissioned at some point after the 

37 end of their operating life or after a decision is made to cease operations. For the proposed 

38 action, license renewal would delay this eventuality for an additional 20 years beyond the 

39 current license period, which ends in 2022 and 2023 for LSCS Units 1 and 2, respectively.
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1 4.15.2.1 Existing Nuclear Power Plant

2 Environmental impacts from the activities associated with the decommissioning of any reactor

3 before or at the end of an initial or renewed license are evaluated in Supplement 1 of 

4 NUREG–0586 (NRC 2002). Additionally, the incremental environmental impacts associated 

5 with decommissioning activities resulting from continued plant operation during the renewal term 

6 are discussed in the GEIS.

7 Table 4–20 lists the Category 1 issues in Table B–1 of Title 10 of the CFR Part 51, Subpart A, 

8 Appendix B, that are applicable to LSCS decommissioning following the license renewal term.

9 Table 4–20. Issues Related to Decommissioning

Issue GEIS Section Category

Radiation doses 4.12.2.1 1

Waste management 4.12.2.1 1

Air quality 4.12.2.1 1

Water quality 4.12.2.1 1

Ecological resources 4.12.2.1 1

Socioeconomic impacts 4.12.2.1 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

10 Decommissioning would occur whether LSCS were shut down at the end of its current operating 

11 license or at the end of the period of the license renewal term. Exelon stated in its ER 

12 (Exelon 2014a) that it is not aware of any new and significant information on the environmental 

13 impacts of LSCS during the license renewal term. The NRC staff has not found any new and 

14 significant information during its independent review of Exelon’s ER, the site visit, or the scoping

15 process. Therefore, the NRC staff concludes that there are no impacts related to 

16 decommissioning, beyond those discussed in the GEIS. For all of these issues, the NRC staff 

17 concluded, in the GEIS, that the impacts are SMALL.

18 4.15.2.2 Replacement Power Plants

19 Fossil Fuel Energy Alternatives

20 The environmental impacts from the termination of power plant operations and 

21 decommissioning of a fossil-fuel-fired plant are dependent on the facility’s decommissioning 

22 plan. General elements and requirements for a fossil fuel plant decommissioning plan are 

23 discussed in Section 4.12.2 of the GEIS and can include the removal of structures to at least 

24 3 ft (1 m) below grade; removal of all coal, combustion waste, and accumulated sludge; removal 

25 of intake and discharge structures; and the cleanup and remediation of incidental spills and 

26 leaks at the facility. The decommissioning plan outlines the actions necessary to restore the 

27 site to a condition equivalent in character and value to the greenfield or brownfield site on which 

28 the facility was first constructed (NRC 2013d).

29 The environmental consequences of decommissioning are discussed in Section 4.12.2 of the 

30 GEIS and can generally include:

31 • short-term impacts on air quality and noise from the deconstruction of facility 

32 structures,

33 • short-term impacts on land use and visual resources,
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1 • long-term reestablishment of vegetation and wildlife communities,

2 • socioeconomic impacts due to the decommissioning workforce and the long-term 

3 loss of jobs, and

4 • elimination of health and safety impacts on operating personnel and the general 

5 public.

6 New Nuclear Alternative

7 Termination of operations and decommissioning impacts for a nuclear plant include all activities 

8 related to the safe removal of the facility from service and the reduction of residual radioactivity 

9 to a level that permits release of the property under restricted conditions or unrestricted use and 

10 termination of a license (NRC 2013d). The environmental impacts of the uranium fuel cycle are 

11 discussed above in Section 4.15.1.1.

12 Renewable Alternative

13 Termination of power plant operation and decommissioning for renewable energy facilities 

14 would be similar to the impacts discussed for fossil-fuel-fired plants above. Decommissioning 

15 would involve the removal of facility components and operational wastes and residues in order 

16 to restore the site to a condition equivalent in character and value to the greenfield or brownfield 

17 site on which the facility was first constructed (NRC 2013d).

18 4.15.3 Greenhouse Gas Emissions and Climate Change

19 The following sections discuss GHG emissions released from operation of LSCS and the 

20 environmental impacts that could occur from changes in climate conditions. The cumulative 

21 impacts of GHG emissions on climate are discussed in Section 4.16.11, “Global Climate 

22 Change.”

23 4.15.3.1 Greenhouse Gas Emissions from the Proposed Project and Alternatives

24 Gases found in the Earth’s atmosphere that trap heat and play a role in the Earth’s climate are 

25 collectively termed GHG. GHGs include carbon dioxide (CO2); methane (CH4); nitrous 

26 oxide (N2O); water vapor (H2O); and fluorinated gases, such as hydrofluorocarbons (HFCs), 

27 perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The Earth’s climate responds to 

28 changes in concentrations of GHGs in the atmosphere because GHGs affect the amount of 

29 energy absorbed and heat trapped by the atmosphere. Increasing GHG concentrations in the 

30 atmosphere generally increases Earth’s surface temperature. Atmospheric concentrations of 

31 carbon dioxide, methane, and nitrous oxide have significantly increased since 1750 

32 (IPCC 2007c, 2013). Carbon dioxide, methane, nitrous oxide, water vapor, and fluorinated 

33 gases (termed long-lived GHGs) are well mixed throughout the Earth’s atmosphere, and their 

34 impact on climate is long lasting as a result of their long atmospheric lifetime (EPA 2009a). 

35 Carbon dioxide is of primary concern for global climate change, due to its long atmospheric 

36 lifetime, and it is the primary gas emitted as a result of human activities. Climate change 

37 research indicates that the cause of the Earth’s warming over the last 50 years is due to the 

38 buildup of GHGs in the atmosphere resulting from human activities (USGCRP 2014; 

39 IPCC 2013). The EPA has determined that GHGs “may reasonably be anticipated both to 

40 endanger public health and to endanger public welfare” (74 FR 66496).

41 Proposed Action

42 Operation of LSCS does not directly emit GHG emissions because fossil fuel is not used to 

43 generate electricity. However, plant operations at LSCS release GHG emissions from 

44 stationary combustion sources, such as diesel generators on site. Other GHG emission 
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1 sources from LSCS plant operations include refrigerant appliances that contain fluorinated 

2 gases, mobile combustion sources (e.g., employee vehicles and nonroad equipment), LSCS’s 

3 carbon dioxide injection system and fire protection system, use of sulfur hexafluoride to locate 

4 leaks in condensers, and indirect purchased electricity emissions (Exelon 2015d). Annual GHG 

5 emissions at LSCS are presented in Table 4–21 for the 2010 to 2014 timeframe. Employee 

6 vehicle GHG emissions are not provided in Table 4–21 because Exelon does not compile or 

7 report GHG data for mobile sources. The NRC staff estimates annual GHG emissions resulting 

8 from employee vehicles to be approximately 9,400 metric tons (MT) per year of carbon dioxide 

9 equivalent emissions.

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

(a) 10

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 36,066 629 39,997

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

11 No-Action Alternative

12 As discussed in previous no-action alternative sections, the no-action alternative represents a 

13 decision by the NRC not to renew the operating license of a nuclear power plant beyond the 

14 current operating license term. At some point, all nuclear plants will terminate operations and 

15 undergo decommissioning. Under the no-action alternative, plant operations for LSCS would 

16 terminate at or before the end of the current license. When the plant stops operating, a 

17 reduction in GHG emissions from activities related to plant operation, such as use of diesel 

18 generators and employee vehicles, will occur. The GHG emissions are anticipated to be less 

19 than those presented in Table 4–21.

20 New Nuclear Alternative

21 As discussed in Section 2.2.2.1, the NRC staff evaluated the new nuclear power plant 

22 alternative that would consist of two units with an approximate generating capacity of

23 1,120 megawatt electric (MWe) each. The GEIS (NRC 2013d) presents life-cycle GHG 

24 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-cycle 1 5 GHG emissions from nuclear power generation can 

2 range from 1 to 288 grams of carbon equivalent per kilowatt hour (g Ce/kWh). Operation of 

3 nuclear power plants does not burn fossil fuels to generate electricity and, therefore, does not 

4 directly emit GHG emissions. Sources of GHG emissions include stationary combustion 

5 sources (e.g., emergency diesel generators and diesel-driven pumps) and mobile sources 

6 (e.g., worker vehicles, onsite heavy equipment, support vehicles, delivery of materials, and 

7 disposal of wastes). It is anticipated that air emissions from a new nuclear power plant would 

8 be similar to those from LSCS. 

9 IGCC Generation Alternative

10 As discussed in Section 2.2.2.2, the NRC staff evaluated the IGCC plant alternative that would 

11 consist of four 618-MWe units for a total 2,472 MW. The GEIS presents life-cycle GHG 

12 emissions associated with coal power generation. As presented in Table 4.12–4 of the GEIS, 

13 life-cycle GHG emissions from coal power generation can range from 264 to 1,689 g Ceq/kWh. 

14 However, these life-cycle emission factors are for conventional coal power plants; recent studies 

15 estimate life-cycle GHG emissions for an IGCC plant to be 937 kilograms of carbon dioxide 

16 equivalent per megawatt-hour (kg CO2e/MWh) (NETL 2012). The NRC staff estimates that 

17 operation of the IGCC alternative directly will emit about 14.3 million tons per year 

18 (13.0 million MT per year) of carbon dioxide equivalent emissions. 

19 NGCC Generation Alternative

20 As discussed in Section 2.2.2.3, the NRC staff evaluated an NGCC alternative that consists of 

21 five NGCC 560-MWe units (total 2,800 MWe). The GEIS presents life-cycle GHG emissions 

22 associated with natural gas power generation. As presented in Table 4.12–5 of the GEIS, 

23 life-cycle GHG emissions from natural gas can range from 120 to 930 g Ceq/kWh. The NRC 

24 staff estimates that operation of the NGCC alternative directly will emit about 9.8 million tons 

25 (8.2 million MT) per year of carbon dioxide equivalent emissions.

26 Combination Alternative (NGCC, Wind, and Solar)

27 As discussed in Section 2.2.2.4, the NRC staff evaluated an alternative that relies on NGCC 

28 (15 percent), wind (75 percent), and solar (10 percent) capacity to replace LSCS. The 

29 combination alternative would consist of a 360-MWe NGCC unit, a 227-MWe solar PV facility, 

30 and a 1,813-MWe windfarm. For this combination alternative, it is assumed that the majority of 

31 the GHG emissions result from the NGCC portion only because renewable portions (wind and 

32 solar PV) do not burn fossil fuels to generate electricity. As discussed in Section 4.3.5., GHG 

33 emissions associated with the operation of the NGCC portion are reduced proportionally

34 because its electricity output is approximately 13 percent that of the NGCC alternative. The 

35 NRC staff estimates that operation of the combination alternative will directly result in about 

36 1.2 million tons (1.1 million MT) per year of carbon dioxide equivalent emissions. 

37 Purchased Power Alternative

38 Purchased power would come from common types of existing technology (coal, natural gas, 

39 nuclear, and renewable sources) within the ROI. GHG emissions from purchased power will 

40 vary and will depend on the type and combination of technology from which purchased power 

41 originates. In 2014, coal, natural gas, and nuclear power accounted for 39-, 27-, and 19-percent 

42 shares, respectively, of total U.S. electricity generation (EIA 2015b). Using these percentage 

43 shares for the purchased power alternative, the NRC staff estimates 8.0 million ton 

44 (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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1 may be greater or less than this estimate and will depend on the technology from which the 

2 purchased power originates.

3 Summary of GHG Emissions from the Proposed Action and Alternatives

4 Table 4–22 presents the direct GHG emissions from operation of the proposed action and 

5 alternatives. GHG emissions from the proposed action (continued operation at LSCS) and the 

6 new nuclear alternative would be the lowest. GHG emissions for IGCC, NGCC, combination, 

7 and purchased power alternatives are higher than those for the proposed action and a new 

8 nuclear alternative by several orders of magnitude. GHG emissions from the purchased power 

9 alternative are expected to be greater than those from the NGCC alternative but less than those 

10 from the IGCC alternative.

Table 4–22. Direct 11 (a) GHG Emissions from Operation

12 of the Proposed Action and Alternatives

Technology CO2e (MT/yr)

LSCS continued operation 1,022

New Nuclear 1,022

IGCC 13.0x106

NGCC 8.2x106

Combination(b) 1.1x106

Purchased Power(c) 7.3x106

(a) The GHG emissions presented include only direct emissions from operation of the 

electricity-generating technology. For the NGCC and IGCC alternatives, GHG emissions 

result from direct combustion of the gas and coal. For the proposed action and new nuclear 

alternatives, direct GHG emissions are a result of stationary combustion sources.

(b) This technology is only the NGCC portion of GHG emissions.

(c) 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 renewable accounted for a 15-percent share of electricity generation.

13 4.15.3.2 Climate Change Impacts to Resource Areas

14 Climate change is the decades or longer change in climate measurements (e.g., temperature

15 and precipitation) that has been observed on a global, national, and regional level (IPCC 2007c; 

16 EPA 2014; USGCRP 2014). Climate change can vary regionally, spatially, and seasonally,

17 depending on local, regional, and global factors. Just as regional climate differs throughout the 

18 world, the impacts of climate change can vary between locations.

19 On a global level, from 1901 to 2013, average surface temperatures rose at a rate of 0.15  ̊F 

20 (0.08  ̊C) per decade, and total annual precipitation increased at an average rate of 0.2 percent 

21 per decade (EPA 2014). The observed global change in average surface temperature and 

22 precipitation has been accompanied by an increase in sea surface temperatures, a decrease in 

23 global glacier ice, an increase in sea level, and changes in extreme weather events. Such 

24 extreme events include an increase in the frequency of heat waves, heavy precipitation, and 

25 recorded maximum daily high temperatures (IPCC 2007c; USGCRP 2009, 2014; EPA 2014).

26 In the United States, the U.S. Global Change Research Program (USGCRP) reports that, from 

27 1895 to 2012, average surface temperature increased by 1.3 °F to 1.9 °F (0.72 to 1.06 °C) and,

28 since 1900, average annual precipitation has increased by 5 percent. On a seasonal basis, 
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1 warming has been the greatest in winter and spring. Since the 1980s, an increase in the length 

2 of the frost-free season, the period between the last occurrence of 32  ̊F (0 °C) in the spring and 

3 first occurrence of 32  ̊F (0 °C) in the fall, has been observed for the contiguous United States; 

4 between 1991 and 2011, the average frost-free season was 10 days longer than between 1901 

5 and 1960 (USGCRP 2014). Since the 1970s, the United States has warmed at a faster rate as 

6 the average surface temperature rose at an average rate of 0.31 to 0.45  ̊F (0.17 to 0.25 °C) per 

7 decade (EPA 2014). The year 2014 was the warmest on record (AMS 2015). Observed 

8 climate-related changes in the United States include increases in the frequency and intensity of 

9 heavy precipitation, earlier onset of spring snowmelt and runoff, rise of sea level in coastal 

10 areas, increase in occurrence of heat waves, and a decrease in occurrence of cold waves 

11 (USGCRP 2014).

12 Temperature data indicate that the Midwest region, where LSCS is located, experienced a 

13 0.06  ̊C (0.11  ̊F) per decade increase in annual mean temperature during the 1900 to 

14 2010 period (NOAA 2013). Temperature data for the recent past indicate an increased rate of 

15 warming for the Midwest region of 0.12 °C (0.22 °F) per decade for the 1950-to-2010 time 

16 period and a 0.26  ̊C (0.47  ̊F) temperature increase for the 1979-to-2010 time period. Average 

17 annual precipitation data for the Midwest region exhibit an increasing trend of 0.31 in. (0.79 cm) 

18 per decade for the long-term period (1895 to 2011) (NOAA 2013). The NRC staff analyzed 

19 temperature and precipitation trends for the period of 1865 to 2014 in the northeast region 

20 (Climate Division No. 2) of Illinois (NCDC 2015). Average annual temperatures during this time 

21 period show large year-to-year variations; however, since 1865, temperatures have increased 

22 0.1 °F (0.05 °C) per decade. Average annual precipitation also displays year-to-year variations, 

23 although precipitation has increased at a rate of 0.48 in. (1.2 cm) per decade.

24 Future GHG emission concentrations (emission scenarios) and climate models are commonly 

25 used to project possible climate change. Climate models indicate that over the next few 

26 decades, temperature increases will continue due to current GHG emission concentrations in 

27 the atmosphere (USGCRP 2014). Over the longer term, the magnitude of temperature 

28 increases and climate change effects will depend on both past and future GHG emissions 

29 (IPCC 2007c; USGCRP 2009, 2014).

30 For the license renewal period of LSCS, Units 1 and Unit 2 (2022 to 2042 and 2023 to 2043, 

31 respectively), climate model simulations (between 2021 and 2050 relative to the reference 

32 period (1971 to 1999)) indicate an increase in annual mean temperature in the Midwest region 

33 of 2.5 to 3.5  ̊F (4.5 to 6.3 °C) for both a low- and high-emission-modeled scenario 

34 (NOAA 2013). The predicted increase in temperature during this time period occurs for all 

35 seasons, with the largest increase occurring in the summertime (June, July, and August). 

36 Climate model simulations (for the time period 2021 to 2050) suggest spatial differences in 

37 annual mean precipitation changes for the Midwest, with northern areas experiencing an 

38 increase in precipitation and with the southern areas experiencing a decrease in precipitation. 

39 For Illinois, the models indicate a 0- to 3-percent increase in annual mean precipitation, with fall, 

40 winter, and spring seasons experiencing precipitation change increases and with the summer 

41 season experiencing a decrease in precipitation. However, these changes in precipitation were 

42 only statistically significant under a high-emission-modeled scenario (NOAA 2013).

43 The implications of climate change on LSCS operations are outside the scope of the NRC’s 

44 license renewal environmental review, which documents the potential environmental impacts 

45 from continued reactor operations. Site-specific environmental conditions are considered when 

46 siting nuclear power plants, including consideration of meteorological and hydrologic siting 

47 criteria in 10 CFR Part 100. LSCS was designed and constructed in accordance with the 

48 General Design Criteria of Appendix A to 10 CFR Part 50. NRC regulations require that plant 

49 structures, systems, and components important to safety be designed to withstand the effects of 
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1 natural phenomena, such as flooding, without loss of capability to perform safety functions. 

2 Furthermore, nuclear power plants are required to operate within technical safety specifications

3 in accordance with the NRC operating license, including coping with natural phenomena 

4 hazards. The NRC conducts safety reviews before allowing licensees to make operational 

5 changes due to changing environmental conditions. Additionally, the NRC evaluates nuclear 

6 power plant operating conditions and physical infrastructure to ensure ongoing safe operations 

7 through its Reactor Oversight Process. If new information about changing environmental 

8 conditions becomes available, the NRC will evaluate the new information to determine whether

9 any safety-related changes are needed at existing nuclear power plants. This process is 

10 separate and distinct from the NRC’s license renewal environmental review that is conducted in 

11 accordance with NEPA (42 U.S.C. 4321 et seq.).

12 Changes in climate have broader implications for public health, water resources, land use and 

13 development, and ecosystems. For instance, changes in precipitation patterns and an increase 

14 in air temperature can affect water availability and quality, distribution of plant and animal 

15 species, land-use patterns, and land cover; these impacts can, in turn, affect terrestrial and 

16 aquatic habitats. The sections below discuss how future climate change may impact air quality,

17 land use, water resources, aquatic resources, terrestrial resources, human health, and minority 

18 and low-income populations in the ROI for LSCS. Although the future effects of climate change 

19 are uncertain, the following discussions describe the potential implications of climate change in 

20 affected environmental resource areas.

21 Air Quality

22 As discussed above, an increase in average temperatures in Illinois has been observed. 

23 Despite the strong year-to-year variations, climate models project continued warming in the 

24 Midwest region during the license renewal period. Air pollutant concentrations result from 

25 complex interactions between physical and dynamic properties of the atmosphere, land, and 

26 ocean. The formation, transport, dispersion, and deposition of air pollutants depend, in part, on 

27 weather conditions (IPCC 2007a). Air pollutant concentrations are sensitive to winds, 

28 temperature, humidity, and precipitation (EPA 2009a). Hence, climate change can impact air 

29 quality as a result of the changes in meteorological conditions.

30 Ozone has been found to be particularly sensitive to climate change (IPCC 2007a; EPA 2009b). 

31 Ozone is formed, in part, as a result of the chemical reaction of nitrogen oxides and VOCs in the 

32 presence of heat and sunlight. Nitrogen oxides and VOC sources include both natural 

33 emissions (e.g., biogenic emissions from vegetation or soils) and human-activity-related 

34 emissions (e.g., motor vehicles and power plants). Sunshine, high temperatures, and air 

35 stagnation are favorable meteorological conditions to produce higher levels of ozone 

36 (IPCC 2007a; EPA 2009a). The emission of ozone precursors also depends on temperature, 

37 wind, and solar radiation (IPCC 2007a); both nitrogen oxide and biogenic VOC emissions are 

38 expected to be higher in a warmer climate (EPA 2009b). Although surface temperatures are 

39 expected to increase in the Midwest, this may not necessarily result in an increase in ozone 

40 concentrations. The observed correlation between increased ozone concentrations and 

41 temperature has been found to occur in polluted and urban regions (i.e., those areas where 

42 ozone concentration are greater than 60 parts per billion). Additionally, increases in ozone 

43 concentrations correlated with temperature increases occur in combination with cloud-free 

44 regions and air stagnation episodes (Jacob and Winner 2009; IPCC 2013). Furthermore, 

45 climate models do not agree on the sign of ozone response to climate change. Some models 

46 indicate increases in ozone concentrations with climate change for the Midwest and Northeast 

47 (e.g., Wu et al. 2008), and others project decreases in ozone concentrations with climates for 

48 the northern regions of the United States (e.g., Tagaris et al. 2009).
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1 Land Use

2 Anthropogenic land use is both a contributor to climate change and a receptor of climate change 

3 impacts (Dale 1997). As described previously in this section, the Midwest will likely experience 

4 rising temperatures and heavier precipitation events during the proposed license renewal 

5 period. Agriculture (the major land use in the vicinity of LSCS) and growing urban areas will 

6 further exacerbate these changes by continuing to inhibit natural ecosystem functions that could 

7 moderate climate change effects. For instance, air temperatures and near-surface moisture 

8 levels change in areas where natural vegetation is converted to agricultural use, and higher 

9 temperatures have been observed in the Midwest as a result of converting land to agricultural 

10 use (USGCRP 2014). The USGCRP (2014) indicates that land use changes, such as the 

11 continued expansion of urban areas, paired with climate change effects, such as heavier 

12 precipitation events, can exacerbate climate change effects, including reduced water filtration 

13 into the soil and increased surface runoff. Although anthropogenic land uses will contribute to 

14 climate change in these and other ways, land uses will also be affected by climate change in 

15 several ways. For instance, plant winter hardiness zones are likely to shift one-half to one full 

16 zone by the end of the proposed license renewal period (USGCRP 2014). This shift will affect 

17 the ability to grow certain crops as the Midwest will likely contain plants now associated with the 

18 Southeast by the end of the century (USGCRP 2014). Additionally, the USGCRP (2014) 

19 projects that the Midwest will experience a loss in cropland cover and an expansion in exurban 

20 and suburban areas. Changes in cropland cover and expansion of exurban and suburban 

21 areas could then reduce the quality and availability of land resources and agricultural 

22 productivity.

23 Water Resources

24 Predicted changes in the timing, intensity, and distribution of precipitation will likely result in 

25 changes in surface water runoff affecting water availability across the Midwest. As discussed 

26 above, the Midwest may experience an increase in mean precipitation during the fall, winter, 

27 and spring and an increase in the frequency and intensity of extreme (heavy) precipitation 

28 (USGCRP 2014). As cited by the USGCRP, in spite of increased annual average precipitation, 

29 the loss of moisture from soils because of higher temperatures, along with increased 

30 evapotranspiration from vegetation and the increased average number of days without 

31 precipitation, is likely to intensify short-term (seasonal or shorter) droughts across the region 

32 into the future (USGCRP 2009, 2014). Such conditions can potentially reduce the amount of 

33 water available for surface runoff and streamflow on a seasonal timeframe. Runoff and 

34 streamflow at a regional scale for the Midwest region indicate no clear trend during the last half 

35 century; however, annual runoff and river flow are projected to increase in the upper Midwest.

36 Climate change impacts on groundwater availability depend on basin geology, frequency and 

37 intensity of high-rainfall periods, recharge, soil moisture, and groundwater and surface water

38 interactions (USGCRP 2014). Precipitation and evapotranspiration are key drivers in aquifer 

39 recharge. Increased precipitation in the fall, winter, and spring is likely to result in increased 

40 groundwater recharge. More precipitation during these seasons (as opposed to summer) would 

41 percolate into the groundwater because it would experience lower evaporation and transpiration 

42 rates. Furthermore, a portion of the winter precipitation would fall as snow. Instead of running 

43 off the land, much of the snow is likely to slowly melt in place and contribute to groundwater 

44 recharge.

45 Terrestrial Resources

46 As described above, the Midwest will likely experience rising temperatures and heavier 

47 precipitation events during the proposed license renewal period. As the climate changes, 

48 terrestrial resources will either need to be able to tolerate the new physical conditions or shift 
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1 their population range to new areas with a more suitable climate. Scientists currently estimate 

2 that species are shifting their ranges at a rate of 20 to 36 ft (6.1 to 11 m) in elevation per decade 

3 and 3.8 to 10.5 mi (6.1 to 16.9 km) in latitude per decade (Chen et al. 2011; Thuiller 2007). 

4 Although some species may readily adapt to a changing climate, others may be more prone to 

5 experience adverse effects. For example, species whose ranges are already limited by habitat 

6 loss or fragmentation or who require very specific environmental conditions may not be able to 

7 successfully shift their ranges over time. Migratory birds that travel long distances may also be 

8 disproportionately affected because they may not be able to pick up on environmental clues that 

9 a warmer, earlier spring is occurring in the United States while overwintering in tropical areas. 

10 Fraser et al. (2013) found that songbirds overwintering in the Amazon did not leave their winter 

11 sites earlier, even when spring sites in the eastern United States experienced a warmer spring. 

12 As a result, the song birds missed periods of peak food availability. For many Midwest species, 

13 migration to changed habitats is projected to be slow due to flat topography, high latitudes, and 

14 fragmented habitats (USGCRP 2014). For instance, in its final rule to list the red knot (Calidris 

15 canutus rufa), a shorebird that uses the Great Lakes during spring and fall migration, FWS cites 

16 several effects resulting from climate change as factors contributing to the species’ decline 

17 (79 FR 73705). These effects include habitat loss from sea level rise, asynchronies in the 

18 timing of annual cycles, and increased frequency of severe storm events. Special status 

19 species and habitats, such as those that are Federally protected by the ESA, would likely be 

20 more sensitive to climate changes because these species’ populations are already experiencing 

21 threats that are endangering their continued existence throughout all, or a significant portion of 

22 their ranges. Habitat ranges for forest systems in the Midwest, such as paper birch 

23 (Betula papyrifera), balsam fir (Abies balsamea), and black spruce (Picea mariana), are 

24 projected to decline across the Midwest as they shift northward, and species that are common 

25 farther south, such as oaks (Quercus spp.) and pines (Pinus spp.), will expand their range north 

26 into the Midwest region (USGCRP 2014). Climate changes could also favor non-native, 

27 invasive species and promote population increases of insect pests and plant pathogens, which 

28 may be more tolerant to a wider range of climate conditions.

29 Aquatic Resources

30 The potential effects of climate change, whether from natural cycles or manmade activities,

31 could result in changes that could affect aquatic resources in the Illinois River. Raised air 

32 temperatures could result in higher water temperatures in the cooling pond and in the Illinois 

33 River and its tributaries. Higher water temperatures would increase the potential for thermal 

34 effects on aquatic biota, such as fish kills within the cooling pond, and could exacerbate existing 

35 environmental stressors, such as excess nutrients, sedimentation, and lowered dissolved 

36 oxygen associated with eutrophication (USGCRP 2014). The Midwest will likely experience an 

37 increased frequency of extreme rainfall events, which will cause erosion and could lead to a 

38 decline in water quality (USGCRP 2014). Species that require cleaner waters, such as 

39 freshwater mussels, could experience further population declines. The USGCRP (2014) 

40 predicts habitat loss and local extinctions of fish and other aquatic species throughout the 

41 United States from the combined effects of water withdrawal and climate change. Shifts in 

42 species assemblages and distributions are also likely as climate change continues 

43 (USGCRP 2014), which could alter the balance of the aquatic community in the Illinois River. 

44 As discussed below under the section entitled, “Terrestrial Resources,” special status species, 

45 such as those that are Federally protected under the ESA (16 U.S.C. 1531 et seq.), would be 

46 more sensitive to climate changes. Invasions of non-native species that thrive under a wide 

47 range of environmental conditions and warmer waters could further disrupt the current 

48 composition of aquatic communities (NRC 2013d).
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1 Historic and Cultural Resources 

2 Increases in river levels because of changes in meteorological conditions due to climate change 

3 could result in the loss of historic and cultural resources from flooding, erosion, or inundation. 

4 Due to water-level changes, some resources could be lost before they could be documented or 

5 otherwise studied. However, the limited extent of climate change that may occur during the 

6 20-year license renewal term would not likely result in any significant loss of historic and cultural 

7 resources at LSCS.

8 Socioeconomics

9 Rapid changes in climate conditions could have an impact on the availability of jobs in certain 

10 industries. For example, tourism and recreation are major job creators in some regions, 

11 bringing billions of dollars to regional economies. Across the Nation, fishing, hunting, and other 

12 outdoor activities make important economic contributions to rural economies and are also a part 

13 of the cultural tradition. A changing climate would mean reduced opportunities for some 

14 activities in some locations and expanded opportunities for others. Hunting and fishing 

15 opportunities could also change as animals’ habitats shift and as relationships among species 

16 are disrupted by their different responses to climate change (USGCRP 2014).

17 Water-dependent recreation could also be affected (USGCRP 2009). The USGCRP reports 

18 that increasing heat and humidity associated with climate change in parts of the Midwest region 

19 by the year 2050 could create unfavorable conditions for summertime outdoor recreation and 

20 tourism activity (USGCRP 2014). However, the limited extent of climate change that may occur 

21 during the 20-year license renewal term would not likely cause any significant changes in 

22 socioeconomic conditions in the vicinity of LSCS.

23 Human Health

24 Increasing temperatures due to changes in climate conditions could have an impact on human 

25 health. However, changes in climate conditions that may occur during the license renewal term 

26 will not result in any significant change to the impacts discussed in Section 4.11.1 from LSCS’s

27 radioactive and nonradioactive effluents.

28 Environmental Justice

29 Rapid changes in climate conditions could disproportionately affect minority and low-income 

30 populations. The USGCRP (2009) indicates that “infants and children, pregnant women, the 

31 elderly, people with chronic medical conditions, outdoor workers, and people living in poverty 

32 are especially at risk from a variety of climate-related health effects.” Examples of these effects 

33 include increased heat stress; air pollution; extreme weather events; and diseases carried by 

34 food, water, and insects. The greatest health burdens related to climate change are likely to fall 

35 on the poor, especially those lacking adequate shelter and access to other resources, such as 

36 air conditioning. Elderly people on fixed incomes, who are more likely to be poor, are more 

37 likely to have debilitating chronic diseases or limited mobility. In addition, the elderly have a 

38 reduced ability to regulate their own body temperature or the ability to sense when they are too 

39 hot. According to the USGCRP (2009), the elderly “are at greater risk of heart failure, which is 

40 further exacerbated when cardiac demand increases in order to cool the body during a heat 

41 wave.” The USGCRP (2009) also found that people taking medications, such as diuretics for 

42 high blood pressure, have a higher risk of dehydration. The USGCRP (2014) reconfirmed the 

43 previous report findings regarding the risks of climate change on low-income populations and 

44 also warns that climate change could affect the availability and access to local plant and animal 

45 species, thus impacting the people who have historically depended on them for food or 

46 medicine. However, minority and low-income populations at LaSalle are not likely to experience 
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1 disproportionately high and adverse impacts from climate change, based on the expected small 

2 or slow change, effectively, in the environment during the 20-year license renewal term.

3 4.16 Cumulative Impacts of the Proposed Action

4 The NRC staff considered potential cumulative impacts in the environmental analysis of 

5 continued operation of LSCS during the 20-year license renewal period. Cumulative impacts 

6 may result when the environmental effects associated with the proposed action are overlaid or 

7 added to temporary or permanent effects associated with other past, present, and reasonably 

8 foreseeable actions. Cumulative impacts can result from individually minor, but collectively 

9 significant, actions taking place over a period of time. An impact that may be SMALL by itself 

10 possibly could result in a MODERATE or LARGE cumulative impact when it is considered in 

11 combination with the impacts of other actions on the affected resource. Likewise, if a resource 

12 is regionally declining or imperiled, even a SMALL individual impact could be important if it 

13 contributes to, or accelerates, the overall resource decline. 

14 For the purposes of this cumulative analysis, past actions are those before the receipt of the 

15 license renewal application; present actions are those related to the resources at the time of 

16 current operation of the power plant; and future actions are those that are reasonably 

17 foreseeable through the end of plant operation, including the period of extended operation. 

18 Therefore, the analysis considers potential impacts through the end of the current license terms, 

19 as well as the 20-year license renewal term. The geographic area over which past, present, 

20 and reasonably foreseeable actions would occur depends on the type of action considered and 

21 is described below for each resource area.

22 To evaluate cumulative impacts, the incremental impacts of the proposed action, as described 

23 in Sections 4.2 to 4.15, are combined with other past, present, and reasonably foreseeable 

24 future actions, regardless of which agency (Federal or non-Federal) or person undertakes such 

25 actions. The NRC staff used the information provided in Exelon’s ER; responses to RAIs; 

26 information from other Federal, State, and local agencies; scoping comments; and information 

27 gathered during visits to the LSCS site to identify other past, present, and reasonably 

28 foreseeable actions. For a project to be considered in the cumulative analysis, the NRC staff 

29 determined whether it would occur within the noted geographic areas of interest and within the 

30 period of extended operation, whether it was reasonably foreseeable, and whether there would 

31 be a potential overlapping effect with the proposed project. For past actions, consideration 

32 within the cumulative impacts assessment is resource and project specific. In general, the 

33 effects of past actions are included in the description of the affected environment in Chapter 3, 

34 which serves as the baseline for the cumulative impacts analysis. However, past actions that 

35 continue to have an overlapping effect on a resource that potentially could be affected by the 

36 proposed action are considered in the cumulative analysis. 

37 Appendix E describes other actions and projects identified during this review and considered in 

38 the NRC staff’s analysis of the potential cumulative effects. Not all actions or projects listed in 

39 Appendix E are considered in each resource area because of the uniqueness of the resource 

40 and its geographic area of consideration.

41 4.16.1 Air Quality and Noise 

42 This section addresses the direct and indirect effects of license renewal on air quality and noise 

43 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

44 actions. As described in Section 4.3.1, the incremental impacts on air quality and noise levels 

45 from the proposed license renewal would be SMALL.
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1 4.16.1.1 Air Quality

2 The geographic area considered in the cumulative air quality analysis is the county where the 

3 proposed action is located, as air quality designations for criteria air pollutants are generally 

4 made at the county level. Counties are further grouped together based on a common airshed—

5 known as an Air Quality Control Region (AQCR)—to provide for the attainment and 

6 maintenance of the NAAQS. LSCS is located in LaSalle County, Illinois, which is part of the 

7 North Central Illinois Intrastate AQCR (40 CFR 81.262). 

8 With regard to NAAQS criteria pollutants, LaSalle County and the entire North Central Illinois 

9 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 10

11 air emission sources, 9 synthetic minor air emissions sources, and 160 facilities designated as 

12 minor air emission sources located in LaSalle County (EPA 2015b). LSCS, as discussed in 

13 Section 3.3.2 of this SEIS, is a synthetic minor air source. Air emissions from permitted sources 

14 at LSCS are presented in Chapter 3, Table 3–4. There will be no refurbishment-related 

15 activities during the license renewal period. Additionally, Exelon does not anticipate equipment 

16 or operational upgrades or replacement activities that would increase air emissions during the 

17 license renewal term (Exelon 2015c). As a result, the NRC staff expects emissions from LSCS 

18 during the license renewal period to be similar to those emissions presented in Section 3.3.2. 

19 Appendix E provides a list of current projects and reasonably foreseeable future actions that 

20 could contribute to cumulative impacts to air quality. Air emissions sources that contribute to air 

21 quality identified in Appendix E are currently operating and, given the designated attainment 

22 status for all NAAQS in LaSalle County, these emissions have not contributed to a violation of 

23 the NAAQS. Consequently, cumulative impacts to air quality in LaSalle County would be the 

24 result of changes to present-day emissions and future actions within the county. Development 

25 and construction activities associated with regional growth of housing, business, and industry, 

26 as well as associated vehicular traffic, can increase air emissions. Regional air quality 

27 conditions could deteriorate from the effects of the growth of the county as construction 

28 activities give rise to dust, exhaust, and emissions that can degrade air quality. Population 

29 growth is estimated to increase by 4 percent per decade in LaSalle County (LaSalle 

30 County 2014). Air quality effects of development are monitored through the statewide ambient 

31 air quality monitoring network. If degradation in air quality is observed, the IEPA can develop air 

32 quality control programs to mitigate the effects of development. Furthermore, any new 

33 stationary sources of emissions that would be established in the region would be required to 

34 apply for an air permit from the IEPA and be operated in accordance with regulatory 

35 requirements. IEPA will examine the potential air quality impacts using various modeling tools 

36 to assess any potential changes to compliance with the NAAQS prior to issuing an air permit to 

37 a new source (or to an existing source that proposes to undergo significant modification).

38 Climate change can impact air quality as a result of changes in meteorological conditions. Air 

39 pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 

40 (EPA 2009a). As discussed in Section 4.15.3.2, ozone levels have been found to be particularly 

41 sensitive to climate change influences (EPA 2009b; IPCC 2007c). Climate change may make it 

42 difficult for regions to meet ozone NAAQS (USGCRP 2009). However, as discussed in 

43 Section 4.15.3, while surface temperatures are expected to increase in the Midwest, this may

44 not necessarily result in an increase in ozone concentrations. Changes in air emission 

 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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1 concentrations will depend on the combination of higher temperatures, current levels of ozone 

2 (increases in ozone concentrations and temperature correlations have been observed in urban 

3 regions), stagnant air masses, sunlight, and emissions of pollutant precursors. Furthermore, 

4 climate models do not agree on the direction of ozone changes (increase or decrease) in 

5 response to climate change for the Midwest (Wu et al. 2008; Tagaris et al. 2009).

6 Because of the small quantity of emissions from LSCS and that no emissions increase 

7 associated with license renewal is expected, the potential for LSCS to contribute to a cumulative 

8 impact with other air pollutant sources is SMALL. Given the current designated attainment 

9 status of LaSalle County and few reasonably foreseeable projects that may increase air 

10 emissions in the region of interest, the NRC staff concludes that, combined with the emissions

11 from other past, present, and reasonably foreseeable future actions, cumulative impacts on air 

12 quality would be SMALL.

13 4.16.1.2 Noise

14 Section 3.3.3 presents a summary of noise sources at LSCS and in the vicinity of the site.

15 Noise levels in the vicinity of a nuclear power plant could increase from planned activities 

16 associated with urban, industrial, and commercial development. The magnitude of cumulative 

17 impacts depends on the nuclear plant’s proximity to other noise sources. A 3 -A-weighted 

18 decibels (-dBA) change in sound level is considered barely discernable (FHWA 2011), as 

19 discussed in Section 3.3.3 of this SEIS. A 3-dBA increase would occur with the placement of 

20 another identical source over an existing source (e.g., a doubling of the traffic volume). 

21 Ongoing or foreseeable future projects in and around LSCS, as identified in Appendix E, would 

22 increase noise levels only in the vicinity of the noise sources. Therefore, contributions to noise 

23 levels from future actions are limited to projects in the vicinity of LSCS (within a 2 mi (3.3 km) 

24 radius). 

25 For example, wind farm projects in the immediate vicinity of LSCS may contribute to noise 

26 impacts, particularly the Grand Ridge Wind Farm. As discussed in Section 4.3.6, noise impacts 

27 from wind generation operations would include aerodynamic noise from the turbine rotors and 

28 mechanical noise from the turbine drivetrain components. Wind-turbine-generated noise will 

29 vary depending on the speed of the turbine, environmental conditions, and the distance of the 

30 receptor from the turbine. Exelon stated that any additional noise from installation and 

31 operation of the wind turbine in the vicinity has been imperceptible (Exelon 2015j). The NRC 

32 staff identified noise concerns raised by the public regarding wind farm installations in counties 

33 surrounding LaSalle (News-Gazette 2013, Daily Herald 2010, FarmProgress 2010; 

34 FairWindEnergy undated). However, the NRC staff did not identify noise concerns raised 

35 specifically in LaSalle County or the immediate area surrounding LSCS. Furthermore, 

36 wind-turbine-generated noise, and other projects, must comply with noise regulations found in 

37 IAC Title 35, Subtitle H. Accordingly, the NRC staff concludes that the cumulative impact to the 

38 noise environment from past, present, and reasonably foreseeable actions is SMALL.

39 4.16.2 Geology and Soils

40 This section addresses the direct and indirect effects of license renewal on geology and soils 

41 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

42 actions. As noted in Section 4.4.1, the NRC staff concludes that the impacts of the proposed 

43 action (license renewal) on geology and soils would be SMALL. The cumulative impacts on the 

44 geologic environment primarily relate to land disturbance and the potential for soil erosion and 

45 loss, as well as the projected consumption of geologic resources. Exelon has no plans to 

46 conduct refurbishment or replacement actions. Ongoing operation and maintenance activities at 

47 LSCS are expected to be confined to previously disturbed areas. Any use of geologic materials 
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1 such as aggregates to support operation and maintenance activities would be procured from 

2 local and regional sources. Thus, activities associated with continued operations are not 

3 expected to affect the geologic environment.

4 The NRC staff assumes that any construction activities would use material from local and 

5 regional sources, as these materials are abundant in the region. These identified projects are of 

6 such a scale as to not be likely to impact regional sources and supplies of the identified 

7 resources. Furthermore, construction activities would need to be conducted in accordance with 

8 State and local requirements and development activities would be subject to BMPs for soil 

9 erosion and sediment control, which would serve to minimize soil erosion and loss. Considering 

10 ongoing activities and reasonably foreseeable actions, the NRC staff concludes the cumulative 

11 impacts on geology and soils during the license renewal term would be SMALL.

12 4.16.3 Water Resources

13 This section addresses the direct and indirect effects of the proposed action (license renewal) 

14 on water resources when added to the aggregate effects of other past, present, and reasonably 

15 foreseeable future actions. 

16 4.16.3.1 Surface Water Resources

17 As described in Section 4.5.1.1, the incremental impacts on surface water resources from 

18 continued operations of LSCS during the license renewal term would be SMALL. The NRC staff 

19 has also evaluated other projects and actions for consideration in determining their contribution 

20 to cumulative impacts on surface water resources (see Appendix E). 

21 The description of the affected environment under Section 3.5.1 of this SEIS serves as the 

22 baseline for the cumulative impacts assessment for surface water resources. The geographic 

23 area of analysis for the surface water resources component of the cumulative impacts analysis 

24 includes the lowermost portion of the Upper Illinois River Basin, as described in Section 3.5.1.1, 

25 with a detailed focus on the Marseilles Pool of the Illinois River and its tributaries. As such, this 

26 review focused on those projects and activities that would withdraw water from or discharge

27 effluent to the Marseilles Pool. The cumulative impacts on surface water use and quality, along 

28 with associated climate change considerations, are presented below.

29 Water Use Considerations

The Upper Illinois River Basin is composed of a 10,949 square mile (mi2 30 ) (28,369 square 

kilometer (km2 31 )) drainage area upstream from Ottawa, Illinois. LSCS is located on the 

32 Marseilles Pool of the main stem of the Illinois River. This pool is one of eight such navigation 

33 pools along the Illinois River and major tributaries that includes an associated lock and dam. 

34 Each pool includes a navigation channel that is at least 9 ft (2.7 m) deep and 300 ft (91 m) wide. 

35 Together, the navigation pools are part of the Illinois Waterway, which enables commercial river 

36 traffic to travel from Lake Michigan to the Mississippi River and from there to the Gulf of Mexico 

37 (Arnold et al. 1999; Talkington 1991; USGS 1998). 

38 Operation of the navigation pools using the locks and dams has the effect of decreasing overall 

39 river flow velocity and stabilizing river water levels, particularly during low flows. As a result of 

40 this extensive management, some 60 percent of the State of Illinois’ commodities travel the 

41 waterway annually. This includes grain, petroleum products, coal, chemicals, sand and gravel, 

42 pulp, paper, and others (Talkington 1991).

43 In support of this cumulative impacts analysis, the NRC staff obtained and evaluated the best 

44 available data on water consumption and projected trends in water use, as compiled by 

45 responsible water resources management agencies. The USGS published a comprehensive 
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1 investigation of hydrologic and water quality conditions in the Upper Illinois River Basin in 1999

2 that also considered water use (Arnold et al. 1999). 

3 Excluding surface water diversions from Lake Michigan in the Chicago area, nearly five times as 

4 much groundwater as surface water is used in the Upper Illinois River Basin for public water 

5 supply. Within the basin, surface water is primarily used for cooling and associated 

6 thermoelectric power generation, followed by public water supply and industrial and commercial 

7 use. In total, more than 90 percent of all reported water use in the basin is for the cooling and 

8 thermoelectric power generation sector, with nearly all of the water from surface water sources. 

9 This percentage reflects total water demands and does not account for water that is withdrawn 

10 and not consumptively used (i.e., water that is returned to the water source rather than being 

11 lost) (Arnold et al. 1999). Thermoelectric power generating plants that use once-through cooling

12 systems return most of the water they withdraw back to the source. In contrast, those using 

13 closed-cycle cooling systems, which are now the standard for new facilities, withdraw much less 

14 water (i.e., about 90 percent less than those with once-through cooling systems) but their 

15 operation entails consumptive loses (i.e., primarily due to evaporation) of greater than 

16 50 percent, resulting in the return of less water (NRC 2013d). 

17 The rankings by water use sector cited above in Arnold et al. (1999) are mirrored in the 

18 county-level forecasts of water use prepared by Southern Illinois University for the Illinois State 

19 Water Survey (Dziegielewski et al. 2005). As part of its analysis, the NRC staff considered the 

20 counties in the lowermost Upper Illinois River Basin, including counties that border LaSalle 

21 County, where LSCS is located, and the immediately upstream portion of the Marseilles Pool in 

22 Grundy County. Total water demand (both groundwater and surface water) overall in the Illinois 

23 counties within the lowermost part of the Upper Illinois River Basin is projected to increase by 

24 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 25 /s)) increase over water use in 2000 

26 (Dziegielewski et al. 2005).

27 By 2025, the demand for public water use within the lowermost Upper Illinois River Basin is 

28 projected to increase by about 36 percent. This reflects an increase of approximately 

69 mgd (261,000 m3 29 /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 30 /d) by 

31 2025 is forecast (Dziegielewski et al. 2005).

32 The NRC staff believes that the county-level total water demand projections likely overestimate 

33 future demand, as they are heavily influenced by large forecasted increases in water demand 

34 for thermoelectric power generation, which have not been realized to date. In addition, the 

35 thermoelectric power generation component of these projections includes the Collins 

36 Generating Station, a fossil-fuel fired power plant in Morris (Grundy County), Illinois, which 

37 withdrew water from the Illinois River. This facility was permanently decommissioned in 2004 

38 and, as a result, the county-level projections, particularly for Grundy County, probably

39 overestimate future total water demand. 

40 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 41 /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 42 /d) per year, or an 

43 increase of about 4 percent as compared to water use in 2000. This total county demand 

includes 62.9 mgd (238,100 m3 44 /d) attributable to LSCS operations. This total projected increase 

by 2025 includes 0.3 mgd (1,140 m3 45 /d) for public water supply (3 percent increase) and 2.5 mgd 

(9,500 m3 46 /d) increase for self-supplied commercial and industrial uses (a nearly 70 percent 

47 increase), with the remainder attributable to use for thermoelectric power generation 

48 (Dziegielewski et al. 2005). The projected increase in public water supply demand is in line with 
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1 the historical trend in LaSalle County’s population growth, which has averaged about 2 percent 

2 per decade. Most recently, the Illinois Department of Commerce and Economic Opportunity has 

3 projected county population to grow at a rate of about 4 percent between 2020 and 2030, or 

4 about 0.4 percent per year (LaSalle County 2014). 

5 Based on the discussion above, the NRC staff estimates that by the end of the period of 

6 extended operations for LSCS in 2043, LaSalle County’s total water demands could increase to 

96.5 mgd (365,000 m3 7 /d). This conservative projection assumes water demand will increase by 

8 about 0.4 percent per year equally across all water use sectors and that LSCS’s river makeup 

9 water withdrawals, which dominate water withdrawals in the county and across the lowermost 

10 Upper Illinois River Basin, will also increase proportionally.

11 However, even if the entire projected water demand for LaSalle County (96.5 mgd, equivalent to 

149 cfs (4.2 m3 12 /s)) which includes water needs by LSCS were to be withdrawn from the 

13 Marseille Pool of the Illinois River and not returned, this would be equivalent to approximately 

14 1.4 percent of the mean annual flow of the Illinois River through the Marseilles Pool. This small 

15 percentage increase would be less because some of the water withdrawn from the pool would 

16 be returned, as more than 50 percent of the water withdrawn by LSCS at present (i.e., about 

55 cfs (1.6 m3 17 /s) is returned directly to the Marseilles Pool). It is extremely likely that future 

18 demands for public water supply will continue to be met by groundwater and not surface water. 

19 There are no municipalities that use the Marseilles Pool of the Illinois River as a public water 

20 supply source. All identified public water supplies within 10 mi (16 km) of LSCS rely on 

21 groundwater (Exelon 2014a, 2014b). Given the abundant groundwater supplies in the county 

22 and also the higher cost of surface water treatment, the NRC staff does not anticipate public 

23 water supplies to switch to surface water as a water source during the license renewal term. 

24 Thus, it is extremely unlikely that continued LSCS operations withdrawing surface water from 

25 the Marseilles Pool of the Illinois River, combined with those of other users in the county, would 

26 substantially impact the downstream availability of surface water. 

27 Water Quality Considerations

28 Water quality within the whole of the Illinois River Basin has historically suffered from rapid 

29 population growth, urbanization, and industrial development. This resulted in the discharge of 

30 poorly treated sewage, the discharge of industrial pollutants and refuse, runoff of agricultural 

31 chemicals and sediments, and the alteration of the natural hydrology of the river (Exelon 2014a; 

32 Talkington 1991).

33 Nonetheless, over the last 50 years, substantial improvements in water quality have occurred,

34 due to municipal and industrial waste treatment and management efforts to address both point 

35 and nonpoint pollutant sources. Ongoing water quality concerns within the Upper Illinois River 

36 Basin remain and include the atmospheric deposition of pesticides and trace metals; endocrine 

37 disrupting compounds in surface and groundwater; nutrient enrichment of surface and 

38 groundwater; the transport and fate of pesticides, trace elements, and volatile organic 

39 compounds in surface and groundwater; and the effects of urbanization on biodiversity, habitat, 

40 and water quality (USGS 1998, Groschen 2004).

41 As discussed in Section 3.5.1.3 of this SEIS, a segment of the Illinois River that encompasses 

42 the Marseilles Pool does not meet designated uses and associated water-quality standards and 

43 is listed as an impaired waterway. The segment is listed as impaired for not meeting designated 

44 uses for fish consumption due to polychlorinated biphenyls (PCBs) and mercury as well as for 

45 primary contact recreation use, due to fecal coliform bacteria. However, the segment is 

46 classified as fully supporting its designated use for aquatic life. IEPA has assigned a medium 

47 priority for the development of Total Maximum Daily Load (TMDL) limits to improve water quality 
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1 in this river segment pursuant to Section 303(d) of the Federal Water Pollution Control Act 

2 (i.e., Clean Water Act (CWA)) (33 U.S.C. 1251). 

3 As noted previously, development in the lowermost Upper Illinois River Basin, including 

4 associated population growth and industrial development, is expected. Upstream development 

5 could lead to increased discharges and pollutant loading to the Marseilles Pool of the Illinois 

6 River with impacts on ambient water quality. The magnitude of cumulative impacts would 

7 depend on the nature and location of the actions relative to receiving surface water bodies, the 

8 number of actions (facilities or projects), and the extent of municipal, county, and state 

9 regulatory agency development planning and environmental regulatory controls. At a minimum, 

10 new and modified industrial and large commercial facilities would be subject to regulation under 

11 the Federal CWA (33 U.S.C. 1251) (i.e., Section 402). This would include IEPA-administered 

12 NPDES permit limits on stormwater and point source discharges designed to be protective of 

13 surface water resources. Likewise, it is this regulatory framework that presently governs 

14 industrial effluent and thermal discharges from LSCS and other major industrial facilities in the 

15 lowermost Upper Illinois River Basin.

16 Climate Change Considerations

17 The NRC staff also considered the USGCRP’s most recent compilations of the state of 

18 knowledge relative to global climate change effects (Melillo et al. 2014). Climate change can 

19 impact surface water as a result of changes in temperature and precipitation. As discussed in 

20 Section 4.15.3.2, climate model simulations for the Midwest region indicate an increase in 

21 annual mean temperature as well as precipitation. More especially, the frequency and intensity 

22 of heavy precipitation events is forecast to increase. Increased precipitation results in greater

23 runoff and streamflow. The USGCRP (Melillo et al. 2014) predicts that runoff and streamflow for 

24 the upper Midwest will increase overall. 

25 In its ER, Exelon (2014a) cites an analysis prepared by the Illinois State Water Survey 

26 (Knapp 2009) that assesses trends in stream flows encompassing the Illinois River Basin and 

27 their implications for flood frequency. For stream gaging sites with a long period of record 

28 (90 years), the analysis indicates a consistent trend of increasing stream flows in the upper 

29 Midwest, attributed to a 7- to 10-percent increase in precipitation over the past 30 years

30 (through 2008). Results from an earlier study prepared by USGS (Arnold et al. 1999) and 

31 specific to the Upper Illinois River Basin also indicate a statistically significant increase in mean 

32 annual stream flow (over the period 1950–1997) at all seven stations selected for analysis, 

33 including as measured at the USGS gage at Marseilles, Illinois. In contrast to Knapp (2009), the 

34 USGS study was not able to correlate any trends in precipitation with the apparent increases in 

35 streamflow. Rather, the authors concluded that the observed trends were more likely 

36 attributable to land-use changes in the affected watersheds, causing more rapid runoff of 

37 precipitation, and to increases in groundwater usage and associated increased return effluent to 

38 receiving waters from wastewater treatment plants in the basin. These two studies serve to 

39 point to the uncertainty over whether there has been an observable trend in precipitation and/or 

40 streamflow in the upper Midwest, as forecast by the USGCRP. 

41 Despite any observable trends to date, rapid runoff events occurring due to more frequent and 

42 intensive precipitation events associated with climate change, especially over cleared or 

43 urbanized areas, will result in increases in erosion and transport of sediment and other 

44 pollutants to receiving waters. This can negatively affect ambient water quality.

45 Further, higher air temperatures and increased runoff associated with heavy precipitation events 

46 could impact the thermal regime of the Marseilles Pool of the Illinois River, along with increases 

47 in runoff laden with nutrients, sediment, and other contaminants. Higher surface water

48 temperatures decrease the cooling efficiency of thermoelectric power generating facilities as 
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1 well as plant capacity, due to the need to reduce the discharge of thermal effluent 

2 (Melillo et al. 2014). As intake water temperatures warm, cooling water makeup requirements 

3 increase. Degradation in ambient surface water quality increases the costs of water treatment 

4 for both industrial cooling water and potable water, due to the need for increased filtration and 

5 higher additions of chemical treatments for such uses as antiscaling and disinfection. With 

6 respect to LSCS operations, these potential climate-induced changes can lead to higher cooling 

7 pond temperatures and an increase in evaporative losses from LSCS’s cooling pond. This can 

8 conceivably result in additional makeup water withdrawals from the Marseilles Pool and an 

9 increased need for blowdown discharges from the cooling pond to the Illinois River. At present, 

10 the data available to the NRC staff is not sufficient to indicate whether or not a warming trend is 

11 evident in the waters of the Illinois River, including the Marseilles Pool. Exelon (2015b) has not 

12 identified any increasing trend in cooling pond temperatures to date, although this observation is 

13 based on limited data. Regardless, as detailed in Section 3.5.1.3 of this SEIS, the chemical and 

14 thermal quality of LSCS’s discharges to the Illinois River are subject to the effluent limitations 

15 and monitoring requirements prescribed by its NPDES permit (IEPA 2013). Additionally, 

16 thermal mixing zone limits set by LSCS’s NPDES permit indirectly limit surface water 

17 withdrawals and consumptive water use during low river flow and extreme summer weather 

18 events.

19 Future thermal and pollutant discharges from new and modified industrial and large commercial 

20 facilities in the lowermost Upper Illinois River Basin would be required to comply with applicable 

21 NPDES permit requirements under the Federal CWA, local and regional health standards, and 

22 TMDLs imposed by the State of Illinois.

23 Conclusion

24 Surface water availability is expected to continue to be sufficient through the license renewal 

25 term, based on the projections and associated assumptions cited above. Surface water from 

26 the Marseilles Pool of the Illinois River has been able to support ongoing demands for uses 

27 ranging from navigation to cooling and thermoelectric power generation to commercial and 

28 industrial water supply. Flows within the Upper Illinois River Basin and through the Marseilles 

29 Pool are not likely to decrease and may trend higher during the LSCS license renewal term, in 

30 part due to climate-induced hydrologic changes. No increase in LSCS consumptive water use 

31 is expected during the license renewal term. Surface water withdrawals and associated 

32 consumptive water use for LSCS operations are expected to remain a small percentage of the 

33 mean annual and 90-percent exceedance flow through the Marseilles Pool of the Illinois River.

34 It is reasonable to anticipate that water-quality-based limits imposed by the IEPA through 

35 NPDES permits and other measures on cooling water, wastewater, and stormwater discharges

36 and similar limits on sources of development, agricultural, and urban runoff will continue to 

37 maintain or improve ambient surface water quality in the Illinois River. LSCS’s combined 

38 cooling pond blowdown, wastewater, and stormwater discharges to the Illinois River are 

39 regulated under an IEPA-administered NPDES permit. Available data indicate that LSCS 

40 operations are a very small contributor to the pollutant and thermal loading to the Illinois River. 

41 Based on the foregoing, the NRC staff concludes that the cumulative impacts from past, 

42 present, and reasonably foreseeable future actions and trends on surface water resources 

43 during the license renewal term would be SMALL. 

44 4.16.3.2 Groundwater Resources

45 This section addresses the direct and indirect effects of license renewal on groundwater use 

46 and quality when added to the aggregate effects of other past, present, and reasonably 

47 foreseeable future actions. As noted in Section 4.5.1.2, the NRC staff concludes the impacts of 

48 the proposed action (license renewal) on groundwater consumption and quality would be 
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1 SMALL. All groundwater consumed at LSCS is obtained from two wells completed in the 

2 Cambrian-Ordovician Aquifer (see Section 3.5.2.2).

3 LaSalle County has an adequate supply of groundwater for industrial, municipal, and domestic 

4 purposes (LaSalle County 2014). The Cambrian-Ordovician Aquifer System is a major source 

5 of water in LaSalle County. Groundwater levels in the Cambrian-Ordovician Aquifer System of 

6 LaSalle County and the plant area have shown little change from 1995 to 2007 

7 (Burch 2002, 2008). Even if this trend does not continue, the plant is unlikely to have a 

8 significant impact on the Cambrian-Ordovician Aquifer System. 

9 Ongoing operations have not impacted the groundwater quality of aquifers on or off the site. 

10 The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitards, which

11 prevent the groundwater quality from being impacted by site activities. Whether an aquifer is 

12 located on site or off site, the low permeability, thickness, and lateral extent of the Wedron 

13 Silty-Clay Till means there is little chance of significant impact to groundwater quality from site 

14 activities.

15 Considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes 

16 that the cumulative impacts on groundwater use and quality during the LSCS license renewal 

17 term would be SMALL.

18 4.16.4 Terrestrial Resources

19 This section addresses the direct and indirect effects of license renewal on terrestrial resources 

20 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

21 actions. Section 4.6 of this SEIS finds that the direct and indirect impacts on terrestrial 

22 resources from the proposed license renewal, when considered in the absence of the aggregate 

23 effects, would be SMALL. The cumulative impact is the total effect on terrestrial resources of all 

24 actions taken, no matter who has taken the actions (the second principle of cumulative effects 

25 analysis in CEQ 1997).

26 Two related concepts bound the analysis of cumulative impacts: (1) the timeframe and 

27 (2) geographic extent. The timeframe for cumulative analyses for ecological resources extends 

28 far enough into the past to understand the processes that affect the present resource conditions 

29 and to examine whether and why terrestrial resources are stable or unstable, which the NRC’s 

30 definitions of impact levels require. The timeframe for cumulative impact analysis is more 

31 extensive than that for the direct and indirect impact analysis.

32 The geographic extent considered in this cumulative terrestrial resource analysis depends on 

33 the particular cumulative impacts being discussed. Direct and indirect impacts from LSCS

34 operation are largely limited to the LSCS site and immediate vicinity. However, projects or 

35 actions located beyond this geographic area could directly or indirectly affect terrestrial 

36 resources in this area. This section focuses on the cumulative effects of such actions.

37 The level of cumulative impacts is measured against a baseline. Consistent with other Federal 

38 agencies’ and the Council on Environmental Quality’s (CEQ 1997) NEPA guidance, the term 

39 “baseline” pertains to the condition of the resource without the action (i.e., under the no-action 

40 alternative). Under the no-action alternative, the plant would shut down, and the resource would 

41 conceptually return to its condition without the plant (which is not necessarily the same as the 

42 condition before the plant was constructed). The baseline, or benchmark, for assessing 

43 cumulative impacts on terrestrial resources takes into account the preoperational environment,

44 as recommended by EPA (1999b) for its review of NEPA documents.
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1 Past Development and Habitat Alteration

2 The LSCS site was partially disturbed during the construction of the facility to develop site 

3 buildings and infrastructure and to create the cooling pond. Of the site’s 1,528 ha (3,776 ac), 

4 65 ha (160 ac) were permanently converted for industrial use to support buildings and 

5 infrastructure, and approximately 800 ha (1,976 ac) are occupied by the cooling pond. During 

6 construction, some additional land may have been temporarily disturbed to allow for laydown 

7 areas for construction supplies or storage of construction equipment.

8 In the broader area—the Illinois/Indiana Prairies Level IV Ecoregion—native tallgrass prairies, 

9 wetlands, and floodplain forests have been converted to agricultural and urban land, which now 

10 account for the major land-use types. Habitat loss, in general, can negatively affect breeding 

11 success, dispersal success, predation rate, and other animal behaviors (Fahrig 2003). Habitat 

12 fragmentation (the breaking up of a larger area of habitat into smaller patches of smaller total 

13 area) can also negatively affect terrestrial biota. In a study of breeding bird communities in 

14 24 Illinois grassland fragments, Herkert (1994) found that fragmentation was likely a factor in 

15 Midwestern grassland bird population declines. A study conducted in 2012 on the partridge pea 

16 (Chamaecrista fasciculata) concludes that native prairie plant species that occur in smaller, 

17 isolated prairie fragments are likely to suffer a reduction in genetic fitness (Mannouris and 

18 Byers 2013). IDNR (2005) reports that remaining prairie remnants within the State lack many 

19 natural ecosystem functions, due to their small size, and areas of prairie restoration often lack 

20 forbs or are overly dominated by big bluestem (Andropogon gerardii) or Indiangrass 

21 (Sorghastrum nutans). Accordingly, remaining native populations in these habitats are likely to 

22 suffer from reduced genetic fitness, which is further exacerbated by fragmentation. 

23 Energy Production and Development

24 Two nuclear power plant sites with four operating reactors (Braidwood Station, Units 1 and 2, 

25 and Dresden Nuclear Power Station, Units 2 and 3) lie within 50 mi (80 km) of the LSCS site. 

26 Because the effects of these facilities would primarily be limited to the terrestrial resources on 

27 each plant’s site and the immediate vicinity, the operation of these two facilities during the 

28 proposed LSCS license renewal term would not result in cumulative effects to the terrestrial 

29 resources affected by LSCS operation.

30 Four fossil-fuel-fired energy facilities occur in the region (Table E–1 in Appendix E) and each is 

31 about 20 mi (30 km) from LSCS. Although no coal or gas energy projects are under 

32 construction in the region at this time, other energy development may arise over the proposed 

33 license renewal term. Air emissions from these facilities include GHGs, such as nitrogen 

34 oxides, carbon dioxide, and methane, all of which can have far-reaching consequences 

35 because they cumulatively contribute to climate change. The effects of climate change on 

36 terrestrial resources are discussed in Section 4.15.3.2.

37 Four wind energy facilities exist in the region (Table E–1 in Appendix E). Grand Ridge Wind 

38 Farm is a 140-unit wind facility located immediately west of the LSCS property, and it extends 

39 southwest for approximately 8 mi (13 km). The other three wind facilities are located between 

40 6 mi (10 km) and 27 mi (43 km) from the LSCS site and consist of a total of 450 wind units. 

41 Operation of wind farms can result in direct mortality of birds and bats through collision with 

42 turbine blades as well as indirect effects, such as wildlife avoidance, habitat disruption, reduced 

43 nesting or breeding density, habitat abandonment, and behavioral effects 

44 (Stewart et al. 2005, 2007). Given that the majority of bird and bat species are migratory, 

45 effects of wind farms on bird and bat populations can be far reaching.
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1 Development, Urbanization, and Habitat Fragmentation

2 As the region surrounding the LSCS site becomes more developed, habitat fragmentation will 

3 increase, and the amount of forested, prairie, and wetland habitat is likely to decline further. 

4 Transmission lines, pipelines, and associated corridors established to connect new buildings to 

5 the regional electric grid and to utilities could further fragment habitats if the corridors split 

6 otherwise continuous tracts of habitat. Edge species that prefer open or partially open habitats 

7 will likely benefit from the fragmentation, whereas species that require interior forest or wetland 

8 habitat will likely suffer. 

9 Continued urbanization in the future will likely include construction of additional housing units 

10 and associated commercial buildings; roads, bridges, and rail; and water or wastewater

11 treatment and distribution facilities and associated pipelines. Increased development will likely 

12 decrease the overall availability and quality of terrestrial habitats. Species that require larger 

13 ranges, especially larger predators, will likely suffer reductions in their populations. Similarly, 

14 species with threatened or endangered Federal or State status or otherwise declining 

15 populations would be more sensitive to declines in habitat availability and quality. Native prairie 

16 plants will likely continue to experience reductions in genetic fitness, as previously discussed.

17 Wildlife Refuges, State Parks, and Recreational Areas

18 A number of State parks, State Fish and Wildlife Areas, and State Natural Areas and 

19 recreational areas are located near LSCS (Table E–1 in Appendix E) that provide valuable 

20 habitat to native wildlife, migratory birds, and protected terrestrial species and habitats. Illini 

21 State Park, which comprises 510 ac (206 ha) and lies 6 mi (10 km) north-northwest of the LSCS 

22 site, provides habitat for a number deciduous trees, including hickory (Carya spp.), ash 

23 (Fraxinus spp.), walnut (Juglans spp.), elm (Ulmus spp.), cottonwood (Populus deltoids), oak 

24 (Quercus spp.), and maple (Acer spp.), as well as white-tailed deer (Odocoileus virginianus), 

25 eastern gray squirrels (Sciurus carolinensis), opossums (Didelphis virginiana), beavers (Castor 

26 canadensis), raccoon (Procyon lotor), groundhogs (Marmota monax), and a variety of waterfowl 

27 and songbirds (IDNR 2015a). Starved Rock State Park, which comprises 2,700 ac (1,090 ha) 

28 and lies 15 mi (24 km) northwest of the LSCS site along the Illinois River, contains a variety of 

29 habitats, including canyons, sandstone bluffs, rolling plains, forest, upland prairies, waterfalls, 

30 rivers, and streams, and provides particularly high-quality habitat to many species of native 

31 wildlife and migrating birds. As fragmentation and land-use changes continue, these protected 

32 areas will become ecologically more important because they provide large, uninterrupted areas 

33 of minimally disturbed habitat.

34 Conclusion

35 The NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity of 

36 the LSCS site are MODERATE to LARGE, based on past, present, and reasonably foreseeable 

37 future actions. This level of impact is primarily the result of past habitat alteration and loss on 

38 the LSCS site and within the larger Illinois/Indiana Prairies Level IV Ecoregion. The 

39 environmental effects of these actions are clearly noticeable and have destabilized important 

40 attributes of certain terrestrial communities. The loss of genetic fitness of native prairie species 

41 and the loss of tallgrass prairies, wetlands, and floodplains are demonstrative of such effects. 

42 The incremental, site-specific impact from the continued operation of LSCS during the license 

43 renewal period would be an unnoticeable or minor contributor to cumulative impacts on 

44 terrestrial resources.
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1 4.16.5 Aquatic Resources

2 This section addresses the direct and indirect effects of license renewal on aquatic resources 

3 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

4 actions. Section 4.7 finds that the direct and indirect impacts on aquatic resources from the 

5 proposed license renewal would be SMALL for all aquatic ecology issues, with the exception of 

6 MODERATE impacts to shad from heat shock in the cooling pond. The geographic area 

7 considered in the cumulative aquatic resources analysis includes the LSCS cooling pond and 

8 the vicinity of the intake and discharge structures on the Illinois River affected by LSCS water 

9 withdrawal and discharge. The baseline, or benchmark, for assessing cumulative impacts on 

10 aquatic resources takes into account the preoperational environment as recommended by EPA

11 (1999b) for its review of NEPA documents.

12 Section 3.7 presents an overview of the current condition of the LSCS cooling pond and Illinois 

13 River and the history and factors that led to current conditions. In summary, the direct and 

14 indirect impacts from draining wetlands, construction of locks and dams, maintenance of 

15 navigation channels, industrial effluent, and sewage discharge are some of the most influential 

16 human activities on the Illinois River Basin (Parker 2014). By the 1960s, biodiversity of fish 

17 within the upper Illinois River was low and freshwater mussels were nearly absent from the 

18 upper Illinois River (Sietman et al. 2001). Pollution-tolerant non-native common carp (Cyprinus 

19 carpio) and goldfish (Carassius auratus) dominated fish populations (Parker 2014). Since the 

20 passage of the CWA in 1974, water quality within the Illinois River has improved, and more 

21 diverse fish assemblages have inhabited the upper Illinois River (Parker 2014). Similarly, 

22 freshwater mussels have recolonized portions of the upper Illinois River since the 1980s 

23 (Sietman et al. 2001). 

24 Many natural and anthropogenic activities can influence the current and future aquatic biota in 

25 the area surrounding the LSCS site and the Illinois River Basin. Potential biological stressors 

26 include operational impacts from LSCS (as described in Section 4.7), energy development, and 

27 urbanization. 

28 4.16.5.1 Energy Development

29 Several other power plants withdraw water from and discharge water to the Illinois River (see 

30 Appendix E). The largest nuclear power plant near LSCS and located on the Illinois River is the 

31 Dresden Nuclear Station, located on River Mile 272.3 of the Illinois River. Dresden Nuclear 

32 Station withdraws water from the Kankakee River and discharges to the Illinois River (EA 2015). 

33 For 3.5 months of the year, Dresden operates in an indirect-open-cycle mode, and during the 

34 remainder of the year (8.5 months), Dresden operates its cooling pond in a closed-cycle mode, 

35 similar to LSCS. Operating in a closed-cycle mode reduces the impacts to aquatic resources 

36 because less water is withdrawn and discharged, and therefore, less thermal effluent is 

37 discharged to the Illinois River. The NRC (2004) determined that the impacts from 

38 impingement, entrainment, and heat shock from Dresden Nuclear Station would be SMALL on 

39 aquatic resources. Furthermore, it is unlikely that the thermal effluent from Dresden Nuclear 

40 Station and LSCS overlap, given that both thermal plumes dissipate within the vicinity of each 

41 respective discharge structure and the distance between the two plants (NRC 2004; 

42 Exelon 2014a). Impingement and entrainment at both plants could affect similar fish 

43 populations; however, operating in the closed-cycle mode would reduce impacts to fish 

44 (NRC 2004; EA 2015). 

45 Kendall County Generation is a natural-gas-fueled plant with 1,140 MW generating capacity that 

46 withdraws water from and discharges water to the Illinois River. This plant is approximately 

47 27 mi (43 km) northeast of LSCS. Given that the discharge plumes are limited to the vicinity of 
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1 the discharge structures, the heated effluent from the two plants would not likely overlap. 

2 However, many of the same fish populations could be affected by impingement and entrainment

3 at LSCS and Kendall County Generation. 

4 The other power plants located on the Illinois River have a much smaller generating capacity—

5 less than 180 MW (see Appendix E)—and therefore require less cooling water. Given the lower 

6 withdraw and discharge rates, effects to aquatic resources from impingement, entrainment, and 

7 thermal effluents would also be lower at these facilities. 

8 Several wind and solar farms operate within 50 mi (80 km) of LSCS (see Appendix E). These 

9 facilities would not have detectable impacts on aquatic resources in the Illinois River because, in 

10 general, they do not require water during operation.

11 4.16.5.2 Future Urbanization and Transportation Development

12 Future urbanization in the vicinity of LSCS would likely include construction of new housing units 

13 and associated commercial buildings; roads, bridges, and rail; and water or wastewater

14 treatment (or both), distribution facilities, and associated pipelines. Continued development of 

15 the area has the potential to increase the rate and volume of stormwater runoff and reduce 

16 groundwater recharge. If not managed appropriately, such development could result in 

17 increased flooding, higher and more frequent storm-related flows, and low flows of longer 

18 duration in streams. The increased runoff rates and high channel velocities from inappropriately 

19 managed sites could result in excessive bank erosion and associated sedimentation and stream 

20 degradation in the Illinois River and its tributaries. As a result, aquatic biota populations may 

21 experience habitat degradation or loss, reduced food or prey availability, and increased 

22 susceptibility to exotic species invasions. Such potential impacts can be mitigated through 

23 implementation of BMPs that address stormwater quality, quantity, and discharge. Stormwater 

24 BMPs are often required by state and local regulations, which would ensure that impacts to 

25 aquatic resources resulting from future development would be appropriately mitigated.

26 4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas

27 Several wildlife preserves, parks, and recreation sites lie within the vicinity of LSCS (see 

28 Appendix E), including the Marseilles State Fish and Wildlife Area, which lies 1.5 mi (2.4 km) 

29 north of the LSCS site. The continued preservation of these areas will protect aquatic habitats 

30 and, as land development continues, these areas will become ecologically more important 

31 because they will provide large areas of unfragmented natural habitat.

32 4.16.5.4 Illinois Wildlife Conservation Plan

33 The State of Illinois maintains a Comprehensive Wildlife Conservation Plan and Strategy 

34 (IDNR 2005), which is implemented by the IDNR and numerous Federal, State, local, and 

35 private partners. The plan addresses long-range landscape-level planning initiatives, which 

36 include projects to address declining wildlife populations and conservation and restoration of 

37 ecologically important, sensitive, and rare habitats. Part of the plan includes the Conservation 

38 Reserve Enhancement Program, which is a voluntary program to assist landowners in 

39 protecting environmentally sensitive land, decreasing erosion, restoring wildlife habitat, 

40 increasing populations of threatened and endangered species, and safeguarding groundwater

41 and surface water in the Illinois River Basin (IDNR 2005). Commitment to this plan will help 

42 protect or restore aquatic habitats and continue to support a diversity of aquatic life in the future.

43 4.16.5.5 Conclusion

44 The stresses from past river flow alterations, increasing urbanization, and demand for water 

45 resources across the geographic area of interest depend on many factors that the NRC staff 

46 cannot quantify but that are likely to noticeably alter aquatic resources when all stresses on the 
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1 aquatic communities are assessed cumulatively. Continued protection of aquatic habitats 

2 through wildlife preserves, parks, and recreational areas, as well as the implementation of the 

3 Illinois Wildlife Conservation Plan, will likely mitigate some of these effects, and, therefore, the 

4 NRC staff finds it reasonable to assume that these activities will ensure that future actions do 

5 not destabilize important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, 

6 the NRC staff concludes that the cumulative impacts from the proposed license renewal and 

7 other past, present, and reasonably foreseeable projects would be MODERATE. 

8 4.16.6 Historic and Cultural Resources

9 This section addresses the direct and indirect effects of license renewal on historic and cultural 

10 resources when added to the aggregate effects of other past, present, and reasonably 

11 foreseeable future actions. The geographic area considered in this analysis is the APE 

12 associated with the proposed undertaking, as described in Section 3.9.

13 The archaeological record for the region indicates prehistoric and historic occupation of the 

14 LSCS site and its immediate vicinity. Given the location of identified cultural resources, the 

15 construction of LSCS may have resulted in destruction of cultural resources within the LSCS 

16 site and its immediate vicinity.

17 Other land uses in the vicinity of LSCS may have resulted in impacts on and the loss of, cultural 

18 resources on the LSCS site and its immediate vicinity. However, there remains the possibility 

19 for additional historic or cultural resources to be located within the LSCS site. The present and 

20 reasonably foreseeable projects that could affect these resources, reviewed in conjunction with 

21 license renewal, are noted in Appendix E of this document. Direct impacts would occur if 

22 historic and cultural resources in the APE were physically removed or disturbed. It is unlikely 

23 that the projects discussed in Appendix E would impact historic and cultural resources on the 

24 LSCS site because those resources are not in areas that would be subject to foreseeable future 

25 development.

26 As described in Section 4.9 of this document, no known cultural resources would be adversely 

27 affected by LSCS license renewal activities, as no associated changes or ground-disturbing 

28 activities will occur (Exelon 2014a). Moreover, as discussed in Section 4.9, Exelon has 

29 established draft procedures to ensure cultural resources are considered in project planning 

30 during operation of LSCS.

31 The NRC staff concludes that the cumulative impact of the proposed license renewal on historic 

32 and cultural resources, when combined with other past, present, and reasonably foreseeable 

33 future activities, would be SMALL.

34 4.16.7 Socioeconomics

35 This section addresses socioeconomic factors that have the potential to be directly or indirectly 

36 affected by changes in operations at LSCS, in addition to the aggregate effects of other past, 

37 present, and reasonably foreseeable future actions. The primary geographic area of interest 

38 considered in this cumulative analysis includes LaSalle, Grundy, and Will Counties, where 

39 approximately 83 percent of LSCS employees reside (see Table 3–15). This is where the 

40 economy, tax base, and infrastructure would most likely be affected because the majority of 

41 LSCS workers and their families reside, spend their incomes, and use their benefits within these 

42 counties.

43 As discussed in Section 4.10, continued operation of LSCS during the license renewal term 

44 would have no impact on socioeconomic conditions in the region beyond what is already being 

45 experienced. Since Exelon has no plans to hire additional workers during the license renewal 
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1 term, overall expenditures and employment levels at LSCS would remain relatively unchanged 

2 with no new or increased demand for housing and public services. Based on this and other 

3 information presented in Chapter 4, there would be no contributory effect on socioeconomic 

4 conditions in the region during the license renewal term from the continued operation of LSCS 

5 beyond what is currently being experienced. Therefore, the only contributory effects would 

6 come from reasonably foreseeable future planned activities at LSCS, unrelated to the proposed 

7 action (license renewal), and other reasonably foreseeable planned offsite activities. For 

8 example, offsite residential development is planned throughout the LSCS region. The 

9 availability of new housing could attract individuals and families from outside the region, 

10 increasing the local population and causing increased traffic on local roads, as well as increased 

11 demand for public services. 

12 When combined with other past, present, and reasonably foreseeable future activities, the 

13 contributory effects of continued reactor operations at LSCS would have no new or increased 

14 impact on socioeconomic conditions in the region beyond what is currently being experienced.

15 4.16.8 Human Health

16 The NRC and EPA established radiological dose limits for protection of the public and workers 

17 from both acute and long-term exposure to radiation and radioactive materials. These dose 

18 limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.11.1, the 

19 NRC staff concluded that impacts to human health from continued plant operations are SMALL. 

20 For the purposes of this analysis, the geographical area considered is the area included within 

21 an 80-km (50-mi) radius of the LSCS plant site. There are four other nuclear power plants 

22 within the applicable geographical area: Braidwood Station, Units 1 and 2, and Dresden 

23 Nuclear Power Station, Units 2 and 3. Also, LSCS’s 80-km (50-mi) radius overlaps with the 

24 80-km (50-mi) radii of Byron Station, Units 1 and 2; Quad Cities Nuclear Power Station, Units 1 

25 and 2; and Clinton Power Station, Unit 1. As discussed in Section 3.1.4.4, in addition to storing 

26 its spent nuclear fuel in a storage pool, LSCS stores some of its spent nuclear fuel in an onsite 

27 independent spent fuel storage installation (ISFSI).

28 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 

29 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 

30 facilities, and transportation of fuel and waste. As discussed in Section 3.1.4.5, LSCS has a 

31 REMP that measures radiation and radioactive materials in the environment from LSCS, its 

32 ISFSI, and all other sources. The NRC staff reviewed the radiological environmental monitoring 

33 results for the 5-year period from 2010 to 2014 as part of the cumulative impacts assessment. 

34 The NRC staff’s review of Exelon’s data showed no indication of an adverse trend in 

35 radioactivity levels in the environment from LSCS or its ISFSI. The data showed that there was 

36 no measurable impact to the environment from operations at LSCS.

37 The NRC staff concludes that the cumulative radiological impacts of the proposed license 

38 renewal, when combined with other past, present, and reasonably foreseeable future activities, 

39 would be SMALL. This is based on the NRC staff’s review of REMP data, radioactive effluent 

40 release data, worker dose, and LSCS’s expected continued compliance with Federal radiation 

41 protection standards during continued operation, and regulation of any future development or 

42 actions in the vicinity of the LSCS site by the NRC and the State of Illinois.

43 4.16.9 Environmental Justice

44 The environmental justice cumulative impact analysis evaluates the potential for 

45 disproportionately high and adverse human health and environmental effects on minority and 

46 low-income populations that could result from past, present, and reasonably foreseeable future 
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1 actions, including the continued operational effects of LSCS during the renewal term. Everyone 

2 living near LSCS currently experiences its operational effects, including minority and low-income 

3 populations. The NRC addresses environmental justice matters for license renewal by 

4 identifying the location of minority and low-income populations, determining whether there would 

5 be any potential human health or environmental effects to these populations, and determining if 

6 any of the effects may be disproportionately high and adverse.

7 Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal adverse 

8 impacts on human health. Disproportionately high and adverse human health effects occur 

9 when the risk or rate of exposure to an environmental hazard for a minority or low-income 

10 population is significant and exceeds the risk or exposure rate for the general population or for 

11 another appropriate comparison group. Disproportionately high environmental effects refer to 

12 impacts or risks of impacts on the natural or physical environment in a minority or low-income 

13 community that are significant and appreciably exceed the environmental impact on the larger 

14 community. Such effects may include biological, cultural, economic, or social impacts. Some of 

15 these potential effects have been identified in resource areas presented in preceding sections of 

16 Chapter 4 in this SEIS. As previously discussed in this chapter, the impact from license renewal 

17 for all resource areas (e.g., land, air, water, ecology, and human health) would be SMALL.

18 As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 

19 adverse impacts on minority and low-income populations from the continued operation of LSCS

20 during the license renewal term. Since Exelon has no plans to hire additional workers during 

21 the license renewal term, employment levels at LSCS would remain relatively constant, and 

22 there would be no additional demand for housing or increased traffic. Based on this information 

23 and the analysis of human health and environmental impacts presented in the preceding 

24 sections, it is not likely there would be any disproportionately high and adverse contributory 

25 effect on minority and low-income populations from the continued operation of LSCS during the 

26 license renewal term. Therefore, the only contributory effects would come from the other 

27 reasonably foreseeable future planned activities at LSCS, unrelated to the proposed action 

28 (license renewal), and other reasonably foreseeable planned offsite activities.

29 Conclusion

30 Exelon has no reasonably foreseeable future planned activities at LSCS beyond continued 

31 reactor operations. When combined with other past, present, and reasonably foreseeable future 

32 activities, the ongoing contributory effects of continued reactor operations at LSCS would not 

33 likely cause disproportionately high and adverse human health and environmental effects on 

34 minority and low-income populations residing in the vicinity of LSCS beyond what is currently 

35 being experienced.

36 4.16.10 Waste Management

37 This section describes waste management impacts during the license renewal term when added 

38 to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 

39 the purpose of this cumulative impacts analysis, the area within a 50-mi (80-km) radius of LSCS

40 was considered. The NRC staff concluded, in Section 4.11, that the potential human health 

41 impacts from LSCS’s waste during the license renewal term would be SMALL.

42 As discussed in Sections 3.1.4 and 3.1.5, Exelon maintains waste management programs for 

43 radioactive and nonradioactive waste generated at LSCS and is required to comply with Federal 

44 and State permits and other regulatory requirements for the management of waste material. 

45 The nuclear power plants and other facilities within a 50-mi (80-km) radius of LSCS are also 

46 required to comply with appropriate NRC, EPA, and state requirements for the management of 

47 radioactive and nonradioactive waste. Current waste management activities at LSCS would 
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1 likely remain unchanged during the license renewal term, and continued compliance with 

2 Federal and State requirements for radioactive and nonradioactive waste is expected.

3 Based on the above, the NRC staff concludes that the potential cumulative impacts from 

4 radioactive and nonradioactive waste during the license renewal term would be SMALL. 

5 Continued compliance with Federal and State requirements for radioactive and nonradioactive 

6 waste management by Exelon is expected.

7 4.16.11 Global Climate Change

8 This section addresses the impact of GHG emissions resulting from continued operation of 

9 LSCS on global climate change when added to the aggregate effects of other past, present, and 

10 reasonably foreseeable future actions.

11 The impacts of climate change on air, water, and ecological resources are discussed in 

12 Section 4.15.3. Climate is influenced by both natural and human-induced factors; the observed 

13 global warming (increase in Earth’s surface temperature) in the 21st century has been attributed 

14 to the increase in GHG emissions resulting from human activities (USGCRP 2009). Climate 

15 model projections indicate that future climate change is dependent on current and future GHG 

16 emissions (IPCC 2007b; USGCRP 2009, 2014). As described in Section 4.15.3.1, operations at 

17 LSCS emit GHG emissions. 

18 The cumulative impact of a GHG emission source on climate is global. GHG emissions are 

19 transported by wind and become well mixed in the atmosphere as a result of their long 

20 atmospheric residence time. Therefore, the extent and nature of climate change is not specific 

21 to where GHGs are emitted. In April 2015, EPA published the official U.S. inventory of GHG 

22 emissions, which identifies and quantifies the primary anthropogenic sources and sinks of 

23 GHGs. The EPA GHG inventory is an essential tool for addressing climate change and 

24 participating with the United Nations Framework Convention on Climate Change to compare the 

25 relative global contribution of different emission sources and GHGs to climate change. In 2013, 

26 the United States emitted 6,673 teragrams (Tg) (6,673 million metric tons (MMT)) of carbon 

27 dioxide equivalents (CO2eq), and from 1990 to 2013, emissions increased by 5.9 percent 

28 (EPA 2015d). In 2012 and 2013, the total amount of CO2eq emissions related to electricity 

29 generation was 2,022 Tg (2,022 MMT) and 2,039 Tg (2,039 MMT), respectively (EPA 2015d). 

30 The Energy Information Administration (EIA) reported that, in 2013, electricity production alone 

31 in Illinois was responsible for 94.1 MMT CO2eq (EIA 2015a). Facilities that emit 25,000 MT 

32 CO2eq or more per year are required to annually report their GHG emissions to EPA. These 

33 facilities are known as direct emitters, and the data are publicly available in EPA’s facility-level 

34 information on GHGs tool (FLIGHT). In 2013, FLIGHT identified 11 facilities in LaSalle County, 

35 Illinois, where LSCS is located, that emitted a total of 0.89 MT CO2eq (EPA 2015c). In 2012, 

36 FLIGHT identified 290 facilities in Illinois that emitted a total of 134 MMT CO2eq (EPA 2015c).

37 Appendix E provides a list of current and reasonably foreseeable future projects and actions 

38 that could contribute to GHG emissions. Permitting and licensing requirements and other 

39 mitigative measures can minimize the impacts of GHG emissions. For instance, in 2012, EPA

40 issued a final GHG Tailoring Rule (77 FR 41051) to address GHG emissions from stationary 

41 sources under the CAA permitting requirements; the GHG Tailoring Rule establishes when an 

42 emission source will be subject to permitting requirements and control technology to reduce 

43 GHG emissions. On June 25, 2013, President Obama set forward a plan to reduce carbon 

44 pollution. The Climate Action Plan will reduce carbon pollution, prepare the United States for 

45 the impacts of climate change, and lead international efforts to combat global climate change. 

46 The Clean Power Plan Final Rule (80 FR 64661–65120), aimed at reducing carbon pollution 

47 from power plants, requires carbon emissions from the power sector to be 32 percent below 
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1 2005 levels (870 million tons less). The Clean Power Plan sets forth carbon dioxide emission 

2 performance rate standards for power plants that should be achieved by 2030. Future actions 

3 and steps taken to reduce GHG emissions can lessen the impacts on climate change.

4 EPA’s U.S. inventory of GHG emissions illustrates the diversity of GHG sources, such as 

5 electricity generation, industrial processes, and agriculture. As presented in Section 4.15.3, 

6 direct GHG emissions from combustion sources resulting from operations at LSCS range from 

7 245 to 1,022 MT CO2eq, and total emissions range from 34,228 to 39,997 MT CO2eq. In 

8 comparing LSCS’s GHG emission contribution to different emissions sources, whether it be total 

9 U.S. GHG emissions, emissions from electricity production in Illinois, or emissions on a county 

10 level, GHG emissions from LSCS are minor relative to these inventories; this is evident, as 

11 presented in Table 4–23. The emissions impact of a single source on climate change requires 

12 that a climate model account for that specific emissions source in order to project the magnitude 

13 and extent of climate change. Climate models indicate that short-term climate change (through 

14 the year 2030) is dependent on past GHG emissions. Therefore, climate change is projected to 

15 occur with or without present and future GHG emissions from LSCS. The NRC staff concludes 

16 that the incremental impact from the contribution of GHG emissions from continued operation of 

17 LSCS on climate change would be SMALL. 

18 Due to the global significance of GHG emissions, this global climate change cumulative impacts 

19 analysis considers the entire Earth’s atmosphere and therefore global emissions (as opposed to 

20 county, state, or national emissions). As discussed in Section 4.15.3.2, climate change and 

21 climate-related environmental changes have been observed on a global level, and climate 

22 models indicate that future climate change will depend on present and future GHG emissions. 

23 With continued increases in GHG emission rates, climate models project that Earth’s average 

24 surface temperature will continue to increase and climate-related changes will persist. 

25 Therefore, the cumulative impact of GHG emissions on climate change is noticeable but not 

26 destabilizing. The NRC staff concludes that the cumulative impacts of GHG emissions from 

27 past, present, and reasonably foreseeable future actions are MODERATE. However, as 

28 discussed above, the incremental addition of GHG emissions from continued operation of 

29 LSCS, when compared to global emissions, are minor.

30 Table 4–23. Comparison of GHG Emission Inventories

Source CO2eq 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) 0.04

(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) Emissions rounded from and obtained from Exelon 2015c. 

31 4.16.12 Summary of Cumulative Impacts

32 The NRC staff considered the potential impacts resulting from the operation of LSCS during the 

33 period of extended operation and other past, present, and reasonably foreseeable future actions 
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1 near LSCS. The preliminary determination is that the potential cumulative impacts would range 

2 from SMALL to LARGE, depending on the resource. Table 4–24 summarizes the cumulative 

3 impacts on resource areas.

4 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.

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 Ecology 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.
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Resource Area Cumulative Impact

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.

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 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 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 from the proposed license renewal and 

other past, present, and reasonably foreseeable projects would be MODERATE.

1 4.17 Resource Commitments

2 4.17.1 Unavoidable Adverse Environmental Impacts

3 Unavoidable adverse environmental impacts are impacts that would occur after implementation 

4 of all workable mitigation measures. Carrying out any of the energy alternatives considered in 

5 this SEIS, including the proposed action, would result in some unavoidable adverse 

6 environmental impacts.

7 Minor unavoidable adverse impacts on air quality would occur, due to emission and release of 

8 various chemical and radiological constituents from power plant operations. Nonradiological 

9 emissions resulting from power plant operations are expected to comply with EPA emissions 

10 standards, although the alternative of operating a fossil-fueled power plant in some areas may 

11 worsen existing attainment issues. Chemical and radiological emissions would not exceed the 

12 national emission standards for hazardous air pollutants.

13 During nuclear power plant operations, workers and members of the public would face 

14 unavoidable exposure to radiation and hazardous and toxic chemicals. Workers would be 
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1 exposed to radiation and chemicals associated with routine plant operations and the handling of 

2 nuclear fuel and waste material. Workers would have higher levels of exposure than members 

3 of the public, but doses would be administratively controlled and would not exceed standards or 

4 administrative control limits. In comparison, the alternatives involving the construction and 

5 operation of a non-nuclear power generating facility would also result in unavoidable exposure 

6 to hazardous and toxic chemicals to workers and the public.

7 The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 

8 hazardous waste, and nonhazardous waste, would be unavoidable. Hazardous and 

9 nonhazardous wastes would be generated at non-nuclear power generating facilities. Wastes 

10 generated during plant operations would be collected, stored, and shipped for suitable 

11 treatment, recycling, or disposal in accordance with applicable Federal and state regulations. 

12 Due to the costs of handling these materials, power plant operators would be expected to carry 

13 out all activities and optimize all operations in a way that generates the smallest amount of 

14 waste possible.

15 4.17.2 Short-Term Versus Long-Term Productivity

16 The operation of power generating facilities would result in short-term uses of the environment, 

17 as described in Chapter 4. “Short term” is the period of time that continued power generating 

18 activities take place.

19 Power plant operations require short-term use of the environment and commitment of resources 

20 (e.g., land and energy), indefinitely or permanently. Certain short-term resource commitments 

21 are substantially greater under most energy alternatives, including license renewal, than under 

22 the no-action alternative because of the continued generation of electrical power and the 

23 continued use of generating sites and associated infrastructure. During operations, all energy 

24 alternatives entail similar relationships between local short-term uses of the environment and 

25 the maintenance and enhancement of long-term productivity.

26 Air emissions from power plant operations introduce small amounts of radiological and 

27 nonradiological constituents to the region around the plant site. Over time, these emissions 

28 would result in increased concentrations and exposure, but they are not expected to impact air 

29 quality or radiation exposure to the extent that public health and long-term productivity of the 

30 environment would be impaired.

31 Continued employment, expenditures, and tax revenues generated during power plant 

32 operations directly benefit local, regional, and state economies over the short term. Local 

33 governments investing project-generated tax revenues into infrastructure and other required 

34 services could enhance economic productivity over the long term.

35 The management and disposal of spent nuclear fuel, low-level radioactive waste, hazardous 

36 waste, and nonhazardous waste requires an increase in energy and consumes space at 

37 treatment, storage, or disposal facilities. Regardless of the location, the use of land to meet 

38 waste disposal needs would reduce the long-term productivity of the land.

39 Power plant facilities are committed to electricity production over the short term. After 

40 decommissioning these facilities and restoring the area, the land could be available for other 

41 future productive uses.

42 4.17.3 Irreversible and Irretrievable Commitments of Resources

43 This section describes the irreversible and irretrievable commitments of resources that have 

44 been noted in this SEIS. Resources are irreversible when primary or secondary impacts limit 
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1 the future options for a resource. An irretrievable commitment refers to the use or consumption 

2 of resources that are neither renewable nor recoverable for future use. Irreversible and 

3 irretrievable commitments of resources for electrical power generation include the commitment 

4 of land, water, energy, raw materials, and other natural and man-made resources required for 

5 power plant operations. In general, the commitments of capital, energy, labor, and material 

6 resources are also irreversible.

7 The implementation of any of the energy alternatives considered in this SEIS would entail the 

8 irreversible and irretrievable commitments of energy, water, chemicals, and—in some cases—

9 fossil fuels. These resources would be committed during the license renewal term and over the 

10 entire life cycle of the power plant, and they would be unrecoverable.

11 Energy expended would be in the form of fuel for equipment, vehicles, and power plant 

12 operations and electricity for equipment and facility operations. Electricity and fuel would be 

13 purchased from offsite commercial sources. Water would be obtained from existing water 

14 supply systems. These resources are readily available, and the amounts required are not 

15 expected to deplete available supplies or exceed available system capacities.

16 4.18 References

17 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

18 protection against radiation.”

19 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

20 production and utilization facilities.”

21 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

22 protection regulations for domestic licensing and related regulatory functions.”

23 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

24 renewal of operating licenses for nuclear power plants.”

25 10 CFR Part 100. Code of Federal Regulations, Title 10, Energy, Part 100, “Reactor site 

26 criteria.”

27 36 CFR 60.4. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, Part 

28 60, “National Register of Historic Places”, Section 60.4, “Criteria for evaluation.”

29 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property. 

30 Part 800, “Protection of Historic Properties.”

31 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

32 “Requirements for preparation, adoption, and submittal of implementation plans.”

33 40 CFR Part 60. Code of Federal Regulations, Title 40, Protection of Environment, Part 60, 

34 “Standards of Performance for New Stationary Sources.”

35 40 CFR Part 63. Code of Federal Regulations, Title 40, Protection of Environment, Part 63, 

36 “National emission standards for hazardous air pollutants for source categories.”

37 40 CFR Part 75. Code of Federal Regulations, Title 40, Protection of Environment, Part 75, 

38 “Continuous emission monitoring.”

39 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

40 “Designation of areas for air quality planning purposes.”

41 40 CFR Part 125. Code of Federal Regulations, Title 40, Protection of Environment, Part 125, 

42 “Criteria and standards for the National Pollutant Discharge Elimination System.”
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1 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

2 “Environmental radiation protection standards for nuclear power operations.”

3 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

4 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

5 49 FR 34658. U.S. Nuclear Regulatory Commission. “Waste confidence decision and 

6 requirements for licensee actions regarding the disposition of spent fuel upon expiration of 

7 reactor operating licenses; Final Rules.” Federal Register 49 (171): 34658–34696. 

8 August 31, 1984.

9 55 FR 38472. U.S. Nuclear Regulatory Commission. “Consideration of environmental impacts 

10 of temporary storage of spent fuel after cessation of reactor operation; and waste confidence 

11 decision review; Final Rules.” Federal Register 55 (181): 38472–38514. September 18, 1990.

12 59 FR 7629. Executive Order No. 12898. “Federal actions to address environmental justice in 

13 minority populations and low-income populations.” Federal Register 59 (32): 7629–7634. 

14 February 16, 1994.

15 61 FR 28467. U.S. Nuclear Regulatory Commission. “Environmental review for renewal of 

16 nuclear power plant operating licenses.” Final Rule. Federal Register 61 (109): 28467–28497. 

17 June 5, 1996.

18 61 FR 66537. U.S. Nuclear Regulatory Commission. “Environmental review for renewal of 

19 nuclear power plant operating licenses.” Federal Register 61 (244): 66537–66544. 

20 December 18, 1996.

21 64 FR 68005. U.S. Nuclear Regulatory Commission. “Waste confidence decision review: 

22 status.” Federal Register 64 (233): 68005–68007. December 6, 1999.

23 65 FR 79825. U.S. Environmental Protection Agency. “Regulatory finding on the emissions of 

24 hazardous air pollutants from electric utility steam generating units.” Federal Register 65 (245): 

25 79825–79831. December 20, 2000

26 74 FR 38117. U.S. Nuclear Regulatory Commission. “Revisions to environmental review for 

27 renewal of nuclear power plant operating licenses.” Proposed Rule. Federal Register 74 (146): 

28 38117–38140. July 31, 2009.

29 74 FR 56260. U.S. Environmental Protection Agency. “Mandatory Reporting of Greenhouse 

30 Gases.” Federal Register 74 (209): 56260–56519. October 30, 2009.

31 74 FR 66496. U.S. Environmental Protection Agency. 2009. “Endangerment and cause or 

32 contribute findings for greenhouse gases under Section 202(a) of the Clean Air Act.”

33 Federal Register 74 (239): 66496–66546. December 15, 2009.

34 75 FR 81032. U.S. Nuclear Regulatory Commission. “Consideration of environmental impacts

35 of temporary storage of spent fuel after cessation of reactor operation.”

36 Federal Register 75 (246): 81032–81037. December 23, 2010.

37 75 FR 81037. U.S. Nuclear Regulatory Commission. “Waste confidence decision update.” 

38 Federal Register 75 (246): 81037–81076. December 23, 2010.

39 76 FR 48208. U.S. Environmental Protection Agency. Federal Implementation Plans: 

40 Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals. 

41 Federal Register 76 (152): 48208–48483
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1 77 FR 9304. Environmental Protection Agency. “National emission standards for hazardous air 

2 pollutants from coal- and oil-fired electric utility steam generating units and standards of 

3 performance for fossil-fuel-fired electric utility, industrial commercial institutional, and small 

4 industrial commercial institutional generating units.” Federal Register 77 (32): 9304–9513.

5 77 FR 41051. Environmental Protection Agency. “Prevention of significant deterioration and 

6 Title V greenhouse gas tailoring rule step 3 and GHG plantwide applicability limits.” 

7 Federal Register 77 (134): 41051–41075.

8 78 FR 37282. U.S. Nuclear Regulatory Commission. “Revisions to environmental review for 

9 renewal of nuclear power plant operating licenses.” Federal Register 78 (119): 37282–37324. 

10 June 20, 2013.

11 79 FR 1430. U.S. Environmental Protection Agency. “Standards of Performance for 

12 Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units.” 

13 Federal Register 79 (5): 1430–1519. January 8, 2014.

14 79 FR 48300. U.S. Environmental Protection Agency. “National Pollutant Discharge 

15 Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake 

16 Structures at Existing Facilities and Amend Requirements at Phase I Facilities.” 

17 Federal Register 79 (158): 48300–48439. August 15, 2014.

18 79 FR 56263. U.S. Nuclear Regulatory Commission. “Generic environmental impact statement 

19 for continued storage of spent nuclear fuel.” Federal Register 79 (182): 56263–56264. 

20 September 19, 2014.

21 79 FR 56238. U.S. Nuclear Regulatory Commission. “Continued storage of spent nuclear fuel.” 

22 Federal Register 79 (182): 56238–56263. September 19, 2014.

23 79 FR 73705. U.S. Fish and Wildlife Service. 2014. Endangered and threatened wildlife and 

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25 73705–73748. December 11, 2014.

26 80 FR 46062. U.S. Nuclear Regulatory Commission. “Exelon Generation Company, LLC; LaSalle 

27 County Station, Units 1 and 2; Environmental assessment and finding of no significant impact; 

28 issuance.” Federal Register 80 (148): 46062-46066. August 3, 2015. 

29 80 FR 64661. U.S. Environmental Protection Agency. “Carbon Pollution Emission Guidelines 

30 for Existing Stationary Sources: Electric Utility Generating Units.” Federal Register 80 (205): 

31 64661–65120. October 23, 2015.

32 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Part 302, “Water 

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34 415 ILCS 5/Tit. VI. Illinois Compiled Statutes. Chapter 415, 5, “Noise.”

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13 Characterization Study LaSalle County Station. Prepared for Exelon Generation Company, 

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14 Gases. Available at <http://www.epa.gov/nsr/ghgpermitting.html> (accessed August 2015)

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16 Online, LaSalle County. Available at <http://echo.epa.gov/?redirect=echo> 

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19 Illinois and LaSalle County. Available at <http://ghgdata.epa.gov/ghgp/main.do> 

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22 Emissions and Sinks: 1990–2013. April 15, 2015. Available at 

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27 (accessed 5 October 2015).

28 [EPA] U.S. Environmental Protection Agency. 2015f. “New Source Review Basic Information 

29 on PSD.” Available at <http://www.epa.gov/NSR/psd.html> (accessed August 2015).

30 [Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 

31 Manager, LaSalle County Station to U.S. NRC, Document control Desk. Subject: 

32 Environmental Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle 

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34 [Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 

35 Assurance Manager, LaSalle County Station to U.S. NRC, Document control Desk. Subject: 

36 Environmental Protection Plan and Operating Report Appendix B to Facility License 

37 No. NPF–11 and NPF–18. April 29, 2002. ADAMS No. ML021330421.

38 [Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 

39 LaSalle County Station to U.S. NRC, Document control Desk. Subject: Environmental 

40 Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle County Station. 

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42 [Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 

43 LaSalle County Station to U.S. NRC, Document control Desk. Subject: Environmental 

44 Non-Routine Event Report for Exelon Generation Company, LLC—LaSalle County Station. 

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2 Operating License Renewal Stage LaSalle County Station, Unit 1 License No. NPF–11, Unit 2 

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6 Safety Analysis Report (UFSAR). Revision 20, April 2014. ADAMS No. ML14113A099.

7 [Exelon] Exelon Generation Company, LLC. 2014c. Letter from M.P. Gallagher, Vice President 

8 License Renewal Projects, Exelon, to Dan Heacock, Facility Evaluation Manager, Illinois 

9 Environmental Protection Agency. Subject: Application for Clean Water Act Section 401 

10 Certification Associated with Renewal of LaSalle County Stations Units 1 and 2 Operating 

11 Licenses. February 4, 2014. In Appendix B of ADAMS No. ML14343A883.

12 [Exelon] Exelon Generation Company, LLC. 2015a. LaSalle County Station, Units 1 and 2, 

13 Annual Radiological Environmental Operating Report, 1 January through 31 December 2014. 

14 May 13, 2015. ADAMS No. ML15141A195.

15 [Exelon] Exelon Generation Company, LLC. 2015b. Letter from M.P. Gallagher, Vice 

16 President, License Renewal Projects, to NRC Document Control Desk. Subject: Response to 

17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

18 Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. 

19 ADAMS No. ML15195A351. 

20 [Exelon] Exelon Generation Company, LLC. 2015c. Letter from M.P. Gallagher, Vice President 

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22 Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 

23 Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: LaSalle 

24 County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental Review 

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27 [Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 

28 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

29 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

30 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

31 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

32 Review Requests for Additional Information. Response to Request for Additional Information

33 MA–07. July 2, 2015. ADAMS No. ML15195A350.

34 [Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 

35 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

36 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

37 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

38 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

39 Review Requests for Additional Information. Response to Request for Additional Information 

40 TE–02. July 2, 2015. ADAMS No. ML15195A380.

41 [Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 

42 License Renewal Projects, Exelon, to NRC Document Control Desk. Subject: Response to 

43 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

44 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 

45 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

46 Review Requests for Additional Information. Response to Request for Additional Information 

47 TE–04. July 2, 2015. ADAMS No. ML15195A382.
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3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 

4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:

5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 

6 Review Requests for Additional Information. Response to Request for Additional Information 

7 TE–05. July 2, 2015. ADAMS No. ML15195A383.

8 [Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice 

9 President - License Renewal Projects to NRC Document Control Desk. Subject: Response to 

10 NRC Request for Additional Information on Severe Accident Mitigation Alternatives Regarding 

11 the LaSalle County Station, Units 1 and 2 License Renewal Application Environmental Review. 

12 Letter RA15–032. May 29, 2015. ADAMS No. ML15149A370.

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14 License Renewal Projects to NRC Document Control Desk. Subject: Revised Response to 

15 Request for Additional Information (RAI) #TR–09 Regarding the LaSalle County Station, Units 1 

16 and 2, License Renewal Application, Environmental Review August 28, 2015. ADAMS 

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20 County Station, Units 1 and 2, License Renewal Application, Applicant’s Environmental 

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28 Exelon Nuclear. 2012. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

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31 Exelon Nuclear. 2013. LaSalle County Station Units 1 and 2, Annual Environmental Operating 

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5-1 

1 5.0 CONCLUSION

2 This draft supplemental environmental impact statement (SEIS) contains the environmental 

3 review of the application for renewed operating licenses for LaSalle County Station, Units 1 

4 and 2 (LSCS), submitted by Exelon Generation Company, LLC (Exelon), as required by the 

5 Code of Federal Regulations (CFR), Part 51 of Title 10 (10 CFR Part 51), the U.S. Nuclear 

6 Regulatory Commission’s (NRC’s) regulations that implement the National Environmental Policy 

7 Act (NEPA). This chapter presents conclusions and recommendations from the site-specific 

8 environmental review of LSCS. Section 5.1 summarizes the environmental impacts of license 

9 renewal; Section 5.2 presents a comparison of the environmental impacts of license renewal 

10 and energy alternatives; and Section 5.3 presents the NRC staff preliminary conclusions and 

11 recommendation. 

12 5.1 Environmental Impacts of License Renewal

13 The NRC staff’s review of site-specific environmental issues in this SEIS leads to the conclusion 

14 that issuing renewed licenses at LSCS would have SMALL to MODERATE impacts for the 

15 Category 2 issues applicable to license renewal at LSCS. The NRC staff considered mitigation

16 measures for each Category 2 issue, as applicable. The NRC staff concluded that no additional 

17 mitigation measure is warranted. 

18 5.2 Comparison of Alternatives

19 In Chapter 4, the staff considered the following alternatives to LSCS license renewal:

20 • no-action alternative,

21 • new nuclear alternative,

22 • integrated gasification combined-cycle alternative,

23 • natural gas combined-cycle (NGCC) alternative,

24 • combination alternative (NGCC, wind, solar), and

25 • purchased power.

26 Based on the summary of environmental impacts provided in Table 2–2, the NRC staff 

27 concluded that the environmental impacts of renewal of the operating licenses for LSCS would 

28 be smaller than those of feasible and commercially viable alternatives. The no-action 

29 alternative, the act of shutting down LSCS on or before its license expiration dates, would have 

30 SMALL environmental impacts with the exception of socioeconomic impacts which would have 

31 SMALL to LARGE environmental impacts. Continued operation of LSCS would have SMALL to 

32 MODERATE environmental impacts for aquatic resources and SMALL environmental impacts in 

33 all other areas. The NRC staff concluded that continued operation of LSCS is the 

34 environmentally preferred alternative.

35 5.3 Recommendation

36 The NRC’s preliminary recommendation is that the adverse environmental impacts of license 

37 renewal for LSCS are not great enough to deny the option of license renewal for 

38 energy-planning decisionmakers. This recommendation is based on the following:
Conclusion

5-2 

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

2 Impact Statement for License Renewal of Nuclear Plants;

3 • the environmental report submitted by Exelon;

4 • the NRC staff’s consultation with Federal, State, local, and Tribal Government

5 agencies;

6 • the NRC staff’s environmental review; and

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

8 process.
6-1 

1 6.0 LIST OF PREPARERS

2 This supplemental environmental impact statement (SEIS) was prepared by members of the 

3 Office of Nuclear Reactor Regulation (NRR) with assistance from other U.S. Nuclear Regulatory 

4 Commission (NRC) organizations and contract support from Pacific Northwest National 

5 Laboratory (PNNL), the Center for Nuclear Waste Regulatory Analyses (CNWRA), a private 

6 contractor and Idoneous Consulting, Inc. (Idoneous). Table 6–1 lists the NRC staff who 

7 contributed to the development of the SEIS. PNNL provides contract support for analysis of

8 transportation impacts of high burnup fuel. CNWRA provides contract support for severe 

9 accident mitigation alternative (SAMA) reviews. Idoneous provides contract support for 

10 technical editing reviews.

11 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.

1 

7-1 

1 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM 

2 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

Ruth Thomas Environmentalists, Inc.

Marvin Lewis Public
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent

7-2 

Name Affiliation

Tom Walsh LaSalle County Board, District 18

Connie Brooks Director, LaSalle County Emergency Management Agency

Nelson Dewey Public

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
8-1 

1 8.0 INDEX

2 A

3 accidents ............................ xxiv, xxix, xxx, 

4 3-8, 3-12, 3-72, 3-100, 4-75, 4-76, 4-77, 

5 4-78, 4-79, 4-80, 4-86, 4-88, 4-91, 4-98, 

6 F-1, F-2, F-8, F-9, F-10, F-11, F-12, 

7 F-13, F-15, F-16, F-17, F-18, F-24, F-25, 

8 F-34, F-37, F-39, F-41, F-46, G-1, G-3, 

9 G-4, G-9, G-11, G-12

10 Advisory Council on Historic 

11 Preservation (ACHP) .....................xxvii, 

12 1-6, 4-60, 4-147, 7-1, B-6, C-3 

13 aesthetic ................ 3-41, 3-101, 4-64, 4-96

14 alternatives.................................... iii, xxiv, 

15 1-4, 2-1, 2-3, 2-4, 2-5, 2-7, 2-16, 2-17, 

16 2-20, 2-21, 2-23, 2-24, 4-1, 4-6, 4-17, 

17 4-18, 4-20, 4-21, 4-29, 4-30, 4-35, 4-36, 

18 4-37, 4-55, 4-59, 4-64, 4-71, 4-72, 4-77, 

19 4-91, 4-97, 4-99, 4-100, 4-102, 4-107, 

20 4-132, 4-133, 4-134, 5-1, 6-2, B-2, C-2, 

21 F-29, F-30, F-43

22 archaeological resources............1-6, 2-4, 

23 3-80, 3-82, 4-62, 4-63, 4-64, 4-126

24 B

25 biocide ................................................ 3-11

26 biological assessment................ C-1, C-2 

27 biota...... 3-10, 3-11, 3-63, 4-35, 4-41, 4-44, 

28 4-45, 4-46, 4-51, 4-52, 4-111, 4-122, 

29 4-124, 4-125

30 boiling water reactor....................2-1, 3-6, 

31 4-80, F-1, G-2 

32 burnup ................. 3-6, 6-3, G-2, G-9, G-11

33 C

34 chronic effects ........ 4-72, 4-73, 4-88, 4-89

35 Clean Air Act (CAA) .................xxvii, 3-25, 

36 3-26, 3-27, 3-112, 4-11, 4-12, 4-15, 

37 4-129, 4-135, 4-137, 4-139, B-3, B-8 

38 closed-cycle cooling.................. 2-8, 2-12, 

39 2-13, 2-14, 3-6, 3-7, 4-24, 4-25, 4-27, 

40 4-28, 4-40, 4-41, 4-44, 4-45, 4-53, 4-117, 

41 4-124

42 Coastal Zone Management Act 

43 (CZMA).......................... 3-22, 3-112, B-4 

44 cold shock .......................................... 4-52

45 consumptive use......................3-40, 4-23, 

46 4-27, 4-28, 4-29, 4-33, 4-52

47 cooling system............................xxii, xxiii, 

48 xxviii, 1-3, 1-5, 2-10, 2-12, 2-13, 2-14, 

49 3-6, 3-7, 3-8, 3-59, 3-72, 3-74, 3-98, 

50 4-19, 4-22, 4-24, 4-31, 4-32, 4-33, 4-37, 

51 4-39, 4-41, 4-44, 4-45, 4-53, 4-54, 4-74, 

52 4-86, 4-87, 4-117, F-6, F-9, F-25, F-26, 

53 F-30, F-37

54 core damage frequency (CDF) .........xxvii, 

55 4-78, 4-79, 4-80, 4-83, 4-84, 4-86, F-1, 

56 F-2, F-3, F-5, F-6, F-7, F-9, F-10, F-11, 

57 F-12, F-13, F-14, F-15, F-17, F-20, F-24, 

58 F-27, F-30, F-31, F-32, F-33, F-37, F-40, 

59 F-42

60 Council on Environmental Quality 

61 (CEQ).......................................xxvii, 1-3, 

62 3-101, 3-112, 4-39, 4-121, 4-137

63 critical habitat...........................3-73, 3-75, 

64 3-76, 3-77, 3-78, 3-79, 4-55, 4-57, 4-58, 

65 B-6, C-1, C-2 

66 cultural resources.......................xxiii, 2-4, 

67 2-26, 3-23, 3-79, 3-82, 4-59, 4-60, 4-61, 

68 4-62, 4-63, 4-64, 4-102, 4-112, 4-126, 

69 4-132, 6-1, 6-2, B-1, B-6 

70 D

71 decommissioning........................ 2-2, 2-3, 

72 4-1, 4-2, 4-26, 4-34, 4-52, 4-57, 4-58, 

73 4-59, 4-62, 4-66, 4-67, 4-68, 4-69, 4-70, 

74 4-98, 4-100, 4-102, 4-103, 4-104, 4-105, 

75 4-106, 4-133, E-1, E-10

76 design-basis accident................ 4-1, 4-76

77 discharges................................. 2-8, 2-10, 

78 2-12, 2-13, 2-14, 3-1, 3-6, 3-7, 3-8, 3-10, 

79 3-11, 3-12, 3-13, 3-14, 3-22, 3-35, 3-36, 

80 3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 

81 3-48, 3-54, 3-60, 3-63, 3-64, 3-65, 3-69, 

82 3-74, 3-75, 3-97, 3-98, 3-99, 3-106, 4-22, 

83 4-23, 4-24, 4-26, 4-27, 4-28, 4-30, 4-32, 

84 4-37, 4-45, 4-46, 4-47, 4-48, 4-49, 4-51, 
Index

8-2 

1 4-52, 4-53, 4-72, 4-73, 4-74, 4-75, 4-85, 

2 4-87, 4-103, 4-116, 4-118, 4-119, 4-120, 

3 4-124, 4-125, 6-2, B-3, B-4, E-4, E-8, 

4 F-29, F-34, F-41, G-7, G-9 

5 dose ...........................................xxxi, 3-13, 

6 3-14, 3-15, 3-16, 3-96, 3-97, 3-106, 4-80, 

7 4-83, 4-101, 4-127, 4-148, B-2, B-5, F-3, 

8 F-19, F-20, F-21, F-22, F-30, F-31, F-39, 

9 F-40, F-42, G-1, G-3, G-4, G-5, G-7, G-8, 

10 G-9, G-10, G-11, G-12

11 dredging ................................... 2-10, 3-45, 

12 3-74, 4-22, 4-26, 4-28, 4-35, 4-37, 4-53, 

13 B-7 

14 E

15 education........................ 3-90, 3-120, 4-65

16 electromagnetic fields ..................... xxviii, 

17 4-72, 4-73, 4-88, 4-89

18 endangered and threatened 

19 species .................................... 1-6, 3-56, 

20 3-74, 3-75, 3-76, 3-77, 3-79, 3-119, 4-46, 

21 4-55, 4-125, 4-136, 4-142, 6-3, B-1, B-6, 

22 C-1, C-2, C-5 

23 Endangered Species Act (ESA).........xxiii, 

24 xxviii, 1-5, 1-6, 1-7, 2-4, 2-30, 3-53, 3-57, 

25 3-73, 3-76, 3-77, 3-79, 3-107, 3-113, 

26 4-55, 4-56, 4-57, 4-58, 4-59, 4-111, 

27 4-135, 4-138, 4-142, B-6, B-8, C-1, C-2, 

28 C-5 

29 entrainment ...............................xxiii, 3-61, 

30 3-70, 3-71, 3-72, 3-74, 3-75, 4-38, 4-39, 

31 4-41, 4-42, 4-43, 4-44, 4-45, 4-52, 4-53, 

32 4-54, 4-124, 4-125, 4-144

33 environmental justice (EJ).................. 2-4, 

34 3-101, 3-108, 4-91, 4-92, 4-102, 4-127, 

35 4-135, 6-1 

36 essential fish habitat (EFH) ...............xxiii, 

37 xxviii, 4-55, 4-58, 6-2, B-6, C-3 

38 eutrophication................ 3-74, 4-37, 4-111

39 evaporative loss...................... 3-40, 4-120

40 Exelon Generation Company 

41 (LLC)...................................... iii, xxi, xxii, 

42 xxiv, xxv, 1-1, 1-5, 1-6, 1-7, 1-8, 2-1, 2-2, 

43 2-3, 2-4, 2-8, 2-9, 2-10, 2-21, 2-26, 2-27, 

44 2-28, 2-30, 3-1, 3-2, 3-3, 3-4, 3-5, 3-6, 

45 3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 3-13, 

46 3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 3-20, 

47 3-21, 3-22, 3-23, 3-24, 3-25, 3-27, 3-29, 

48 3-30, 3-32, 3-33, 3-34, 3-35, 3-36, 3-38, 

49 3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 

50 3-46, 3-47, 3-48, 3-49, 3-51, 3-54, 3-55, 

51 3-56, 3-57, 3-58, 3-59, 3-60, 3-63, 3-64, 

52 3-67, 3-68, 3-69, 3-70, 3-72, 3-74, 3-76, 

53 3-77, 3-78, 3-79, 3-80, 3-82, 3-83, 3-84, 

54 3-85, 3-92, 3-93, 3-94, 3-95, 3-96, 3-97, 

55 3-100, 3-106, 3-113, 3-114, 3-115, 

56 3-116, 3-117, 3-118, 3-120, 3-121, 

57 3-122, 3-125, 3-127, 4-1, 4-3, 4-7, 4-8, 

58 4-22, 4-23, 4-24, 4-25, 4-31, 4-32, 4-33, 

59 4-34, 4-35, 4-38, 4-40, 4-41, 4-44, 4-45, 

60 4-47, 4-49, 4-50, 4-51, 4-52, 4-55, 4-56, 

61 4-60, 4-61, 4-65, 4-69, 4-72, 4-73, 4-74, 

62 4-75, 4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 

63 4-83, 4-86, 4-87, 4-88, 4-92, 4-93, 4-98, 

64 4-101, 4-103, 4-105, 4-113, 4-114, 

65 4-115, 4-118, 4-119, 4-120, 4-124, 

66 4-126, 4-127, 4-128, 4-129, 4-130, 

67 4-132, 4-136, 4-138, 4-139, 4-140, 

68 4-141, 4-143, 4-146, 4-147, 5-1, 5-2, 7-2, 

69 B-7, B-8, C-2, D-1, D-2, E-4, E-8, F-1, 

70 F-2, F-3, F-4, F-5, F-6, F-9, F-10, F-11, 

71 F-12, F-13, F-14, F-15, F-16, F-17, F-18, 

72 F-19, F-20, F-21, F-22, F-23, F-24, F-25, 

73 F-26, F-27, F-28, F-29, F-30, F-31, F-32, 

74 F-37, F-38, F-39, F-40, F-41, F-42, F-43, 

75 F-44, F-45, F-46, G-2, G-4, G-5, G-9, 

76 G-11, G-13

77 F

78 Fish and Wildlife Coordination Act 

79 (FWCA) ..................................... xxix, B-8 

80 G

81 Generic Environmental Impact 

82 Statement (GEIS) .........................iii, xxi, 

83 xxii, xxv, xxix, 1-2, 1-3, 1-4, 1-5, 1-6, 1-7, 

84 1-8, 2-1, 2-2, 2-3, 2-4, 2-17, 2-19, 2-31, 

85 2-32, 3-6, 3-35, 3-86, 3-99, 3-124, 3-125, 

86 4-1, 4-2, 4-6, 4-7, 4-11, 4-20, 4-22, 4-24, 

87 4-31, 4-32, 4-33, 4-34, 4-35, 4-36, 4-37, 

88 4-38, 4-45, 4-52, 4-53, 4-54, 4-55, 4-60, 

89 4-62, 4-65, 4-72, 4-73, 4-75, 4-76, 4-77, 

90 4-91, 4-97, 4-98, 4-99, 4-100, 4-101, 

91 4-102, 4-103, 4-105, 4-106, 4-145, 

92 4-146, 4-147, 5-2, G-2, G-14

93 greenhouse gases..................... 2-7, 2-13, 

94 3-27, 4-8, 4-135, 4-136
Index

8-3

1 groundwater..............................xxiii, 3-13, 

2 3-17, 3-18, 3-41, 3-42, 3-43, 3-46, 3-48, 

3 3-51, 3-91, 3-98, 4-21, 4-24, 4-25, 4-26, 

4 4-27, 4-28, 4-29, 4-30, 4-92, 4-93, 4-102, 

5 4-110, 4-117, 4-118, 4-119, 4-120, 

6 4-121, 4-125, 4-131, 6-2, B-1, E-4

7 H

8 hazardous waste...............................3-18, 

9 4-133, B-5, B-7, B-8

10 heat shock.............4-48, 4-49, 4-51, 4-124

11 high burnup fuel................... 6-1, D-1, D-2

12 high-level waste ...........................xxii, 1-3, 

13 4-97, 4-98, 4-101, G-2

14 I

15 Illinois Department of Natural 

16 Resources................................xxix, 3-1, 

17 3-21, 3-22, 3-23, 3-39, 3-43, 3-52, 3-53, 

18 3-56, 3-57, 3-58, 3-59, 3-60, 3-67, 3-68, 

19 3-69, 3-70, 3-71, 3-72, 3-78, 3-120, 

20 3-121, 4-50, 4-51, 4-74, 4-122, 4-123, 

21 4-125, 4-143, 7-1, B-7, E-5, E-6, E-8, E-9

22 impingement.............................3-70, 3-71, 

23 3-72, 3-74, 3-75, 4-38, 4-39, 4-40, 4-41, 

24 4-42, 4-43, 4-44, 4-45, 4-52, 4-53, 4-54, 

25 4-124, 4-125

26 independent spent fuel storage 

27 installation (ISFSI) ..................3-1, 3-17, 

28 3-19, 4-127

29 Indian tribes ...........................3-81, 3-101, 

30 3-122, 4-91, 4-92

31 invasive species......................4-40, 4-111

32 L

33 LaSalle County Station................... iii, xxi, 

34 xxii, xxiii, xxiv, xxv, xxx, 1-1, 1-2, 1-4, 

35 1-5, 1-6, 1-7, 1-8, 2-1, 2-2, 2-3, 2-4, 2-5, 

36 2-8, 2-9, 2-10, 2-12, 2-13, 2-14, 2-16, 

37 2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-23, 

38 2-24, 2-25, 2-26, 2-30, 3-1, 3-2, 3-3, 3-4, 

39 3-5, 3-6, 3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 

40 3-13, 3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 

41 3-20, 3-21, 3-22, 3-23, 3-24, 3-25, 3-26, 

42 3-27, 3-28, 3-29, 3-30, 3-31, 3-32, 3-33, 

43 3-34, 3-35, 3-36, 3-38, 3-39, 3-40, 3-41, 

44 3-42, 3-43, 3-44, 3-45, 3-46, 3-47, 3-49, 

45 3-50, 3-51, 3-52, 3-53, 3-54, 3-55, 3-56, 

46 3-57, 3-58, 3-59, 3-60, 3-61, 3-62, 3-63, 

47 3-64, 3-65, 3-66, 3-67, 3-68, 3-69, 3-70, 

48 3-71, 3-72, 3-73, 3-74, 3-75, 3-76, 3-77, 

49 3-78, 3-79, 3-80, 3-82, 3-83, 3-84, 3-85, 

50 3-86, 3-87, 3-88, 3-89, 3-90, 3-91, 3-93, 

51 3-94, 3-95, 3-96, 3-97, 3-98, 3-100, 

52 3-101, 3-102, 3-103, 3-104, 3-105, 

53 3-106, 3-110, 3-112, 3-113, 3-114, 

54 3-115, 3-116, 3-117, 3-118, 3-121, 

55 3-122, 3-125, 3-127, 4-1, 4-2, 4-3, 4-4, 

56 4-6, 4-7, 4-8, 4-9, 4-10, 4-11, 4-12, 4-13, 

57 4-16, 4-17, 4-19, 4-20, 4-22, 4-23, 4-24, 

58 4-25, 4-26, 4-27, 4-28, 4-29, 4-31, 4-32, 

59 4-33, 4-34, 4-35, 4-36, 4-37, 4-38, 4-39, 

60 4-40, 4-41, 4-42, 4-43, 4-44, 4-45, 4-46, 

61 4-47, 4-48, 4-49, 4-50, 4-51, 4-52, 4-53, 

62 4-54, 4-55, 4-56, 4-57, 4-58, 4-59, 4-60, 

63 4-61, 4-62, 4-63, 4-65, 4-66, 4-67, 4-68, 

64 4-69, 4-70, 4-71, 4-72, 4-73, 4-74, 4-75, 

65 4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 4-83, 

66 4-84, 4-86, 4-87, 4-88, 4-89, 4-91, 4-92, 

67 4-93, 4-94, 4-95, 4-97, 4-98, 4-100, 

68 4-101, 4-102, 4-103, 4-104, 4-105, 

69 4-106, 4-107, 4-108, 4-109, 4-110, 

70 4-112, 4-113, 4-114, 4-115, 4-116, 

71 4-117, 4-118, 4-119, 4-120, 4-121, 

72 4-122, 4-123, 4-124, 4-125, 4-126, 

73 4-127, 4-128, 4-129, 4-130, 4-131, 

74 4-132, 4-136, 4-138, 4-139, 4-140, 

75 4-141, 4-143, 4-144, 4-147, 5-1, A-1, 

76 B-2, B-6, B-7, B-8, C-1, C-2, C-4, D-1, 

77 D-2, E-1, E-2, E-8, F-1, F-2, F-3, F-4, 

78 F-5, F-6, F-7, F-8, F-9, F-10, F-11, F-12, 

79 F-13, F-14, F-15, F-16, F-17, F-18, F-19, 

80 F-20, F-21, F-22, F-23, F-24, F-25, F-26, 

81 F-27, F-28, F-29, F-30, F-31, F-33, F-37, 

82 F-38, F-40, F-41, F-42, F-43, F-44, F-45, 

83 F-46, G-1, G-2, G-3, G-4, G-6, G-7, G-8, 

84 G-9, G-10, G-11, G-12, G-13

85 long-term dose.................................. F-40

86 low-level waste...............3-17, 4-98, 4-101

87 M

88 Magnuson-Stevens Fishery 

89 Conservation and Management Act 

90 (MSA)................................. xxx, 1-5, 1-6, 

91 3-73, 4-58, 4-145, B-6, B-9, C-3

92 Marine Mammal Protection Act 

93 (MMPA)..................xxx, 3-73, 3-123, B-9
Index

8-4 

1 mitigation.....................................xxii, xxxi, 

2 1-3, 1-4, 4-17, 4-51, 4-53, 4-55, 4-57, 

3 4-63, 4-64, 4-86, 4-87, 4-132, 4-148, 5-1, 

4 D-1, F-9, F-37, F-41

5 mixed waste .............................. 3-13, 3-17

6 Myotis sodalis ................. 3-53, 3-57, 3-75, 

7 3-78, 3-119, 3-126, 3-130, 4-56, 4-57

8 N

9 National Environmental Policy Act 

10 (NEPA)...................................... xxii, xxx, 

11 1-1, 1-7, 2-1, 2-31, 3-73, 3-101, 3-112, 

12 3-124, 4-39, 4-56, 4-61, 4-65, 4-91, 

13 4-109, 4-121, 4-124, 4-137, 4-138, 

14 4-145, 4-146, 5-1, 6-1, 6-2, B-2, C-1, 

15 C-3, C-5, G-12, G-14

16 National Marine Fisheries Service 

17 (NMFS)....................................xxxi, 3-73, 

18 4-55, 4-56, 4-57, 4-58, 4-142, B-6, C-1, 

19 C-2, C-3, C-5 

20 National Pollutant Discharge Elimination 

21 System (NPDES)....................xxxi, 3-10, 

22 3-11, 3-12, 3-18, 3-39, 3-41, 3-42, 3-43, 

23 3-44, 3-45, 3-97, 3-106, 3-108, 3-109, 

24 3-121, 4-23, 4-26, 4-27, 4-28, 4-29, 4-30, 

25 4-32, 4-44, 4-46, 4-47, 4-51, 4-52, 4-53, 

26 4-73, 4-74, 4-75, 4-119, 4-120, 4-134, 

27 4-136, 4-143, B-1, B-4, B-7, B-8, E-4, 

28 E-7 

29 Native American tribes ..................... 3-81, 

30 3-122, 4-91, 4-92

31 no-action alternative..................... iii, xxiv, 

32 2-1, 2-3, 2-4, 2-23, 2-24, 2-26, 4-2, 4-34, 

33 4-39, 4-53, 4-57, 4-93, 4-98, 4-105, 

34 4-121, 4-133, 5-1 

35 nonattainment ........................... 3-26, 4-19

36 O

37 once-through cooling.................. 4-31, 4-38, 

38 4-44, 4-45, 4-117

39 P

40 postulated accidents ................. 4-1, 4-75, 

41 4-76, 4-77, 4-91, G-1 

42 pressurized water reactor................... xxxi 

43 R

44 radioactive nuclides........................... 3-14

45 radon.................................. 3-13, 3-17, G-8 

46 reactor............................ xxi, xxxi, 2-1, 2-2, 

47 2-3, 2-9, 2-10, 2-28, 3-1, 3-6, 3-12, 3-15, 

48 3-17, 3-19, 3-21, 3-24, 3-29, 3-34, 3-43, 

49 3-51, 3-80, 3-97, 3-106, 4-2, 4-52, 4-60, 

50 4-62, 4-65, 4-66, 4-76, 4-77, 4-78, 4-80, 

51 4-83, 4-86, 4-88, 4-93, 4-97, 4-103, 

52 4-108, 4-127, 4-128, 4-132, 4-135, 6-1, 

53 6-3, E-1, E-10, F-3, F-9, F-10, F-12, 

54 F-16, F-18, F-20, F-25, F-26, F-32, F-37, 

55 F-40, G-1, G-2, G-3, G-4, G-7, G-11, 

56 G-12

57 refurbishment............................ 2-2, 3-80, 

58 4-6, 4-28, 4-32, 4-61, 4-65, 4-114, 4-115

59 replacement power ....................xxiv, xxxi, 

60 2-3, 2-5, 2-7, 2-16, 4-29, 4-71, 4-80, 

61 4-93, 4-94, 4-95, 4-100, 4-102, F-3, F-22, 

62 F-39, F-40

63 S

64 scoping..............................iii, xxi, xxii, xxv, 

65 1-1, 1-2, 1-5, 1-7, 4-1, 4-7, 4-20, 4-22, 

66 4-24, 4-31, 4-38, 4-61, 4-65, 4-72, 4-77, 

67 4-98, 4-101, 4-103, 4-113, 5-2, A-1, C-2, 

68 C-3, C-4, D-1 

69 seismic......................................xxxii, 3-29, 

70 3-34, F-4, F-9, F-11, F-12, F-15, F-24, 

71 F-27, F-28

72 severe accident mitigation alternative 

73 (SAMA) ....................................xxiii, xxxi, 

74 4-77, 4-78, 4-80, 4-81, 4-82, 4-83, 4-84, 

75 4-85, 4-86, 4-87, 4-88, 4-145, 6-1, 6-2, 

76 6-3, D-1, F-1, F-2, F-4, F-6, F-10, F-11, 

77 F-13, F-14, F-15, F-16, F-17, F-18, F-19, 

78 F-20, F-21, F-22, F-23, F-24, F-25, F-26, 

79 F-27, F-28, F-29, F-30, F-31, F-32, F-33, 

80 F-34, F-35, F-36, F-37, F-38, F-39, F-41, 

81 F-42, F-43, F-45

82 severe accidents ........................xxiii, xxxi, 

83 4-1, 4-76, 4-77, 4-86, 4-91, 6-1, D-1, F-1, 

84 F-11, F-20, F-37, F-40

85 solid waste.................................xxiv, 2-22, 

86 3-13, 3-16, 3-17, 3-97, 3-106, 4-13, 4-99, 

87 4-102, B-1, E-4 
Index

8-5 

1 spent fuel.............................. xxii, 1-3, 3-6, 

2 3-12, 3-17, 3-19, 3-20, 4-52, 4-101, 

3 4-102, 4-135, E-1, G-1, G-2, G-3, G-4, 

4 G-6, G-7, G-8, G-9, G-11, G-12

5 State Historic Preservation Office 

6 (SHPO)................................... 3-82, 4-60, 

7 4-61, 4-62, 4-147

8 State Pollutant Discharge Elimination 

9 System (SPDES) .............................. B-1 

10 stormwater ............................... 3-36, 3-39, 

11 3-43, 3-44, 3-45, 3-48, 4-26, 4-27, 4-28, 

12 4-29, 4-30, 4-31, 4-32, 4-33, 4-53, 4-119, 

13 4-120, 4-125, B-4 

14 surface runoff............................. 3-7, 3-30, 

15 3-36, 3-39, 3-42, 3-44, 3-60, 4-26, 4-27, 

16 4-28, 4-29, 4-30, 4-32, 4-34, 4-108, 

17 4-110, 4-118, 4-119, 4-120, 4-125, B-4 

18 surface water............................ 3-10, 3-35, 

19 3-36, 3-39, 3-40, 3-41, 3-45, 3-59, 3-98, 

20 4-21, 4-22, 4-23, 4-26, 4-27, 4-28, 4-29, 

21 4-30, 4-33, 4-47, 4-52, 4-74, 4-92, 4-102, 

22 4-110, 4-116, 4-117, 4-118, 4-119, 

23 4-120, 4-125, 4-131, 6-2, B-1, B-4 

24 T

25 taxes ................................. 3-93, 3-95, 4-65

26 transmission line corridors................ 4-6, 

27 4-29, 4-34

28 transmission lines .............................. 2-4, 

29 2-12, 2-13, 2-14, 2-16, 3-1, 3-7, 3-20, 

30 3-21, 3-72, 3-74, 3-78, 3-79, 3-99, 3-100, 

31 4-2, 4-5, 4-6, 4-7, 4-19, 4-20, 4-28, 4-29, 

32 4-30, 4-31, 4-34, 4-36, 4-37, 4-38, 4-53, 

33 4-60, 4-62, 4-63, 4-64, 4-72, 4-75

34 tritium ............................... 3-15, 3-51, 4-25

35 U

36 U.S. Army Corps of Engineers ......... 3-20, 

37 3-35, 3-45, 3-59, 3-127, 4-26, 4-28, 4-29, 

38 4-53, B-4, B-7, B-8 

39 U.S. Department of Energy 

40 (DOE)...............................xxviii, 2-4, 2-8, 

41 2-9, 2-10, 2-11, 2-12, 2-14, 2-15, 2-16, 

42 2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-27, 

43 2-28, 2-29, 2-30, 2-31, 2-33, 3-17, 4-10, 

44 4-14, 4-17, 4-67, 4-68, 4-70, 4-73, 4-137, 

45 4-138, 4-145, 6-3, G-3, G-5, G-7, G-13

46 U.S. Environmental Protection Agency 

47 (EPA) .....................................xxviii, xxix, 

48 1-1, 2-4, 2-12, 2-21, 2-22, 2-23, 2-30, 

49 3-8, 3-10, 3-12, 3-13, 3-14, 3-15, 3-16, 

50 3-25, 3-26, 3-27, 3-28, 3-29, 3-41, 3-42, 

51 3-45, 3-51, 3-66, 3-67, 3-73, 3-93, 3-97, 

52 3-106, 3-108, 3-110, 3-113, 3-115, 

53 3-121, 3-122, 3-125, 3-130, 4-9, 4-11, 

54 4-12, 4-14, 4-15, 4-25, 4-39, 4-43, 4-44, 

55 4-53, 4-73, 4-74, 4-89, 4-90, 4-104, 

56 4-105, 4-107, 4-108, 4-109, 4-114, 

57 4-121, 4-124, 4-127, 4-128, 4-129, 

58 4-130, 4-132, 4-135, 4-136, 4-138, 

59 4-139, 4-140, 4-143, 4-147, 5-1, 7-1, B-1, 

60 B-3, B-4, B-5, B-8, B-9, D-1, E-3, E-4, 

61 E-5, E-8, E-9, F-20

62 U.S. Fish and Wildlife Service 

63 (FWS)................................ xxix, 1-6, 1-7, 

64 2-8, 2-9, 2-14, 2-15, 2-33, 3-53, 3-58, 

65 3-73, 3-74, 3-75, 3-76, 3-77, 3-78, 3-79, 

66 3-107, 3-108, 3-119, 3-126, 4-55, 4-56, 

67 4-57, 4-58, 4-111, 4-136, 4-142, B-6, 

68 C-1, C-2, C-5 

69 uranium................................. xxii, 2-8, 3-6, 

70 3-19, 4-1, 4-3, 4-4, 4-34, 4-35, 4-36, 

71 4-89, 4-100, 4-101, 4-102, 4-104, G-1, 

72 G-2, G-4, G-9 

73 W

74 wastewater................................. 3-1, 3-18, 

75 3-39, 3-42, 3-43, 3-45, 3-91, 4-119, 

76 4-120, 4-123, 4-125, 6-2, E-4, E-7, E-8 

77 Y

78 Yucca Mountain ......................... G-2, G-3, 

79 G-4, G-6, G-7, G-8, G-9, G-11, G-12, 

80 G-13

APPENDIX A 

COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW

A-1 

A. COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW

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 the 

Federal Register (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’s prepared statements pertaining to 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 

using the NRC’s Agencywide Documents Access and Management System (ADAMS). The 

ADAMS Public Electronic Reading Room is accessible at http://www.nrc.gov/readingrm/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 comments received during 

the public meetings, one comment was received 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 and, thus, 

were not responded to by the NRC staff. These commenters, along with their affiliation and the 

source of their comments (i.e., afternoon or evening scoping meeting transcript) are listed in the 

LSCS Scoping Summary Report available at 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 these comments are available in the LSCS

Scoping Summary Report at ADAMS No. ML15147A380.

APPENDIX B 

APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

B-1 

1 B. APPLICABLE LAWS, REGULATIONS, AND OTHER 

2 REQUIREMENTS

3 There are a number of Federal laws and regulations that affect environmental protection, health, 

4 safety, compliance, and consultation at every nuclear power plant licensed by the U.S. Nuclear 

5 Regulatory Commission (NRC). Certain Federal environmental requirements have been 

6 delegated to state authorities for implementation, enforcement, or oversight. Furthermore, 

7 states have also enacted laws to protect public health and safety and the environment. It is the 

8 NRC’s mission, among other things, to ensure that U.S. nuclear power plants are operated in a 

9 manner that provides adequate protection of the public health and safety and of the 

10 environment through compliance with applicable Federal and state laws, regulations, and other 

11 requirements.

12 The requirements that may be applicable to the operation of NRC-licensed nuclear power plants 

13 encompass a broad range of Federal and state laws and regulations, addressing environmental, 

14 historic and cultural, health and safety, transportation, and other concerns. Generally, these 

15 laws and regulations are relevant to how the work involved in performing the proposed action 

16 would be conducted to protect workers, the public, and environmental resources. Some of 

17 these laws and regulations require permits or consultation with other Federal agencies or state, 

18 tribal, or local governments.

19 The Atomic Energy Act of 1954, as amended (AEA) (42 United States Code (U.S.C.) §2011 

20 et seq.), authorizes any state to enter into agreement with the NRC to assume regulatory 

21 authority for certain activities (see 42 U.S.C. §2021). For example, through this Agreement 

22 State Program, Illinois assumed regulatory responsibility over certain byproduct, source, and 

23 quantities of special nuclear materials not sufficient to form a critical mass. The Illinois 

24 Emergency Management Agency (IEMA), Division of Nuclear Safety, administers several 

25 programs to protect citizens and the environment, including: a comprehensive monitoring 

26 system for the 11 operating nuclear power reactors in Illinois, inspection and regulation of 

27 radioactive materials licensees and x-ray machines, and oversight of cleanup efforts at sites 

28 contaminated with radioactive materials (IEMA undated).

29 In addition to carrying out some Federal programs, state legislatures develop their own laws. 

30 State statutes supplement, as well as implement, Federal laws for the protection of air, water 

31 quality, and groundwater. State legislation may address solid waste management programs, 

32 locally rare or endangered species, and historic and cultural resources. 

33 The Clean Water Act (CWA) (33 U.S.C. §1251 et seq.) allows for primary enforcement and 

34 administration through state agencies, provided that the state program is at least as stringent as 

35 the Federal program. The state program must conform to the CWA and to the delegation of 

36 authority for the Federal National Pollutant Discharge Elimination System (NPDES) program 

37 from the U.S. Environmental Protection Agency (EPA) to the state. The primary mechanism to 

38 control water pollution is the requirement for direct dischargers to obtain an NPDES permit or, in 

39 the case of states where the authority has been delegated from the EPA, such as Illinois, a 

40 State Pollutant Discharge Elimination System permit. 

41 One important difference between Federal regulations and certain state regulations is the 

42 definition of waters regulated by the state. Certain state regulations may include underground 

43 waters, whereas the CWA only regulates surface waters. The Illinois Environmental Protection 

44 Agency (IEPA), Bureau of Water, Water Pollution Control, conducts the numerous programs, 

45 including permit programs and surface water quality monitoring and assessment programs, to 

46 protect and enhance the quality of the state’s surface waters (IEPA undated).
Appendix B

B-2

1 Federal and State Requirements

2 LaSalle County Station, Units 1 and 2 (LSCS), are subject to Federal and State requirements. 

3 Table B–1 lists the principal Federal and State laws and regulations that are used or mentioned 

4 in this supplemental environmental impact statement (SEIS) for LSCS.

5 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. §271 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 Endangered Species Act (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.

1 Operating Licenses and Other Permits

2 Table B–2 lists the licenses and permits issued by Federal, state, and local authorities for 

3 activities at LSCS. 
Appendix B

B-7 

1 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 

#750440086 

ID# 099802AA

Issued: 12/11/2000

Expires: 12/11/2005

Renewal application 

submitted 

7/15/2005(a)

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-2006-

185

Issued: 04/16/2006

Expires: 12/31/2015(b)

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

(a) 415 ILCS 5, Title II, “Air Pollution,” Sec. 9.1(f) extends the effective term of the FESOP if the permit holder 

submits a completed application for renewal to the IEPA at least 90 days prior to the permit expiration. Exelon

met this requirement, therefore, the permit is administratively extended (415 ILCS 5/9.1).

(b) Extension of this permit must be filed at least 1 month prior to the permit expiration date (Permit CEMVR-OD-P2006-185, p.2, General Condition #1). LSCS applied for a renewed permit on 11/20/2015. 

Sources: Exelon 2014, 2015
Appendix B

B-8

1 References

2 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

3 production and utilization facilities.”

4 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

5 protection regulations for domestic licensing and related regulatory functions.”

6 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

7 renewal of operating licenses for nuclear power plants.”

8 40 CFR Part 122. Code of Federal Regulations, Title 40, Protection of Environment, Part 122, 

9 “EPA administered permit programs: the National Pollutant Discharge Elimination System.”

10 49 CFR Part 107. Code of Federal Regulations, Title 49, Transportation, Part 107, “Hazardous 

11 materials program procedures.”

12 49 U.S.C. 5108. United States Code, Title 49, Chapter 51, Part 5108, “Registration.”

13 [IAC] Illinois Administrative Code Title 32, Chapter II, Subchapter d, Part 609, “Access to 

14 facilities for treatment, storage, or disposal of low-level radioactive waste.”

15 [IAC] Illinois Administrative Code Title 35, Subtitle B, Chapter I, Subchapter a, Part 201, 

16 “Permits and general provisions.”

17 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter I, Part 309, “Permits.”

18 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter II, Part 391, “Design criteria for 

19 sludge application on land.”

20 [IAC] Illinois Administrative Code Title 35, Subtitle G, Chapter I, Subchapter c, Part 722, 

21 “Standards applicable to generators of hazardous waste.”

22 415 ILCS 5/Tit. II. Illinois Compiled Statutes. Chapter 415, 5, “Environmental Protection Act,” 

23 Title II, “Air pollution.”

24 415 ILCS 5/Tit. III. Illinois Compiled Statutes. Chapter 415, 5, “Environmental Protection Act,” 

25 Title III, “Water pollution.”

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

27 [CAA] Clean Air Act of 1963, as amended. 42 U.S.C. §7401 et seq.

28 [CWA] Clean Water Act of 1977, as amended. 33 U.S.C. §1251 et seq.

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

30 [Exelon] Exelon Generation Company, LLC. 2014. LaSalle County Station, Units 1 and 2 

31 License Renewal Application, Applicant’s Environmental Report. December 9, 2014. 

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

33 ML14343A897.

34 [Exelon] Exelon Generation Company, LLC. 2015. E-mail from N. Ranek, Exelon, to 

35 D. Drucker, NRC. Subject: RE: USACE permit. December 10, 2015. ADAMS 

36 No. ML15363A237.

37 [FWCA] Fish and Wildlife Coordination Act of 1934, as amended. 16 U.S.C. §661 et seq.

38 [IEMA] Illinois Emergency Management Agency, Division of Nuclear Safety. undated. Available 

39 at <http://www.illinois.gov/iema/Pages/default.aspx> (accessed September 3, 2015).
Appendix B

B-9 

1 [IEPA] Illinois Environmental Protection Agency, Bureau of Water. undated. “Water Pollution 

2 Control.” Available at <http://www.epa.state.il.us/water/index-wpc.html> (accessed 

3 3 September 2015). 

4 [MMPA] Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. §1361 et seq.

5 [MSA] Magnuson–Stevens Fishery Conservation and Management Act, as amended. 

6 16 U.S.C. §1801 et seq.

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

8 Pollution Prevention Act of 1990. 42 U.S.C. §13101 et seq.

9 [RCRA] Resource Conservation and Recovery Act of 1976, as amended. 42 U.S.C. §6901 

10 et seq.

11 Wild and Scenic Rivers Act, as amended. 16 U.S.C. §1271 et seq.

1 APPENDIX C 

2 CONSULTATION CORRESPONDENCE

C-1 

1 C. CONSULTATION CORRESPONDENCE

2 Endangered Species Act (ESA) Section 7 Consultation

3 C.1.1. Federal Agency Obligations Under ESA Section 7

4 As a Federal agency, the U.S. Nuclear Regulatory Commission (NRC) must comply with the 

5 Endangered Species Act of 1973, as amended (16 United States Code (U.S.C.) 1531 et seq., 

6 herein referred to as ESA), as part of any action authorized, funded, or carried out by the 

7 agency, such as the proposed agency action that this supplemental environmental impact 

8 statement (SEIS) evaluates whether to issue renewed licenses for the continued operation of 

9 LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years beyond the current 

10 license terms. Under section 7 of the ESA, the NRC must consult with the U.S. Fish and 

11 Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) (referred to jointly as 

12 “the Services” and individually as “Service”), as appropriate, to ensure that the proposed agency 

13 action is not likely to jeopardize the continued existence of any endangered or threatened 

14 species or result in the destruction or adverse modification of designated critical habitat. 

15 The ESA and the regulations that implement ESA section 7 (Title 50 of the Code of Federal 

16 Regulations (50 CFR) Part 402, “Interagency cooperation—Endangered Species Act of 1973, 

17 as amended”) describe the consultation process that Federal agencies must follow in support of 

18 agency actions. As part of this process, the Federal agency shall either request that the 

19 Services provide a list of any listed or proposed species or designated or proposed critical 

20 habitats that may be present in the action area or request that the Services concur with a list of 

21 species and critical habitats that the Federal agency has created (50 CFR 402.12(c)). If it is 

22 determined that any such species or critical habitats may be present, the Federal agency is to 

23 prepare a biological assessment to evaluate the potential effects of the action and determine 

24 whether the species or critical habitat are likely to be adversely affected by the action 

25 (16 U.S.C. 1536(c), 50 CFR 402.12(a)). Further, biological assessments are required for any 

26 agency action that is a “major construction activity” (50 CFR 402.12(b)), which the ESA 

27 regulations define to include major Federal actions significantly affecting the quality of the 

28 human environment under the National Environmental Policy Act of 1969, as amended 

29 (42 U.S.C. 4321 et seq., herein referred to as NEPA) (50 CFR 402.02).

30 Federal agencies may fulfill their obligations to consult with the Services under ESA section 7 

31 and to prepare a biological assessment in conjunction with the interagency cooperation 

32 procedures required by other statutes, including NEPA (50 CFR 402.06(a)). In such cases, the 

33 Federal agency should include the results of the ESA section 7 consultation in the NEPA 

34 document (50 CFR 402.06(b)). Accordingly, Section C.1.2 describes the biological assessment 

35 prepared for the proposed agency action evaluated in this SEIS, and Section C.1.3 describes 

36 the chronology and results of the ESA section 7 consultation.

37 C.1.2. Biological Assessment

38 The NRC considers this SEIS to fulfill its obligation to prepare a biological assessment under 

39 ESA section 7. Accordingly, the NRC did not prepare a separate biological assessment for the 

40 proposed LSCS license renewal.

41 Although the contents of a biological assessment are at the discretion of the Federal agency 

42 (50 CFR 402.12(f)), the ESA regulations suggest information that agencies may consider for 

43 inclusion. The NRC has considered this information in the following sections.
Appendix C

C-2

1 Section 3.8 describes the action area and the Federally listed and proposed species and 

2 designated and proposed critical habitat that have the potential to be present in the action area. 

3 This section includes information pursuant to 50 CFR 402.12(f)(1), (2), and (3).

4 Section 4.8 provides an assessment of the potential effects of the proposed LSCS license 

5 renewal on the species and critical habitat present and the NRC’s effect determinations, which 

6 are consistent with those identified in Section 3.5 of the Endangered Species Consultation 

7 Handbook (FWS and NMFS 1998). The NRC also addresses alternatives to the proposed 

8 action. This section includes information pursuant to 50 CFR 402.12(f)(4) and (5).

9 C.1.3. Chronology of ESA Section 7 Consultation

10 Upon receipt of Exelon’s license renewal application, the NRC staff considered whether any 

11 Federally listed or proposed species or designated or proposed critical habitats may be present 

12 in the action area (as defined at 50 CFR 402.02) for the proposed LSCS license renewal. No 

13 species under the NMFS’s jurisdiction occur within the action area. Therefore, the NRC staff did 

14 not consult with the NMFS. With respect to species under the FWS’s jurisdiction, in late 

15 February 2015, NRC staff filled an online form for an updated protected species list for LSCS on 

16 the FWS’s Environmental Conservation Online System (ECOS), Information for Planning and 

17 Conservation (IPaC). FWS (2015b) responded with a list of threatened and endangered 

18 species that may occur in the project location and may be affected by the Federal action. In 

19 October 2015, NRC staff checked the FWS (2015a) online Illinois County distribution of listed 

20 species for updates. From this, the NRC staff compiled a list of ESA-protected species and 

21 critical habitats in the vicinity of the facility. 

22 In Section 3.8, the NRC staff concludes that no ESA-protected species or critical habitats occur 

23 in the action area, and, in Section 4.8, concludes that the proposed action would have no effect 

24 on any ESA-protected species or critical habitats. The FWS (2013) does not typically provide its 

25 concurrence with “no effect” determinations by Federal agencies. Thus, the ESA does not 

26 require further informal consultation or the initiation of formal consultation with the FWS for the 

27 proposed LSCS license renewal. Nonetheless, because this SEIS constitutes the NRC’s 

28 biological assessment, the NRC staff submitted a copy of the draft SEIS to the FWS for its 

29 review in accordance with 50 CFR 402.12(j).

30 Table C–1 lists the correspondence related to the NRC’s ESA obligations with respect to its 

31 review of the LSCS license renewal application. This table will be updated in the final SEIS, as 

32 applicable, to include correspondence transpiring between the issuance of the draft and final 

33 SEIS.

34 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 

1 Essential Fish Habitat Consultation

2 The NRC must comply with the Magnuson–Stevens Fishery Conservation and Management 

3 Act, as amended (16 U.S.C. §1801 et seq., herein referred to as MSA), for any actions 

4 authorized, funded, or undertaken, or proposed to be authorized, funded, or undertaken that 

5 may adversely affect any essential fish habitat (EFH) identified under the MSA.

6 In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that the NMFS has not designated 

7 EFH under the MSA in the Illinois River and that the proposed LSCS license renewal would 

8 have no effect on EFH. Thus, the MSA does not require the NRC to consult with the NMFS for 

9 the proposed LSCS license renewal.

10 National Historic Preservation Act of 1966 Consultation

11 The National Historic Preservation Act (NHPA) requires Federal agencies to consider the effects 

12 of their undertakings on historic properties and consult with applicable state and Federal 

13 agencies, tribal groups, and individuals and organizations with a demonstrated interest in the

14 undertaking before taking action. Historic properties are defined as resources that are eligible 

15 for listing on the National Register of Historic Places. The historic preservation review process 

16 (Section 106 of the National Historic Preservation Act of 1966, as amended) is outlined in 

17 regulations issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800. 

18 In accordance with 36 CFR 800.8(c), the NRC has elected to use the NEPA process to comply 

19 with its obligations under Section 106 of the NHPA.

20 Table C–2 lists the chronology of consultations and consultation documents related to the NRC 

21 Section 106 review. The NRC staff is required to consult with the noted agencies and 

22 organizations in accordance with the statutes listed above. Table C–2 will be updated in the 

23 final SEIS, as applicable, to include correspondence transpiring between the issuance of the 

24 draft and final SEIS.

25 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
Appendix C

C-4 

Date Sender and Recipient Description ADAMS No. (a)

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

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

(a) These documents can be accessed through the NRC’s ADAMS at http://adams.nrc.gov/wba/.
Appendix C

C-5 

1 References

2 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

3 Part 800, “Protection of historic properties.”

4 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

5 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

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

7 [FWS] U.S. Fish and Wildlife Service. 2013. “Endangered Species Program: What We Do: 

8 Consultations: Frequently Asked Questions.” July 15, 2013. Available at 

9 <http://www.fws.gov/endangered/what-we-do/faq.html#8> (accessed 5 June 2014).

10 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 

11 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 

12 September 30, 2015. Available at http://www.fws.gov/midwest/endangered/lists/illinois-cty.html

13 (accessed 9 October 2015). 

14 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC. Subject: LaSalle 

15 Power Plant License Renewal. List of threatened and endangered species that may occur in 

16 your proposed project location, and/or may be affected by your proposed project. 

17 February 27, 2015. ADAMS No. ML15126A069.

18 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 

19 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 

20 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 

21 Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf> 

22 (accessed 8 July 2013).

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

24 16 U.S.C. §1801 et seq.

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

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

1 APPENDIX D 

2 CHRONOLOGY OF ENVIRONMENTAL 

3 REVIEW CORRESPONDENCE 

D-1 

1 D. CHRONOLOGY OF ENVIRONMENTAL REVIEW 

2 CORRESPONDENCE

3 This appendix contains a chronological listing of correspondence between the U.S. Nuclear 

4 Regulatory Commission (NRC) and external parties as part of its license renewal application 

5 (LRA) environmental review for LaSalle County Station, Units 1 and 2 (LSCS) other than 

6 consultation correspondence and comments received during the scoping process. Consultation 

7 correspondence is listed and discussed in Appendix C of this supplemental environmental 

8 impact statement (SEIS). Scoping comments are provided and addressed in Appendix A of this 

9 SEIS and in the Scoping Summary Report (see Table D–1 below). All documents are available 

10 electronically from the NRC’s Public Electronic Reading Room found on the Internet at the 

11 following Web address: http://www.nrc.gov/reading-rm.html. From this site, the public can gain 

12 access to the NRC’s Agencywide Documents Access and Management System (ADAMS), 

13 which provides text and image files of the NRC’s public documents in ADAMS. The ADAMS 

14 No. for each document is included in the following table. 

15 Environmental Review Correspondence

16 Table D–1 lists the environmental review correspondence, by date, beginning with the request 

17 by Exelon Generation Company, LLC (Exelon) to renew the operating licenses for LSCS. 

18 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
1 APPENDIX E 

2 PROJECTS AND ACTIONS CONSIDERED 

3 

IN CUMULATIVE IMPACTS ANALYSIS 

E-1 

1 E. PROJECTS AND ACTIONS CONSIDERED IN THE CUMULATIVE

2 IMPACTS ANALYSIS

3 Table E–1 identifies actions and projects considered in the U.S. Nuclear Regulatory

4 Commission (NRC) staff’s analysis of cumulative impacts related to the environmental analysis

5 of the continued operation of LaSalle County Station, Units 1 and 2 (LSCS). Potential

6 cumulative impacts associated with these actions and projects are addressed in Section 4.16 of

7 this supplemental environmental impact statement. However, not all actions or projects listed in 

8 this appendix are considered in each resource area because of the uniqueness of the resource 

9 and its geographic area of consideration.

10 Projects and Actions Considered in Cumulative Impacts 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) eastnortheast

Operational (NRC 2015f, 

2015g)

Dresden Nuclear 

Power Station, Unit 1 

Nuclear power plant

(undergoing 

decommissioning)

Grundy County, IL, 

approximately 

23 mi (37 km) eastnortheast

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) westnorthwest. 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) southsoutheast

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 biomassfueled facility with 2 MW 

generating capacity

Grundy County, IL, 

approximately 

17 mi (27 km) 

northwest

Operational (EIA 2015h)

Prairie View 

Renewable Energy

Waste-to-energy biomassfueled facility with 4.8 MW 

generating capacity

Will County, IL, 

approximately 

30 mi (49 km) eastnortheast

Operational (EIA 2015i)
Appendix E

E-3 

Project Name Summary of Project

Location (Relative 

to LSCS) Status

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) northnorthwest

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) northnortheast

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) northnorthwest

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 Generating 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) northnorthwest

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

1 References

2 Agrium. 2015. “Marseilles Solution Storage.” Available at <http://www.agrium.com/en/what3 we-do/locations> (accessed 8 September 2015).

4 CFIndustries. 2015. “Seneca Ammonia Terminal.” Available at 

5 <http://www.cfindustries.com/distribution_seneca-terminal.html> (accessed 18 August 2015).

6 EDP Renewables. 2015. “Illinois/Top Crop Factsheet.” Available at <http://topcrop.edpr7 windfarms.com/wp-content/uploads/sites/14/2014/03/Top-Crop_Fact-Sheet_6.25.15.pdf> 

8 (accessed 7 August 2015). 

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11 Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015).

12 [EIA] U.S. Energy Information Administration. 2015b. “Illinois State Profile and Energy 

13 Estimates, Profile Overview Interactive Map – Blackstone II [Top Cropn II] Wind Farm LLC.” 

14 Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015).

15 [EIA] U.S. Energy Information Administration. 2015c. “Illinois State Profile and Energy 

16 Estimates, Profile Overview Interactive Map – Grand Ridge Solar Farm.” Available at 

17 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).

18 [EIA] U.S. Energy Information Administration. 2015d. “Illinois State Profile and Energy 

19 Estimates, Profile Overview Interactive Map – Minonk Wind Farm.” Available at 

20 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).

21 [EIA] U.S. Energy Information Administration. 2015e. “Illinois State Profile and Energy 

22 Estimates, Profile Overview Interactive Map – Streator Cayuga Ridge South.” Available at 

23 <http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015). 

24 [EIA] U.S. Energy Information Administration. 2015f. “Illinois State Profile and Energy 

25 Estimates, Profile Overview Interactive Map – Peru Hydro.” Available at 

26 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).

27 [EIA] U.S. Energy Information Administration. 2015g. “Illinois State Profile and Energy 

28 Estimates, Profile Overview Interactive Map – Dayton Hydro.” Available at 

29 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).
Appendix E

E-8

1 [EIA] U.S. Energy Information Administration. 2015h. “Illinois State Profile and Energy 

2 Estimates, Profile Overview Interactive Map – Morris Genco LLC.” Available at 

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4 [EIA] U.S. Energy Information Administration. 2015i. “Illinois State Profile and Energy 

5 Estimates, Profile Overview Interactive Map – Prairie View.” Available at 

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7 [EIA] U.S. Energy Information Administration. 2015j. “Illinois State Profile and Energy 

8 Estimates, Profile Overview Interactive Map – Oglesby.” Available at 

9 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).

10 [EIA] U.S. Energy Information Administration. 2015k. “Illinois State Profile and Energy 

11 Estimates, Profile Overview Interactive Map – Morris Cogeneration LLC.” Available at 

12 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).

13 [EIA] U.S. Energy Information Administration. 2015l. “Illinois State Profile and Energy 

14 Estimates, Profile Overview Interactive Map – Kendall County Generation Facility.” Available at 

15 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).

16 [EPA] U.S. Environmental Protection Agency. 2013. “Region 5 Cleanup Sites: Joliet Army 

17 Ammunition Plant.” November 14, 2013. Available at 

18 <http://www.epa.gov/region05/cleanup/jolietarmy/index.html> (accessed 17 August 2015).

19 [EPA] U.S. Environmental Protection Agency. 2015a. “Envirofacts PCS/ICIS search results for 

20 Peru Illinois: Facilities with permits to discharge wastewater to waters of the United States.” 

21 August 14, 2015. Available at <http://oaspub.epa.gov/enviro/PCSICISQuery.list?minx=-

22 89.148560&miny=40.996484&maxx=-88.187256&maxy=4l> (accessed 14 August 2015).

23 [EPA] U.S. Environmental Protection Agency. 2015b. “Envirofacts SDWIS search results for 

24 LaSalle, Illinois: List of Safe Drinking Water Systems.” August 17, 2015. Available at 

25 <http://www.epa.gov/enviro/facts/sdwis/search.html> (accessed 17 August 2015).

26 [Exelon] Exelon Generation Company, LLC. 2014. Applicant’s Environmental Report –

27 Operating License Renewal Stage, LaSalle County Station, Units 1 and 2, License Renewal 

28 Application. Kennett Square, PA: Exelon. December 9, 2014. ADAMS No. ML14343A883.

29 [Glen-Gery] Glen-Gery Corporation. 2015. “Marseilles Plant.” Available at 

30 <http://www.glengery.com/about-us/locations/item/164981492-marseilles-plant/164981492-

31 marseilles-plant> (accessed 1 October 2015).

32 H.B. Fuller. 2015. Available at <http://www.hbfuller.com/north-america> 

33 (accessed 1 October 2015)

34 [IDNR] Illinois Department of Natural Resources. 2015a. “LaSalle Lake State Fish & Wildlife 

35 Area.” Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/LASALLE.HTM> 

36 (accessed 18 August 2015).

37 [IDNR] Illinois Department of Natural Resources. 2015b. “Marseilles State Fish & Wildlife 

38 Area.” Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/MARSEIL.HTM> 

39 (accessed 18 August 2015).

40 [IDNR] Illinois Department of Natural Resources. 2015c. “Illini State Park.” Available at 

41 <http://www.dnr.illinois.gov/Parks/Pages/Illini.aspx> (accessed 18 August 2015).

42 [IDNR] Illinois Department of Natural Resources. 2015d. “Buffalo Rock State Park.” Available 

43 at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/I&M/EAST/BUFFALO/Home.htm>

44 (accessed 18 August 2015).
Appendix E

E-9 

1 [IDNR] Illinois Department of Natural Resources. 2015e. “Gebhard Woods State Park.” 

2 Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/I&M/EAST/

3 GEBHARD/Park.htm> (accessed 18 August 2015).

4 [IDNR] Illinois Department of Natural Resources. 2015f. “Starved Rock State Park.” 2015. 

5 Available at <http://www.dnr.illinois.gov/Parks/Pages/StarvedRock.aspx> (accessed 

6 18 August 2015).

7 [IDNR] Illinois Department of Natural Resources. 2015g. “Matthiessen State Park.” Available 

8 at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/mttindex.htm> (accessed

9 18 August 2015).

10 [IDNR] Illinois Department of Natural Resources. 2015h. “Goose Lake Prairie State Natural 

11 Area.” Available at <http://www.dnr.illinois.gov/Parks/Pages/GooseLakePrairie.aspx> 

12 (accessed 18 August 2015).

13 [IDNR] Illinois Department of Natural Resources. 2015i. “Heidecke Lake State Fish and Wildlife 

14 Area.” Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R2/Heidecke.htm> 

15 (accessed 18 August 2015).

16 [IEPA] Illinois Environmental Protection Agency. 2013. Nonhazardous Solid Waste 

17 Management and Landfill Capacity in Illinois: 2012. Springfield, IL: IEPA. October 2013. 67 p. 

18 Available at <http://www.epa.state.il.us/land/landfill-capacity/2012/report.pdf> (accessed 

19 14 August 2015).

20 [IEPA] Illinois Environmental Protection Agency. 2015. Illinois Landfill Projections of Disposal 

21 Capacity as of January 1, 2015. Springfield, IL: IEPA. July 2015. 48 p. Available at 

22 <http://www.epa.illinois.gov/Assets/iepa/waste-management/landfills/landfill-capacity/landfill23 capacity-report-2015.pdf> (accessed 14 August 2015).

24 [Independence] Independence Tube Corporation. 2015. Available at 

25 <http://www.independencetube.com/history> (accessed 1 October 2015).

26 [ING] Illinois National Guard. undated. “Marseilles Training Area.” Available at

27 <http://www.il.ngb.army.mil/MilitaryAffairs/MTA/> (accessed 18 August 2015).

28 [Invenergy] Invenergy, LLC. 2015a. “Grand Ridge I.” Available at 

29 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeI.aspx> (accessed 

30 14 August 2015). 

31 [Invenergy] Invenergy, LLC. 2015b. “Grand Ridge II – IV.” Available at 

32 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeIIIV.aspx> (accessed 

33 14 August 2015). 

34 [Invenergy] Invenergy, LLC. 2015c. “Grand Ridge IV Storage.” Available at 

35 http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeIVStorage.aspx

36 (accessed 14 August 2015). 

37 [Invenergy] Invenergy, LLC. 2015d. “Grand Ridge Energy Storage.” Available at 

38 http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeEnergyStorage.aspx

39 (accessed 14 August 2015). 

40 [Invenergy] Invenergy, LLC. 2015e. “Grand Ridge Solar.” Available at 

41 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeSolar.aspx> 

42 (accessed 14 August 2015). 

43 Mortenson 2015. “Minonk Wind Farm Project.” Available at 

44 <http://www.mortenson.com/wind/projects/minonk-wind-farm> (accessed 14 August 2015).
Appendix E

E-10

1 [NewsTribune] LaSalle News Tribune. 2014. “Sorting out LaSalle County’s four newest sand 

2 mines.” July 2, 2014. Available at <http://newstrib.com/main.asp?SectionID=

3 2&SubSectionID=232&ArticleID=37558> (accessed 8 September 2015).

4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. “Clinton Power Station, Unit 1.” 

5 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/clin.html> (accessed 

6 11 August 2015).

7 [NRC] U.S. Nuclear Regulatory Commission. 2015b. “Byron Station, Unit 1.” June 30, 2015. 

8 Available at <http://www.nrc.gov/info-finder/reactor/byro1.html> (accessed 11 August 2015).

9 [NRC] U.S. Nuclear Regulatory Commission. 2015c. “Byron Station, Unit 2.” June 30, 2015. 

10 Available at <http://www.nrc.gov/info-finder/reactor/byro2.html> (accessed 11 August 2015).

11 [NRC] U.S. Nuclear Regulatory Commission. 2015d. “Braidwood Station, Unit 1.” 

12 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/brai1.html> (accessed 

13 11 August 2015).

14 [NRC] U.S. Nuclear Regulatory Commission. 2015e. “Braidwood Station, Unit 2.” 

15 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/brai2.html> (accessed 

16 11 August 2015).

17 [NRC] U.S. Nuclear Regulatory Commission. 2015f. “Dresden Nuclear Power Station, Unit 2.” 

18 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/dres2.html> (accessed 

19 11 August 2015).

20 [NRC] U.S. Nuclear Regulatory Commission. 2015g. “Dresden Nuclear Power Station, Unit 3.” 

21 July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/dres3.html> (accessed 

22 11 August 2015).

23 [NRC] U.S. Nuclear Regulatory Commission. 2015h. “Dresden – Unit 1.” June 12, 2015. 

24 Available at <http://www.nrc.gov/info-finder/decommissioning/power-reactor/ 

25 dresden-nuclear-power-station-unit-1.html> (accessed 11 August 2015).

26 [NRC] U.S. Nuclear Regulatory Commission. 2015i. “Quad Cities Nuclear Power Station, 

27 Unit 1.” July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/quad1.html> 

28 (accessed 11 August 2015).

29 [NRC] U.S. Nuclear Regulatory Commission. 2015j. “Quad Cities Nuclear Power Station, 

30 Unit 2.” July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/quad2.html> 

31 (accessed 11 August 2015).

32 PotashCorp 2015. “PotashCorp – Marseilles.” Available at 

33 <http://www.potashcorp.com/about/facilities/phosphate/marseilles/> (accessed 

34 18 August 2015).

35 [SABIC] Saudi Basic Industries Corporation. 2015. “Annual Report 2014.” Available at 

36 <http://www.sabic.com/me/en/newsandmediarelations/publications/overview_annual_report> 

37 (accessed 1 October 2015).

38 [Unimin] Unimin Corporation. 2015. “Unimin Locations.” Available at 

39 <http://www.unimin.com/unimin-locations.cfm> (accessed 9 September 2015.)

40 U.S. Silica 2015. “U.S. Silica Locations – Ottawa IL.” Available at 

41 <http://www.ussilica.com/locations/ottawa-il> (accessed 19 August 2015).

42 Windpower 2015a. “The Windpower - Grand Ridge I Wind Farm.” Available at 

43 <http://www.thewindpower.net/windfarm_en_4022_grand-ridge-i.php> (accessed 

44 7 August 2015).
Appendix E

E-11

1 Windpower 2015b. “The Windpower - Grand Ridge II Wind Farm.” Available at 

2 <http://www.thewindpower.net/windfarm_en_10985_grand-ridge-ii.php> (accessed 

3 7 August 2015).

4 Windpower 2015c. “The Windpower - Grand Ridge III Wind Farm.” Available at 

5 <http://www.thewindpower.net/windfarm_en_10986_grand-ridge-iii.php> (accessed 

6 7 August 2015).

7 Windpower 2015d. “The Windpower - Grand Ridge IV Wind Farm.” Available at 

8 <http://www.thewindpower.net/windfarm_en_18016_grand-ridge-iv.php> (accessed 

9 7 August 2015).

10 Windpower 2015e. “The Windpower – Top Crop Wind Farm.” Available at 

11 <http://www.thewindpower.net/windfarm_en_724_top-crop.php> (accessed 7 August 2015).

12 Windpower 2015f. “The Windpower - Top Crop II Wind Farm.” Available at 

13 <http://www.thewindpower.net/windfarm_en_21266_top-crop-ii.php> (accessed 7 August 2015).

14 Windpower 2015g. “The Windpower – Streator Cayuga Ridge Wind Farm.” Available at 

15 <http://www.thewindpower.net/windfarm_en_10983_streator-cayuga-ridge-wind-farm.php> 

16 (accessed 14 August 2015).

1 APPENDIX F

2 U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

3 SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR LASALLE 

4 COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE 

5 RENEWAL APPLICATION REVIEW 

F-1 

1 F. U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 

2 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 

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

4 LICENSE RENEWAL APPLICATION REVIEW

5 Introduction

6 Exelon Generation Company, LLC (Exelon) submitted a license renewal application for LaSalle 

7 County Station (LSCS), Units 1 and 2. Exelon assessed severe accident mitigation alternatives 

8 (SAMAs) for LSCS in Appendix F of its Environmental Report (ER) (Exelon 2014a). This 

9 assessment was based on the most recent LSCS probabilistic risk assessment (PRA) available 

10 at that time, a plant-specific offsite consequence analysis performed using the MELCOR 

11 Accident Consequence Code System (MACCS2) Version 1.13.1 computer code, and insights 

12 from the LSCS individual plant examination (IPE) and individual plant examination of external 

13 events (IPEEE). In identifying and evaluating potential SAMAs, Exelon considered SAMAs that 

14 addressed the major contributors to core damage frequency (CDF) and release frequency at 

15 LSCS, as well as SAMA candidates from six other boiling water reactor (BWR) plants. Exelon 

16 initially identified 27 potential SAMAs. Then, Exelon reduced the list to 25 unique SAMA 

17 candidates by eliminating SAMAs that are not applicable to LSCS, that have already been 

18 implemented at LSCS, or that have excessive implementation costs. Next, Exelon assessed 

19 the costs and benefits associated with each of the 25 potential SAMAs and concluded that 

20 14 SAMA candidates were potentially cost beneficial at the 95th percentile. Exelon performed 

21 sensitivity analyses on the real discount rate, CDF uncertainty at the 95th percentile, as well as 

22 the offsite consequence parameters, and considered those results in the cost-benefit analysis. 

23 As an additional sensitivity analysis in the ER, Exelon considered the planned installation of a 

24 hardened vent pipe as the base case to provide supplemental information on potentially 

25 cost-beneficial SAMAs following the vent pipe installation. 

26 Based on a review of Exelon’s SAMA assessment and the SAMA audit held on April 7‒8, 2015, 

27 the U.S. Nuclear Regulatory Commission (NRC) staff issued requests for additional information 

28 (RAIs) to Exelon by letter dated April 30, 2015 (NRC 2015). Key questions concerned the 

29 differences between LSCS Units 1 and 2, systems shared between the two units and how these 

30 are modeled in the PRA; the definition and assignment of accident classes; additional details on 

31 the Level 2 and 3 PRA models, including the basis for representative sequences for each 

32 release category; the determination of the frequency of the intact release category; the 

33 identification and screening of candidate SAMAs; the potential for additional SAMAs to mitigate 

34 fire risk; the evaluation of the risk reduction of certain SAMAs; and the basis for the SAMA cost 

35 estimates. By letter dated May 29, 2015, Exelon submitted additional information that included 

36 revisions and a correction, which changed the determination of one SAMA from potentially cost

37 beneficial in the ER to not cost beneficial (Exelon 2015). Exelon’s responses addressed the 

38 NRC staff’s concerns. 

39 The evaluation of the LSCS SAMA analysis is presented below.

40 Estimate of Risk for LSCS

41 Exelon’s estimates of offsite risk at LSCS are summarized in Section F.2.1. The summary is 

42 followed by the NRC staff’s review of Exelon’s risk estimates in Section F.2.2.
Appendix F

F-2

1 F.2.1. Exelon’s Risk Estimates

2 Exelon combined two distinct analyses to form the basis for risk estimates used in the SAMA

3 analysis: (1) the LSCS Level 1 and 2 PRA models and (2) a supplemental analysis of offsite 

4 consequences and economic impacts (essentially a Level 3 PRA model) developed specifically 

5 for the SAMA analysis. The Level 1 model is a significant upgrade and revision of the IPE 

6 Level 1 model, while the Level 2 model is an update of the prior large early release frequency

7 (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 and 2 PRA 

8 models available at the time of the ER, referred to as the LSCS PRA 2013A (or LS213A) model. 

9 This LSCS PRA includes internal flooding but does not include external events.

The LSCS CDF is approximately 2.6×10−6 10 per year (Exelon 2014a). Exelon did not explicitly 

11 include the contribution from external events within the LSCS SAMA risk estimates; however, it 

12 did account for the potential risk reduction benefits associated with external events by 

13 multiplying the estimated benefits for internal events by 5.2. This is discussed further in 

14 Section F.2.2.2.

15 The breakdown of CDF by initiating event is provided in Table F–1. As shown in this table, 

16 events initiated by a turbine trip with bypass, a dual unit loss of offsite power (LOOP), a loss of 

17 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 18 per year, or 

19 25 percent of the total CDF for internal events while anticipated transients without scram 

(ATWS) contributes 4.9×10−7 20 per year, or approximately 19 percent, of the total CDF for each 

21 unit (Exelon 2015).

22 Regarding Level 2 analysis, Exelon stated:

23 The expansion of the LERF model to a full Level 2 model involved a 

24 reassessment of the timing and release categorization of each containment event 

25 tree (CET) end state. To perform this reassessment, MAAP calculations for each 

26 accident class were performed and used to assess the CET end states. Each 

27 CET node was evaluated and updated to reflect the current state of knowledge 

28 regarding Level 2 accident phenomenology. The end state timing was also 

29 updated to reflect the current emergency plan and evacuation time estimates.

30 The Level 2 model uses three general containment event tree (CET) types to assess the 

31 accident progression during a core damage event. CETs contain both phenomenological and 

32 containment system status events. Level 1 core damage sequences are binned into plant 

33 damage states (PDSs) or accident classes, which provide the interface between the Level 1 and 

34 Level 2 CET analysis. Each accident class bin is entered into the CET, resulting in 

35 15 LSCS-specific CETs. The CET is linked directly to the Level 1 event trees, and CET nodes 

36 are evaluated using supporting fault trees (Exelon 2015).

37 The result of the Level 2 PRA is a set of 13 release bins or categories with their respective 

38 frequency and release characteristics. The results of this analysis for LSCS are provided in 

39 Tables F.2–5, F.2–6, F.3–15, F.3–16, and F.3–19 of the ER (Exelon 2014a). The categories 

40 were defined based on the timing of release (three release time ranges) and the magnitude of 

41 release (four release magnitude ranges). One additional release category was included for an 

42 intact containment.

43 For the SAMA analysis, the release category for high magnitude and early timing was divided 

44 into two bins (one with containment isolation and one without). Due to the small release

45 category contributions from six categories, the number of release category bins was reduced to 

46 eight cases. The frequency of each release category was obtained by summing the frequency 

47 of the individual accident progression CET endpoints binned into the release category. Source 
Appendix F

F-3

1 terms were developed for each of the 13 release categories using the results of Modular 

2 Accident Analysis Program (MAAP) Version 4.0.5 computer code calculations (Exelon 2014a).

3 Exelon computed offsite consequences for potential releases of radiological material using the 

4 MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its 

5 determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 

6 site-specific input values for core radionuclide inventory, source term and release 

7 characteristics, site meteorological data, projected population distribution and growth within a 

8 50-mile (80-km) radius, emergency response evacuation modeling, and economic data. The 

9 estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and 

10 occupational dose) is based on guidance in NUREG/BR–0184 (NRC 1997a). In its calculation 

11 for replacement power costs, Exelon accounted for the increased electric power output of LSCS

12 compared to the generic reactor power output presented in NUREG/BR–0184 (NRC 1997a).

13 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 1.1×10−8 4

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% to total CDF.

(c) Column totals may be different because of rounding.

Key: CDF = core damage frequency

Source: Exelon 2014a

14 In the ER, as updated by the response to RAIs (Exelon 2015), Exelon calculated the dose risk 

15 to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to the population within 

16 80 km (50 mi) of the LSCS site. The offsite economic cost risk was calculated to be 

17 $57,700 per year. The breakdown of the population dose risk by containment release category

18 is summarized in Table F–2. The medium magnitude, intermediate release category accounted 

19 for 52 and 62 percent of the population dose risk and offsite economic cost risk, respectively. 
Appendix F

F-4

1 Additionally, two categories (medium magnitude, early release and high magnitude, early 

2 releases for breaks outside containment) together accounted for approximately 41 and 

3 31 percent of the population dose risk and offsite economic cost risk, respectively.

4 F.2.2. Review of Exelon’s Risk Estimates 

5 Exelon’s determination of offsite risk at the LSCS site is based on the following three major 

6 elements of the analysis:

7 (1) Upgraded Level 1 risk model that supersedes the 1994 IPE/IPEEE submittal 

8 (CECO 1994), a new interim fire PRA and the seismic and other external event 

9 analyses of the 1994 IPE/IPEEE submittal;

10 (2) Expanded Level 2 risk model; and

11 (3) MACCS2 analyses performed by Exelon to translate fission product source terms 

12 and release frequencies from the Level 2 PRA model into offsite consequence 

13 measures.

14 The NRC staff reviewed each of these analyses to determine the acceptability of the LSCS risk 

15 estimates for the SAMA analysis.

16 Base Case Mean Population Dose Risk and

17 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
Appendix F

F-5

Release Category Population Dose Risk(a) Offsite Economic Cost Risk

(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) 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

1 F.2.2.1. Internal Events CDF Model

2 Commonwealth Edison Company submitted a combined IPE/IPEEE report to fulfill the 

3 requirements of Generic Letter 88-20 (NRC 1988). This submittal was brief and referred to the 

4 information in NUREG/CR–4832, “Analysis of the LaSalle Unit 2 Nuclear Power Plant: Risk 

5 Methods Integration and Evaluation Program (RMIEP),” which was performed by Sandia 

6 National Laboratories (SNL) and sponsored by the NRC (NRC 1992).

7 The NRC staff’s review of the LSCS IPE is described in its 1995 memorandum (NRC 1995). 

8 Based on its review of the LSCS nuclear power plant IPE submittal and associated 

9 documentation, the NRC staff concluded that the licensee met the intent of Generic Letter 88-20 

10 (NRC 1988). As indicated in the NRC staff review, while the licensee concluded that no 

11 vulnerabilities exist at LSCS, the licensee cited potential improvements identified and discussed 

12 in Volume 3, Part 1 of the RMIEP report. These potential improvements are discussed in 

13 Section F.3.2.

14 There have been numerous revisions to the LSCS PRA since the original 1994 IPE submittal. 

15 A listing of the complete revision history of the LSCS PRA, since the original IPE submittal, was 

16 provided in the ER (Exelon 2014a) and in response to an NRC staff RAI (Exelon 2015). The 

17 PRA revision history is summarized in Table F–3. A comparison of the CDF for internal events 

18 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 year7 19 to 

2.6×10−6 20 per year).

The CDF value from the 1994 IPE (3.4×10−5 21 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 22

 7 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

per year to 4×10−5 1 per year (NRC 1997b). It is recognized that other plants have updated the 

2 values for CDF subsequent to the IPE submittals to reflect modeling and hardware changes.

3 The NRC staff considered the peer review performed for the LSCS PRA and the potential 

4 impact of the review findings on the SAMA evaluation. In the ER, Exelon described the 

5 2008 Boiling Water Reactor Owners Group (BWROG) peer review of the LSCS PRA. The peer 

6 review was indicated to be performed against Addendum B of the then current PRA Standard 

7 (ASME/ANS 2005) with the criteria in Regulatory Guide 1.200, Revision 1 (NRC 2007),

8 including the NRC positions stated in Appendix A of the regulatory guide.

9 Exelon indicated that a PRA update was conducted in 2011 that addressed the majority of 

10 2008 peer review findings and American Society of Mechanical Engineers/American Nuclear 

11 Society (ASME/ANS) PRA standards supporting requirements assigned a Capability Category II 

12 or lower. In ER Table F.2–7 (Exelon 2014a), a summary was presented on the remaining open 

13 supporting requirements identified from the peer review as not meeting Capability Category II 

14 and associated findings, along with an assessment of the impact on the base PRA. Of the six 

15 open supporting requirements, three are related to documentation and three have a relatively 

16 minor impact on the PRA results.

17 The NRC staff has determined that Exelon has demonstrated sufficient internal events PRA 

18 quality by addressing the peer review open findings noted above consistent with the guidance in 

19 Nuclear Energy Institute (NEI) 05-01 (NEI 2005) and that the final resolution of the findings 

20 provides reasonable assurance of a minimal impact on the results of the SAMA analysis. As 

21 previously indicated, the 2013A update to the PRA model (LS213A) is the most recent 

22 evaluation of the risk profile at LSCS for internal events. Exelon indicates this PRA model is 

23 documented as an application-specific model developed for use in the SAMA application. The 

24 current PRA model of record is the 2011A PRA. In the 2013A model, Level 1 logic from the 

25 2011A model was not changed beyond what was required to integrate it with the Level 2 model. 

26 CDF portions of the 2011A and 2013A PRA models are identical. Therefore, updates 

27 performed in the 2011A model to resolve the peer review comments were carried into the 

28 2013A model.

29 Section F.2 of the ER states that the LSCS PRA is a Unit 2 model. Because the units are nearly 

30 identical, the PRA for Unit 2 is considered to be applicable to Unit 1, unless otherwise noted. In 

31 an RAI, the NRC staff asked Exelon to provide a brief description of the differences between the 

32 units, particularly those differences that might impact internal flooding and their impacts on the 

33 unit risk. Exelon responded that the major difference between the units is that the common or 

34 “0” diesel generator is located in the Unit 1 Auxiliary Building and the “0” diesel generator 

35 cooling water pump is located in the Unit 1 Division 1 core standby cooling system (CSCS) 

36 pump room. A flood event that initiates in the Unit 1 Division 1 CSCS pump room does not 

37 propagate from this room, because the surrounding areas are protected by a water tight door 

38 and walls. Exelon indicated that this specific flood scenario is a negligible contributor to risk on 

39 both units because it only impacts one division of CSCS equipment. The Unit 1 CDF

40 contribution from a flood in this area would be slightly higher than Unit 2 because the internal 

41 flood also will impact the Unit 1 residual heat removal service water (RHRSW) pumps. The 

42 Unit 1 RHRSW pumps do not have a function for Unit 2; therefore, loss of these pumps has no 

43 quantitative impacts on the Unit 2 CDF values. Because these flood scenarios have a negligible 

44 CDF impact and a limited impact on plant equipment and operator response, Exelon concluded 

45 there would be no impact on the SAMA evaluation. Exelon also discussed the general plant 

46 layout; internal flooding scenarios; and other asymmetries between units, including the power 

47 supplies for the shared systems. Exelon concluded and the NRC staff agrees that none of the 

48 minor differences has an impact on the SAMA evaluation (Exelon 2015).
Appendix F

F-7

1 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 size-

• specific 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., SLC 

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 Owner’s 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; SLC = standby liquid control

Sources: Exelon 2014a, 2015

1 In response to an NRC staff RAI to identify shared plant systems, or those that could be 

2 cross-tied between units, and to describe the modeling, including the treatment of unavailability 

3 during outages or accidents involving the other unit, Exelon responded that the most significant 

4 piece of equipment shared between units is the common or “0” diesel generator. This diesel 

5 generator is shared between the Unit 1 and Unit 2 Division 1 AC power divisions. Modeling of 

6 this component assumes that it loads automatically to the modeled unit 50 percent of the time 

7 when demanded. The model includes an operator action to manually align the “0” diesel 

8 generator to the modeled unit if the “0” diesel generator does not automatically align to the unit.

9 The model also includes an operator action related to the failure to control the loading of the 

10 diesel generator when it is aligned to both units. Exelon further indicated that the Division 1 and 
Appendix F

F-10

1 Division 2 AC safety-related 4 (kV) buses can be cross-tied between units, which provides a 

2 means to power these buses via the opposite unit offsite power sources. The PRA model 

3 includes the opposite unit offsite power sources, divisional crosstie breakers, and the operator 

4 action necessary to complete this alignment.

5 Other shared systems include the instrument air system, the service water system, and the fire 

6 protection system (FPS). Other than the “0” diesel generator, crosstie breakers, and AC power 

7 supplies, the model does not explicitly consider the impacts of events occurring at one unit that 

8 affect the other unit. Service water and instrument air have the capability to support both units

9 simultaneously during events at both units. With respect to the FPS, it could be aligned to both 

10 units and could be shared for injection. However, the PRA model does not account for this 

11 condition probabilistically. For all shared systems, system unavailability during outages is 

12 considered in the development of system maintenance unavailability basic events.

13 (Exelon 2015).

14 Exelon stated in the ER: 

15 The freeze date for data and plant modifications to be considered for the Level 1 

16 portion of the LS213A model (the 2011 LSCS PRA update, LS211A) is 

17 December 31, 2010. The Emergency Operating Procedures (EOPs) and Severe 

18 Accident Guidelines (SAGs) used in this analysis are those in place as of the 

19 freeze date. No significant plant modifications affecting the risk profile were 

20 performed since the PRA model freeze date. EOP and SAG changes made 

21 since the freeze date were reviewed and incorporated, as necessary, into the 

22 LS213A model. The freeze date for the LS213A model was December 31, 2013.

23 In an RAI, the NRC staff asked Exelon to identify any planned changes or modifications to the 

24 LSCS design (other than the hardened pipe vent), operation, reactor power level, fuel cycle, or 

25 fuel design that might affect the SAMA analysis and describe their expected impacts. In 

26 response, Exelon indicated that the PRA open items tracking database (commonly referred to 

27 as the updating requirement evaluation (URE) database) was reviewed and no outstanding 

28 modifications were identified, with the exception of the necessary plant modifications to meet 

29 the NRC order related to the Near Term Task Force (NTTF) on Fukushima. In particular, these 

30 changes will be made in relation to mitigating strategies (EA-12-049) and the installation of the 

31 hardened pipe containment vent (EA-12-050) (Exelon 2015).

As noted above, the CDF due to ATWS events is 4.9x10-7 per year 32 8 or 19 percent of the total 

33 CDF for internal events. In response to an RAI to discuss the reasons for the relatively high 

34 contribution to the total CDF for internal events, Exelon responded by summarizing the plant 

35 design and operating features that affect the ATWS CDF. The joint human error probabilities 

36 (HEPs) for operator actions that must be performed in short time windows are prevalent in the 

37 ATWS cutsets and are the dominant contributors to CDF from this accident class. Some short 

38 time windows for response are due to the plant design and the lack of a redundant, 

39 high-pressure, high-volume injection system for use in these scenarios. The only high-pressure, 

40 high-volume injection system available in an ATWS is feedwater. Emergency operating 

41 procedures require the high-pressure core spray system to be secured, and the Reactor Core 

42 Isolation Cooling System (RCIC) is a low-volume system. The capability of feedwater is limited 

43 by the rate at which water can be made up to the condenser.

44 Exelon further provided the ATWS CDF and relative contribution to total CDF for a number of 

45 other BWR units. Exelon concluded that, in general, ATWS CDF and the percent contribution of

 8 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

1 ATWS to the CDF vary significantly in the industry, and values can be found both above and

2 below those documented for LSCS (Exelon 2015).

3 The NRC staff noted that Section F.2.3.1 of the ER states “all ATWS events are modeled as a 

4 turbine trip.” In response to an RAI to clarify this statement, Exelon indicated that this statement 

5 was intended to explain the prior statement in the ER that “The turbine trip initiating event is 

6 important to note because it also represents the ATWS frequency.” A better way to describe the 

7 relationship of the turbine trip initiator to the ATWS is that ATWS sequences are a large 

8 contributor to the percentage of CDF attributed to the turbine trip initiating event. Exelon noted 

9 that other initiating events also result in ATWS sequences (Exelon 2015).

10 On the basis of the NRC staff’s evaluation of internal events Level 1 PRA previously described 

11 in this subsection, and Exelon’s response to the NRC staff RAIs, the NRC staff concludes that 

12 the internal events Level 1 PRA model is of sufficient quality to support the SAMA evaluation.

13 F.2.2.2. External Events

14 As previously indicated, the LSCS PRA used for the SAMA analysis does not include external 

15 events. In the absence of such an analysis, Exelon used the results of a new interim fire PRA 

16 and the LSCS IPEEE to identify the highest risk accident sequences and the potential means of 

17 reducing the risk posed by those sequences and to estimate the benefit of potential SAMAs, as 

18 discussed below and in Section F.3.2.

19 The LSCS IPEEE was submitted in April 1994 (CECO 1994) in response to Supplement 4 of 

20 Generic Letter 88-20 (NRC 1991). The submittal cited the external events analysis performed 

21 as part of the NRC-sponsored RMIEP analysis of LSCS (NRC 1992). This analysis included 

22 internal fire, internal flood, and seismic risk assessments, as well as a probabilistic bounding 

23 analysis of the other external hazards (turbine-generated missiles, accidental aircraft impacts, 

24 high winds, transportation and nearby facility accidents, and external flooding). The IPEEE did 

25 not provide a definition of a vulnerability and did not identify any plant improvements resulting 

26 from the fire, seismic, or other external hazard analyses in the IPEEE submittal. The RMIEP 

27 report identified two issues in the fire area that were “provided to the station for disposition.” 

28 These were (1) to install tops on the main control room electrical panels and (2) to institute an 

29 inspection program for penetration seals at the top of switchgear panels. The disposition of 

30 these improvements is discussed in Section F.3. Upon completion of the NRC staff review of 

31 the IPEEE submittal and the supporting RMIEP work, the NRC staff concluded that the 

32 licensee’s IPEEE process is capable of identifying the most likely severe accidents and severe 

33 accident vulnerabilities and the LSCS IPEEE has met the intent of Supplement 4 to Generic 

34 Letter 88-20 (NRC 2000).

35 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 36 per year due to 

37 seismic events. The dominant seismic CDF sequences are listed in Table F–4.

38 The RMIEP seismic PRA used seismic hazard curves available at that time. In the ER, Exelon

39 provided an updated seismic CDF utilizing currently available hazard curves and the conditional 

40 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 41 per year. In response to 

42 an NRC staff RAI to provide more information on the source of these hazard curves, Exelon 

43 indicated that the LSCS hazard curves used in the SAMA analysis are the same as the LSCS 

44 hazard curves included in the response to the NRC’s NTTF on Fukushima Recommendation 2.1

45 (Exelon 2014b, 2015).
Appendix F

F-12

1 Also in response to an NRC staff RAI, Exelon provided the LSCS seismic CDF using the 

2 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 3 per year, based on peak ground 

4 acceleration (Exelon 2015). The NRC staff notes that this seismic CDF is somewhat larger than 

5 that based on the RMIEP conditional core damage probabilities, which can be expected based 

6 on the simplified nature of the GI-199 estimate.

7 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

8 As discussed in Section F.3, Exelon reviewed the dominant sequences listed in Table F–4 to 

9 identify potential SAMAs to mitigate those sequences. The total updated seismic CDF was 

10 used in developing the external events multiplier, as discussed later in this subsection.

11 Seismic walkdowns of LSCS Units 1 and 2 were conducted as part of Exelon’s actions in 

12 response to the 50.54(f) letter (NRC 2012a) requesting information related to the Fukushima 

13 Daiichi NTTF recommendations. Exelon reported that the walkdowns resulted in no adverse

14 anchorage conditions, no adverse seismic spatial interactions, and no other adverse seismic 

15 conditions associated with the items on the seismic walkdown equipment list (SWEL) for either 

16 unit. Similarly, area walk-bys resulted in no adverse seismic conditions associated with other 

17 systems, structures, or components located in the vicinity of the SWEL item(s). The Unit 1 

18 seismic walkdown identified 9 minor conditions while the Unit 2 walkdown identified 10 minor 

19 conditions. Other than these minor conditions, the seismic walkdowns identified no degraded, 

20 nonconforming, or unanalyzed conditions that required either immediate or follow-on action 

21 (Exelon 2012a, 2012b). The NRC staff notes that the agency’s and industry’s response to the 

22 Fukushima Daiichi event includes additional seismic evaluations, as outlined in the 

23 NRC’s 50.54(f) letter dated March 12, 2012 (NRC 2012a).
Appendix F

F-13

1 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 2 per year for 

Unit 1 and 9.4×10-6 3 per year for Unit 2. Table F–5(a) and Table F–5(b) provide a summary of 

4 dominant fire zone CDF results from the LSCS fire PRA. The LSCS IPEEE fire assessment did 

5 not provide a definition of the term “fire vulnerability” nor identify fire-related improvements. As 

6 discussed above, the RMIEP report identified two issues in the fire area that were “provided to 

7 the station for disposition.” These were (1) to install tops on the main control room electrical 

8 panels and (2) to institute an inspection program for penetration seals at the top of switchgear 

9 panels. The disposition of these improvements is discussed in Section F.3.

10 Exelon considers this fire model to be an interim implementation of NUREG/CR–6850 

11 (NRC 2005) because all tasks identified in that document were not completely addressed or

12 implemented in the model. The ER includes a listing of limitations of the current LSCS fire PRA 

13 relative to the tasks of NUREG/CR–6850 (NRC 2005). While some limitations may result in 

14 additional fire scenarios or impact the frequency of existing scenarios, others lead to 

15 conservatisms in the current result. Exelon also notes that the fire PRA utilizes the 

16 2006C internal events PRA, which is not integrated with the current internal events 2013A PRA. 

17 Accordingly, the LSCS fire PRA cannot be used in an integrated analysis with the internal 

18 events PRA. Therefore, the total fire CDF from the analysis was used to determine the external 

19 events multiplier, while the listing of dominant sequences was used to identify potential 

20 cost-beneficial SAMAs as allowed by the industry guidance in NEI 05-01 and further discussed 

21 in Section F.3.

22 The LSCS IPEEE/RMIEP analysis of high winds, tornadoes, external floods, and other external 

23 events (HFO) consisted of a bounding probabilistic assessment. For these events, the 

24 IPEEE/RMIEP concluded that these events were not significant contributors to plant risk and 

25 there were no improvements identified for these events (CECO 1994).

26 The ER discusses each of these external events and provides the following CDF estimates from

27 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 Accidents9 3.0×10-8 per year

External Flooding3 3.0×10-8 per year

Total HFO external events 6.9×10-7 per year

28 The NRC staff considers the use of these CDFs consistent with the guidance provided in 

29 NEI 05-01.

 9 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

1 Table F–5(a). Dominant LSCS Unit 1 Fire Zone 

Contributors to Fire CDF of 8.9×10-6 2 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

3 Table F–5(b). Dominant LSCS Unit 2 Fire Zone 

Contributors to Fire CDF of 9.4×10-6 4 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

5 The NRC staff notes that Exelon’s response to the NRC’s 50.54(f) letter (NRC 2012a) 

6 requesting information related to the Fukushima Daiichi NTTF recommendations includes a 

7 flooding walkdown and a flood hazards reevaluation. As reported in the NRC staff assessment 

8 of the walkdown report (NRC 2014), five deficiencies were identified during the course of the 

9 flooding walkdowns and entered into the corrective action program for tracking and resolution. 

10 Two deficiencies were related to lack of seal or significant rust in penetrations. 

11 Three deficiencies were related to exterior doors’ threshold elevations being lower than the 

12 calculated flood elevation. The NRC staff concluded that the licensee’s implementation of 

13 flooding walkdown methodology meets the intent of the walkdown guidance.

14 In the flood hazards reevaluation (Exelon 2014c), Exelon concluded that “The current design 

15 basis flood does not bound the reevaluated hazard for all applicable flood-causing mechanisms, 

16 combined-effect floods, associated effects, and/or flood event duration parameters.” Because 

17 of this result, Exelon is preparing a fully integrated assessment of these flood hazards. Exelon’s 

18 flood hazard evaluation also includes a summary of interim evaluations and actions taken or 

19 planned to address the instances for which the reevaluated hazard exceeds the design basis. 

20 These issues are being addressed via the ongoing Japan Lessons Learned program and 

21 implementation of the Fukushima Daiichi NTTF recommendations, including NRC Order 

22 EA-12-049, “Order to Modify Licenses with Regard to Requirements for Mitigation Strategies for 

23 Beyond-Design-Basis External Events” (NRC 2012b) and is outside the scope of the SAMA

24 analysis.
Appendix F

F-15

1 As discussed in the ER, there are no up-to-date quantitative external event models for LSCS, so 

2 a multiplier to the internal events PRA results was developed to account for risk contributions

3 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 4 per year. For fire contributions to risk, Exelon 

used a Unit 2 fire CDF of 9.4×10−6 5 per year, discussed above. For HFO events, the value of 

6.9x10-7 6 per year was used.

7 Based on these results, Exelon indicated in the ER that the total CDF for external events is 

approximately 1.08×10−5 8 per year. The total CDF (internal and external events) is then 

approximately 1.33×10−5 9 per year or 5.2 times the CDF for internal events. This multiplier was 

10 used by Exelon in the SAMA analysis to account for the impact of external events on the 

11 calculated benefits.

12 The NRC staff agrees with the applicant’s overall conclusion concerning use of the multiplier to 

13 represent the impact of external events and finds that a multiplier of 5.2 will reasonably account 

14 for external events in the SAMA evaluation.

15 F.2.2.3. Level 2 Fission Product Release Analysis

16 The NRC staff reviewed the general process Exelon used to translate the results of the Level 1 

17 PRA into containment releases, as well as the results of the Level 2 analysis, as described in 

18 the ER (Exelon 2014a) and Exelon’s responses to NRC staff RAIs (Exelon 2015). Exelon 

19 indicates this PRA model is documented as an application-specific model developed for the use 

20 in the SAMA application. The SAMA Level 2 model is an expansion of the prior LERF-only 

21 model to a full Level 2 model.

22 The LSCS Level 1 PRA postulates accident sequences that lead to core damage and potentially 

23 challenge containment. These discrete accident sequences contribute to the CDF, represent 

24 the spectrum of possible challenges to containment, and are placed into functional sequence 

25 groupings (i.e., accident classes and subclasses). The Level 1 accident class bins are then 

26 used as the starting point for the Level 2 PRA CET analysis. Level 1 accident sequences and 

27 resulting cutsets are incorporated directly into the Level 2 analysis to maintain the propagation 

28 of dependencies. The accident classes and subclasses used for the LSCS SAMA analysis are 

29 summarized in ER Table F.2–3 (Exelon 2014a). 

30 The response of containment to core damage is analyzed by a CET for each accident class or 

31 subclass. Each node in the CET is evaluated using the nodal functional fault trees that include 

32 the following considerations:

33 • fault tree models from the Level 1 analysis for the system or function,

34 • any Level 2 limitations in timing, procedures, access, or dependencies,

35 • phenomenological effects, and

36 • environmental impacts on equipment or operator actions.

37 The CETs and the end-state assignments are based on deterministic core melt progression 

38 calculations. Exelon directly links the Level 1 and Level 2 models using a single top logic 

39 structure and quantifies them using the Electric Research Power Institute (EPRI)

40 Computer-Aided Fault Tree Analysis (CAFTA) software. Functional event nodes of the LSCS

41 Level 2 CET are:

42 • Containment Isolated (IS),

43 • RPV Depressurization (OP),
Appendix F

F-16

1 • Core Melt Arrested In-Vessel (RX),

2 • Combustible Gas Venting Initiated (GV),

3 • Containment Remains Intact (CZ),

4 • Injection Established to RPV or Drywell (TD),

5 • Containment Flooding Occurs with Drywell Vent (FC),

6 • Containment Heat Removal (HR),

7 • Containment Vent (CV),

8 • Suppression Pool Bypass (SP),

9 • No Large Containment Failure (NC),

10 • Inventory Makeup Available (MU),

11 • Drywell Intact (DI),

12 • Wetwell (WW) Airspace Failure, and

13 • Reactor Building Effectiveness (RB).

14 As described in ER Section F.2.1 (Exelon 2014a), the release categories were defined based on 

15 the timing and magnitude of releases. Each CET end state represents a radionuclide release to 

16 the environment and is assigned to a release category based on the CET sequence 

17 characteristics, MAAP 4.0.5 results, and a set of release category rules. When MAAP is not 

18 well suited to modeling the accident phenomena associated with a scenario, the scenario is 

19 modeled using conservative estimates (e.g., steam explosion) and insights from other Level 2 

20 PRA models from plants of a similar type.

21 ER Table F.2–6 provides a summary of the LSCS Level 2 release category frequencies for each 

22 of the 15 accident classes or subclasses (Exelon 2014a). For accident class II (accident 

23 sequences involving a loss of containment heat removal with the reactor pressure vessel initially 

24 intact but with post containment failure or venting induced by core damage), the NRC staff 

25 noted in an RAI that the subclasses listed in ER Table F.2–6 were different from those in ER 

26 Table F.2–3. In response, Exelon indicated that the four accident Class II subclasses 

27 (II, IIE, IIV, IIVE), used in the SAMA analysis and included in ER Table F.2–6, represent early 

28 (IIE and IIVE) releases resulting from containment failure and containment venting, respectively; 

29 and non-early (II and IIV) releases resulting from containment failure and containment venting, 

30 respectively. Exelon indicated that for convenience in modeling, the Class II accident classes 

31 are separated into two CETs; one representing the early releases and the other representing

32 intermediate or late (non-early) releases for the containment failure sequences and two similar 

33 ones for venting sequences.

34 Exelon further indicated that the analysis of the timing of a General Emergency declaration has 

35 been evaluated from a probabilistic standpoint for Class II accident scenarios. This evaluation 

36 was performed because of the potential differences in interpretation of the Emergency Action 

37 Levels (EALs) and the probability that the Emergency Director could delay the declaration of the 

38 General Emergency resulting in an early release. Interviews of key emergency response 

39 personnel were performed to determine the best estimate probability that the EALs would be 

40 interpreted such that the General Emergency declaration would be delayed resulting in an early 

41 release as opposed to an intermediate or late release. These interviews consisted of case 

42 studies and a discussion of EALs. The mean probability of failure to declare a General 

43 Emergency with adequate time to take protection measures for the general public prior to 
Appendix F

F-17

1 containment failure is 5 percent or 0.05 based on expert opinions. As a result, the LSCS

2 Level 2 model is structured such that 5 percent of the Class II accidents can result in an “Early” 

3 release, but 95 percent of the Class II accident releases are “non-early” releases.

4 The NRC staff noted in an RAI that ER Table F.2–6, which provides the accident class 

5 frequency contribution to each release category, includes a significant intact containment

6 frequency for the Class II accident subclasses. Class II accidents are normally considered, and 

7 defined in ER Table 2–3, to include sequences where core damage occurs after containment 

8 failure; therefore, there should be no intact containment sequences in Class II. In response to 

9 the RAI to discuss the reasons for these results, Exelon indicated that the “intact” frequency was 

10 obtained from the difference between the CDF for each accident subclass and the total of all the 

11 other release category frequencies. As discussed above, the Class II accident classes are split 

12 into two timing categories; early and non-early and a separate Class II event tree was used for 

13 each category. For the early release class, the total Class II frequency is multiplied by 

14 0.05 when the CDF value is transferred into the Level 2 model. Then, the remaining event tree 

15 nodes are evaluated. This results in truncation of low-frequency sequences leading to the total 

16 of all the release categories being significantly less than the CDF for the Class II subclasses. 

17 To account for this undercounting of Class II releases, Exelon performed a sensitivity study to 

18 determine the impact of this truncation issue. The study was performed by setting the PRA 

19 model basic event related to the General Emergency declaration to 1.0 (instead of 0.95 and 

20 0.05) and requantifying the model. After quantification, the 95 percent and 5 percent split

21 between non-early and early releases were calculated. Because the results demonstrated that 

22 low-frequency sequences had previously been truncated from the final results, Exelon revised 

23 the release category frequencies in its response to the RAI (Exelon 2015, Table F.2–6 revised). 

24 Exelon noted that in the requantified results, there is still a very small unaccounted for frequency 

25 in the Level 2 release results due to additional truncated sequences (approximately 5 percent of 

26 the CDF). This release frequency was divided proportionally among each release category 

27 applicable to that accident class (i.e., Class II, IIE, IIV and IIVE). Exelon indicated that model 

28 truncation is a known source of uncertainty in model results and while the proportional 

29 redistribution of the truncated cutsets does not provide an exact solution to this quantification 

30 issue, it is considered to be a reasonable approximation of how these low contributors should be 

31 allocated to the release categories. Exelon concluded that any deviations between the true 

32 release category allocations of the truncated frequency and those resulting from the proportional 

33 distribution of the frequency would correlate to very small changes to the cost-benefit results; 

34 therefore, no impacts on the conclusions of the SAMA analysis were expected.

35 Exelon noted further that the Class II accident subclasses are the only accident classes where 

36 the CDF values were multiplied by a split fraction before transferring into the Level 2 fault trees. 

37 Therefore, the larger impact observed for this accident class is not applicable to other accident 

38 classes. Other truncation issues would be small and are bounded by the uncertainty in other 

39 inputs. Exelon concluded that the SAMA evaluation would not be impacted by model truncation 

40 issues.

41 The NRC staff agrees, for the purposes of the SAMA analysis, with the Exelon approach to 

42 resolving the issue associated with the original ER analysis of Class II release category 

43 assessment, the conclusions associated with this issue, and the more general issue of impacts 

44 from model truncation. The NRC staff also notes that the issue of how the “intact” release 

45 category frequency was determined for other accident classes would have a very small impact 

46 on the SAMA analysis because major accident class contributors to those other-than-Class II 

47 release categories that are most important to offsite cost risk (Classes IIID, IV, and V) had a 

48 zero “intact” containment frequency in the original ER analysis. Exelon’s revisions to 
Appendix F

F-18

1 the release category frequencies influenced the base case maximum averted cost risk (MACR) 

2 and the cost-benefit analysis for each SAMA (Exelon 2015).

3 Exelon developed the accident progression and associated release characteristics for each 

4 release category by using the results of MAAP Version 4.0.5 computer code calculations. 

5 A MAAP case was identified as a representative case for each of the LSCS Level 2 PRA 

6 release categories based on a review of the Level 2 model cutsets and the dominant types of 

7 scenarios that contribute to the release category. Tables F.3–17 and F.3–18 in the ER provide 

8 a description of the representative cases for each release category and additional information 

9 on the selection of these representative cases (Exelon 2014a).

10 With regard to the selection of representative cases, the NRC staff noted in an RAI that the 

11 dominant contributor to the low-magnitude early (L/E) release category is an ATWS sequence. 

12 This event sequence involves successful depressurization of the reactor pressure vessel (RPV) 

13 with core melt arresting in the vessel and a WW airspace failure. However, the MAAP scenario 

14 stated in ER Tables F.3–17 and F.3–18 to be used as the reference MAAP case for this 

15 sequence was not used to represent this release category. Instead, an alternate MAAP case 

16 with a significantly lower cesium iodide release fraction was stated to have been used. 

17 In response to the RAI, Exelon clarified that the reference MAAP cases in the Level 2 analysis 

18 are not necessarily exact models of the sequence but are instead used along with the Level 2 

19 Release Category rules to assign an appropriate end state to the Level 2 sequence

20 (Exelon 2015). A specific MAAP scenario modeling the dominant sequence for the L/E release 

21 category was not developed for the LSCS SAMA analysis. Rather, expert judgment and review 

22 of similar MAAP cases were used. In-vessel retention would be expected to reduce 

23 radionuclide release fractions significantly because (1) RPV injection post-core damage 

24 prevents further heat up of radionuclides, and (2) the suppression pool is not bypassed 

25 (i.e., fission products are retained in the pool instead of being released directly to the 

26 environment).

27 Exelon noted that while Tables F.3–17 and F.3–18 of the ER indicate that MAAP 

28 case LS130533B was used to represent the L/E release category, MAAP case LS130524B was 

29 actually used to represent the L/E release category indicated in Table F.3–19 of the ER. Use of 

30 the LS130524B scenario in place of the LS130533B scenario is conservative because the 

31 LS130524B release fractions bound the release fractions from the LS130533B scenario, and

32 the LS130524B scenario results in a substantial release of radionuclides several hours earlier

33 than the LS130533B scenario (containment breach in LS130524B vs. containment vent in

34 LS130533B). Both scenarios are containment flooding scenarios. As indicated above, the 

35 dominant release category sequence is an ATWS sequence with a WW airspace failure, 

36 successful RPV depressurization, in-vessel retention, and no suppression pool bypass. The 

37 MAAP case LS130524B represents an ATWS sequence with WW airspace failure, successful 

38 RPV depressurization, core spray available after core damage at vessel breach, and 

39 containment flooding. Use of MAAP scenario LS130524B to model this sequence as a 

40 surrogate for the L/E release category was judged by Exelon to be reasonable since 

41 LS130524B models containment flooding shortly after vessel breach, which mimics the actions 

42 of in-vessel retention by both cooling debris and retaining fission products in the local water 

43 inventory (i.e., scrubbing the release). The NRC staff reviewed the logic of this assessment of 

44 the release characteristics for the L/E release category and concludes that the results are 

45 acceptable for the purposes of the SAMA analysis because the release category is bounding 

46 and conservative.

47 In response to an NRC staff RAI to provide justification for the adequacy of the MAAP release 

48 fraction results from simulation times less than 48 hours past the declaration of a general 
Appendix F

F-19

1 emergency, Exelon discussed each of these MAAP analysis cases. The run times were 

2 considered adequate based on either: (i) results at the end of the run having reached an 

3 obvious plateau and being stable well before the end of the run, or (ii) the core debris being 

4 quenched in a large body of water (the suppression pool) and stabilized at a relatively low 

5 temperature (Exelon 2015). Based on this discussion and the fact that the run times were no 

6 more than 8.5 hours less than the desired run time, the NRC staff agrees that the run times

7 used in Exelon’s SAMA analysis are acceptable.

8 Section F.2.2.11 of the ER, titled "2013A UPGRADE" (Exelon 2014a), states:

9 In order to support the SAMA analysis, the LSCS LERF model was replaced by a 

10 full Level 2 model. The Level 1 logic from the 2011A model was not changed 

11 beyond what was required to integrate it with the Level 2 model. 

12 In response to an NRC staff RAI to describe the changes in the Level 2 model that are 

13 considered upgrades as opposed to updates and to describe the steps taken to assure technical 

14 adequacy of the 2013A Level 2 model, Exelon responded that the word “upgrade” in the 

15 subheading “2013A Upgrade” in Section F.2.2.11 of the ER was intended to have its common 

16 meaning rather than the meaning ascribed by the ASME/ANS PRA Standard (ASME/ANS 2009) 

17 and, in retrospect, was misleading. No change to the LERF analysis or methodology that would 

18 be considered an “upgrade” by the ASME/ANS PRA Standard definition was made during the 

19 model update that created the 2013A model. Accordingly, the 2013A model did not require a 

20 peer review. Exelon further indicated that it has implemented procedures and processes to 

21 assure the technical adequacy of the full power internal event (FPIE) PRA models. 

22 The 2013A model was reviewed and approved in accordance with these procedures and 

23 processes. (Exelon 2015).

24 On the basis of the NRC staff’s review of Exelon’s Level 2 model, the peer review performed on 

25 the 2006C PRA model, the general process Exelon used to translate the results of the Level 1 

26 PRA into containment releases, and Exelon’s responses to NRC staff RAIs, the NRC staff 

27 concludes that the Level 2 PRA as modified in response to the NRC staff RAIs is of sufficient 

28 quality to support the SAMA evaluation.

29 F.2.2.4. Level 3 Offsite Consequence Analysis

30 The NRC staff reviewed Exelon’s process to propagate the containment performance (Level 2) 

31 portion of the PRA to an assessment of offsite consequences (Level 3 PRA). Using the 

32 MACCS2 Version 1.13.1 code, Exelon determined the offsite consequences from potential 

33 releases of radioactive material (Exelon 2014a). In the Level 3 analysis, Exelon combined 

34 release fractions and release categories, discussed in Section F.2.2.3, with the calculated core 

35 inventory to yield potential source terms of radionuclides released to the outside environment. 

36 In response to an NRC staff RAI, Exelon indicated that the LSCS radionuclide inventory was 

37 calculated with ORIGEN Version 2.1 software (Exelon 2015). The NRC staff finds the 

38 MACCS2 and ORIGEN codes to be acceptable for the SAMA evaluation because the codes are 

39 widely used for radiological dose calculations resulting from airborne releases of radioactive 

40 material and radionuclide source term determinations, respectively.

41 Exelon determined radionuclide inventories in the core for a thermal power output of 

42 3489 (MWt). Because the current licensed core power level is 3546 MWt, Exelon applied a 

43 scaling factor of 1.0163 (3546 MWt/3489 MWt = 1.0163) to the radionuclide inventories in the 

44 core presented in Table F.3–11 of the ER (Exelon 2014a). In response to an NRC staff RAI on 

45 the core inventory calculation performed by Exelon for Unit 1, Exelon indicated that the core 

46 inventory calculation was bounding for either unit because time spent during refueling outages 

47 was ignored, an extended cycle length was modeled, and the higher activity value for each 
Appendix F

F-20

1 radioisotope was chosen from two results for the end of the fuel cycle (Exelon 2015). 

2 Furthermore, Exelon reported the core design process ensures that the core inventory of each 

3 unit remains within the single design basis source term. The NRC staff finds these reasons 

4 provide reasonable assurance that actual radionuclide core inventories will be lower than the 

5 radionuclide inventories used in the SAMA analysis. 

6 In response to an NRC staff RAI on planned changes or modifications to the LSCS design, 

7 operation, reactor power level, fuel cycle, or fuel characteristics, Exelon indicated planned 

8 modifications in response to the NRC order arising from the severe accidents at the Fukushima

9 Daiichi nuclear generating station, include mitigating strategies and installing a hardened pipe 

10 containment vent, as required by EA-12-050 and described within the ER. Additionally, Exelon 

11 highlighted its PRA sensitivity study that indicated modifications excluding the hardened pipe 

12 containment vent lowered the CDF by approximately 5 percent (Exelon 2015). The NRC staff 

13 finds the Exelon approach to not take credit for the hardened pipe containment vent or other 

14 modifications in the SAMA analysis to be conservative and acceptable because this treatment 

15 does not cause potentially cost-beneficial SAMAs to be missed. 

16 The NRC staff also requested additional information on the assumptions used to calculate the 

17 inventories of radioactive cobalt, and Exelon described that guidance values for cobalt were 

18 scaled to the core thermal power level of the LSCS units (Exelon 2015). Exelon further 

19 described that one of the cobalt radioisotopes was overestimated and explained the limited 

20 influence of cobalt radioisotopes to the offsite dose and offsite economic costs, which are 

21 dominated by other radionuclides in the core inventory. Because the radionuclide inventories 

22 for cobalt have not been underestimated and the offsite dose and offsite economic cost 

23 components provide the largest contributions to the MACR, the NRC staff agrees that the 

24 inventories for the radioisotopes of cobalt are acceptable for use in the SAMA analysis. 

25 The NRC staff concludes that the current radionuclide inventory calculations in Table F.3–11 of 

26 the ER (Exelon 2014a) are adequate for the estimation of offsite consequences because current 

27 calculations bound the expected radionuclide inventory for either reactor core, and Exelon’s 

28 additional information further justifies the appropriateness of the calculated core inventory.

29 Exelon presented the major input parameter values and assumptions of the offsite consequence 

30 analyses in Appendix F of the ER (Exelon 2014a). Exelon considered site-specific 

31 meteorological data for the calendar years 2010, 2011, and 2012. Meteorological data from 

32 2012 were selected for input to the MACCS2 code because they resulted in the highest 

33 population dose risk and offsite economic cost risk, as described in Section F.3.7 of the ER 

34 (Exelon 2014a). Exelon acquired meteorological data, such as wind speed, wind direction, 

35 atmospheric stability class, and precipitation, from onsite meteorological monitoring stations at 

36 LSCS. Atmospheric mixing heights were obtained from information published by the 

37 U.S. Environmental Protection Agency. The NRC staff finds the applicant’s modeling of 

38 atmospheric conditions and plume dispersion to be acceptable because it is supported by 

39 site-specific annual meteorological data and implemented using widely accepted software. 

40 Because selection of the 2012 meteorological data set resulted in the highest population dose 

41 risk and offsite economic cost risk, the NRC staff accepts its use in the SAMA evaluation.

42 Exelon addressed missing meteorological data either by interpolation or by substitution. For 

43 missing wind-speed data, a power law was used to convert wind speeds measured at different 

44 heights. For data gaps less than 6 hours, interpolation was performed with valid data 

45 immediately before and after the data gap. For data gaps greater than 6 hours, data 

46 substitution was performed with valid data for the same times from either the day before or after 

47 the missing data. Exelon indicated that missing data represented 2 percent or less for each of 

48 the three annual meteorological data sets. Because these percentages of missing data are 
Appendix F

F-21

1 reasonable and the methods used to substitute missing data are common remedies, the NRC 

2 staff finds these approaches to be acceptable for use in the SAMA analysis.

3 Having assessed the sensitivity to different annual meteorological data sets, release heights, 

4 plume heat, and deposition velocities, Exelon found the population dose risk and offsite 

5 economic cost risk either decreased (by as much as 9 percent) or increased slightly (by as 

6 much as 3 percent) due to the alternative inputs. In response to an NRC staff RAI, Exelon 

7 quantified the influence of precipitation on the population dose risk and offsite economic cost 

8 risk. Specifically, Exelon compared the total annual precipitation, population dose risk, and total 

9 offsite economic cost risk for the previously identified calendar years 2010, 2011, and 2012 and 

10 reported that the single year (2012) with the highest population dose risk and total economic 

11 cost risk had the lowest total annual precipitation (Exelon 2015). This observation indicated that 

12 other atmospheric parameters during the modeled release had a greater influence on the 

13 consequence analysis results than the time-integrated precipitation for the entire year. 

14 The NRC staff finds that the selection of the 2012 meteorological data and the other parameter 

15 values for atmospheric dispersion are appropriate for use in the SAMA analysis because 

16 changes to the analysis typically lower expected benefits for individual SAMAs and any small 

17 increases would not change the identification of cost-beneficial SAMAs. As previously 

18 described, the sources of data and models for atmospheric dispersion used by the applicant are 

19 appropriate for calculating consequences from potential airborne releases of radioactive 

20 material.

21 Exelon used the SECPOP2000 Version 3.12 code, projected the expected growth and 

22 distribution of population out to the year 2043, and reported that the total population within 

23 80 km (50 mi) surrounding LSCS is anticipated to increase from 1,546,445 in the year 2000 to 

24 approximately 3,107,897 in the year 2043, as shown in Table F.3–7 of the ER (Exelon 2014a). 

25 From Section F.3.2, as well as Tables F.3–1 and F.3–2 of the ER, Exelon considered census 

26 data from years 2000 and 2010, county growth rates for the year 2030, and transient population 

27 contributions in the projection. The NRC staff finds that the methodology for population 

28 projection is consistent with relevant guidance (NEI 2005). In response to an NRC staff RAI, 

29 Exelon indicated the county population growth rate data were based on projections published by 

30 the State of Illinois (Exelon 2015). The NRC staff verified the appropriateness of selected data 

31 and compared the county growth rate data reported in the ER with the data source and found no 

32 discrepancies.

33 Compared to the previously discussed atmospheric parameters, Exelon reported greater 

34 influences on potential increases to the population dose risk and offsite economic cost risk from 

35 sensitivity assessments of the population within 80 km [50 mi], evacuation speed, intermediate 

36 phase resettlement, wealth values, and other economic inputs and rates. These results were 

37 presented in Section F.7.3 of the ER (Exelon 2014a). In response to an NRC staff RAI, Exelon 

38 confirmed that known SECPOP errors were prevented from influencing the SAMA analysis 

39 results and that manual entry of population and economic data conformed to formatting 

40 requirements (Exelon 2015). The NRC staff also requested supporting justification for spatial 

41 distribution assumptions used in the population projections. Exelon responded by explaining 

42 that the uniform population distribution within a county overestimates the population within 

43 80 km (50 mi) of the LSCS site because many of the highly dense population areas lie outside 

44 the radial distance of 80 km (50 mi), and portions of the highest populated counties that lie 

45 within that radial distance tend to be more rural, more suburban, and much less populated 

46 (Exelon 2015). The NRC staff finds the use of block-level census data to be acceptable 

47 because it is site-specific and more representative than uniformly distributed population 

48 estimates within a county. Because the applicant provided adequate RAI responses on the 

49 population projection, and because an additional analysis was performed by the applicant that 
Appendix F

F-22

1 demonstrated the current approach was conservative, the NRC staff finds the methods, 

2 assumptions, and data used for estimating population to be reasonable and acceptable for 

3 purposes of the SAMA evaluation.

4 For the 16-km (10-mi) emergency planning zone at LSCS, Exelon considered site-specific 

5 information in LSCS evacuation time estimates in its determination of evacuation times, time 

6 delays, and travel speeds. For the baseline Level 3 calculation described in Section F.3.6 of the 

7 ER (Exelon 2014a), Exelon assumed 95 percent of the population within the emergency 

8 planning zone would evacuate with an evacuation speed of 1.6 meters per second (3.6 miles 

9 per hour). In a sensitivity analysis (Exelon 2014a), Exelon reported an increase in the 

10 population dose risk by 5 percent (negligible change to the offsite economic cost risk) due to an 

11 assumed factor-of-2 reduction in the average evacuation speed. Because Exelon used 

12 site-specific information and applied more pessimistic (lower) fractions for the evacuating 

13 population in the emergency planning zone compared to generic values, the NRC staff 

14 concludes that the evacuation assumptions and analyses are reasonable and acceptable for the 

15 purposes of the SAMA analysis at LSCS.

16 Exelon developed economic values using data from the 2007 National Census of Agriculture 

17 and Bureau of Economic Analysis for the counties within the 80-km (50-mi) radius of LSCS. 

18 Exelon updated economic values to a reference timeframe of July 2013 using the consumer 

19 price index from the Bureau of Labor Statistics. As stated in Table F.3–9 of the ER, weighted 

20 average wealth values were $283,637/person for nonfarm wealth and $11,937/hectare for 

21 farmland wealth. The NRC staff considers the values for nonfarm wealth to be reasonable 

22 ranges that would not be expected to result in underestimates of offsite economic cost risk. 

23 In response to an NRC RAI on more recent data from the 2012 National Census of Agriculture, 

24 Exelon assessed the differences and indicated that annual sales of farm products and farm 

25 wealth values from 2012 were typically larger than the 2007 data adjusted to 2013 values by the 

26 consumer price index (Exelon 2015). Overall differences in county data for the fraction of 

27 farmland and fraction of dairy farms were small between the 2012 and 2007 data sets. Having 

28 calculated that the farm-dependent costs comprise 5 percent of the total offsite economic cost 

29 risk, Exelon concluded that incorporation of the data from the 2012 National Census of 

30 Agriculture would not have a significant impact on the SAMA analysis (Exelon 2015). 

31 Farm-dependent costs do not influence the onsite and replacement power components of the 

32 total averted cost risk. Given that estimated benefits at the 95th percentile for SAMA candidates 

33 determined to be not cost beneficial were more than 20 percent below their estimated 

34 implementation costs in Exelon’s revised analysis (Exelon 2015), the NRC staff concludes that 

35 incorporation of 2012 agricultural data would not change the determination of cost-beneficial 

36 SAMAs. Additionally, extrapolation of economic data to the year of the assessment, and not 

37 through the period of extended operation, is consistent with guidance accepted by NRC 

38 (NEI 2005). Because Exelon’s assessment included site-specific data and followed an

39 approach that is consistent with economic guidance, the NRC staff finds the data sources, 

40 adjustments, and considerations made by the applicant in the Level 3 analysis to be acceptable

41 for the SAMA analysis. 

42 Exelon estimated present dollar values based on the internal events PRA at LSCS and applied 

43 a multiplication factor of 5.2 to account for external events. As shown in Section F.4.6 of the ER 

44 (Exelon 2014a), offsite economic costs and offsite exposure costs provided the greatest 

45 contributions to the total dollar value at approximately 74 and 20 percent, respectively. Onsite 

46 cleanup and replacement power costs collectively contributed about 6.5 percent to the baseline 

47 total dollar value for a real discount rate of 3 percent. Onsite exposure costs contributed less 

48 than 1 percent. Section F.6 provides more detailed information on the cost-benefit calculation 
Appendix F

F-23

1 and its evaluation. Changes to the maximum averted cost risk as a result of Exelon’s revised 

2 analysis are presented in Section F.6.1. 

3 Based on its review of Exelon’s submissions, the NRC staff concludes that Exelon’s 

4 methodology to estimate offsite consequences for LSCS provides an acceptable basis to 

5 assess the risk reduction potential for SAMA candidates. Because the conservative modeling 

6 assumptions were included in the assessment and input data were either obtained for the LSCS 

7 site or found to be consistent with guidance values, the NRC staff concludes that data and 

8 modeling assumptions for the Level 3 analysis are appropriate for the SAMA evaluation. 

9 Accordingly, the NRC staff based its assessment of offsite risk on the core damage frequencies, 

10 population doses, and offsite economic costs reported by Exelon.

11 Potential Plant Improvements

12 The process for identifying potential plant improvements, an evaluation of that process, and the 

13 improvements evaluated in detail by Exelon are discussed in this section.

14 F.3.1. Process for Identifying Potential Plant Improvements

15 Exelon identified potential plant improvements (SAMAs) by review of:

16 • LSCS PRA results and PRA group insights;

17 • Potentially cost-effective Phase 2 SAMAs from

18 – Susquehanna Steam Electric Station SAMA Analysis,

19 – Cooper Nuclear Station SAMA Analysis,

20 – Duane Arnold Energy Center SAMA Analysis,

21 – Nine Mile Point Unit 2 SAMA Analysis,

22 – Columbia Generating Station SAMA Analysis, and

23 – Grand Gulf Nuclear Station SAMA Analysis;

24 • LSCS IPE; and

25 • LSCS IPEEE.

26 Exelon indicated that in addition to the “Industry Phase 2 SAMA” review identified above, an 

27 industry-based SAMA list from NEI 05-01 (NEI 2005) was used to help identify the types of

28 changes that could be used to address the areas of concern identified through the LSCS

29 importance list review.

30 Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as 

31 Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the 

32 initial list of SAMAs and eliminated SAMAs from further consideration using the following 

33 criteria:

34 • Applicability to the plant: If a proposed SAMA does not apply to the LSCS design or 

35 has already been implemented, it is not retained.

36 • Implementation cost greater than the screening cost: If the estimated cost of 

37 implementation is greater than the MACR, the SAMA is screened out from further 

38 analysis.
Appendix F

F-24

1 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. 2 10 Table F.6–1 of the ER (Exelon 2014a) 

3 provides a description of each of the 24 Phase II SAMA candidates, which was later revised to 

4 25 Phase II SAMA candidates in Exelon’s revised analysis (Exelon 2015).

5 In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as 

6 discussed in Sections F.4 and F.6. To account for the potential impact of external events, the 

7 estimated benefits based on internal events were multiplied by a factor of 5.2, as discussed in 

8 Section F.2.2.2.

9 F.3.2. Review of Exelon’s Process

10 Exelon’s efforts to identify potential SAMAs focused primarily on areas associated with LSCS

11 specific internal initiating events. The NRC staff reviewed the discussions of the SAMA

12 identification process and the listing of Phase I candidate SAMAs included in the ER.

13 The primary source of candidate SAMAs (22 of a total of 26) was the review of the LSCS

14 Level 1 and Level 2 importance analysis. Four additional SAMAs were identified based on the 

15 review of other BWR cost-effective SAMAs and the review of external events.

16 In the ER, Exelon provided a tabular listing of the Level 1 PRA basic events sorted according to 

17 their risk reduction worth (RRW) (Exelon 2014a). These results were reviewed by Exelon to 

18 identify those potential risk contributors that made a significant contribution to CDF. The RRW 

19 rankings were reviewed down to 1.01. Events below this point would influence the CDF by less 

20 than 1 percent and are judged, by Exelon, to be highly unlikely contributors for the identification 

21 of cost-beneficial enhancements. These basic events, which include component failures, 

22 operator actions, initiating events, and sequence identification markers (or flags), were reviewed 

23 to determine any additional mitigating actions that may need to be considered.

24 In the ER, Exelon provides a discussion of the appropriate importance threshold for the 

25 identification of candidate SAMAs. Guidance in NEI 05-01 indicates that “dominant risk 

26 contributors” should be considered, but a “dominant” risk contributor was not clearly defined. 

27 The NEI 05-01 example uses an RRW of 1.005, which corresponds to the ASME/ANS PRA 

28 Standards (ASME/ANS 2009) definition of risk significant events. A 1 percent change in LSCS

CDF corresponds to approximately 3×10-8 29 per year compared to Regulatory Guide 1.174 

(NRC 2011) definition that anything less than a 1×10-6 30 per year is a “very small change.” It is 

31 noted that an RRW of 1.01 corresponds to a maximum averted cost risk (including external 

32 events) of approximately $56,000, if it is assumed that a SAMA is 100 percent effective in 

33 eliminating the events contribution to CDF and that the total cost-risk is proportional to CDF. 

34 As Exelon indicates, while this is larger than a typically assumed simple procedure change cost 

35 of $50,000, the cost for a procedure change can vary widely depending on complexity of the 

36 change and the systems involved.

37 Considering the above and that (1) the Exelon review of the LSCS importance analyses results 

38 includes, in addition to basic events, accident sequence markers and the individual contributors 

39 to these sequences, which effectively results in looking at risk contributors that are lower than 

40 the RRW threshold; and (2) a separate review of the important contributors to fire and seismic

41 risk for candidate SAMAs was performed, as discussed below, the NRC staff therefore 

42 concludes that Exelon’s use of an RRW threshold of 1.01 for identifying candidate SAMAs from 

43 the Level 1 internal events importance analysis is acceptable.

 10 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

1 In the ER, Exelon also provided tabular listings of the Level 2 PRA basic events for the 

2 combined “High” (H/E-BOC, H/E, H/I), the “Medium Early” (M/E), and the “Medium 

3 Intermediate” (M/I) release categories. These release categories combine to represent over 

4 97 percent of the offsite risk. Exelon used an RRW cutoff of 1.03 when reviewing these basic 

5 events for additional SAMA candidates. While higher than the cutoff used for the Level 1 

6 review, the NRC staff considers this to be acceptable based on their combined contribution to 

7 offsite risk, the release frequency of each is a relatively small part of the total release frequency 

8 (6 to 36 percent), and many of the events are also included in the Level 1 importance review.

9 The NRC staff developed several RAIs during its review of Exelon’s assessment of SAMAs. 

10 The following discussion summarizes these RAIs and Exelon’s responses (Exelon 2015).

11 The NRC staff noted that the turbine trip with bypass initiating event (%TT) is indicated to have 

12 a frequency of 0.8 per year, which implies that a number of turbine trips with bypass have 

13 occurred over the LSCS operating history and asked if any of these occurrences suggest 

14 possible cost-beneficial SAMAs. Exelon responded that the LSCS turbine trip initiating event 

15 frequency is based on a Bayesian update of a generic prior for the period of 2006−2010, which 

16 includes two plant-specific events (one for each unit). Review of the two plant-specific events 

17 used in the Bayesian update indicates that the causes of the events are not related to one 

18 another, and that the site has taken corrective action to address the root causes of the events. 

19 These conditions do not imply any outlier behavior at LSCS or indicate that there is a potential 

20 to identify cost-beneficial SAMAs related to turbine trip events.

21 The NRC staff noted that the discussion of potential SAMAs for a significant number of events 

22 involve water-hammer-induced loss of coolant accidents (LOCAs) related to the generation of a 

23 LOCA signal on high drywell pressures when an actual LOCA does not exist. These events are 

24 mitigated by SAMA 7, and the NRC staff asked Exelon to provide more detail on the water 

25 hammer scenarios and the potential for other SAMAs to mitigate the water-hammer-induced 

26 core damage. In response, Exelon provided a discussion of the four typical cases associated 

27 with water hammer events at LSCS and the potential for other SAMAs. Exelon indicated that 

28 procedures already are in place and credited in the PRA for the operators to prevent residual 

29 heat removal (RHR) starting (and thereby preventing the conditions that led to a water hammer) 

30 for certain scenarios and that installing fast-acting valves (that also would prevent the conditions 

31 that led to water hammer) would be expensive and have some adverse consequences. Exelon 

32 clarified that the “LOOP-delayed LOCA” scenario, that was stated to not have been modeled in 

33 the PRA, is a series of operator actions required to address the automated actuations that occur 

34 in some potential water hammer scenarios. These actions are not explicitly included in the PRA 

35 because the dominant contributors to core damage are considered to be the water hammer 

36 events. Exelon concluded and the NRC staff agrees that including these scenarios in the PRA 

37 model would result in a very small change in plant risk that would impact neither the SAMA 

38 identification process nor the conclusions of the SAMA analysis.

39 The NRC staff noted that for an event involving an emergency core cooling systems (ECCS)

40 room cooling fan failing to run, Exelon indicated that previous LSCS evaluations could not 

41 demonstrate that portable fans would provide adequate cooling for the reactor building corner 

42 rooms when the normal cooling system failed. Exelon was asked to discuss this previous 

43 evaluation and if sufficient cooling can be achieved if the portable fans can provide air 

44 movement through the room coolers, assuming cooling water remains available. In response, 

45 Exelon provided the results of a cost-benefit assessment for a SAMA that utilized portable fans 

46 and ducting to provide air flow through modified room coolers. This assessment assumed that 

47 the previously described commitment to install a reliable hardened pipe containment vent

48 (SAMA 1) had been implemented thereby resulting in a benefit including uncertainty of 

49 approximately $42,000 versus a cost of $475,000.
Appendix F

F-26

1 The NRC staff noted that for an event where the operator fails to recover low-pressure systems, 

2 the discussion indicates that low-pressure systems would not have the power to function. 

3 Exelon was asked to consider the potential for utilizing a fire truck or other portable 

4 self-powered pumps for injection into the containment. Exelon responded that SAMA 1 (reliable 

5 hardened pipe containment vent) with its planned implementation and SAMA 8 (portable 

6 480V AC generator) were determined to be potentially cost beneficial and are proposed in the 

7 ER to address the risk contributions from this event. The combination of these two SAMAs 

8 would help prevent core damage by providing a means for (i) containment heat 

9 removal/pressure control via the reliable hardened pipe containment vent, and (ii) maintaining 

10 RPV injection using the existing FPS connection, by providing long-term support for the safety 

11 relief valves (SRVs) so that they do not reclose and cause RPV re-pressurization. The addition 

12 of a portable self-powered injection pump without SAMA 8 for these contributors would provide 

13 very little additional benefit. There would be no apparent reduction in the implementation cost, 

14 and it would serve the less desirable function of mitigating a core-damage event rather than 

15 preventing core damage. Exelon concluded and the NRC staff agrees that the use of a portable 

16 self-powered pump is not considered to be the optimal choice for mitigating the risk associated 

17 with the cited event.

18 Exelon’s discussion of the review of industry cost-beneficial SAMAs included Grand Gulf 

19 SAMA 59 (to increase operator training to alternate the operation of ECCS pumps for 

20 loss-of-room cooling). Exelon stated that rather than cycling large pumps in scenarios where 

21 the cooling system is lost, a more effective means of maintaining injection with the ECCS

22 pumps is considered to be through the use of portable/temporary cooling alignment, which is 

23 addressed in the LSCS importance list review by SAMA 16. In an RAI, the NRC staff asked 

24 Exelon to consider a SAMA similar to Grand Gulf’s SAMA 59 for rooms where the use of 

25 portable fans may not be effective. In response, Exelon provided a discussion of the various 

26 cases where use of portable fans may not be effective and pointed out that most are mitigated 

27 by the hardened pipe containment vent (SAMA 1), which Exelon has already committed to 

28 installing. Exelon concluded and the NRC staff agrees that once the requirement to install the 

29 reliable hardened pipe containment vent has been implemented, the potential benefit of a 

30 procedure change to cycle the ECCS pumps would be small (Exelon 2015).

31 While the LSCS IPE submittal did not identify any vulnerability, as discussed in the NRC’s IPE 

32 Safety Evaluation Report, the IPE did cite NUREG/CR–4832, Volume 3, Part 1, for insights into 

33 potential improvements to:

34 • Eliminate the sneak circuit in the RCIC isolation logic that results in the RCIC steam 

35 line inboard isolation valve closing when offsite AC power is lost and the appropriate 

36 diesel generator starts.

37 • Change the RCIC room temperature isolation logic so that, in cases where AC power 

38 from Train A has failed but AC power from Train B is available, this isolation logic 

39 does not isolate if no other ECCS is working.

40 • Change the venting procedure so that venting does not result in severe 

41 environments in the reactor building. 

42 In response to an NRC staff RAI to discuss the current status of these potential improvements, 

43 Exelon replied, for the first two improvements listed above, changes have been made so that 

44 the described sneak circuit and the RCIC isolation no longer exist at LSCS. For the third listed 

45 improvement, design improvements were considered and dispositioned at the time of the IPE

46 and no design changes were made at that time to install a hardened pipe containment vent and 

47 prevent the rupture of the containment vent piping. Rather, procedure changes were made to 

48 acknowledge the design deficiency and initiate alignment of alternate injection systems prior to 
Appendix F

F-27

1 containment venting, if at all possible. Changes also were made to procedures to control 

2 containment pressure within a specific range during the venting evolution. The potential for 

3 containment vent path rupture/failure will be addressed through the installation of the reliable 

4 hardened pipe containment vent (SAMA 1) (Exelon 2015).

5 Based on the above discussion, the NRC staff concludes that the set of SAMAs evaluated in the 

6 ER, together with those identified in response to NRC staff RAIs, addresses the major 

7 contributors to the CDF for internal events.

8 As previously discussed, the best available information on seismic and internal fire risk is not 

9 compatible with the internal events risk model. Consequently, the search for SAMA candidates 

10 to mitigate these risks was based on a review of the dominant risk contributors identified and 

11 discussed in Section F.2.2.2.

12 In the ER, Exelon discussed the dominant seismic risk sequences listed in Table F–4

13 (Exelon 2014a), remarked that changes to LSCS as well as reanalysis of important failures has 

14 led to reductions in the significance of several of these sequences, and identified two SAMA

15 candidates that mitigate the seismic risk. The NRC staff notes that the lowest seismic risk 

16 contribution considered has a CDF of approximately 1 percent of the CDF for internal events. 

17 This value corresponds to a benefit of $11,000 if mitigating only the seismic risk, or $56,000 if 

18 mitigating all the other risk contributors. The NRC staff concludes that this is an acceptably low 

19 cutoff for identification of SAMA candidates since it is lower than the typical cost for revising a 

20 procedure.

21 The ER also includes a discussion of the contributors to the dominant fire zone risks listed in 

22 Table F–5(a) and Table F–5(b) (Exelon 2014a). This discussion describes the important fire 

23 scenarios that contribute to the fire CDF for this fire zone, the results of a review of the 

24 important cutsets, and those SAMAs that would reduce the frequency of these fire scenarios. 

25 Exelon’s review and analysis did not identify any unique SAMAs for mitigating these fire 

26 scenarios, but Exelon concluded that three of the previous SAMA internal events would 

27 significantly impact the fire risk.

28 Exelon noted that the largest unreviewed fire zone represents less than 2.5 percent of the 

29 overall total CDF, including external events or about $142,000. In response to an RAI to 

30 consider additional fire zones, Exelon provided a discussion of 15 additional fire zones with 

31 benefits down to $37,500 per unit. This value was based on a procedure development cost of 

32 $50,000 for the first unit and half of that for the second unit, averaging $37,500 per unit. The 

33 contributors to the fire risk for each of these zones were reviewed by Exelon to determine if

34 there were any procedure changes that could be potentially cost beneficial. The results of this

35 review are presented in the RAI response on a zone-by-zone basis. No potentially 

36 cost-beneficial procedure changes were identified (Exelon 2015).

37 In an RAI, the NRC staff noted that fires in the Division 1 and Division 2 essential switchgear 

38 rooms for each unit comprise 60 percent of the total fire CDF and that the only SAMA proposed

39 for mitigating these fires is SAMA 1, installing a reliable hardened pipe containment vent. 

40 SAMA 1 only mitigates the adverse consequences of venting and does not mitigate the direct 

41 impact of the fire. The NRC staff asked Exelon to discuss these fire scenarios and the potential 

42 for other SAMAs to directly mitigate the fire at an earlier stage of the scenario or to mitigate 

43 events in the cutsets other than adverse conditions due to venting. Exelon indicated that 

44 79 percent of the contributions are cases in which injection is initially available but subsequently 

45 fails due to harsh environmental conditions after containment failure. The unavailability of the 

46 containment vent is due to fire-induced failures associated with vent valve support systems, with 

47 the vent valve control cables, or both. The reliable hardened pipe containment vent (SAMA 1) 
Appendix F

F-28

1 eliminates support system requirements and would provide a means of preventing the

2 containment failures and vent path failures that lead to loss of injection capability.

3 Further, for the remaining 21 percent of the contributors, hardware failures result in the 

4 unavailability of injection systems, such that even if a containment vent path were available, 

5 core damage would still occur. The hardware failures are comprised of both failures of the 

6 4 kV AC power sources that support the injection systems and the failures of the injection 

7 system components themselves. LSCS already has the B.5.b pump, which can provide this 

8 RPV injection capability for the long-term scenarios that are characteristic of these contributors, 

9 but it is not currently credited in the PRA model. LSCS operators have been trained to use the 

10 B.5.b pump and the current emergency operating procedures include the B.5.b pump as a 

11 potential alternate RPV injection source that could be used to mitigate the Division 1 and 

12 Division 2 essential switchgear room fire scenarios. In addition, diverse and flexible coping 

13 capability, “FLEX” (NRC 2012b), is intended to provide a separate set of portable makeup 

14 pumps that also could be used to perform this function. While the details of the FLEX changes 

15 are not finalized, they would further improve the capability of LSCS to respond to these types of 

16 scenarios (Exelon 2015).

17 In an RAI, the NRC staff noted that the largest contributing fire scenario to the Auxiliary 

18 Electrical Equipment Room fire risk is a bounding cable fire caused by hot work but no SAMAs 

19 were identified to mitigate this risk. The NRC staff asked Exelon to discuss the potential for a 

20 SAMA to mitigate this risk. In response, Exelon indicated that the transient fire ignition 

21 frequency calculated for a fire compartment considers the potential for ignition due to “hot work” 

22 (cutting, grinding, or welding tasks), among other sources. Based on the 2009 LSCS Fire PRA, 

23 the hot work influence factor for the Auxiliary Electrical Equipment Room is “low,” which is the 

24 lowest possible factor for this area. Procedures already are in place that require a fire watch to 

25 be posted (with portable extinguishes available) and for nearby equipment to be protected when 

26 “hot work” is being performed. These practices already are accounted for in the fire risk 

27 evaluation for the Auxiliary Electrical Equipment Room. Based on these considerations, no 

28 potential SAMAs related to hot work limitations are available that would yield a measurable 

29 change in Auxiliary Electrical Equipment Room fire risk. Because the hot work is associated 

30 with a bounding transient fire scenario that is assumed to lead to failure of all equipment in the 

31 fire compartment, further details are not available to generate additional SAMAs to mitigate the 

32 fire beyond those associated with the initiating event frequency (Exelon 2015).

33 As discussed in Section F.2.2.2, the LSCS IPEEE did not provide a definition of vulnerability 

34 and did not identify any plant improvements resulting from the fire, seismic, or other external 

35 events analyses. However, the RMIEP report identified two issues in the fire area that were 

36 “provided to the station for disposition.” These issues were to install tops on the main control 

37 room electrical panels and to institute an inspection program for penetration seals at the top of 

38 switchgear panels. As discussed in the ER, these improvements were not implemented. Based 

39 on the current understanding of fires in electrical panels, such as those installed at LSCS, and 

40 on industry guidance for the treatment of fire in these panels in NUREG/CR–6285, Exelon

41 concluded that these two identified potential improvements would not be effective in mitigating 

42 the associated fire risk.

43 In an RAI, the NRC staff noted that the RMIEP Summary (NUREG/CR–4832, Volume 1) 

44 identifies the common cause failures (CCF) of the CSCS cooling water pumps as the dominant 

45 events in the seismic risk reduction importance assessment. In response to the RAI to discuss 

46 these events and their importance in the seismic analysis used for SAMA identification, Exelon

47 discussed the internally cited conflicting information in Volume 1 (Summary) and Volume 8 

48 (Seismic Analysis) and concluded that CCFs of the CSCS cooling water pumps do not appear 

49 to drive the results of seismic risk at LSCS. While no SAMAs were generated to directly 
Appendix F

F-29

1 address these specific failures, the consequences of the CCF of the CSCS cooling water pumps 

2 is essentially a long-term SBO, a scenario previously addressed by SAMAs evaluated in the 

3 LSCS analysis. SAMA 27 mitigates cases in which RCIC remains available (not failed by 

4 seismically induced failure of the condensate storage tank), and SAMA 26 reduces the risk

5 associated with scenarios in which RCIC is not available. These SAMAs are considered by 

6 Exelon to adequately address any potential contributions from CCF of the CSCS cooling water 

7 pumps. In addition, Exelon stated that review of the LOOP and dual unit LOOP contributors 

8 from the LSCS 2013A PRA model indicates that CCFs of the CSCS pumps are low contributors 

9 to those scenarios. If, as stated in Section 4.5.1 of NUREG/CR–4832 Volume 1, the dominant

10 seismic sequences are “all seismically induced losses of offsite power and look exactly like the

11 equivalent internally initiated sequences except that no credit is given for recovering offsite

12 power,” then the conclusion would be that CCF of the CSCS cooling water pumps are not

13 significant contributors to seismic risk. Exelon also noted that subsequent to the completion of 

14 the RMIEP analysis, Commonwealth Edison (now Exelon) performed a review of that study and 

15 largely used the results as the basis for the combined IPE and IPEEE submittal. Exelon 

16 indicated that one of the conclusions of the review effort, documented in the executive summary 

17 of the April 1994 IPE/IPEEE (CECO 1994), is that Commonwealth Edison considered the “Beta 

18 factor” CCF process used in the RMEIP analysis to be overly conservative (Exelon 2015). As 

19 stated earlier, the Exelon IPEEE analysis of other external hazards (high winds, tornadoes, 

20 external floods, and other external events) did not identify opportunities for improvements for 

21 these events.

22 As discussed in Section F.2.2.2, the LSCS external flooding design and capability was 

23 assessed in the engineering walkdowns and flood hazard reevaluation required for the response 

24 to the Fukushima NTTF’s Recommendation 2.3 (NRC 2012a). The walkdown identified 

25 deficiencies that are being addressed through the LSCS corrective action program, while the 

26 results of the hazard reevaluation led to the requirement for the performance of a full external 

27 flooding integrated assessment, now underway. These issues are being addressed via the 

28 ongoing Japan Lessons Learned program and implementation of the Fukushima Daiichi NTTF 

29 recommendations, including NRC Order EA-12-049, “Order to Modify Licenses with Regard to 

30 Requirements for Mitigation Strategies for Beyond-Design-Basis External Events” (NRC 2012b). 

31 The NRC staff concludes that for the purposes of SAMA identification, external flooding is 

32 adequately addressed. Since external flooding is not a significant contributor to plant risk, a 

33 cost-beneficial SAMA is not likely to be identified. Additionally, the ongoing programs described 

34 above provide improvements to the external flooding risk that are more conservative than a 

35 cost-beneficial SAMA.

36 Regarding the prevention of water hammer events, the NRC staff questioned Exelon about 

37 potentially lower cost alternatives to SAMA 7 (alter the LOCA signal logic to require both high 

38 drywell pressure and low RPV water level for initiation of a LOCA signal). In non-LOCA 

39 transient scenarios, the heat load rejected to the containment is sufficient to prompt the initiation 

40 of suppression pool cooling (SPC), but even with SPC in operation, the drywell pressure will 

41 reach 2 psig and a LOCA signal will register. If a consequential LOOP occurs with the LOCA 

42 signal, the RHR discharge line can drain to the suppression pool in the ~45 seconds between 

43 RHR pump load shed and the time it is reloaded on the diesel-backed bus, which sets up a 

44 water hammer condition in the voided pipe. The lower cost alternative would be to change the 

45 suppression pool cooling operating procedures or practices to reduce the chances of the 2 psi 

46 high drywell pressure signal being reached for normal transients. In response, Exelon indicated 

47 that no changes to the LSCS operating procedures would reduce the chance that the 2 psig 

48 high drywell pressure signal would be reached in the scenarios of interest. The issue is that in 

49 the scenarios of interest (initiators that result in the loss of containment cooling), SPC does not 

50 have the capacity to remove enough heat to prevent the containment pressure from exceeding 
Appendix F

F-30

1 2 psig without venting containment in accordance with normal operating procedures to maintain 

2 containment pressure less than the LOCA signal initiation pressure setpoint. Any changes to 

3 the suppression pool cooling system operating procedures intended to increase the time 

4 available between the initiating event and the 2 psig high drywell pressure signal would have a 

5 very small impact on risk. Human error probabilities (HEPs) are influenced by a number of 

6 factors, including time available for response. In this case, the HEP for the operator action to 

7 vent the containment to prevent the high drywell signal is not significantly impacted by timing 

8 considerations, and increasing the time available to the operators would correlate to very small 

9 averted cost-risk values. The more difficult mitigating actions for water hammer scenarios are 

10 associated with the approximate 20-second time interval between the occurrence of the loss of 

11 the running pump on the LOCA-induced LOOP and the time when the pumps are automatically 

12 started and reloaded onto the emergency bus. This short time period is not associated with the 

13 operation of suppression pool cooling; therefore, a SAMA would have no benefit to these 

14 scenarios. In these scenarios, the operators must put the pump in pull-to-lock to prevent restart 

15 and then fill and vent the system to ensure a water hammer does not occur (Exelon 2015).

16 The NRC staff notes that the set of SAMAs submitted is not all-inclusive because additional, 

17 possibly even less expensive, alternatives can always be postulated. However, the NRC staff 

18 concludes that the benefits of any additional modifications are unlikely to exceed the benefits of 

19 the modifications evaluated and that the alternative improvements would not likely cost less 

20 than the least expensive alternatives evaluated, when the subsidiary costs associated with 

21 maintenance, procedures, and training are considered.

22 The NRC staff concludes that Exelon used a systematic and comprehensive process for 

23 identifying potential plant improvements for LSCS, and that the set of potential plant 

24 improvements identified by Exelon is reasonably comprehensive and, therefore, acceptable. 

25 This search included reviewing insights from the plant-specific risk studies, and reviewing plant 

26 improvements considered in previous SAMA analyses. While explicit treatment of external 

27 events in the SAMA identification process was limited, the NRC staff has determined that the 

28 prior implementation of plant modifications and the absence of external event vulnerabilities 

29 reasonably justify examining primarily the internal events risk results for this purpose.

30 Risk Reduction Potential of Plant Improvements

31 Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II 

32 evaluation in a revised analysis (Exelon 2015). The SAMA evaluations were generally 

33 performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit 

34 of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be 

35 optimistically low, thereby overestimating the benefit of the SAMA. In other cases, it was 

36 assumed that the SAMA eliminated all of the risk associated with the proposed enhancement. 

37 The NRC staff notes that this bounding approach overestimates the benefit and therefore 

38 is appropriately conservative.

39 Exelon used model requantification to determine the potential benefits for each of the SAMAs. 

40 The CDFs, population dose reductions, and offsite economic cost reductions were estimated 

41 using the LSCS PRA model. The changes made to the model to quantify the impact of each 

42 SAMA are described in Section F.6 of the ER. Table F–6 summarizes the assumptions used to 

43 estimate the risk reduction for each evaluated SAMA, the estimated risk reduction in terms of 

44 CDF percent reduction, population dose, offsite economic cost, and the estimated total benefit 

45 (present value) of the averted risk. The determination of the benefits for the various SAMAs is 

46 further discussed in Section F.6.
Appendix F

F-31

1 The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction 

2 estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that 

3 resulted from this review follow.

4 The discussions of SAMA 8 in Section F.6.8 of the ER and SAMA 14 in Section F.6.13 of the 

5 ER include the statement “Flow from the fire protection system, in its current configuration, is 

6 only adequate in cases where RCIC....” In response to an RAI to discuss what is meant by 

7 “current configuration,” and the potential for a SAMA to address the FPS configuration and 

8 make it possible to use without prior RCIC operation, Exelon responded that there are two major 

9 issues that preclude the use of the FPS for RPV makeup in early time frames to prevent core 

10 damage. The first is related to the low flow rate of the makeup path, and the second is related 

11 to the relatively long time that is required to align the FPS for injection. The connection that is 

12 currently used to provide RPV makeup from the FPS consists of fire hoses that are manually 

13 aligned between the FPS header and the feedwater injection lines. The RPV pressure must be

14 reduced below 75 psig for Unit 1 and 60 psig for Unit 2 to achieve a flow rate of 200 gpm into 

15 the RPV and would be successful only after 4 hours following initial high pressure injection and 

16 subsequent RPV depressurization. Prior to 4 hours, decay heat levels would be such that 

17 200 gpm would be insufficient for RPV makeup. Relative to the second issue, Exelon indicated 

18 that operator interviews indicate that about 40 minutes are required to establish the flow path 

19 from the FPS to the RPV. It would not be possible to align this injection path even if adequate 

20 flow could be obtained from the FPS to make up for boil-off. Exelon indicated and the NRC staff 

21 agrees that both of these issues were assumed mitigated by SAMA 18, “Improvement of the 

22 Connection Between the Fire Protection and Feedwater Systems.” While this SAMA was 

23 developed to reduce the alignment time such that it would be possible to perform the alignment 

24 in cases where RCIC injection fails, one of the assumptions made in the SAMA 18 assessment 

25 was that the improved connection also would improve the flow rate of FPS injection to a point 

26 where it could provide adequate makeup in loss of all injection scenarios (Exelon 2015).

27 In Section F.6.13 of the ER, the discussion of SAMA 14 (provide a portable DC source to 

28 support RCIC and SRV operation) indicates that the PRA model was changed to include a 

29 lumped event to represent the 480 V AC power source that feeds the Division 1 battery 

30 chargers. The SAMA description and the basic events cited to be mitigated by this SAMA 

31 indicated that a DC power source to directly supply an engineered safety feature (ESF) DC 

32 distribution panel is needed. In response to an RAI to discuss the inclusion of an AC power 

33 supply in the model, Exelon responded that the description of the PRA model changes related 

34 to the lumped event that was added to “represent the 480V AC power source that feeds the 

35 Division 1 battery charger” is erroneous and that the text should read “a lumped event was 

36 added to represent the 125 V DC generator that would supply 125 V ESF DC distribution 

37 panel 1(2)11Y.” The detailed PRA model change descriptions documented in Section F.6.13 of 

38 the ER accurately describe how the lumped event (basic event ID “SAMA 14”) was incorporated 

39 into the PRA model for SAMA 14 (Exelon 2015).

40 In an RAI, the NRC staff noted that SAMA 7 (water hammer prevention) and SAMA 25 (periodic 

41 training on water hammer scenarios resulting from a false LOCA signal) both are intended to 

42 mitigate the water hammer scenarios involving SPC operation interrupted by a LOOP. The 

43 changes made to the model and the impacts on population dose risk and offsite economic cost 

44 risk are significantly different for the two SAMAs. In response to the NRC staff RAI to discuss 

45 these SAMAs and their analyses in more detail to justify these differences, Exelon responded 

46 that SAMA 7 and SAMA 25 are different approaches to addressing the risk associated with 

47 water hammer events at LSCS. While the different approaches might be expected to lead to 

48 some differences in the CDF and risk impact of the two SAMAs, the difference in person-rem 

49 and offsite economic risk impacts reported in the ER was found to be due to a recently 
Appendix F

F-32

1 discovered error in a supporting spreadsheet calculation for SAMA 25. Exelon provided 

2 corrected values in the RAI response and indicated that the reduced benefit for SAMA 25 

3 changed its disposition from cost beneficial to not cost beneficial (Exelon 2015). The NRC staff 

4 agrees that these values are correct.

5 The NRC staff noted that SAMA 9 (Develop flood zone specific procedures) and SAMA 11 

6 (Provide the capability to trip the FPS pumps) both address internal flooding; whose principal 

7 contributor is a FPS pipe rupture in the reactor building. The assumption that all of the relevant 

8 internal flooding risk will be eliminated by implementing SAMA 9, lowers the overall CDF by

9 9 percent and results in this SAMA being cost beneficial. As stated in Section F.6.11 of the ER, 

10 SAMA 11 is designed to eliminate the FPS’s flow. For SAMA 11, there is less than a 2 percent 

11 reduction in CDF. In response to an RAI to discuss the FPS design, the FPS pipe break 

12 scenarios, and associated modeling to support the above results, Exelon responded that the 

13 primary reason for the significant difference between SAMA 9 and SAMA 11 risk reductions is 

14 that they target different portions of flooding risk. SAMA 9 targets all flooding initiators while 

15 SAMA 11 targets only a subset of FPS flooding scenarios. SAMA 9 was conservatively 

16 modeled by assuming that it eliminated all internal flooding risk. The 9 percent reduction in CDF 

17 is consistent with the CDF values reported for the internal flooding initiators in Table F.2–2 of 

18 the ER. SAMA 11 provides only a means of tripping the FPS pumps in the main control room, 

19 which helps reduce the risk of FPS flooding events that require a rapid response (i.e., large 

20 breaks) but would only have a small impact on the longer term FPS flooding scenarios. Since 

21 SAMA 11 only improves the reliability of one human action in the PRA model, only a small

22 improvement in CDF is expected. In contrast, SAMA 9 improves the reliability of all human 

23 response actions to all flood scenarios and, therefore, has a larger overall impact on the model

24 (Exelon 2015).

25 The NRC staff reviewed Exelon’s bases for calculating the risk reduction for the various plant 

26 improvements and concludes, with the above clarifications and corrections, that the rationale 

27 and assumptions for estimating risk reduction are reasonable and generally conservative 

28 (i.e., the estimated risk reduction is higher than what would actually be realized). Accordingly, 

29 the NRC staff based its estimates of averted risk for the various SAMAs on Exelon’s risk 

30 reduction estimates.
F-33

SAMA Cost-Benefit Screening Analysis for LSCS Station(a) 1

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 88K 

SAMA Modeling: The contribution related to common cause failure strainer clogging was eliminated by setting the corresp

the cutset files to zero.
F-34

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 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.

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-35

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-36

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-37

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-38

1 Cost Impacts of Candidate Plant Improvements

2 Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other 

3 licensees’ estimates for similar improvements and the development of site-specific cost 

4 estimates where appropriate.

5 SAMA cost estimates were based on initial hardware, installation, and implementation costs. 

6 In response to an NRC staff RAI to provide further information as to what was included in the 

7 LSCS cost estimates, Exelon clarified that maintenance and testing costs during the license 

8 renewal period were conservatively not included in the estimate (Exelon 2015).

9 The NRC staff reviewed the applicant’s cost estimates presented in Section F.6 of the ER 

10 (Exelon 2014a). For certain improvements, the NRC staff also compared the cost estimates to 

11 estimates developed elsewhere for similar improvements, including estimates developed as part 

12 of other licensees’ analyses of SAMAs for operating reactors.

13 The NRC staff noted that a few SAMAs (e.g., 8, 14, and 27) involve use of equipment that may 

14 be available as a result of the B.5.b program and asked Exelon to discuss this further and the 

15 impact on the cost-benefit analysis. Exelon responded that the B.5.b program at LSCS includes 

16 a small generator that is used to support two individual SRV solenoids to hold the SRVs open

17 after 125V DC battery depletion, but the generator does not power the station battery chargers 

18 and it is not designed to support the RCIC system through direct DC feeds. Because of these 

19 limitations, the B.5.b generator is not a viable substitute for the generators that have been 

20 proposed for SAMAs 8, 14, and 27; therefore, the availability of the B.5.b generator would not 

21 reduce the implementation costs for these SAMAs. With the above clarifications, the NRC staff 

22 concludes that the cost estimates provided by Exelon are sufficient and appropriate for use in 

23 the SAMA evaluation.

24 Cost-Benefit Comparison

25 Exelon’s cost-benefit analysis and the NRC staff’s review are described in the following 

26 sections.

27 F.6.1. Exelon’s Evaluation

28 The methodology used by Exelon was based primarily on NRC’s guidance for performing 

29 cost-benefit analysis, NUREG/BR–0184 (NRC 1997a) and industry guidance (NEI 2005) 

30 endorsed by NRC. As described in Section F.4 of the ER (Exelon 2014a), the modified 

31 maximum averted cost risk (MMACR) was determined for each SAMA according to the 

32 following formula, which the staff accepts as mathematically equivalent to the formula in the 

33 NUREG/BR–0184: 

34 MMACR = EEM (WPHA + WEA + WO + WCD + WRP) 

35 where

36 EEM = external event multiplier (unitless)

37 WPHA = present value of averted offsite exposure cost ($)

38 WEA = present value of averted offsite economic cost ($)

39 WO = present value of averted onsite exposure cost ($)

40 WCD = present value of averted onsite cleanup cost ($)
Appendix F

F-39

1 WRP = present value of averted replacement power cost ($)

2 Exelon’s derivation of each of the associated costs is presented separately in this section. For 

3 each SAMA, the applicant’s analysis determined percentage reductions in population dose risk 

4 (PDR%), offsite economic cost risk (OECR%), and onsite cost risk (OCR%). The internal and 

5 external benefit from the implementation of an individual SAMA is determined from these 

6 percentage reductions and their associated present value costs according to the following 

7 formula:

8 SAMA Benefit = EEM [PDR% WPHA + OECR% WEA + OCR% (WO + WCD + WRP)]

9 For each SAMA, the estimated benefit is compared to the cost of implementation. If the cost of 

10 implementing the SAMA is larger than the benefit associated with the SAMA, the SAMA is not 

11 considered to be cost beneficial. If the cost of implementing the SAMA is smaller than the 

12 benefit associated with the SAMA, the SAMA is considered to be cost beneficial. In the ER, 

13 Exelon calculated the net value for individual SAMAs in a similar manner. Positive net values 

14 indicated a potentially cost-beneficial SAMA, and negative net values implied that the SAMA 

15 was not cost beneficial.

16 In accordance with NUREG/BR–0058 guidance (NRC 2004) that states present worth estimates 

17 should be developed using both the 3 percent and 7 percent discount rates, Exelon conducted a 

18 baseline analysis using the 3 percent discount rate and a sensitivity analysis using the 7 percent 

19 discount rate (Exelon 2014a). Additional sensitivity analyses were performed by the applicant to 

20 quantify influences on the calculated benefits from the 95th percentile PRA results, offsite 

21 consequence modeling parameter changes, and assumed implementation of a hardened pipe 

22 containment vent. Additional details on the sensitivity analysis are presented in Section F.6.2.

23 Averted Offsite Exposure Cost (WPHA)

24 Exelon defined WPHA cost as the monetary value of accident risk avoided from population doses 

25 after discounting (Exelon 2014a). The WPHA costs were calculated using the following formula:

26 WPHA = Averted public dose risk (person-rem per year)

27 × monetary equivalent of unit dose ($2,000 per person-rem)

28 × present value conversion factor (NRC 1997a)

29 As stated in NUREG/BR–0184 (NRC 1997a), it is important to note that the monetary value of 

30 the public health risk after discounting does not represent the expected reduction in public 

31 health risk because of a single accident. Rather, it is the present value of a stream of potential 

32 losses extending over the remaining lifetime (in this case, the 20-year renewal period) of the 

33 facility. Thus, it reflects the expected annual loss caused by a single accident, the possibility 

34 that such an accident could occur at any time over the renewal period, and the effect of 

35 discounting these potential future losses to present value. For a discount rate of 3 percent, 

36 Exelon calculated the WPHA cost of $213,863 due to internal events in the ER (Exelon 2014a).

37 Averted Offsite Economic Cost (WEA)

38 Exelon defined WEA as the monetary value of risk avoided from offsite property damage after 

39 discounting (Exelon 2014a). The WEA values were calculated using the following formula:

40 WEA = Annual offsite property damage risk before discounting in dollars per year

41 × present value conversion factor (NRC 1997a)

42 For a discount rate of 3 percent, Exelon calculated the WEA cost of $802,484 due to internal 

43 events in the ER (Exelon 2014a).
Appendix F

F-40

1 Averted Onsite Exposure Cost (WO)

2 Exelon defined WO as the avoided onsite exposure (Exelon 2014a). Similar to the WPHA

3 calculations, the applicant calculated costs for immediate onsite exposure. Long-term onsite 

4 exposure costs were calculated consistent with guidance in the Regulatory Analysis Technical 

5 Evaluation Handbook (NRC 1997a), which included an additional term for accrual of 

6 long-term doses.

7 Exelon derived the values for averted occupational exposure from information provided in 

8 Section 5.7.3 of the Regulatory Analysis Technical Evaluation Handbook (NRC 1997a). Best 

9 estimate values providing for an immediate occupational dose (3,300 person-rem) and 

10 long-term occupational dose (20,000 person-rem over a 10-year cleanup period) were used. 

11 The present value of these doses was calculated using the equations provided in the handbook 

12 in conjunction with a monetary equivalent of unit dose of $2,000 per person-rem, a real discount 

13 rate of 7 percent, and a time period of 20 years to represent the license renewal period. 

14 Immediate and long-term onsite exposure costs were summed to determine the WO cost. For a 

15 discount rate of 3 percent, Exelon calculated the WO cost of $1,597 due to internal events in the 

16 ER (Exelon 2014a).

17 Averted Onsite Cleanup Cost (WCD)

18 Exelon defined WCD as the avoided cost for cleanup and decontamination of the site 

19 (Exelon 2014a). The applicant derived the values for WCD based on information provided in 

20 Section 5.7.6 of NUREG/BR–0184, the Regulatory Analysis Technical Evaluation Handbook

21 (NRC 1997a). 

22 Averted cleanup and decontamination costs were calculated using the following formula:

23 WCD = Annual CDF × present value of cleanup costs per core damage event × present value 

24 conversion factor.

25 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 26 (undiscounted). This 

27 value was converted to present costs over a 10-year cleanup period and integrated over the 

28 term of the proposed license extension. For a discount rate of 3 percent, Exelon calculated the 

29 WCD cost of $50,284 due to internal events in the ER (Exelon 2014a).

30 Averted Replacement Power Cost (WRP) 

31 Exelon defined WRP as the avoided costs of replacement power (Exelon 2014a). Long-term 

32 replacement costs were calculated using the following formula:

33 WRP = Annual CDF × present value of replacement power for a single event 

34 × factor for remaining service years for which replacement power is required

35 × reactor power scaling factor

36 Exelon based its calculations on the net electric output for LSCS, specifically 

37 1,210 megawatt-electric (MWe), and scaled up from reference plant value of 910 MWe specified 

38 in NUREG/BR–0184 (NRC 1997a). For a discount rate of 3 percent, Exelon calculated WRP

39 costs of $18,955 due to internal events in the ER (Exelon 2014a).

40 Modified Maximum Averted Cost Risk (MMACR)

Using the above equations and an annual CDF of 2.58×10‒6 41 , Exelon estimated the total present 

42 dollar value equivalent associated with completely eliminating severe accidents caused by 

43 internal events, referred to as the MACR, to be about $1,087,183 at a single unit for a discount 

44 rate of 3 percent in the ER (Exelon 2014a). In Exelon’s revised analysis, the MACR increased 
Appendix F 

F-41

1 to approximately $1,168,000. To account for the risk contributions from external events and 

2 yield the internal and external benefit, Exelon selected an external event multiplier (EEM) value 

3 of 5.2 for LSCS, as described in Section F.4.6.2 of the ER (Exelon 2014a). By multiplying 

4 MACR and EEM, Exelon estimated MMACR to be about $5,657,600 for a single unit with a 

5 discount rate of 3 percent, as presented in Section F.4.6.3 of the ER (Exelon 2014a). In 

6 Exelon’s revised analysis, the MMACR increased to $6,073,600 (Exelon 2015). As described 

7 above in the SAMA benefit formula, components of the MMACR calculation factor into the 

8 benefit determination for individual SAMAs. When Exelon revised its analysis in response to 

9 RAIs from the NRC staff, updates were not presented for the individual components of MACR 

10 (WPHA, WEA, WO, WCD, WRP).

11 Exelon’s Results

12 If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 

13 was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 

14 SAMA candidate was considered to be potentially cost beneficial. Results of the cost-benefit 

15 evaluation are presented in Table F–6. Exelon’s cost-benefit analysis identified 14 SAMA 

16 candidates determined to be potentially cost beneficial at the 95th percentile on an individual 

17 basis:

18 • SAMA 2: Automate suppression pool cooling.

19 • SAMA 3: Passive vent path.

20 • SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation

21 bypass switch.

22 • SAMA 5: Automate standby liquid control (SBLC) initiation.

23 • SAMA 8: Obtain a 480 V AC portable generator to supply the 125 V DC battery

24 chargers and proceduralize its use.

25 • SAMA 9: Develop flood zone specific procedures.

26 • SAMA 10: Change the logic to close the turbine driven feedwater pump discharge

27 valves when the pumps are not running.

28 • SAMA 14: Provide a portable DC source to support RCIC and SRV operation.

29 • SAMA 15: Tie RHRSW to the low-pressure core spray (LPCS) system for interfacing

30 systems loss-of-coolant accident (ISLOCA) mitigation.

31 • SAMA 16: Provide portable fans for alternate room cooling in the CSCS vaults.

32 • SAMA 18: Improve the connection between the fire protection and

33 feedwater systems.

34 • SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for

35 LOCA mitigation.

36 • SAMA 21: Install Automatic ATWS level control system.

37 • SAMA 23: Enhance fuel pool emergency makeup pump and connection.

38 When the planned installation of a hardened pipe containment vent is considered as the base 

39 case, the number of SAMA candidates considered to be potentially cost beneficial at the 

40 95th percentile may reduce. Because a new baseline is established following the 

41 implementation of a SAMA, which further influences the benefits provided by the remaining 

42 SAMA candidates, Exelon defined an optimal set to containing SAMAs that, if implemented, 
Appendix F

F-42

1 would render the remaining SAMAs to be not cost beneficial. Acknowledging Exelon’s planned 

2 installation of the hardened pipe containment vent (SAMA 1), additional modifications included 

3 in the optimal set are SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). 

4 Assessment of the optimal set was performed prior to Exelon generating revised results in 

5 response to the NRC staff’s RAIs (Exelon 2015). Because a priori credit for installation of the 

6 hardened pipe containment vent was not taken by Exelon, revision of the optimal set 

7 assessment was not required. Exelon is referring the 14 potentially cost-beneficial SAMAs from 

8 its revised analysis (Exelon 2015) to the LSCS Plant Health Committee for further 

9 implementation considerations within the established plant procedural process, as indicated in 

10 Section 4.15 of the ER (Exelon 2014d).

11 F.6.2. Review of Exelon’s Cost-Benefit Evaluation

12 During its review of the cost-benefit analysis performed by Exelon, the NRC staff compared the 

13 applicant’s approach with guidance in NUREG/BR–0184 (NRC 1997a) and discount rate 

14 guidelines in NEI 05-01 (NEI 2005). NEI guidance states that two sets of estimates should be 

15 developed for discount rates of 7 percent and 3 percent (NEI 2005). Exelon performed 

16 assessments using both discount rates. Exelon provided a baseline set of results using a 

17 discount rate of 3 percent. For the other types of potential sensitivity analyses suggested 

18 (NEI 2005), the NRC staff finds that Exelon’s information provided in the ER submittal and 

19 subsequent RAI responses on plant modifications, peer review findings or observations, and 

20 evacuation speeds have been adequately addressed in the baseline analysis, as discussed in 

21 this appendix. As previously indicated, Exelon performed the cost-benefit evaluation using an 

22 analysis time period of 20 years. Because Exelon explicitly accounted for uncertainty in its 

23 sensitivity analysis by applying a multiplication factor of 2.14 and the results of the sensitivity 

24 analysis were used to identify additional potentially beneficial SAMAs, the NRC staff finds that 

25 an additional sensitivity analysis for a timeframe longer than 20 years is not necessary. 

26 Although longer timeframes would increase estimated benefits compared to baseline results, 

27 the 20-year timeframe is consistent with the later expiration month of December 2043 for a 

28 renewed license of Unit 2 stated in Section 1.1 of the ER (Exelon 2014a), and it is unlikely that 

29 influences from a longer timeframe would exceed the factor of 2.14 already considered by 

30 Exelon. Based on its review of the applicant’s cost-benefit evaluation, the NRC staff determined 

31 that the applicant’s approach is consistent with the guidance and acceptable.

32 The applicant considered possible increases in benefits from analysis uncertainties on the 

33 results of the SAMA assessment. In the ER (Exelon 2014a), Exelon indicated that the 

34 95th percentile value of the LSCS CDF was greater than the mean CDF by a factor of 2.14, and 

35 thus, a multiplication factor of 2.14 was selected to account for uncertainty. This multiplication 

36 factor was applied in addition to the separate external events multiplication factor of 5.2 

37 (Exelon 2014a). Exelon’s assessment accounted for the potential risk-reduction benefits 

38 associated with both internal and external events. The NRC staff considers the multipliers 

39 of 2.14 for uncertainty and 5.2 for external events at LSCS provide an adequate margin and are 

40 acceptable for the SAMA analysis. 

41 Using Exelon’s information presented in the ER (Exelon 2014a), the NRC staff spot checked the 

42 applicant’s calculations of delta CDF (i.e., percentage reduction in CDF due to accumulated 

43 differences in the release categories for a specific SAMA candidate compared to the base 

44 case), population dose risk, and offsite economic cost risk. By applying the formula for SAMA 

45 benefit presented in Section F.6.1 and comparing the results with those presented in the ER 

46 (Exelon 2014a), the NRC staff found the results to be in agreement and within small round-off 

47 errors.
Appendix F

F-43

1 Exelon’s revised cost-benefit analysis identified 14 SAMA candidates as potentially cost 

2 beneficial at the 95th percentile (Exelon 2015). From its sensitivity analyses in the ER, no 

3 additional SAMA candidates were determined to be potentially cost beneficial. As described in 

4 Section F.3.2, the NRC staff asked the applicant to evaluate potentially lower cost alternatives

5 to SAMA 7. From its review of the original SAMA analysis and additional information, the NRC 

6 staff agrees with Exelon’s disposition of potentially lower cost alternatives.

7 Because Exelon’s cost-benefit evaluations have been reviewed by the NRC staff and Exelon 

8 satisfactorily addressed NRC staff questions regarding the evaluations, the NRC staff concludes 

9 that the cost-benefit evaluations are of sufficient quality to support the SAMA evaluation. 

10 Therefore, the NRC staff concludes that, with the exception of the potentially cost-beneficial 

11 SAMAs discussed above, the costs of the other SAMAs evaluated would be higher than their 

12 associated benefits and not cost beneficial.

13 Conclusions

14 Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 

15 updated probabilistic safety assessment models, SAMA-related industry documentation, 

16 plant-specific enhancements, and its review of SAMA candidates from potential improvements 

17 primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 

18 SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 

19 been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 

20 costs and benefits associated with each of the 25 potential SAMAs shown in Table F–6. Exelon 

21 concluded that 14 SAMA candidates were potentially cost beneficial at the 95th percentile. 

22 Despite it being not cost beneficial, Exelon has decided to proceed with the modification to 

23 install a hardened pipe containment vent regardless of cost. Exelon also performed a sensitivity 

24 analysis, and no additional SAMA candidates were identified as potentially cost beneficial. 

25 Because the potentially cost-beneficial SAMAs do not relate to aging management during the 

26 period of extended operation, their implementation is not required as part of license renewal 

27 pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Part 54, “Requirements for 

28 Renewal of Operating Licenses for Nuclear Power Plants.” Nevertheless, as stated in 

29 Section 4.15 of the ER (Exelon 2014d), Exelon indicated that the potentially cost-beneficial 

30 SAMAs are being referred to the LSCS Plant Health Committee for further implementation

31 considerations within the established plant procedural process.

32 The NRC staff reviewed Exelon’s SAMA analysis and concludes that the methods used and 

33 implementation of the methods were sound. On the basis of the applicant’s treatment of SAMA 

34 benefits and costs, the NRC staff finds that the SAMA evaluations performed by Exelon are 

35 reasonable and sufficient for the license renewal submittal. The NRC staff concurs with 

36 Exelon’s conclusion that 14 SAMA candidates are potentially cost beneficial for LSCS and notes 

37 that Exelon’s assessment was based on generally conservative treatment of costs, benefits, and 

38 uncertainties. Based on the NRC staff’s review of Exelon’s SAMA evaluations, including 

39 Exelon’s response to the NRC staff’s RAIs, the NRC staff concludes that Exelon has adequately 

40 identified areas where risk can be further reduced in a cost-beneficial manner through the 

41 implementation of the identified potentially cost-beneficial SAMAs. Given the potential for 

42 cost-beneficial risk reduction, the NRC staff concludes that further evaluation by Exelon of the 

43 14 SAMA candidates identified by Exelon as being potentially cost beneficial is warranted.

44 The NRC staff also evaluated whether any of the potentially cost-beneficial SAMAs identified 

45 are subject to aging management such that they would be within the scope of license renewal. 

46 The evaluation considered any structures, systems, and components associated with these 

47 SAMAs that perform intended functions without moving parts or without a change in 
Appendix F

F-44

1 configuration or properties and would not be subject to replacement based on a qualified life or 

2 specified time period. The NRC staff determined that the potentially cost-beneficial SAMAs do 

3 not relate to adequately managing the effects of aging during the period of extended operation. 

4 Therefore, they need not be implemented as part of license renewal in accordance with 

5 10 CFR Part 54. 

6 References

7 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

8 Renewal of Operating Licenses for Nuclear Power Plants.”

9 [ASME/ANS] (American Society of Mechanical Engineers/American Nuclear Society). 2005. 

10 Addenda RA-Sa-2003 and RA-Sb-2005 to ASME RA-S-2002, Standard for Probabilistic Risk 

11 Assessment for Nuclear Power Plant Applications. December 2005. 

12 [ASME/ANS] American Society of Mechanical Engineers and American Nuclear Society. 2009. 

13 Addenda to ASME/ANS RA-S–2008, Standard for Level 1/Large Early Release Frequency 

14 Probabilistic Risk Assessment for Nuclear Power Plant Applications. New York, NY: ASME. 

15 ASME/ANS RA-Sa-2009. February 2, 2009. 352 p. This document is proprietary and available 

16 for sale on www.asme.org.

17 [CECO] Commonwealth Edison Company. 1994. LaSalle County Nuclear Power Station, 

18 Individual Plant Examination and Individual Plant Examination (External Events). April 1994. 

19 [Exelon] Exelon Generating Company, LLC. 2012a. “Seismic Walkdown Report In Response 

20 To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 

21 Recommendation 2.3: Seismic for the LaSalle County Station, Unit 1, Report Number: 

22 12Q0108.50-R-001, Revision 1.” November 27, 2012. ADAMS No. ML12353A225.

23 [Exelon] Exelon Generating Company, LLC. 2012b. “Seismic Walkdown Report In Response 

24 To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 

25 Recommendation 2.3: Seismic for the LaSalle County Station, Unit 2, Report Number: 

26 12Q0108.50-R-002, Revision 1.” November 27, 2012. ADAMS No. ML12353A207. 

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

28 Operating License Renewal Stage, LaSalle County Station. Appendix F: Severe Accident 

29 Mitigation Alternatives Analysis.” ADAMS No. ML14343A897. December 2014. 

30 [Exelon] Exelon Generation Company, LLC. 2014b. Letter from Glen T. Kaegi to NRC 

31 Document Control Desk. Subject: Exelon Generation Company, LLC, Seismic Hazard and 

32 Screening Report (Central and Eastern United States (CEUS) Sites), Response to NRC 

33 Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the 

34 Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident. Exelon letter 

35 RS-14-068. March 31, 2014. ADAMS No. ML14091A013.

36 [Exelon] Exelon Generation Company, LLC. 2014c. Letter from T. John Conner to NRC 

37 Document Control Desk. Subject: Exelon Generation Company, LLC Response to 

38 March 12, 2012, Request for Information Enclosure 2, Recommendation 2.1, Flooding, 

39 Required Response 2, Flood Hazard Reevaluation Report. Exelon letter RS-14-055. 

40 March 12, 2014. ADAMS Nos. ML14079A425 and ML14079A426.

41 [Exelon] Exelon Generation Company, LLC. 2014d. “Applicant’s Environmental Report, 

42 Operating License Renewal Stage, LaSalle County Station.” ADAMS No. ML14343A883. 

43 December 2014.
Appendix F 

F-45

1 [Exelon] Exelon Generation Company, LLC. 2015. Letter from Michael P. Gallagher, Vice 

2 President, License Renewal Projects Exelon Generation Company, LLC, to NRC Document 

3 Control Desk. Subject: Response to NRC Request for Additional Information on Severe 

4 Accident Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2 License 

5 Renewal Application Environmental Review. Letter RA15-032. May 29, 2015. ADAMS 

6 No. ML15149A370. 

7 [NEI] Nuclear Energy Institute. 2005. Severe Accident Mitigation Alternative (SAMA) Analysis 

8 Guidance Document. Revision A. Washington, DC: NEI. NEI 05-01. November 2005. 79 p. 

9 ADAMS No. ML060530203.

10 [NRC] U.S. Nuclear Regulatory Commission. 1988. “Individual Plant Examination for Severe 

11 Accident Vulnerabilities—10 CFR 50.54(f).” Washington, DC: NRC. Generic Letter No. 88-20. 

12 November 23, 1988. Available at <http://www.nrc.gov/reading-rm/doc-collections/gen13 comm/gen-letters/1988/gl88020.html> (accessed 21 October 2014).

14 [NRC] U.S. Nuclear Regulatory Commission. 1991. “Individual Plant Examination of External 

15 Events for Severe Accident Vulnerabilities.” Washington, DC: NRC. Generic Letter No. 88-20, 

16 Supplement 4. June 28, 1991.

17 [NRC] U.S. Nuclear Regulatory Commission. 1992. Analysis of the LaSalle Unit 2 Nuclear 

18 Power Plant: Risk Methods Integration and Evaluation Program (RMIEP). Washington, DC: 

19 NRC. NUREG/CR–4832, Vols. 1‒9, 1992‒1993.

20 [NRC] U.S. Nuclear Regulatory Commission. 1995. Memorandum from M. Wayne Hodges, 

21 NRC, to Steven A Varga, NRC. Subject: Review of LaSalle Individual Plant Examination (IPE) 

22 Submittal-Internal Events. November 1, 1995.

23 [NRC] U.S. Nuclear Regulatory Commission. 1997a. Regulatory Analysis Technical Evaluation 

24 Handbook. Washington, DC: NRC. NUREG/BR–0184. January 1997. 308 p. ADAMS 

25 No. ML050190193.

26 [NRC] U.S. Nuclear Regulatory Commission. 1997b. Individual Plant Examination Program: 

27 Perspectives on Reactor Safety and Plant Performance,” NUREG–1560, Washington, D.C. 

28 1997. 

29 [NRC] U.S. Nuclear Regulatory Commission. 2000. Letter from Donna M. Skay to Oliver D. 

30 Kingsley, Commonwealth Edison Company. Subject: LaSalle County Station, Units 1 and 2, 

31 NRC Staff Evaluation of the Individual Plant Examination of External Events (IPEEE) Submittal. 

32 (TAC Nos. M83634 and M83635). December 8, 2000. ADAMS No. ML003776159.

33 [NRC] U.S. Nuclear Regulatory Commission. 2004. Regulatory Analysis Guidelines of the 

34 U.S. Nuclear Regulatory Commission. Revision 4. Washington, DC: NRC. NUREG/BR–0058. 

35 September 2004. 56 p. Available at<http://www.nrc.gov/reading-rm/doc-collections/nuregs/

36 brochures/br0058/> (accessed 21 October 2014).

37 [NRC] U.S. Nuclear Regulatory Commission. 2005. EPRI/NRC-RES Fire PRA Methodology 

38 for Nuclear Power Facilities. Vols. 1 and 2. Washington, DC: NRC. NUREG/CR–6850. 

39 September 2005. ADAMS Nos. ML052580075 and ML052580118.

40 [NRC] U.S. Nuclear Regulatory Commission. 2007. An Approach for Determining the 

41 Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities. 

42 Revision 1. Regulatory Guide 1.200. January 2007. ADAMS No. ML070240001.
Appendix F

F-46

1 [NRC] U.S. Nuclear Regulatory Commission. 2010. Letter from T. McGinty, Director, to All 

2 Holders of an Operating License. Subject: NRC Information Notice 2010-18: Generic 

3 Issue 199, “Implications of Updated Probabilistic Seismic Hazard Estimates in Central and 

4 Eastern United States on Existing Plants.” September 2, 2010. ADAMS No. ML101970221.

5 [NRC] U.S. Nuclear Regulatory Commission. 2011. An Approach for Using Probabilistic Risk 

6 Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis. 

7 Revision 2. Regulatory Guide 1.174. May 2011. ADAMS No. ML100910006.

8 [NRC] U.S. Nuclear Regulatory Commission. 2012a. Letter from E. Leeds, Director, to All 

9 Power Reactor Licensees. Subject: Request for information pursuant to Title 10 of the Code of 

10 Federal Regulations 50.54(f) regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term 

11 Task Force review of insights from the Fukushima Dai-ichi accident. March 12, 2012. ADAMS 

12 No. ML12053A340.

13 [NRC] U.S. Nuclear Regulatory Commission. 2012b. Letter from E. Leeds, Director, to All 

14 Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status.

15 EA-12-049. Subject: Issuance of Order to Modify Licenses with Regard to Requirements for 

16 Mitigation Strategies for Beyond-Design-Basis External Events. March 12, 2012. ADAMS 

17 No. ML12054A735.

18 [NRC] U.S. Nuclear Regulatory Commission. 2014. Letter from Blake Purnell, Project 

19 Manager, NRC, to Michael J. Pacilio, Senior Vice President, Exelon Generation Company. 

20 Subject: LaSalle County Station, Units 1 and 2 - Staff Assessment of the Flooding Walkdown 

21 Report Supporting Implementation of the Near-Term Task Force Recommendation 2.3 Related 

22 to the Fukushima Dai-ichi Accident. (TAC Nos. MF0240 and MF0241). June 30, 2014. 

23 ADAMS No. ML14177A859.

24 [NRC] U.S. Nuclear Regulatory Commission. 2015. Letter from D. Drucker, Environmental 

25 Project Manager, to Michael P. Gallagher, Vice President License Renewal Projects, Exelon

26 Generation Company, LLC. Subject: Request for Additional Information on Severe Accident 

27 Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2, License Renewal 

28 Application Environmental Review (TAC Nos. MF5567 and MF5568). April 30, 2015. ADAMS 

29 Nos. ML15114A320 and ML15114A102.
1 APPENDIX G 

2 TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL 

G-1 

1 G. TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL

2 Introduction

3 The U.S. Nuclear Regulatory Commission (NRC) has generically determined in its license 

4 renewal application reviews that the environmental impacts of the transportation of fuel and 

5 radioactive wastes to and from nuclear power facilities are small for all reactors as long as 

6 certain specific conditions are met. The application for license renewal of LaSalle County

7 Station, Units 1 and 2 (LSCS) stated that the specific conditions that allow the transportation 

8 impacts of spent fuel to be generically determined to be small may not be met for LSCS. 

9 Therefore, this appendix provides the NRC staff’s analysis of the environmental impacts of 

10 transporting spent fuel from LSCS. 

11 Background

12 The U.S. Nuclear Regulatory Commission (NRC) performed a generic analysis of the 

13 environmental effects of the transportation of fuel and waste to and from light-water reactors 

14 (LWRs) in WASH–1238, “Environmental Survey of Transportation of Radioactive Materials to 

15 and from Nuclear Power Plants” (AEC 1972), and in a supplement to WASH–1238,

16 NUREG–75/038 (NRC 1975), and found the impact to be small. These documents provided the 

17 basis for Table S–4 in Title 10 of the Code of Federal Regulations (CFR) Part 51.52(b) that 

18 summarizes the environmental impacts of transportation of fuel and waste to and from one 

19 3,000- to 5,000-megawatt-thermal (MWt) (1,000- to 1,500-megawatt-electric (MWe)) LWR. 

20 Impacts are provided for normal conditions of transport and accidents in transport for a 

reference 1,100-MWe LWR.11 21 Dose to transportation workers during normal transportation 

22 operations was estimated to result in a collective dose of 4 person-rem per reference 

23 reactor-year. The combined dose to the public along the route and the dose to onlookers were 

24 estimated to result in a collective dose of 3 person-rem per reference reactor-year.

25 Environmental risks of radiological effects during accident conditions, as stated in Table S–4, 

26 are small. Nonradiological impacts from postulated accidents were estimated as one fatal injury 

27 in 100 reference reactor-years and one nonfatal injury in 10 reference reactor-years. 

28 Subsequent reviews of transportation impacts in NUREG–0170, Final Environmental Statement 

29 on the Transportation of Radioactive Material by Air and Other Modes (NRC 1977), and 

30 NUREG/CR–6672, Reexamination of Spent Fuel Shipment Risk Estimates (Sprung et al. 2000), 

31 concludes that impacts were bounded by Table S–4 in 10 CFR 51.52. In accordance with 

32 10 CFR 51.52(a), a full description and a detailed analysis of transportation impacts are not 

33 required in the initial licensing of an LWR (i.e., impacts are assumed to be bounded by

34 Table S–4) if the reactor meets the following criteria: 

35 • The reactor has a core thermal power level that does not exceed 3,800 MWt.

36 • Fuel is in the form of sintered uranium oxide pellets having a uranium-235

37 enrichment not exceeding 4 percent by weight, and the pellets are encapsulated in

38 Zircaloy-clad fuel rods.

11 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 

1 • The average level of irradiation of the fuel from the reactor does not exceed

2 33,000 megawatt-days per metric ton of uranium (MWd/MTU), and no irradiated fuel

3 assembly is shipped until at least 90 days after it is discharged from the reactor.

4 • With the exception of irradiated fuel, all radioactive waste shipped from the reactor is

5 packaged and in a solid form.

6 • Unirradiated fuel is shipped to the reactor by truck; irradiated fuel is shipped from the

7 reactor by truck, rail, or barge; and radioactive waste other than irradiated fuel is

8 shipped from the reactor by truck or rail.

9 The environmental impacts of the transportation of fuel and radioactive wastes to and from 

10 nuclear power facilities are resolved generically in 10 CFR 51.52 as long as the specific 

11 conditions in the rule (see above) are met. 

12 10 CFR 51.52 does not specifically address license renewal. However, NUREG–1437, Generic 

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

14 (NRC 2013), points out that nuclear fuel is needed for the operation of light water reactors 

15 during the license renewal term in the same way that it is needed during the current license 

16 period. Therefore, the factors that affect the data presented in Table S–4 of 10 CFR 51.52 do 

17 not change when a light water reactor is operating under a renewed license. The GEIS further 

18 states that the NRC reevaluated the transportation issues and the adequacy of Table S–4 for 

19 license renewal application reviews (NRC 2013). In 1999, the NRC issued an addendum to the 

20 GEIS (NRC 1999) in which the agency evaluated the applicability of Table S–4 to future license 

21 renewal proceedings, particularly because shipments of spent fuel were likely to involve more 

22 highly enriched fresh fuel (more than 4 percent as assumed in Table S–4) and higher-burnup

23 spent fuel (higher than 33,000 MWd/MTU as assumed in Table S–4). On the basis of the 

24 evaluations, the NRC concluded that the values given in Table S–4 would still be bounding, as 

25 long as the (1) enrichment of the fresh fuel was 5 percent or less, (2) burnup of the spent fuel 

26 was 62,000 MWd/MTU or less, and (3) higher-burnup spent fuel (higher than 

27 33,000 MWd/MTU) was cooled for at least 5 years before being shipped offsite.

28 The GEIS (NRC 2013) quotes the conclusion of the 1999 addendum as follows: 

29 The impacts of transporting spent fuel enriched up to 5 percent uranium-235 with 

30 average burnup for the peak rod to current levels approved by NRC up to 

31 62,000 MWd/MTU and the cumulative impacts of transporting high-level waste to 

32 a single repository, such as Yucca Mountain, Nevada are found to be consistent 

33 with the impact values contained in 10 CFR 51.52(c), Summary Table S–4, 

34 “Environmental Impact of Transportation of Fuel and Waste to and from One 

35 Light-Water-Cooled Nuclear Power Reactor.” If fuel enrichment or burnup

36 conditions are not met, the applicant must submit an assessment of the 

37 implications for the environmental impact values reported in 10 CFR 51.52.

38 Therefore, when the fuel burnup rate may exceed 62,000 MWd/MTU during the period of 

39 extended operation, further analysis of transportation impacts is warranted. 

40 Exelon Generation Company, LLC (Exelon), submitted an environmental report (ER)

41 (Exelon 2014a) as part of its license renewal application (Exelon 2014b) for LSCS in 

42 December 2014. LSCS is located in north-eastern Illinois. Each LSCS reactor is a General 

43 Electric boiling water reactor (BWR), Type 5, with a thermal power rating of 3,546 MWt. The 

44 two reactors at LSCS have a combined electrical output of 2,327 MWe. Both LSCS units 

45 operate using low-enriched uranium dioxide fuel with enrichment not exceeding a nominal 

46 5.0 percent by weight of uranium-235; these units have been historically operated within a 

47 maximum analyzed fuel burnup rate of 62,000 MWd/MTU. However, during some future fuel 
Transportation Impacts of High Burnup Fuel

G-3

1 cycles, the peak fuel burnup is projected to exceed 62,000 MWd/MTU in some part-length fuel 

2 rods. The part-length fuel rods are attached to the fuel bundle lower tie plate and typically 

3 experience higher burnups and higher power than full-length rods due to the bottom-peaked 

4 axial power shapes that exist throughout a large portion of a BWR fuel cycle, and a 

5 representative high-burnup case was identified based on a burnup of 75,000 MWd/MTU and a 

6 uranium-235 enrichment of 5.0 percent by weight. Accordingly, Exelon provided a full 

7 description and detailed analyses of the transportation impacts of shipping irradiated fuel from 

8 LSCS in its ER (Exelon 2014a) and provided an update to that analysis by letter dated 

9 August 28, 2015 (Exelon 2015). In this analysis, the radiological impacts of transporting 

10 irradiated fuel from LSCS were calculated using the RADTRAN 6.02 computer code 

11 (Weiner et al. 2015). RADTRAN 6.02 was also used in this SEIS and is the most commonly 

12 used transportation impact analysis software in the nuclear industry. 

13 NRC Analysis of LSCS High Burnup Fuel Transportation Impacts

14 This section provides the NRC staff’s analysis of the environmental impacts of transporting 

15 spent fuel from LSCS to a monitored retrievable storage facility or a permanent repository for

16 normal operating conditions and transportation accidents.

17 For the purposes of this analysis, the NRC staff considered the proposed Yucca Mountain

18 repository site in Nevada as a surrogate destination. Currently, the NRC has not made a 

19 decision about the U.S. Department of Energy (DOE) application for the proposed geologic 

20 repository at Yucca Mountain. However, the NRC staff considers that an estimate of the 

21 impacts of the transportation of spent fuel to a possible repository in Nevada is a reasonable 

22 bounding estimate of the transportation impacts on a storage or disposal facility because of the 

23 distances involved and the representativeness of the distribution of members of the public in 

24 urban, suburban, and rural areas (i.e., population distributions) along the shipping routes. 

25 The NRC Yucca Mountain adjudicatory proceeding is currently suspended, and Yucca 

26 Mountain-related matters are pending in Federal Court. Regardless of the outcome of these 

27 proceedings, the NRC staff concludes that transportation impacts are roughly proportional to the 

28 distance from the reactor site to the repository site, in this case, Illinois to Nevada.

29 This NRC staff’s analysis is based on shipment of spent fuel by legal-weight trucks in shipping 

30 casks with characteristics similar to currently available casks (i.e., massive, heavily shielded, 

31 cylindrical metal pressure vessels). Because of the large size and weight of spent fuel shipping 

32 casks, each shipment is assumed to consist of a single shipping cask loaded on a modified 

33 trailer. These assumptions are consistent with those made in the evaluation of the 

34 environmental impacts of transportation of spent fuel in Addendum 1 to NUREG–1437 

35 (NRC 1999). Because the alternative transportation methods involve rail transportation or 

36 heavy-haul trucks, which would reduce the overall number of spent fuel shipments (NRC 1999), 

37 thereby reducing impacts, these assumptions are conservative. In addition, the use of current 

38 shipping cask designs for this analysis results in conservative impact estimates because the 

39 current designs are based on transporting short-cooled spent fuel (approximately 120 days out 

40 of reactor). Future shipping casks would be designed to transport longer cooled fuel (greater 

41 than 5 years out of reactor) and would require much less shielding to meet external dose

42 limitations. Therefore, future shipping casks are expected to have higher cargo capacities, thus 

43 reducing the numbers of shipments and associated impacts.

44 The NRC staff calculated radiological impacts of transportation of spent fuel using the 

45 RADTRAN 6.02 computer code (Weiner et al. 2015). Routing and population data used in 

46 RADTRAN 6.02 for truck shipments were obtained from the Transportation Routing Analysis 

47 Geographical Information System (TRAGIS) routing code (ORNL 2015). The population data in 
Transportation Impacts of High Burnup Fuel

G-4

1 the TRAGIS code are based on the 2010 Census. The traffic accident rates input to 

2 RADTRAN 6.02 were taken from Weiner et al. (2015). 

3 G.3.1. Normal Conditions

4 Normal conditions, sometimes referred to as “incident free” transportation, are transportation 

5 activities in which shipments reach their destination without an accident occurring en route. 

6 Impacts from these shipments would be from the low levels of radiation that penetrate the 

7 heavily shielded spent fuel shipping cask. Radiation exposures would occur to the following 

8 populations: (1) persons residing along the transportation corridors between LSCS and the 

9 proposed repository location, (2) persons in vehicles traveling on the same route as a spent fuel 

10 shipment, (3) persons at vehicle stops for refueling, rest, and vehicle inspections, and 

11 (4) transportation crew workers (drivers). This analysis assumed that the surrogate destination 

12 for the spent fuel shipments is the proposed Yucca Mountain repository site in Nevada. This 

13 assumption is conservative because it tends to maximize the shipping distance from LSCS.

14 The NRC staff assumed that the capacity of a truck shipment of reactor spent fuel was 

15 0.5 metric ton of uranium (MTU) per shipment, the same capacity as that used in WASH–1238 

16 (AEC 1972). Exelon assumed a shipping cask capacity of 0.5 MTU per shipment in its analysis 

17 (Exelon 2014a, 2015).

18 Appendix G input to RADTRAN 6.02 includes the total shipping distance between the origin and 

19 destination sites and the population distributions along the routes. This information was 

20 obtained by running the TRAGIS computer code (ORNL 2015) for highway routes from LSCS to 

21 the proposed Yucca Mountain repository site. The resulting route characteristics information is 

22 shown in Table G–1. For truck shipments, all the spent fuel is assumed to be shipped to the 

23 proposed Yucca Mountain repository site over designated highway-route controlled-quantity 

24 routes. In addition, TRAGIS data were used in RADTRAN 6.02 on a state-by-state basis. The 

25 use of state-specific data from TRAGIS increases precision and could allow the results to be 

26 presented for each state along the route between LSCS and the proposed Yucca Mountain 

27 repository site, if desired.

28 Transportation Route Information for Shipments from

LSCS to the Proposed Yucca Mountain Repository Site(a) 29

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, 2015). Input to the RADTRAN 6.02

computer code was disaggregated to a state-by-state level.

30 Radiation doses are a function of many parameters, including vehicle speed, traffic count, dose

31 rate, packaging dimensions, number in the truck crew, stop time, and population density at 

32 stops. A list of the values for these and other parameters and the sources of the information is 

33 provided in Table G–2

34 For the purposes of this analysis, the transportation crew for spent fuel shipments delivered by 

35 truck is assumed to consist of two drivers. Escort vehicles and drivers were considered, but 

36 they were not included because their distance from the shipping cask would reduce the dose

37 rates to levels well below the dose rates experienced by the drivers and the dose rates would be 
Transportation Impacts of High Burnup Fuel

G-5

1 negligible (DOE 2002a). Stop times for refueling and rest were assumed to occur at the rate of 

2 30 minutes per 4 hours of driving time. TRAGIS outputs were used to determine the number of 

3 stops. Doses to the public at truck stops have been significant contributors to the doses

4 calculated in previous RADTRAN 6.02 analyses. For this analysis, doses to the public at 

5 refueling and rest stops (i.e., stop doses) are the sum of the doses to individuals located in two 

6 annular rings centered at the stopped vehicle, as illustrated in Figure G–1. The inner ring 

7 represents persons who may be at the truck stop at the same time as a spent fuel shipment and 

8 extends 1 to 10 m from the edge of the vehicle. The outer ring represents persons who reside 

9 near a truck stop and it extends from 10 to 800 m from the vehicle. This scheme is similar to 

10 that used by Sprung et al. (2000). Population densities and shielding factors were also taken 

11 from Sprung et al. (2000), which were based on observations in Griego et al. (1996).

12 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 (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 (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

13 The results of these normal (incident-free) exposure calculations are shown in Table G–3

14 Population dose estimates are given for workers (truck crew members), onlookers (doses to 
Transportation Impacts of High Burnup Fuel

G-6

1 persons at stops and persons on highways exposed to the spent fuel shipment), and persons 

2 along the route (persons living near the highway).

3 Shipping schedules for spent fuel generated by LSCS have not been determined. The NRC 

4 staff determined that it is reasonable to calculate annual doses assuming the annual number of 

5 spent fuel shipments is equivalent to the annual refueling requirements. Population doses were 

6 normalized to the reference LWR in WASH–1238 (880 MWe (net)) (AEC 1972). This 

7 corresponds to a 1,100-MWe LWR operating at 80-percent capacity.

8 Figure G–1. Illustration of Truck Stop Model

9 Annual Normal (Incident-Free) Radiation Doses to Transport Workers and the 

10 Public from Shipping Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 

11 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

1 The bounding cumulative doses to the exposed population given in Table S–4 are as follows:

2 • 4 person-rem per reactor-year to transport workers and

3 • 3 person-rem per reactor-year to general public (onlookers) and members of the 

4 public along the route.

5 The calculated population doses to onlookers for the reference LWR and the LSCS shipments 

6 exceed Table S–4 values. One of the key reasons for the higher population doses relative to 

7 Table S–4 is the longer shipping distances assumed for this analysis (i.e., to a proposed 

8 repository in Nevada) than the distances used in WASH–1238 (AEC 1972). WASH–1238 

9 assumed that each spent fuel shipment would travel a distance of 1,000 mi, whereas the 

10 shipping distances used in this SEIS were about 1,800 mi. If the shorter distance were used to 

11 calculate the impacts for LSCS spent fuel shipments, the doses to onlookers would be reduced 

12 by about 40 percent to 14 person-rem for the reference LWR and to 9.5 person-rem for the 

13 LSCS shipments. In addition, some of the other key conservative assumptions in the analysis 

14 were as follows:

15 • Use of the regulatory maximum dose rate (10 millirem (mrem) per hour at 2 m) in the 

16 RADTRAN calculations. The shipping casks assumed in the environmental impact 

17 statement prepared by DOE in support of the application for a geologic repository at 

18 the proposed Yucca Mountain repository site (DOE 2002a) would transport spent 

19 fuel that has cooled for a minimum of 5 years (see Subpart B of 10 CFR Part 961). 

20 Most spent fuel would have cooled for much longer than 5 years before being

21 shipped to a possible geologic repository. Based on this, shipments from LSCS also 

22 are expected to be cooled for longer than 5 years. Consequently, the estimated 

23 population doses in Table G–3 could be further reduced if more realistic dose rate 

24 projections are used.

25 • Use of the shipping cask capacity used in WASH–1238 (AEC 1972). The 

26 WASH–1238 analyses that form the basis for Table S–4 assumed that spent fuel

27 would be shipped at least 90 days after discharge from a current LWR. The spent 

28 fuel shipping casks described in WASH–1238 were designed to transport 

29 90-day-cooled fuel; therefore, their shielding and containment designs must 

30 accommodate this highly radioactive cargo. Shipping cask capacities assumed in 

31 WASH–1238 were approximately 0.5 MTU per truck cask. DOE (2008) assumed a 

32 10-year cooling period for spent fuel to be shipped to the repository. This cooling 

33 period allowed DOE to increase the assumed shipping cask capacity to about 

34 0.88 MTU per truck shipment of spent fuel. The NRC staff believes this is a 

35 reasonable projection for future spent fuel truck shipping cask capacities. If this 

36 assumption was used in this SEIS, the number of shipments of spent fuel would be 

37 reduced by about 40 percent to 23 shipments with a similar reduction in incident-free 

38 radiological impacts.

39 • Use of 30 minutes as the average time at a truck stop in the calculations. Many 

40 stops made for actual spent fuel shipments are of short duration (i.e., 10 minutes) for 

41 brief visual inspections of the cargo (e.g., checking the cask tie-downs). These stops 

42 typically occur in minimally populated areas (e.g., an overpass or freeway ramp in an 

43 unpopulated area). Furthermore, empirical data provided by Griego et al. 1996 

44 indicate that a 30-minute duration is toward the high end of the stop time distribution. 

45 Average stop times observed by Griego et al. 1996 were about 18 minutes. More 

46 realistic stop times would further reduce the population doses in Table G–3
Transportation Impacts of High Burnup Fuel

G-8

1 A sensitivity study was performed by the NRC staff to demonstrate the effects of using more 

2 realistic dose rates and stop times on the incident-free population dose calculations for 

3 shipments of LSCS spent fuel. For this sensitivity study, the dose rate was reduced to 5 mrem

4 per hour, which is the approximate 50-percent confidence interval of the dose rate distribution 

5 estimated by Sprung et al. (2000) for future spent fuel shipments. The number of shipments 

6 was reduced to 23 shipments per year, and the stop time was reduced to 18 minutes per stop. 

7 All other RADTRAN 6.02 input values were unchanged. The result is that the annual crew 

8 doses, onlooker doses, and doses to persons along the route were reduced by about 80 percent 

9 of the annual doses shown in Table G–3 to 0.29 person-rem, 2.7 person-rem, and 

10 0.078 person-rem, respectively. If the shipping distance was reduced from 1,800 mi to 1,000 mi 

11 as discussed above, the annual crew doses, onlooker doses, and doses to persons along the 

12 route would be further reduced to 0.16 person-rem, 1.5 person-rem, and 0.043 person-rem, 

13 respectively.

14 Radiation protection experts assume that any amount of radiation may pose some risk of 

15 causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 

16 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 

17 relationship between radiation dose and detriments, such as cancer induction. The National 

18 Research Council (National Research Council 2006) uses the linear, no-threshold dose 

19 response model as a basis for estimating the risks from low doses. This approach is accepted 

20 by the NRC as a conservative method for estimating health risks from radiation exposure, 

21 recognizing that the model may overestimate those risks. Based on this method, the NRC staff 

22 estimated the risk to the public from radiation exposure using the nominal probability coefficient 

23 for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 

24 severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem. 

25 The coefficient is taken from the International Commission on Radiological Protection (ICRP) 

26 Publication 103 (ICRP 2007).

27 Both the National Council on Radiation Protection and Measurements (NCRP) and ICRP 

28 suggest that when the collective effective dose is smaller than the reciprocal of the relevant risk 

29 detriment (in other words, less than 1/0.00057, which is less than 1,754 person-rem), the risk 

30 assessment should note that the most likely number of excess health effects is zero 

31 (NCRP 1995; ICRP 2007). The annual public dose impacts for transporting spent fuel from 

32 LSCS to the proposed Yucca Mountain repository site were estimated to be about 

33 17 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 

34 NCRP (1995) suggest would most likely result in zero excess health effects. 

35 To place these impacts in perspective, the average U.S. resident receives about 311 mrem per 

36 year effective dose equivalent from natural background radiation (i.e., exposures from cosmic 

37 radiation; naturally occurring radioactive materials, such as radon; and global fallout from testing 

38 of nuclear explosive devices) (NCRP 2009). Using this average effective dose, the collective 

39 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 40 person-rem. Therefore, 

41 the radiation doses from transporting irradiated fuel from LSCS to the proposed Yucca Mountain 

42 repository site are minimal compared to the collective population dose to the same population 

43 from exposure to natural sources of radiation. This assessment is a comparative assessment 

44 for which there is no regulatory standard to base an impact level, and, again, it is provided only 

45 to place the impacts in perspective.
Transportation Impacts of High Burnup Fuel

G-9

1 G.3.2. Radiological Impacts of Accidents

2 As discussed previously, the NRC staff used the RADTRAN 6.02 computer code to estimate the 

3 impacts of transportation accidents involving spent fuel shipments. RADTRAN 6.02 considers a 

4 spectrum of postulated transportation accidents, ranging from those with high frequencies and 

5 low consequences (e.g., “fender benders”) to those with low frequencies and high 

6 consequences (i.e., accidents in which the shipping container is exposed to severe mechanical 

7 and thermal conditions).

8 Radionuclide inventories are important parameters in the calculation of accident risks. The 

9 radionuclide inventories used in this analysis were from the Exelon ER (Exelon 2014a, 2015). 

10 The spent fuel inventory used in the NRC staff analysis is listed in Table G–4 and is based on a 

11 burnup of 75,000 MWd/MTU.

12 Robust shipping casks are used to transport spent fuel because of the radiation shielding and 

13 accident resistance required by 10 CFR Part 71. Spent fuel shipping casks must be certified 

14 Type B packaging systems, which means that they must withstand a series of severe postulated 

15 accident conditions with essentially no loss of containment or shielding capability. These casks 

16 also are designed with fissile material controls to ensure that the spent fuel remains subcritical 

17 under normal and accident conditions. According to Sprung et al. (2000), the probability of 

18 encountering accident conditions that would lead to shipping cask failure is less than 

19 0.01 percent (i.e., more than 99.99 percent of all accidents would result in no release of

20 radioactive material from the shipping cask). The NRC staff assumed that shipping casks 

21 approved for transportation of LSCS spent fuel would provide equivalent mechanical and 

22 thermal protection of the spent fuel cargo.

23 Accident frequencies are calculated in RADTRAN 6.02 using user-specified accident rates and 

24 conditional shipping cask failure probabilities. State-specific accident rates were taken from 

25 Weiner et al. (2015) and used in the RADTRAN 6.02 calculations. Conditional shipping cask 

26 failure probabilities (i.e., the probability of cask failure as a function of the mechanical and 

27 thermal conditions applied in an accident) were taken from Sprung et al. 2000.

28 The RADTRAN 6.02 accident risk calculations were performed using the radionuclide 

29 inventories (curie(s) per metric ton of uranium [Ci/MTU]) in Table G–4 multiplied by the shipping 

30 cask capacity (0.5 MTU). The resulting risk estimates were then multiplied by assumed annual 

31 spent fuel shipments (shipments per year) to derive estimates of the annual accident risks 

32 associated with spent fuel shipments from LSCS to the proposed Yucca Mountain repository 

33 site in Nevada. As was done for routine exposures, the NRC staff assumed that the numbers of 

34 shipments of spent fuel per year are equivalent to the annual discharge quantities. For this 

35 assessment, release fractions for current-generation LWR fuel designs (Sprung et al. 2000) 

36 were used. 

37 The NRC staff used RADTRAN 6.02 to calculate the population dose from the released 

radioactive material from four of five possible exposure pathways.12 38 These pathways are as 

39 follows:

40 • External dose from exposure to the passing cloud of radioactive material 

41 (cloudshine).

42 • External dose from the radionuclides deposited on the ground by the passing plume 

43 (groundshine). The NRC staff’s analysis included the radiation exposure from this 

 12 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

1 pathway even though the area surrounding a potential accidental release would be 

2 evacuated and decontaminated, thus preventing long-term exposures from this 

3 pathway.

4 • Internal dose from inhalation of airborne radioactive contaminants (inhalation).

5 • Internal dose from resuspension of radioactive materials that were deposited on the 

6 ground (resuspension). The NRC staff’s analysis included the radiation exposures 

7 from this pathway even though evacuation and decontamination of the area 

8 surrounding a potential accidental release would prevent long-term exposures.

9 Radionuclide Inventories Used in Transportation 

Accident Risk Calculations for the LSCS Reactors(a)(b) 10

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
Transportation Impacts of High Burnup Fuel

G-11

Radionuclide Inventory Ci/Assembly Inventory Ci/MTU

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

(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, 2015)

1 Table G–5 presents the environmental consequences of transportation accidents when shipping 

2 spent fuel from LSCS to the proposed Yucca Mountain repository site. The shipping distances 

3 and population distribution information for the routes were the same as those used for the 

4 normal incident-free conditions (see Section G.3.1). The results are normalized to the 

5 WASH–1238 (AEC 1972) reference reactor (880-MWe) net electrical generation (1,100-MWe 

6 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 7 person-rem per year) are less than 

the reference LWR impacts (1.8x10−5 8 person-rem per year). The transportation accident impact 

9 analysis conducted by Exelon (Exelon 2014a, 2015) used methods and data that are similar to 

10 those used in this SEIS. The differences are insignificant in terms of the overall results.

11 Annual Spent Fuel Transportation Accident Impacts from Shipping Spent Fuel 

12 from LSCS to the Proposed Yucca Mountain Repository Site, Normalized to Reference 

13 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

14 Radiation protection experts assume that any amount of radiation may pose some risk of 

15 causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 

16 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 

17 relationship between radiation dose and detriments, such as cancer induction. The National 

18 Research Council (National Research Council 2006) uses the linear, no-threshold dose 

19 response model as a basis for estimating the risks from low doses. This approach is accepted 

20 by the NRC as a conservative method for estimating health risks from radiation exposure, 

21 recognizing that the model may overestimate those risks. Based on this method, the NRC staff 

22 estimated the risk to the public from radiation exposure using the nominal probability coefficient 

23 for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 

24 severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem. 

25 The coefficient is taken from ICRP Publication 103 (ICRP 2007).

26 Both the NCRP and ICRP suggest that when the collective effective dose is smaller than the 

27 reciprocal of the relevant risk detriment (in other words, less than 1/0.00057, which is less than 

28 1,754 person-rem), the risk assessment should note that the most likely number of excess 

29 health effects is zero (NCRP 1995; ICRP 2007). The annual accident impacts from transporting 
Transportation Impacts of High Burnup Fuel

G-12

1 spent fuel from LSCS to the proposed Yucca Mountain repository site were estimated to be 

about 1.2x10-5 2 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 

3 NCRP (1995) suggest would most likely result in zero excess health effects. 

4 In addition, the collective population dose from natural background radiation to the population 

5 along the representative routes from LSCS to the proposed Yucca Mountain repository site 

would be about 1.6x105 6 person-rem. Therefore, the accident impacts from transporting spent 

7 fuel to the proposed Yucca Mountain repository site are minimal compared to the collective 

8 population dose to the same population from exposure to natural sources of radiation. This 

9 assessment is a comparative assessment for which there is no regulatory standard to base an 

10 impact level and is provided only to place the impacts in perspective.

11 G.3.3. Nonradiological Impacts of Accidents

12 A nonradiological accident is a truck accident in which the property damage, injuries, or fatalities 

13 are caused by the force of the impact; no release of, or exposure to, radiological materials 

14 occurs as a result of the truck accident. In WASH–1238 (AEC 1972) and NUREG–75/038 

15 (NRC 1975), the NRC staff assessed the impacts of these nonradiological truck accidents that 

16 may occur during the transport of fuel and waste to and from LWRs and estimated the impacts 

17 from these nonradiological accidents as one fatal injury in 100 reference reactor-years and one 

18 nonfatal injury in 10 reference reactor-years. Using data from the National Highway 

19 Transportation Safety Administration for large trucks over the period 2009 through 2013, NRC 

20 staff estimated that there would be less than one fatal injury per 100 reference reactor-years 

21 and less than one nonfatal injury per 10 reference reactor-years for shipments of spent fuel from 

22 LSCS to the proposed Yucca Mountain repository site. Therefore, the nonradiological impacts 

23 of accidents from the transportation of LSCS spent fuel would be small. 

24 Conclusions for Transportation Impacts of High Burnup Fuel

25 The NRC staff performed an independent confirmatory analysis of the impacts under normal 

26 operating and accident conditions of transporting irradiated fuel from LSCS to the proposed 

27 Yucca Mountain repository site. To make comparisons to Table S–4, the environmental impacts 

28 were adjusted (i.e., normalized) to the environmental impacts associated with the reference 

29 LWR in WASH–1238 (AEC 1972) by multiplying the LSCS impact estimates by the ratio of the 

30 total electric output for the reference reactor to the electric output of the LSCS reactors.

31 Because of the conservative approaches and data used to calculate impacts, the NRC staff 

32 does not expect the actual environmental effects to exceed those calculated in this SEIS. Thus, 

33 the NRC staff concludes that the environmental impacts of the transportation of irradiated fuel 

34 from LSCS would be SMALL and would be consistent with the environmental impacts

35 associated with the transportation of fuel and radioactive wastes to and from current-generation 

36 reactors presented in Table S–4 of 10 CFR 51.52.

37 The NRC staff concludes that transportation impacts are roughly proportional to the distance 

38 from LSCS to the repository site—in this case Illinois to Nevada. The distance from LSCS to 

39 any new planned repository in the contiguous United States would be no more than double the 

40 distance from LSCS to the proposed Yucca Mountain repository site. Doubling the 

41 environmental impact estimates from the transportation of spent reactor fuel, as presented in 

42 this section, would provide a reasonable bounding estimate of the impacts to meet the 

43 requirements of the National Environmental Policy Act of 1969, as amended (42 U.S.C. 4321

44 et seq.). The NRC staff concludes that the environmental impacts of these doubled estimates 

45 would not be significant and, therefore, would still be SMALL.
Transportation Impacts of High Burnup Fuel

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1 References

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3 licensing of production and utilization facilities.” 

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7 transportation of radioactive material.” 

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24 No. ML12192A286. 

25 [DOE] U.S. Department of Energy. 2008. “Final Supplemental Environmental Impact 

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28 DOE/EIS-0250F-S1. June 2008. Available at http://energy.gov/downloads/final-supplemental29 environmental-impact-statement-geologic-repository-disposal-spent-2 (accessed 

30 5 October 2015).

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

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37 [Exelon] Exelon Generation Company, LLC. 2015. LaSalle County Station, Units 1 and 2—

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42 Parameters for Truck Stops. Albuquerque, New Mexico: Sandia National Laboratories. 

43 March 13, 1996. ADAMS No. ML14111A188. 
Transportation Impacts of High Burnup Fuel

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1 [ICRP] International Commission on Radiological Protection. 2007. “The 2007 

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35 Guide. 




NUREG-1437

Supplement 57

Draft

Generic Environmental Impact Statement for License Renewal of Nuclear Plants 

Regarding LaSalle County Station, Units 1 and 2