Generic Environmental 

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 53

Regarding Sequoyah Nuclear 

Plant, Units 1 and 2

Draft Report for Comment

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 53
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Generic Environmental

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 53

Regarding Sequoyah Nuclear 

Plant, Units 1 and 2

Draft Report for Comment

Manuscript Completed: July 2014

Date Published: July 2014

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 53
1 COMMENTS ON DRAFT REPORT

2 Any interested party may submit comments on this report for consideration by the NRC staff. 

3 Comments may be accompanied by additional relevant information or supporting data. Please 

4 specify the report number NUREG-1437, Supplement 53 in your comments, and send them by 

5 the end of the comment period specified in the Federal Register notice announcing the 

6 availability of this report.

7 Addresses: You may submit comments by any one of the following methods. Please include 

8 Docket ID NRC-2013-0037 in the subject line of your comments. Comments submitted in 

9 writing or in electronic form will be posted on the NRC Web site and on the Federal rulemaking 

10 Web site http://www.regulations.gov. 

11 Federal Rulemaking Web site: Go to http://www.regulations.gov and search for documents 

12 filed under Docket ID NRC-2013-0037. Address questions about NRC dockets to 

13 Carol Gallagher at 301-287-3422 or by e-mail at Carol.Gallagher@nrc.gov. 

14 Mail comments to: Cindy Bladey, Chief, Rules, Announcements, and Directives Branch

15 (RADB), Division of Administrative Services, Office of Administration, Mail Stop: 

16 3WFN-06-A44MP, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. 

17 For any questions about the material in this report, please contact: David Drucker, Senior 

18 Project Manager, at phone number 301-415-6223 or by e-mail at david.drucker@nrc.gov. 

19 Please be aware that any comments that you submit to the NRC will be considered a public 

20 record and entered into the Agencywide Documents Access and Management System 

21 (ADAMS). Do not provide information you would 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 53, Regarding Sequoyah Nuclear Plant, Units 1 and 2, Draft Report for Comment 

6 (NUREG-1437). Sequoyah Nuclear Plant (SQN), Units 1 and 2, are located in Hamilton County, 

7 Tennessee.

8 For additional information or copies of this document contact:

9 Division of License Renewal

10 U.S. Nuclear Regulatory Commission

11 Office of Nuclear Reactor Regulation

12 Mail Stop O-11F1

13 11555 Rockville Pike

14 Rockville, Maryland 20852

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

16 Email: david.drucker@nrc.gov

17 ABSTRACT

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

19 application submitted by Tennessee Valley Authority (TVA) to renew the operating license for 

20 Sequoyah Nuclear Plant, Units 1 and 2 (SQN), for an additional 20 years.

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

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

23 natural gas combined-cycle generation, supercritical pulverized coal generation, new nuclear 

24 generation, combination wind and solar generation, and no renewal of the license (the no-action 

25 alternative).

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

27 adverse environmental impacts of license renewal for SQN are not great enough to deny the 

28 option of license renewal for energy-planning decisionmakers. This recommendation is based 

29 on the following:

30 • the analysis and findings in NUREG–1437, Generic Environmental Impact 

31 Statement for License Renewal of Nuclear Plants; 

32 • the Environmental Report submitted by TVA; 

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

34 • the NRC’s environmental review; and

35 • consideration of public comments received during the scoping process.

v 

1 TABLE OF CONTENTS

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

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

4 FIGURES.................................................................................................................................. xi

5 TABLES ................................................................................................................................. xiii

6 EXECUTIVE SUMMARY ....................................................................................................... xvii

7 ABBREVIATIONS AND ACRONYMS ...................................................................................xxiii

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

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

10 1.2 Purpose and Need for the 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 .......................................................... 1-5

14 1.6 Decision To Be Supported by the SEIS....................................................................... 1-5

15 1.7 Cooperating Agencies ................................................................................................. 1-6

16 1.8 Consultations .............................................................................................................. 1-6

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

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

19 1.11 Related Federal and State Activities.......................................................................... 1-7

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 Operation During the License Renewal Term .......................................... 2-1

24 2.1.2 Refurbishment and Other Activities Associated With License Renewal ............ 2-2

25 2.1.3 Termination of Nuclear Power Plant Operation and Decommissioning After 

26 the License Renewal Term ............................................................................. 2-2

27 2.2 Alternatives ................................................................................................................. 2-2

28 2.2.1 No-Action Alternative........................................................................................ 2-3

29 2.2.2 Replacement Power Alternatives...................................................................... 2-3

30 2.3 Alternatives Considered but Dismissed ..................................................................... 2-13

31 2.3.1 Wind Power.................................................................................................... 2-14

32 2.3.2 Solar Power.................................................................................................... 2-14

33 2.3.3 Conventional Hydroelectric Power.................................................................. 2-15

34 2.3.4 Geothermal Energy ........................................................................................ 2-16

35 2.3.5 Biomass Energy ............................................................................................. 2-16

36 2.3.6 Municipal Solid Waste .................................................................................... 2-17

37 2.3.7 Wood Waste................................................................................................... 2-18

38 2.3.8 Ocean Wave and Current Energy................................................................... 2-18
Table of Contents

vi

1 2.3.9 Oil-Fired Power............................................................................................... 2-18

2 2.3.10 Fuel Cells ..................................................................................................... 2-19

3 2.3.11 Coal-Fired Integrated Gasification Combined Cycle ..................................... 2-19

4 2.3.12 Delayed Retirement...................................................................................... 2-20

5 2.3.13 Energy Efficiency and Demand Side Management ....................................... 2-20

6 2.3.14 Purchased Power ......................................................................................... 2-21

7 2.4 Comparison of Alternatives ....................................................................................... 2-21

8 2.5 References................................................................................................................ 2-23

9 3.0 AFFECTED ENVIRONMENT............................................................................................ 3-1

10 3.1 Description of Nuclear Power Plant Facilities and Operation ....................................... 3-1

11 3.1.1 External Appearance and Setting ..................................................................... 3-1

12 3.1.2 Nuclear Reactor Systems ................................................................................. 3-5

13 3.1.3 Cooling and Auxiliary Water Systems ............................................................... 3-5

14 3.1.4 Radioactive Effluent, Waste, and Environmental Monitoring Programs........... 3-11

15 3.1.5 Nonradioactive Waste Management Systems ................................................ 3-17

16 3.1.6 Utility and Transportation Infrastructure .......................................................... 3-18

17 3.1.7 Nuclear Power Plant Operations and Maintenance......................................... 3-19

18 3.2 Land Use and Visual Resources ............................................................................... 3-20

19 3.2.1 Land Use........................................................................................................ 3-20

20 3.2.2 Visual Resources............................................................................................ 3-21

21 3.3 Meteorology, Air Quality, and Noise .......................................................................... 3-21

22 3.3.1 Meteorology and Climatology ......................................................................... 3-21

23 3.3.2 Air Quality....................................................................................................... 3-22

24 3.3.3 Noise.............................................................................................................. 3-24

25 3.4 Geologic Environment ............................................................................................... 3-25

26 3.5 Water Resources....................................................................................................... 3-28

27 3.5.1 Surface Water Resources............................................................................... 3-28

28 3.5.2 Groundwater Resources................................................................................. 3-35

29 3.6 Terrestrial Resources ................................................................................................ 3-38

30 3.6.1 SQN Ecoregion............................................................................................... 3-38

31 3.6.2 SQN Site and Vicinity ..................................................................................... 3-38

32 3.6.3 Transmission Line Corridors........................................................................... 3-48

33 3.7 Aquatic Resources .................................................................................................... 3-48

34 3.7.1 Description of the Tennessee River................................................................ 3-48

35 3.7.2 Description of Chickamauga Reservoir........................................................... 3-50

36 3.8 Special Status Species and Habitats......................................................................... 3-74

37 3.8.1 Species and Habitats Protected Under the Endangered Species Act ............. 3-75

38 3.8.2 Species and Habitats Protected Under the Magnuson–Stevens Act............... 3-87

39 3.9 Historic and Cultural Resources ................................................................................ 3-87

40 3.9.1 Cultural Background ....................................................................................... 3-88

41 3.9.2 Historic and Cultural Resources ..................................................................... 3-89
Table of Contents

vii

1 3.10 Socioeconomics ...................................................................................................... 3-92

2 3.10.1 Power Plant Employment and Expenditures ................................................. 3-92

3 3.10.2 Regional Economic Characteristics .............................................................. 3-93

4 3.10.3 Demographic Characteristics........................................................................ 3-95

5 3.10.4 Housing and Community Services .............................................................. 3-100

6 3.10.5 Tax Revenues ............................................................................................ 3-101

7 3.10.6 Local Transportation................................................................................... 3-102

8 3.11 Human Health ....................................................................................................... 3-103

9 3.11.1 Radiological Exposure and Risk ................................................................. 3-103

10 3.11.2 Chemical Hazards ...................................................................................... 3-104

11 3.11.3 Microbiological Hazards.............................................................................. 3-104

12 3.11.4 Electromagnetic Fields ............................................................................... 3-106

13 3.11.5 Other Hazards ............................................................................................ 3-107

14 3.12 Environmental Justice ........................................................................................... 3-108

15 3.12.1 Minority Population ..................................................................................... 3-109

16 3.12.2 Low-Income Population .............................................................................. 3-111

17 3.13 Waste Management and Pollution Prevention ....................................................... 3-113

18 3.13.1 Radioactive Waste...................................................................................... 3-113

19 3.13.2 Nonradioactive Waste................................................................................. 3-113

20 3.14 References............................................................................................................ 3-113

21 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS............................. 4-1

22 4.1 Introduction ................................................................................................................. 4-1

23 4.2 Land Use and Visual Resources ................................................................................. 4-1

24 4.2.1 Proposed Action ............................................................................................... 4-1

25 4.2.2 No-Action Alternative – Land Use and Visual Resources.................................. 4-2

26 4.2.3 NGCC Alternative – Land Use and Visual Resources....................................... 4-2

27 4.2.4 SCPC Alternative – Land Use and Visual Resources ....................................... 4-3

28 4.2.5 New Nuclear Alternative – Land Use and Visual Resources............................. 4-4

29 4.2.6 Combination Alternative – Land Use and Visual Resources ............................. 4-5

30 4.3 Air Quality and Noise................................................................................................... 4-6

31 4.3.1 Proposed Action ............................................................................................... 4-6

32 4.3.2 No-Action Alternative – Air Quality and Noise................................................... 4-8

33 4.3.3 NGCC Alternative – Air Quality and Noise........................................................ 4-8

34 4.3.4 SCPC Alternative – Air Quality and Noise....................................................... 4-10

35 4.3.5 New Nuclear Alternative – Air Quality and Noise ............................................ 4-11

36 4.3.6 Combination Alternative – Air Quality and Noise............................................. 4-12

37 4.3.7 Air Quality and Noise Summary...................................................................... 4-13

38 4.4 Geologic Environment ............................................................................................... 4-14

39 4.4.1 Proposed Action ............................................................................................. 4-14

40 4.4.2 No-Action Alternative – Geology and Soils ..................................................... 4-15

41 4.4.3 Alternatives to the Proposed Action – Geology and Soils ............................... 4-15
Table of Contents

viii

1 4.4.4 NGCC Alternative – Geology and Soils .......................................................... 4-15

2 4.4.5 SCPC Alternative – Geology and Soils ........................................................... 4-15

3 4.4.6 New Nuclear Alternative – Geology and Soils................................................. 4-15

4 4.4.7 Combination Alternative – Geology and Soils ................................................. 4-15

5 4.5 Water Resources....................................................................................................... 4-16

6 4.5.1 Proposed Action ............................................................................................. 4-16

7 4.5.2 No-Action Alternative - Water Resources........................................................ 4-21

8 4.5.3 NGCC Alternative - Water Resources............................................................. 4-21

9 4.5.4 SCPC Alternative - Water Resources ............................................................. 4-23

10 4.5.5 New Nuclear Alternative - Water Resources................................................... 4-23

11 4.5.6 Combination Alternative - Water Resources ................................................... 4-24

12 4.6 Terrestrial Resources ................................................................................................ 4-25

13 4.6.1 Proposed Action ............................................................................................. 4-25

14 4.6.2 No-Action Alternative – Terrestrial Resources ................................................ 4-28

15 4.6.3 NGCC Alternative – Terrestrial Resources ..................................................... 4-28

16 4.6.4 SCPC Alternative – Terrestrial Resources...................................................... 4-28

17 4.6.5 New Nuclear Alternative – Terrestrial Resources............................................ 4-29

18 4.6.6 Combination Alternative – Terrestrial Resources............................................ 4-29

19 4.7 Aquatic Resources .................................................................................................... 4-30

20 4.7.1 Proposed Action ............................................................................................. 4-30

21 4.7.2 No-Action Alternative – Aquatic Resources .................................................... 4-42

22 4.7.3 NGCC Alternative – Aquatic Resources ......................................................... 4-42

23 4.7.4 SCPC Alternative – Aquatic Resources .......................................................... 4-43

24 4.7.5 New Nuclear Alternative – Aquatic Resources................................................ 4-43

25 4.7.6 Combination Alternative - Aquatic Resources................................................. 4-44

26 4.8 Special Status Species and Habitats......................................................................... 4-44

27 4.8.1 Proposed Action ............................................................................................. 4-44

28 4.8.2 No-Action Alternative – Special Status Species and Habitats ......................... 4-46

29 4.8.3 NGCC Alternative – Special Status Species and Habitats .............................. 4-47

30 4.8.4 SCPC Alternative – Special Status Species and Habitats............................... 4-48

31 4.8.5 New Nuclear Alternative – Special Status Species and Habitats .................... 4-48

32 4.8.6 Combination Alternative – Special Status Species and Habitats..................... 4-48

33 4.9 Historic and Cultural Resources ................................................................................ 4-49

34 4.9.1 Proposed Action ............................................................................................. 4-49

35 4.9.2 No-Action Alternative – Historic and Cultural Resources ................................ 4-52

36 4.9.3 NGCC Alternative – Historic and Cultural Resources ..................................... 4-52

37 4.9.4 SCPC Alternative – Historic and Cultural Resources ...................................... 4-52

38 4.9.5 New Nuclear Alternative – Historic and Cultural Resources............................ 4-53

39 4.9.6 Combination Alternative – Historic and Cultural Resources ............................ 4-53
Table of Contents

ix

1 4.10 Socioeconomics ...................................................................................................... 4-54

2 4.10.1 Proposed Action ........................................................................................... 4-54

3 4.10.2 No-Action Alternative – Socioeconomics ...................................................... 4-55

4 4.10.3 NGCC Alternative – Socioeconomics ........................................................... 4-55

5 4.10.4 SCPC Alternative – Socioeconomics ............................................................ 4-57

6 4.10.5 New Nuclear Alternative – Socioeconomics.................................................. 4-58

7 4.10.6 Combination Alternative – Socioeconomics .................................................. 4-59

8 4.11 Human Health ......................................................................................................... 4-60

9 4.11.1 Proposed Action ........................................................................................... 4-60

10 4.11.2 No-Action Alternative.................................................................................... 4-78

11 4.11.3 NGCC Alternative – Human Health............................................................... 4-79

12 4.11.4 SCPC Alternative – Human Health ............................................................... 4-79

13 4.11.5 New Nuclear Alternative – Human Health..................................................... 4-80

14 4.11.6 Combination Alternative – Human Health ..................................................... 4-80

15 4.12 Environmental Justice ............................................................................................. 4-81

16 4.12.1 Proposed Action ........................................................................................... 4-81

17 4.12.2 No-Action Alternative – Environmental Justice ............................................. 4-83

18 4.12.3 NGCC Alternative – Environmental Justice................................................... 4-83

19 4.12.4 SCPC Alternative – Environmental Justice ................................................... 4-84

20 4.12.5 New Nuclear Alternative – Environmental Justice......................................... 4-84

21 4.12.6 Combination Alternative – Environmental Justice ......................................... 4-85

22 4.13 Waste Management ................................................................................................ 4-86

23 4.13.1 Proposed Action ........................................................................................... 4-86

24 4.13.2 No-Action Alternative – Waste Management ................................................ 4-87

25 4.13.3 NGCC Alternative – Waste Management...................................................... 4-87

26 4.13.4 SCPC Alternative – Waste Management ...................................................... 4-88

27 4.13.5 New Nuclear Alternative – Waste Management............................................ 4-88

28 4.13.6 Combination Alternative – Waste Management ............................................ 4-89

29 4.14 Evaluation of New and Potentially Significant Information ....................................... 4-89

30 4.15 Impacts Common to All Alternatives ........................................................................ 4-90

31 4.15.1 Fuel Cycles................................................................................................... 4-90

32 4.15.2 Terminating Power Plant Operations and Decommissioning......................... 4-92

33 4.15.3 Greenhouse Gas Emissions and Climate Change........................................ 4-93

34 4.16 Cumulative Impacts of the Proposed Action .......................................................... 4-101

35 4.16.1 Air Quality and Noise.................................................................................. 4-102

36 4.16.2 Geology and Soils ...................................................................................... 4-104

37 4.16.3 Water Resources........................................................................................ 4-105

38 4.16.4 Terrestrial Ecology...................................................................................... 4-110

39 4.16.5 Aquatic Ecology.......................................................................................... 4-111

40 4.16.6 Historic and Cultural Resources ................................................................. 4-115

41 4.16.7 Socioeconomics ......................................................................................... 4-116
Table of Contents

x 

1 4.16.8 Human Health............................................................................................. 4-118

2 4.16.9 Environmental Justice................................................................................. 4-119

3 4.16.10 Waste Management.................................................................................. 4-121

4 4.16.11 Global Climate Change............................................................................. 4-122

5 4.16.12 Summary of Cumulative Impacts .............................................................. 4-123

6 4.17 Resource Commitments ........................................................................................ 4-126

7 4.17.1 Unavoidable Adverse Environmental Impacts............................................. 4-126

8 4.17.2 Short-Term Versus Long-Term Productivity................................................ 4-127

9 4.17.3 Irreversible and Irretrievable Commitments of Resources........................... 4-127

10 4.18 References............................................................................................................ 4-128

11 5.0 CONCLUSION.................................................................................................................. 5-1

12 5.1 Environmental Impacts of License Renewal ................................................................ 5-1

13 5.2 Comparison of Alternatives ......................................................................................... 5-1

14 5.3 Recommendation ........................................................................................................ 5-1

15 6.0 LIST OF PREPARERS ..................................................................................................... 6-1

16 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES OF 

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

18 8.0 INDEX............................................................................................................................... 8-1

19 APPENDIX A COMMENTS RECEIVED ON THE SQN ENVIRONMENTAL REVIEW ........... A-1

20 APPENDIX B APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS....... B-1

21 APPENDIX C CONSULTATION CORRESPONDENCE ........................................................ C-1

22 APPENDIX D CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE ...... D-1

23 APPENDIX E ACTIONS AND PROJECTS CONSIDERED IN CUMULATIVE ANALYSIS.... E-1

24 APPENDIX F U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

25 SEVERE ACCIDENT MITIGATION ALTERNATIVES ..................................... F-1
Table of Contents

xi

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 3–1. SQN 50-mi Radius Map ..................................................................................... 3-2

5 Figure 3–2. SQN 6-mi Radius Map ....................................................................................... 3-3

6 Figure 3–3. SQN General Site Layout................................................................................... 3-4

7 Figure 3–4. Location of SQN Cooling Water Supply Facilities and Surface Water 

8 Features............................................................................................................. 3-7

9 Figure 3–5. Site Geologic Formations and Structure........................................................... 3-27

10 Figure 3–6. Locations of Inadvertent Liquid Releases Containing Tritium ........................... 3-37

11 Figure 3–7. Land Cover at the SQN Site............................................................................. 3-40

12 Figure 3–8. Typical Food Web for the Chickamauga Reservoir........................................... 3-51

13 Figure 3–9. 2010 Census Minority Block Groups Within a 50-mi Radius of SQN .............. 3-110

14 Figure 3–10. 2010 Census Low-Income Block Groups Within a 50-mi Radius of SQN........ 3-112

15 Figure 4–1. Analysis of Hydrothermal Conditions for the Tennessee Valley Reflecting 

16 Observed Air Temperature and Estimated Natural River Flow at 

17 Chattanooga, Tennessee ............................................................................... 4-109

Table of Contents

xiii

1 TABLES

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

3 License Renewal ............................................................................................... xix

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

5 Considered in Depth......................................................................................... 2-6

6 Table 2–2. Summary of Environmental Impacts of Proposed Action and Alternatives ...... 2-22

7 Table 3–1. Air Emission Estimates for Permitted Combustion Sources at SQN................ 3-24

8 Table 3–2. Common Noise Sources and Sound Levels.................................................... 3-25

9 Table 3–3. SQN Reported Annual Water Withdrawals and Return Discharges to 

10 Chickamauga Reservoir ................................................................................. 3-31

11 Table 3–4. Ecological Health Indicators for Chickamauga Reservoir, 2011 ...................... 3-33

12 Table 3–5. Primary Land Cover on the SQN Site ............................................................. 3-39

13 Table 3–6. State-listed Plant Species in Hamilton County ................................................ 3-43

14 Table 3–7. Most Common or Abundant Wildlife on or Within the Vicinity of the SQN 

15 Site................................................................................................................. 3-45

16 Table 3–8. State-Listed Bird Species in Hamilton County................................................. 3-47

17 Table 3–9. Average Mean Density Per Square Meter of Benthic Taxa Collected at 

18 Downstream and Upstream Sites Near SQN .................................................. 3-55

19 Table 3–10. Results of the Native Mussel and Snail Survey Near the SQN Site in 

20 2010 ............................................................................................................... 3-57

21 Table 3–11. Species Identified During Sampling Studies in the Vicinity of the SQN 

22 Site From 1999 to 2011 .................................................................................. 3-59

23 Table 3–12. Percent Composition of the Dominant Species Caught Upstream and 

24 Downstream of the SQN Site by Electrofishing, 2002 Through 2011 .............. 3-61

25 Table 3–13. Percent Composition of the Dominant Species Caught Upstream and 

26 Downstream of the SQN Site by Gillnetting, 2002 Through 2011.................... 3-62

27 Table 3–14. Percent of Fish in Each Trophic Group by Season and Location in 2011........ 3-63

28 Table 3–15. Commercial Harvest Rates for Paddlefish From Chickamauga 

29 Reservoir: 2008 to 2012 ................................................................................ 3-64

30 Table 3–16. Commercial Harvest Rates for Nonroe Fish and Turtles From 

31 Chickamauga Reservoir From 2008 to 2011................................................... 3-65

32 Table 3–17. Number of Fish Caught in Annual Creel Surveys of the Chickamauga 

33 Reservoir........................................................................................................ 3-66

34 Table 3–18. State-Listed Protected Aquatic Species Present in Hamilton County, TN ....... 3-73

35 Table 3–19. Federally Listed Species in Hamilton County, TN ........................................... 3-77

36 Table 3–20. Known Occurrences of Federally Listed Mussels in and Near the Action 

37 Area................................................................................................................ 3-85

38 Table 3–21. Cultural Resources Within the SQN Site......................................................... 3-92

39 Table 3–22. 2010 SQN Employee Residence by County ................................................... 3-93

40 Table 3–23. Major Employers of the SQN ROI in 2012 ...................................................... 3-94

41 Table 3–24. Estimated Income Information for the SQN ROI in 2011................................. 3-94

42 Table 3–25. 2007−2012 Annual Unemployment Rates in the SQN ROI ............................. 3-95
Table of Contents

xiv

1 Table 3–26. Population and Percent Growth in SQN ROI Counties 1970–2010, 2012, 

2 and Projected for 2020–2060.......................................................................... 3-95

3 Table 3–27. Demographic Profile of the Population in the SQN Socioeconomic 

4 Region of Influence in 2010 ............................................................................ 3-96

5 Table 3–28. 2007-2011 Estimated Seasonal Housing in Counties Located Within 

6 50 Mi of SQN.................................................................................................. 3-97

7 Table 3–29. Migrant Farm Workers and Temporary Farm Labor in Counties Located 

8 Within 50 Mi of SQN ....................................................................................... 3-99

9 Table 3–30. Housing in the SQN ROI............................................................................... 3-100

10 Table 3–31. Public School System Statistics, 2010–11 School Year................................ 3-100

11 Table 3–32. Local Public Water Supply Systems ............................................................. 3-101

12 Table 3–33. 2008−2011 Payments in Lieu of Taxes Attributable to SQN ......................... 3-102

13 Table 3–34. Major Commuting Routes in the Vicinity of SQN: 2012 AADT...................... 3-102

14 Table 4–1. Land Use and Visual Resources....................................................................... 4-2

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

16 Table 4–3. Estimated Direct Air Emissions from Operation of SQN, NGCC, SCPC, 

17 New Nuclear, and Combination Alternative..................................................... 4-14

18 Table 4–4. Geology and Soils .......................................................................................... 4-14

19 Table 4–5. Surface Water Resources............................................................................... 4-16

20 Table 4–6. Reservoir Operating System, Minimum Flows for Chickamauga Dam ............ 4-18

21 Table 4–7. Groundwater................................................................................................... 4-20

22 Table 4–8. Terrestrial Resources ..................................................................................... 4-26

23 Table 4–9. Aquatic Resources ......................................................................................... 4-31

24 Table 4–10. List of Fish Species by Family, Scientific, and Common Name and 

25 Numbers Collected in Impingement Samples From 2005 Through 2007 

26 at the SQN Intake........................................................................................... 4-35

27 Table 4–11. Entrainment Percentages for Fish Eggs and Larvae at Sequoyah 

28 Nuclear Plant 1981–1985 and 2004................................................................ 4-38

29 Table 4–12. Total Estimated Numbers of Fish Impinged by Year at SQN and TVA’s 

30 Modeled Numbers Using Equivalent Adult and Production Foregone 

31 Models............................................................................................................ 4-40

32 Table 4–13. Special Status Species and Habitats .............................................................. 4-45

33 Table 4–14. Effect Determinations for Federally Listed Species......................................... 4-45

34 Table 4–15. Historic and Cultural Resources ..................................................................... 4-49

35 Table 4–16. Socioeconomic Issues.................................................................................... 4-54

36 Table 4–17. Human Health Issues ..................................................................................... 4-61

37 Table 4–18. Issues Related to Postulated Accident............................................................ 4-64

38 Table 4–19. SQN Units 1 and 2 CDF for Internal Events.................................................... 4-67

39 Table 4–20. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 

40 for Internal Events .......................................................................................... 4-69

41 Table 4–21. Estimated Cost Ranges of SAMA Implementation Costs at SQN.................... 4-71

42 Table 4–22. Potentially Cost-Beneficial SAMAs for Units 1 and 2 of the SQN .................... 4-72

43 Table 4–23. Environmental Justice..................................................................................... 4-81
Table of Contents

xv 

1 Table 4–24. Waste Management........................................................................................ 4-86

2 Table 4–25. Issues Related to the Uranium Fuel Cycle ...................................................... 4-90

3 Table 4–26. Issues Related to Decommissioning ............................................................... 4-92

4 Table 4–27. Estimated GHG emissions from Operations at SQN....................................... 4-95

5 Table 4–28. Direct GHG Emissions from Operation of the Proposed Action and 

6 Alternatives..................................................................................................... 4-96

7 Table 4–29. Comparison of GHG Emission Inventories.................................................... 4-124

8 Table 4–30. Summary of Cumulative Impacts on Resource Areas ................................... 4-124

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

10 Table A–1. Individuals Providing Comments During the Scoping Comment Period................. A-2

11 Table A–2. Issue Categories................................................................................................... A-3

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

13 Table B–2. Licenses and Permits............................................................................................ B-5

14 Table C–1. ESA Section 7 Consultation Correspondence....................................................... C-3

15 Table C–2. NHPA Correspondence ........................................................................................ C-4

16 Table D–1. Environmental Review Correspondence ............................................................... D-2

17 Table E–1. Actions and Projects Considered in Cumulative Analysis...................................... E-2

18 Table F–1. SQN Units 1 and 2 CDF for Internal Events .......................................................... F-3

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

20 for Internal Events .............................................................................................. F-5

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

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

23 Table F–4. Significant Fire Areas at SQN Included in Final Screening Phase and Their 

24 Corresponding CDF ......................................................................................... F-15

25 Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN ................................ F-28

xvii

1 EXECUTIVE SUMMARY

2 BACKGROUND

3 By letter dated January 7, 2013, Tennessee Valley Authority (TVA), submitted an application to 

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

5 Sequoyah Nuclear Plant, Units 1 and 2 (SQN) for an additional 20-year period.

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

7 renewal of a power reactor operating license requires preparation of an environmental impact 

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

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

10 supplement to the Commission’s NUREG-1437, Generic Environmental Impact Statement

11 (GEIS) for License Renewal of Nuclear Plants. 

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

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

14 (SEIS) and conduct scoping. In preparation of this SEIS for SQN, the NRC staff performed the 

15 following:

16 • conducted public scoping meetings on April 3, 2013, in Soddy-Daisy, 

17 Tennessee;

18 • conducted a site audit at SQN on April 7–11, 2013;

19 • reviewed TVA’s Environmental Report and compared it to the GEIS; 

20 • consulted with Federal, state, and local agencies;

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

22 NUREG-1555, Standard Review Plans for Environmental Reviews for 

23 Nuclear Power Plants, Supplement 1, Revision 1: Operating License 

24 Renewal; and

25 • considered public comments received during the scoping process.

26 PROPOSED FEDERAL ACTION

27 TVA initiated the proposed Federal action—issuing renewed power reactor operating licenses—

28 by submitting an application for license renewal of SQN, for which the existing licenses (DPR-77 

29 and DPR-79) expire on September 17, 2020, and September 15, 2021, respectively. The 

30 NRC’s Federal action is the decision whether or not to renew the licenses for an additional 

31 20 years. In accordance with 10 CFR 2.109, if a licensee of a nuclear power plant files an 

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

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

34 environmental reviews are completed and the NRC has made a final decision to either deny the 

35 application or issue a renewed license for the additional 20 years. 

36 PURPOSE AND NEED FOR THE PROPOSED FEDERAL ACTION

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

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

39 plant operating license to meet future system generating needs. Such needs may be 
Executive Summary

xviii

1 determined by other energy-planning decisionmakers, such as state, utility, and, where 

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

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

4 Energy Act or findings in the National Environmental Policy Act (NEPA) environmental analysis 

5 that would lead the NRC to reject a license renewal application, the NRC does not have a role in 

6 the energy-planning decisions as to whether a particular nuclear power plant should continue to 

7 operate.

8 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL

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

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

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

12 criteria:

13 • The environmental impacts associated with the 

14 issue are determined to apply either to all plants 

15 or, for some issues, to plants having a specific 

16 type of cooling system or other specified plant or 

17 site characteristics.

18 • A single significance level (i.e., SMALL, 

19 MODERATE, or LARGE) has been assigned to 

20 the impacts, except for collective offsite 

21 radiological impacts from the fuel cycle and from 

22 high-level waste and spent fuel disposal.

23 • Mitigation of adverse impacts associated with the 

24 issue is considered in the analysis, and it has 

25 been determined that additional plant-specific 

26 mitigation measures are likely not to be 

27 sufficiently beneficial to warrant implementation.

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

29 required in this SEIS unless new and significant information is 

30 identified. Chapter 4 of this SEIS presents the process for 

31 identifying new and significant information. Site-specific issues (Category 2) are those that do 

32 not meet one or more of the criteria for Category 1 issues; therefore, an additional site-specific 

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

34 Neither TVA nor NRC identified information that is both new and significant related to 

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

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

37 applicant’s activities, the public scoping process and substantive comments raised, and the 

38 findings from the environmental site audit conducted by the NRC staff. The NRC staff, 

39 therefore, relies upon the conclusions of the GEIS for all Category 1 issues applicable to SQN.

40 Table ES-1 summarizes the Category 2 issues relevant to SQN as well as the NRC staff’s 

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

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

43 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

xix

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 Radionuclides released to groundwater SMALL

Terrestrial Resources

Effects on terrestrial resources (non-cooling 

system impacts)

Water use conflicts with terrestrial resources 

(plants with cooling ponds or cooling towers 

using makeup water from a river)

SMALL

SMALL

Aquatic Resources

Impingement and entrainment of aquatic 

organisms

Thermal impacts on aquatic organisms

Water use conflicts with aquatic resources 

SMALL

SMALL

SMALL

Special Status Species Threatened or endangered species No effect(a)

Historic and Cultural Historic and cultural resources No adverse effect(b)

Human Health Microbiological hazards to the public health

Electric shock hazards SMALL

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

Cumulative Impacts

Surface Water

Terrestrial resources

Aquatic resources

Environmental Justice

Global Climate Change

All other resource areas

SMALL-MODERATE

MODERATE

LARGE

See note below(c)

MODERATE

SMALL

(a)

For Federally protected species, the NRC reports the effects from continued operation of SQN during the license 

renewal period in terms of its Endangered Species Act (ESA) findings of “no effect,” “may effect, but not likely to 

adversely effect,” or “may affect, and is likely to adversely affect.”

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

effects of their undertakings on historic properties. (c)

 There would be no disproportionately high and adverse impacts to minority and low-income populations and 

subsistence consumption from continued operation of SQN during the license renewal period and from cumulative 

impacts.

3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 

4 Since TVA had not previously considered alternatives to reduce the likelihood or potential 

5 consequences of a variety of highly uncommon but potentially serious accidents at SQN, 

6 10 CFR 51.53(c)(3)(ii)(L) requires that TVA evaluate severe accident mitigation alternatives 

7 (SAMAs) in the course of the license renewal review. SAMAs are potential ways to reduce the 
Executive Summary

xx 

1 risk or potential impacts of uncommon, but potentially severe accidents, and they may include 

2 changes to plant components, systems, procedures, and training.

3 The NRC staff reviewed the ER’s evaluation of potential SAMAs. Based on the staff’s review, 

4 the NRC staff concluded that none of the potentially cost beneficial SAMAs relate to adequately 

5 managing the effects of aging during the period of extended operation. Therefore, they need 

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

7 ALTERNATIVES

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

9 renewal. These alternatives include other methods of power generation and not renewing the 

10 SQN operating license (the no-action alternative). The feasible and commercially viable 

11 replacement power alternatives considered were:

12  natural gas combined-cycle (NGCC),

13  supercritical pulverized coal (SCPC),

14  new nuclear, and

15  a combination of wind and solar power.

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

17 to the license renewal of SQN; these were later dismissed because of technical, resource 

18 availability, or commercial limitations that currently exist and that the NRC staff believes are 

19 likely to continue to exist when the existing SQN licenses expire. The no action alternative and 

20 the effects it would have were also considered by the NRC staff. 

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

22 located both at the SQN site and at some other unspecified alternate location. Alternatives 

23 considered, but dismissed, were:

24  wind power, 

25  solar power,

26  conventional hydroelectric power, 

27  geothermal power, 

28  biomass energy,

29  municipal solid waste, 

30  wood waste, 

31  ocean wave and current energy, 

32  oil-fired power,

33  conventional hydroelectric power, 

34  fuel cells, 

35  coal-fired integrated gasification combined-cycle (IGCC),

36  delayed retirement, 

37  demand-side management (DSM), and

38  purchased power.
Executive Summary

xxi

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’s preliminary recommendation is that the adverse environmental impacts of license 

5 renewal for SQN are not great enough to deny the option of license renewal for energy-planning 

6 decisionmakers. This recommendation is based on the following:

7  the analyses and findings in the GEIS; 

8  the ER submitted by TVA; 

9  the NRC staff’s consultation with Federal, state, and local agencies;

10  the NRC staff’s independent environmental review; and

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

12 process. 

xxiii

1 ABBREVIATIONS AND ACRONYMS

2 °C degree(s) Celsius

3 °F degree(s) Fahrenheit

4 μm micrometer(s)

5 AADT average annual daily traffic 

6 ac acre(s)

7 AC alternating current

8 ACHP Advisory Council on Historic Preservation

9 ACRS Advisory Committee on Reactor Safeguards

10 ACS American Community Survey

11 ADAMS Agencywide Documents Access and Management System

12 AEA Atomic Energy Act of 1954 

13 AFW auxiliary feedwater

14 ALARA as low as is reasonably achievable

15 ANS American Nuclear Society

16 ANSI American National Standards Institute

17 AP Associated Press

18 APE area of potential effect

19 AQCR air quality control region 

20 ASLBP Atomic Safety and Licensing Board Panel

21 ASME American Society of Mechanical Engineers

22 ATSDR Agency for Toxic Substances and Disease Registry

23 ATWS anticipated transient(s) without scram 

24 BEA Bureau of Economic Analysis

25 BLEU blended low-enriched uranium

26 BLS Bureau of Labor Statistics

27 BMP best management practice

28 BREDL Blue Ridge Environmental Defense League

29 BWR boiling water reactor

30 CAA Clean Air Act, as amended through 1990

31 CACC Chattanooga Area Chamber of Commerce

32 CAFTA cutset and fault tree analysis/analyses

33 CAIR Clean Air Interstate Rule

34 CAPS Circular Area Profiles
Abbreviations and Acronyms

xxiv

1 CCDP conditional core damage probability

2 CCS carbon capture and sequestration/storage

3 CCS component cooling system

4 CCW component cooling water

5 CCW condenser circulating water

6 CDC Centers for Disease Control and Prevention

7 CDF core damage frequency

8 CDL Cropland Data Layer

9 CEQ Council on Environmental Quality

10 Ceq/kWh carbon equivalent per kilowatt-hour

11 CET containment event tree

12 CFR Code of Federal Regulations

13 cfs cubic foot/feet per second

CH4 14 methane

15 CHCAPCB Chattanooga–Hamilton County Air Pollution Control Bureau

16 CHCRPA Chattanooga–Hamilton County Regional Planning Agency

17 Ci curie(s)

18 CLB current licensing basis/bases

19 cm centimeter(s)

20 CNWRA Center for Nuclear Waste Regulatory Analyses

21 CO carbon monoxide 

22 CO2 carbon dioxide

23 CO2e carbon dioxide equivalent(s)

24 COL combined license

25 CPC Center for Plant Conservation

26 CS candidate species

27 CSAPR Cross-State Air Pollution Rule

28 CSP concentrated solar power

29 CT combustion turbine

30 CWA Clean Water Act of 1972

31 dBA decibels adjusted

32 DBA design-basis accident

33 DC direct current

34 DOE U.S. Department of Energy

35 DOI digital object identifier
Abbreviations and Acronyms

xxv 

1 DSEIS draft supplemental environmental impact statement

2 DSM demand-side management

3 DT104 definitive phage type 104

4 DWS drinking water standard

5 E.O. Executive Order

6 EA environmental assessment

7 EA equivalent adult

8 EAB exclusion area boundary

9 EAC Early Action Compact

10 EDG emergency diesel generator

11 EEDR energy efficiency and demand response

12 EF4 Enhanced Fujita Scale of tornado strength (166–200 mph)

13 EFH essential fish habitat

14 EIA Energy Information Administration (of DOE) 

15 EIS environmental impact statement

16 ELF extremely low frequency

17 EMF electromagnetic field

18 EnerNOC EnerNOC Utility Solutions Consulting

19 EPA U.S. Environmental Protection Agency 

20 EPRI Electric Power Research Institute

21 ER Environmental Report

22 ERC Energy Recovery Council

23 ERCW emergency/essential raw cooling water

24 ERDC Engineer Research and Development Center

25 ESA Endangered Species Act of 1973, as amended

26 FAQ frequently asked question

27 FDCT floor drain collector tank

28 FEMA Federal Emergency Management Agency

29 FES final environmental statement

30 FHWA Federal Highway Administration

31 FIVE fire-induced vulnerability evaluation

32 fps foot/feet per second

33 FR Federal Register

34 ft foot/feet

ft2 35 square foot/feet
Abbreviations and Acronyms

xxvi 

ft3 1 cubic foot/feet

2 FW feedwater

3 FWPCA Federal Water Pollution Control Act

4 FWS U.S. Fish and Wildlife Service

5 g gram(s)

6 g Ceq/kWh gram(s) of carbon equivalent per kilowatt-hour

7 gal gallon(s)

8 GEA Geothermal Energy Association

9 GEIS Generic Environmental Impact Statement for License Renewal of 

10 Nuclear Plants, NUREG–1437

11 GEP Global Energy Partners

12 GHG greenhouse gas

13 GI generic issue

14 GIS geographic information system

15 GISS Goddard Institute for Space Studies

16 GL generic letter

17 gpd gallons per day 

18 gpm gallons per minute

19 Gt gigatonne(s)

20 GW gigawatt(s)

21 GW groundwater

22 GWh gigawatt hour(s)

23 GWP global warming potential

24 GWPS gaseous waste processing system

25 H2O water vapor

26 ha hectare(s)

27 HAP hazardous air pollutant

28 HCFC hydrochlorofluorocarbon

29 HCLPF high confidence in low probability of failure

30 HEP human error probability

31 HEU highly enriched uranium

32 HFC hydrofluorocarbon

33 Hg mercury

34 HPA habitat protection area

35 HSDT hot shower drain tank
Abbreviations and Acronyms

xxvii 

1 HUD Housing and Urban Development

2 HVAC heating, ventilation, and air conditioning

3 HWSF hazardous waste storage facility

4 Hz hertz

5 IAEA International Atomic Energy Agency

6 IEA International Energy Agency

7 IEEE Institute of Electrical and Electronics Engineers

8 IGCC integrated gasification combined cycle 

9 in. inch(es)

10 INEEL Idaho National Engineering and Environmental Laboratory

11 IPCC Intergovernmental Panel on Climate Change

12 IPE individual plant examination

13 IPEEE individual plant examination(s) of external events

14 IPPNW International Physicians for the Prevention of Nuclear War

15 IPS Intake Pumping Station

16 IRP Integrated Resource Plan

17 ISFSI independent spent fuel storage installation

18 ISLOCA interfacing-systems loss-of-coolant accident

19 ISSG Invasive Species Specialist Group

20 ITIS Integrated Taxonomic Information System

21 ISO International Organization for Standardization

22 kg kilogram(s)

23 km kilometer(s)

km2 24 square kilometer(s)

25 kV kilovolt(s)

26 kW kilowatt(s)

27 kWh kilowatt-hour(s)

kWh/m2 28 /day kilowatt hour(s) per square meter per day

29 L litre(s)

30 L/min liter(s) per minute

31 lb pound(s)

32 LEFM Leading Edge Flow Meter

33 LERF large early release frequency

34 LIDAR light detection and ranging

35 LLMW low-level mixed waste
Abbreviations and Acronyms

xxviii 

1 LLRW low-level radioactive waste

2 LNB low NOx burner

3 LNT linear, no-threshold

4 LOCA loss-of-coolant accident

5 LOOP loss(es) of offsite power

6 Lpd litre(s) per day

7 LRA license renewal application

8 LUB Loudon Utilities Board

9 LWPS liquid waste processing system

10 m meter(s)

11 m/s meter(s) per second

m2 12 square meter(s)

m3 13 cubic meter(s)

m3 14 /s cubic meters per second

m3 15 /y cubic meters per year

16 mA milliampere(s)

17 MAAP Modular Accident Analysis Program

18 MACCS2 MELCOR Accident Consequence Code System 2 

19 MACR maximum averted cost-risk

20 MAIS macroinvertebrate aggregated index for streams 

21 MATS Mercury and Air Toxics Standards 

22 MBq megabecquerel(s)

23 MBTA Migratory Bird Treaty Act

24 MDAFWP motor-driven auxiliary feedwater pump

25 MF migratory fishes

26 mg/L milligrams per liter

27 mgd million gallons per day 

28 mgy million gallons per year

29 mGy milligray

30 mi mile(s)

mi2 31 square mile(s)

32 min minute(s)

33 mm millimeter(s)

34 MMACR modified maximum averted cost-risk

35 MMI Modified Mercalli Intensity
Abbreviations and Acronyms

xxix

1 MMS Minerals Management Service

2 MMSHT Michigan Mine Safety & Health Training

3 MMT million metric ton(s)

4 MOXF mixed-oxide fuel

5 mph mile(s) per hour

6 mrad milliradiation absorbed dose

7 mrem milliroentgen equivalent man

8 MSA Magnuson–Stevens Fishery Conservation and Management Act

9 MSL mean sea level

10 mSv millisievert

11 MSW municipal solid waste

12 MT metric ton(s)

13 MUR measurement uncertainty recapture

14 MW megawatt(s)

15 MWd megawatt-day(s) 

16 MWd/MTU megawatt-day(s) per metric ton of uranium 

17 MWe megawatt(s) electrical 

18 MWh megawatt hour(s)

19 MWt megawatt(s) thermal

20 N/A not applicable

21 N2O nitrous oxide

22 NAAQS National Ambient Air Quality Standards

23 NAICS North American Industry Classification System

24 NARUC National Association of Regulatory Utility Commissioners

25 NAS National Academy of Sciences

26 NASA National Aeronautics and Space Administration

27 NASS National Agricultural Statistics Service

28 NBII National Biological Information Infrastructure

29 NCADAC National Climate Assessment Development Advisory Committee

30 NCDC National Climatic Data Center

31 NCES National Center for Education Statistics

32 NEI Nuclear Energy Institute

33 NEPA National Environmental Policy Act of 1969

34 NERC North American Electric Reliability Corporation

35 NESC National Electrical Safety Code
Abbreviations and Acronyms

xxx 

1 NETL National Energy Technology Laboratory

2 NGCC natural gas combined-cycle 

3 NHPA National Historic Preservation Act of 1966, as amended

4 NIEHS National Institute of Environmental Health Sciences

5 NMFS National Marine Fisheries Service (of NOAA)

6 NNSA National Nuclear Security Administration

7 NO2 nitrogen dioxide

8 NOAA National Oceanic and Atmospheric Administration 

9 NOx nitrogen oxide(s)

10 NPDES National Pollutant Discharge Elimination System 

11 NPS National Park Service

12 NRC U.S. Nuclear Regulatory Commission 

13 NREL National Renewable Energy Laboratory

14 NRHP National Register of Historic Places

15 NRR Office of Nuclear Reactor Regulation

16 NSR New Source Review

17 NUREG NRC technical report designation (Nuclear Regulatory 

18 Commission)

19 NWS National Weather Service

20 O3 ozone

21 OCA Owner-Controlled Area

22 ODCM Offsite Dose Calculation Manual

23 OECD Organisation for Economic Co-operation and Development

24 OECR offsite economic cost risk

25 OSHA Occupational Safety and Health Administration

26 OTM OSHA Technical Manual

27 P.L. Public Law

28 PAH polycyclic aromatic hydrocarbon

29 Pb lead

30 PCB polychlorinated biphenyl 

31 pCi/L picocuries per liter

32 PDS plant damage state

33 PF production foregone

34 PFC perfluorocarbon

35 PGA peak ground acceleration
Abbreviations and Acronyms

xxxi 

1 pH potential of hydrogen

2 PHAC Public Health Agency of Canada

3 PM particulate matter

4 PM10 particulate matter >2.5 microns and ≤10 microns in diameter

5 PM2.5 particulate matter ≤2.5 microns in diameter

6 PNNL Pacific Northwest National Laboratory

7 PORV power-operated relief valve

8 PPA power purchase agreement

9 PRA probabilistic risk assessment

10 PSD Prevention of Significant Deterioration

11 psia pounds per square inch absolute

12 Pu plutonium

13 PV photovoltaic

14 PWR pressurized water reactor

15 RAI request for additional information

16 RCA radiological control area

17 RCP reactor coolant pump

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

19 RCS reactor coolant system

20 RCW raw cooling water

21 REIRS Radiation Exposure Information and Reporting System

22 rem roentgen equivalent(s) man

23 REMP radiological environmental monitoring program

24 RG Regulatory Guide

25 RGPP Radiological Groundwater Protection Program

26 RHR Regional Haze Rule

27 RHR residual heat removal

28 RKm river kilometer

29 RLE review-level earthquake

30 RM river mile

31 ROI region of influence

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

33 RPS renewable portfolio standard

34 RRW risk reduction worth

35 RSP radwaste storage pad
Abbreviations and Acronyms

xxxii 

1 RV recreational vehicle

2 RWCU reactor water cleanup

3 SAMA severe accident mitigation alternative

4 SAMDA Severe Accident Mitigation Design Alternative

5 SAMGs Severe Accident Mitigation Guidelines

6 SAR safety analysis report

7 SBO station blackout

8 SCCW supplemental condenser cooling water

9 SCPC supercritical pulverized coal

10 SCR selective catalytic reduction 

11 SDWA Safe Drinking Water Act

12 SE state endangered

13 SEIDA Southeast Industrial Development Association

14 SEIS supplemental environmental impact statement 

15 SER safety evaluation report

16 SERC SERC Reliability Corporation

17 SF6 sulfur hexafluoride

18 SFU Simon Fraser University

19 SGTS standby gas treatment system

20 SHPO State Historic Preservation Officer

21 SIP State Implementation Plan

22 SMA Seismic Margin Assessment

23 SMR small modular reactor

24 SNF spent nuclear fuel

25 SO2 sulfur dioxide

26 SOx sulfur oxide(s)

27 SPCC Spill Prevention Control and Countermeasure

28 SQN Sequoyah Nuclear Plant, Units 1 and 2

29 SR state rare

30 SREL Savannah River Ecology Laboratory

31 SRP Standard Review Plan

32 SRST spent resin storage tank

33 SSC species of special concern

34 SSCs structures, systems, and components

35 SSE safe-shutdown earthquake
Abbreviations and Acronyms

xxxiii 

1 SSEL Safe Shutdown Equipment List

2 ST state threatened

3 STG steam turbine generator

4 Sv sievert

5 SW surface water

6 SWPPP Stormwater Pollution Prevention Plan

7 TAC technical assignment control

8 TAW Tennessee American Water

9 TCA Tennessee Code Annotated

10 TDAFWP turbine-driven auxiliary feedwater pump

11 TDCT tritium drain collector tank

12 TDEC Tennessee Department of Environment and Conservation

13 TDH Tennessee Department of Health

14 TDLWD Tennessee Department of Labor and Workforce Development

15 TDOT Tennessee Department of Transportation

16 TLD thermoluminescent dosimeters

17 TMDL total maximum daily upload

18 TNR Tennessee Rule

19 TPBAR tritium-producing burnable absorber rod

20 tpy ton(s) per year

21 TRM Tennessee River Mile

22 TRU transuranic

23 TS technical specification

24 TSP Tennessee State Parks

25 TSP total suspended particles

26 TVA Tennessee Valley Authority

27 TWh terawatt-hour(s)

28 TWRA Tennessee Wildlife Resources Agency

29 U uranium

30 U.S. United States

31 U.S.C. United States Code

32 UFSAR updated final safety analysis report

33 UO uranium oxide

34 USACE U.S. Army Corps of Engineers 

35 USCB U.S. Census Bureau
Abbreviations and Acronyms

xxxiv 

1 USDA U.S. Department of Agriculture

2 USEC U.S. Enrichment Corporation

3 USGCRP United States Global Change Research Program [or GCRP]

4 USGS U.S. Geological Survey

5 USST unit station service transformer

6 UT The University of Tennessee

7 VDGIF Virginia Department of Game and Inland Fisheries

8 VOC volatile organic compound

9 WAW wet active waste

10 WBN Watts Bar Nuclear Power Plant

11 WBN 2 Watts Bar Unit 2

12 WBUD Watts Bar Utility District

13 WCAP Westinghouse Commercial Atomic Power
1-1 

1 1.0 INTRODUCTION

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

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

4 National Environmental Policy Act (NEPA)—issuance of a new nuclear power plant operating 

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

6 The Atomic Energy Act of 1954 (AEA) specifies 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 Tennessee Valley Authority (TVA) initiated the proposed Federal action by submitting an 

18 application for license renewal of Sequoyah Nuclear Plant, Units 1 and 2 (SQN), for which the 

19 existing licenses (DPR-77 and DPR-79) expire on September 17, 2020, and 

20 September 15, 2021, respectively. The NRC’s proposed Federal action is the decision whether 

21 to renew the licenses for an additional 20 years.

22 1.2 Purpose and Need for the Proposed Federal Action

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

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

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

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

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

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

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

30 State regulators and utility officials as to whether a particular nuclear power plant should 

31 continue to operate.

32 1.3 Major Environmental Review Milestones

33 TVA submitted an Environmental Report (ER) (TVA 2013b) as part of its LRA (TVA 2013a) on 

34 January 15, 2013. After reviewing the LRA and ER for sufficiency, the NRC staff published a 

35 Federal Register Notice of Acceptability and Opportunity for Hearing (78 FR 14362) on 

36 March 5, 2013. Then, on March 8, 2013, the NRC published another notice in the 

37 Federal Register (78 FR 15055) on the intent to conduct scoping, thereby beginning the 60-day 

38 scoping period.

39 The NRC staff held two public scoping meetings on April 3, 2013, in Soddy-Daisy, Tennessee. 

40 The comments received during the scoping process are presented in their entirety in 

41 “Environmental Impact Statement Scoping Process, Summary Report, Sequoyah Nuclear Plant, 

42 Units 1 and 2,” published in April 2014 (NRC 2014). The staff presents comments considered to 
Introduction

1-2 

1 be within the scope of the environmental license renewal review and the NRC responses in 

2 Appendix A of this supplemental environmental impact statement (SEIS).

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

4 audit at SQN, in April 2013. During the site audit, the staff met with plant personnel, reviewed 

5 specific documentation, toured the facility, and met with interested Federal, State, and local 

6 agencies. A summary of that site audit and the attendees is contained in the audit summary 

7 report (NRC 2013b).

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

9 draft SEIS. This document is made available for public comment for 45 days. During this time, 

10 the staff hosts public meetings and collects public comments. Based on the information 

11 gathered, it amends the draft SEIS findings, as necessary, and publishes the final SEIS for 

12 license renewal. Figure 1–1 shows the major milestones of the NRC’s license renewal 

13 application environmental review.

14 Figure 1–1. Environmental Review Process

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

16 reasonable period with clear requirements to assure safe plant operation for up to an additional 

17 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 

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

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

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

21 1.4 Generic Environmental Impact Statement

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

23 license renewal to improve the efficiency of its license renewal review. The Generic 
Introduction

1-3 

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

2 NUREG-1437, Revision 1 (NRC 1996, 1999, 2013a), documented the results of the staff’s 

3 systematic approach to evaluate the environmental consequences of renewing the licenses of 

4 individual nuclear power plants and operating them for an additional 20 years. The staff 

5 analyzed in detail and resolved those environmental issues that could be resolved generically in 

6 the GEIS. The GEIS was originally issued in 1996 (NRC 1996), Addendum 1 to the GEIS was 

7 issued in 1999 (NRC 1999), and Revision 1 to the GEIS was issued in 2013 

8 (NRC 2013b). Unless otherwise noted, all references to the GEIS include the GEIS, 

9 Addendum 1 and Revision 1.

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

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

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

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

14 Appendix B to Subpart A of 10 CFR 51 provides a summary of the staff findings in the GEIS. 

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

16 • describes the activity that affects the environment,

17 • identifies the population or resource that is affected,

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

19 or resource,

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

21 effects,

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

23 • considers whether additional mitigation measures would be warranted for 

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

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

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

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

28 SMALL: Environmental effects are not 

29 detectable or are so minor that they will neither 

30 destabilize nor noticeably alter any important 

31 attribute of the resource.

32 MODERATE: Environmental effects are 

33 sufficient to alter noticeably, but not to destabilize, 

34 important attributes of the resource.

35 LARGE: Environmental effects are clearly noticeable and are sufficient to destabilize important 

36 attributes of the resource.

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

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

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

40 issues are those that meet the following criteria:

41 • The environmental impacts associated with the issue have been determined 

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

43 type of cooling system or other specified plant or site characteristics.

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

2 assigned to the impacts (except for offsite radiological impacts—collective

3 impacts from other than the disposal of spent fuel and high-level waste).

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

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

6 mitigation measures are likely not to be sufficiently beneficial to warrant 

7 implementation.

8 Figure 1–2 illustrates the process used to analyze and categorize issues in the GEIS and in 

9 each SEIS.

10 Figure 1–2. Environmental Issues Evaluated For License Renewal

11 In the GEIS, 78 issues were evaluated. 

12 A site-specific analysis is required for 17 of those 78 issues

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

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

15 significant information is presented in Chapter 4. Site-specific issues (Category 2) are those 

16 that do not meet one or more of the criteria of Category 1 issues; therefore, additional 
Introduction

1-5 

1 site-specific review for these issues is required. The results of that site-specific review are 

2 documented in the SEIS.

3 1.5 Supplemental Environmental Impact Statement

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

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

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

7 environmental impacts from alternatives while Chapter 5 presents the recommendation of the 

8 NRC on whether or not the environmental impacts of license renewal are so great that 

9 preserving the option of license renewal would be unreasonable. The final recommendation will 

10 be made after consideration of comments received on the draft SEIS during the public comment 

11 period.

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

13 • reviewed the information provided in the TVA’s ER;

14 • consulted with other Federal, State, local agencies, and tribal nations; 

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

16 • considered the public comments received (during the scoping process and, 

17 subsequently, on the draft SEIS).

18 New information can be identified from many 

19 sources, including the applicant, the NRC, other 

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

21 revealed, it is first analyzed to determine whether 

22 it is within the scope of the license renewal 

23 environmental evaluation. If the new issue is not 

24 addressed in the GEIS, the NRC staff would 

25 determine the significance of the issue and document the analysis in the SEIS.

26 1.6 Decision To Be Supported by the SEIS

27 The decision to be supported by the SEIS is whether or not to renew the operating licenses for 

28 SQN for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103:

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

30 chapter, the Commission shall determine whether or not the adverse 

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

32 of license renewal for energy planning decisionmakers would be unreasonable.

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

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

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

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

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

38 of the final GEIS analysis. These decisions concern the following issues: changes to plant 

39 cooling systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and 

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

New and significant 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

(i.e., impacts of greater severity than impacts 

considered in the GEIS, considering their intensity 

and context).
Introduction

1-6 

1 1.7 Cooperating Agencies

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

3 agencies in the preparation of this SEIS.

4 1.8 Consultations

5 The Endangered Species Act of 1973, as amended (ESA); the Magnuson–Stevens Fishery 

6 Conservation and Management Act of 1996, as amended (MSA); and the National Historic 

7 Preservation Act of 1966 (NHPA) require that Federal agencies consult with applicable state 

8 and Federal agencies and groups prior to taking action that may affect endangered species, 

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

10 following agencies and groups:

11 • State Historic Preservation Office, 

12 • Advisory Council on Historic Preservation, 

13 • U.S. Fish and Wildlife Service (FWS),

14 • Cherokee Nation,

15 • The Chickasaw Nation,

16 • Alabama Quassarte Tribal Town,

17 • Muscogee (Creek) Nation,

18 • Alabama-Coushatta Tribe of Texas, 

19 • Thlopthlocco Tribal Town, 

20 • Eastern Shawnee Tribe of Oklahoma, 

21 • Kialegee Tribal Town, 

22 • Eastern Band of the Cherokee Indians, 

23 • Absentee Shawnee Tribe of Oklahoma, 

24 • United Keetoowah Band of Cherokee Indians in Oklahoma, 

25 • Seminole Tribe of Florida, and

26 • Seminole Nation of Oklahoma.

27 Appendix C contains a discussion of consultation related documents sent and received during 

28 the environmental review.

29 1.9 Correspondence 

30 The NRC staff corresponded with Federal, State, regional, local, and tribal agencies during the 

31 environmental review. Appendix D contains a chronological list of documents sent and received 

32 during the environmental review.

33 1.10 Status of Compliance

34 TVA is responsible for complying with all NRC regulations and other applicable Federal, state, 

35 and local requirements. Appendix F of the GEIS describes some of the major applicable 
Introduction

1-7 

1 Federal statutes. There are numerous permits and licenses issued by Federal, State, and local 

2 authorities for activities at SQN. Appendix B contains further discussion about SQN status of 

3 compliance.

4 1.11 Related Federal and State Activities

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

6 renewal of the operating license for SQN. There are no Federal projects that would make it 

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

8 this supplemental EIS. There are no known Native American reservations or controlled lands 

9 within 50 mi of SQN (TVA 2013b). There are approximately 37 Federal and 88 State-managed 

10 lands within 50 mi of SQN. There are four Federal lands and one State-managed land within 

11 6 mi of SQN. These Federal lands are TVA-managed habitat protection areas. Harrison Bay 

12 State Recreation Park is the only state-managed area within 6 mi of SQN (TVA 2013b). 

13 The NRC is required under Section 102(2)(C) of NEPA to consult with and obtain comments 

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

15 environmental impact involved in the subject matter of the EIS. For example, during the course 

16 of preparing the SEIS, the NRC consulted with the FWS. A complete list of key consultation 

17 correspondences is listed in Appendix C. 

18 1.12 References

19 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

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

21 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

22 renewal of operating licenses for nuclear power plants.”

23 61 FR 28467. U.S. Nuclear Regulatory Commission. “Environmental review for renewal of 

24 nuclear power plant operating licenses.” Federal Register 61(109):28467–28497. June 5, 1996.

25 78 FR 14362. U.S. Nuclear Regulatory Commission. “Tennessee Valley Authority; notice of 

26 acceptance for docketing of application and notice of opportunity for hearing regarding renewal 

27 of Sequoyah Nuclear Plant, Units 1 and 2 facility operating license nos. DPR–77, DPR–79 for 

28 an additional 20-year period.” Federal Register 78(43):14362–14365. March 5, 2013.

29 78 FR 15055. U.S. Nuclear Regulatory Commission. “License renewal application for Sequoyah 

30 Nuclear Plant, Units 1 and 2, Tennessee Valley Authority.” Federal 

31 Register 78(46):15055–15056. March 8, 2013.

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

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

34 [MSA] Magnuson–Stevens Fishery Conservation and Management Act, as amended.

35 16 U.S.C. §1801 et seq.

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

37 [NHPA] National Historic Preservation Act of 1966. 16 U.S.C. §470 et seq.

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

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

40 Volumes 1, 2, and 3. June 2013. 1,535 p. Agencywide Documents Access and Management 

41 System (ADAMS) No. ML13107A023. 
Introduction

1-8 

1 [NRC] U.S. Nuclear Regulatory Commission. 2013b. Memorandum from D. Drucker, Sr. Project 

2 Manager, to Tennessee Valley Authority. Subject: Summary of the site audit related to the 

3 review of the license renewal application for Sequoyah Nuclear Plant, Units 1 and 2.

4 August 7, 2013. 6 p. ADAMS No. ML13120A198. 

5 [NRC] U.S. Nuclear Regulatory Commission. 2014. Environmental Impact Statement Scoping 

6 Process, Summary Report, Sequoyah Nuclear Plant, Units 1 and 2, Hamilton County, TN. 

7 Washington, DC: NRC. 2014. ADAMS No. ML14041A118. 

8 [TVA] Tennessee Valley Authority. 2013a. License Renewal Application, Sequoyah Nuclear 

9 Plant, Units 1 and 2. January 7, 2013. 1,544 p. ADAMS No. ML13024A011.

10 [TVA] Tennessee Valley Authority. 2013b. Sequoyah Nuclear Plant, Units 1 and 2, License 

11 Renewal Application, Appendix E, Applicant’s Environmental Report, Operating License 

12 Renewal Stage. Chattanooga, TN: TVA. January 7, 2013. 783 p. ADAMS No. ML130240007, 

13 Parts 2 through 8 of 8.
2-1 

1 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION

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

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

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

5 requires consideration of the environmental impacts of potential alternatives to renewing a 

6 plant’s operating license. While the ultimate decision about which alternative (or the proposed 

7 action) to carry out falls to utility, state, or other Federal officials (non-NRC), comparing the 

8 impacts of renewing the operating license to the environmental impacts of alternatives allows 

9 the NRC to determine whether the environmental impacts of license renewal are so great that 

10 preserving the option of license renewal for energy-planning decisionmakers would be 

11 unreasonable (10 CFR 51.95(c)(4)). 

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

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

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

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

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

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

18 would be the most likely alternative in any given case.

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

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

21 (3) alternatives to Sequoyah Nuclear Plant, Units 1 and 2 (SQN), license renewal that were 

22 considered and eliminated from detailed study. Chapter 4 of this plant-specific supplemental 

23 environmental impact statement (SEIS) compares the impacts of renewing the operating 

24 licenses of SQN and continued plant operations to the environmental impacts of alternatives. 

25 2.1 Proposed Action

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

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

28 determine the impacts from continued operation of SQN an understanding of that operation is 

29 needed. A description of normal power plant operations during the license renewal term is 

30 provided in Section 2.1.1. SQN is a two-unit, nuclear-powered steam-electric generating facility 

31 that began commercial operation in July 1981 (Unit 1) and June 1982 (Unit 2). The nuclear 

32 reactor for each unit is a Westinghouse pressurized-water reactor (PWR), producing a reactor 

33 core rated thermal power of 3,455 megawatts thermal. 

34 2.1.1 Plant Operation During the License Renewal Term

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

36 occurring during the current license term (NRC 2013 new GEIS). Section 2.1.1 of the Generic 

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

38 NUREG-1437, Revision 1 (NRC 2013 new GEIS) describes the general types of activities that 

39 are carried out during the operation of a nuclear power plant such as SQN, as follows:

40 • reactor operation;

41 • waste management;

42 • security;
Alternatives Including the Proposed Action

2-2 

1 • office and clerical work;

2 • surveillance, monitoring, and maintenance; and

3 • refueling and other outages.

4 As stated in the Tennessee Valley Authority (TVA) Environmental Report (ER), SQN will 

5 continue to operate during the license renewal term in the same manner as during the current 

6 license term except for, as appropriate, additional aging management programs to address 

7 structure and component aging, in accordance with Title 10, Part 54, of the Code of Federal 

8 Regulations (10 CFR Part 54). 

9 2.1.2 Refurbishment and Other Activities Associated With License Renewal

10 Refurbishment activities include replacement and repair of major systems, structures, and 

11 components. Replacement activities include replacement of steam generators for PWRs and 

12 recirculation piping systems for boiling water reactors (BWRs). 

13 SQN Units 1 and 2 are PWRs. All original SQN steam generators have been replaced. The 

14 last steam generator replacement took place in 2012. The TVA ER states that no plant 

15 refurbishment activities were identified as necessary to support the continued operation of SQN 

16 beyond the end of the existing operating license terms.

17 2.1.3 Termination of Nuclear Power Plant Operation and Decommissioning After the 

18 License Renewal Term

19 The impacts of decommissioning are described in the Generic Environmental Impact Statement

20 on Decommissioning of Nuclear Facilities: Regarding the Decommissioning of Nuclear Power 

21 Reactors, NUREG-0586 (NRC 2002a). The majority of the activities associated with plant 

22 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 

23 spent nuclear fuel) would remain unchanged, while others (waste management, office and 

24 clerical work, laboratory analysis, and surveillance, monitoring, and maintenance) would 

25 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 

26 operations; however, impacts from their physical presence may continue if not removed after 

27 reactor shutdown. For sites such as SQN, with more than one unit, shared systems may 

28 operate at reduced capacities. Impacts associated with dedicated systems that remain in place 

29 or shared systems that continue to operate at normal capacities would remain unchanged.

30 Decommissioning would occur whether SQN was shut down at the end of its current operating 

31 licenses or at the end of the period of extended operation. There are no site-specific issues 

32 related to decommissioning. The GEIS concludes SMALL (Category 1) impacts of terminating 

33 operation and decommissioning on all resources for nuclear power plants.

34 2.2 Alternatives

35 As stated at the beginning of this chapter, the NRC has the obligation to consider reasonable 

36 alternatives to the proposed action of renewing the license for a nuclear reactor. The 2013 

37 GEIS update incorporated the latest information on replacement power alternatives; however, 

38 rapidly evolving technologies are likely to outpace the information presented in the GEIS. As 

39 such, a site-specific analysis of alternatives must be performed for each SEIS, taking into 

40 account changes in technology and science since the preparation of the GEIS.
Alternatives Including the Proposed Action

2-3 

1 Sections 2.2.1 below describes the no-action alternative, i.e., the NRC takes no action and does 

2 not issue renewed licenses for SQN. Sections 2.2.2.1–2.2.2.4 describe the characteristics of 

3 replacement power alternatives for SQN.

4 2.2.1 No-Action Alternative

5 At some point, operating nuclear power plants will terminate operations and undergo 

6 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 

7 operating license of a nuclear power plant beyond the current operating license term. Under the 

8 no-action alternative, the NRC denies the renewed operating licenses, and the SQN plant will 

9 shut down at or before the end of the current licenses, in 2020 and 2021. After shutdown, plant 

10 operators will initiate decommissioning in accordance with 10 CFR 50.82.

11 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 

12 SEIS. The environmental impacts from decommissioning and related activities are addressed in 

13 several other documents, including the Final Generic Environmental Impact Statement on 

14 Decommissioning of Nuclear Facilities, NUREG-0586, Supplement 1 (NRC 2002); the license 

15 renewal GEIS, Chapter 4 (NRC 2013 new GEIS); and Chapter 4 of this SEIS. These analyses 

16 either directly address or bound the environmental impacts of decommissioning whenever TVA

17 ceases to operate SQN.

18 Even with renewed operating licenses, SQN will eventually shut down, and the environmental 

19 impacts addressed later in Chapter 4 of this SEIS will occur at that time. As with 

20 decommissioning impacts, shutdown impacts are expected to be similar whether they occur at 

21 the end of the current license or at the end of a renewed license. 

22 Termination of operations at SQN would result in the total cessation of electrical power 

23 production. Unlike the alternatives described below in Section 2.2.2, no-action does not 

24 expressly meet the purpose and need of the proposed action as described in Section 2.2, as it 

25 does not provide a means of delivering baseload power to meet future electric system needs. 

26 Assuming that a need currently exists for the power generated by SQN, the no-action alternative 

27 would likely create a need for a replacement power alternative. A full range of replacement 

28 power alternatives (including fossil fuels, new nuclear, and renewable energy sources) are 

29 described in the following section, and their potential impacts are assessed in Chapter 4. 

30 Although the NRC’s authority only extends to the decision of whether to grant or deny the 

31 renewed SQN operating licenses, the replacement power alternatives described in the following 

32 sections represent possible options for energy-planning decisionmakers should NRC choose to 

33 deny the SQN operating licenses.

34 2.2.2 Replacement Power Alternatives

35 In evaluating alternatives to license renewal, the NRC considered energy technologies or 

36 options currently in commercial operation, as well as technologies not currently in commercial 

37 operation but likely to be commercially available by the time the current SQN operating licenses 

38 expire. The current operating licenses for the SQN reactors expire on September 17, 2020, and 

39 September 15, 2021. Alternatives that cannot be constructed, permitted, and connected to the 

40 grid by the time the SQN licenses expire were eliminated from detailed consideration.
Alternatives Including the Proposed Action

2-4 

1 Alternatives that cannot provide the equivalent of SQN’s current generating capacity and, in 

2 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 

3 reasonable alternatives, were eliminated from detailed consideration. Each alternative 

4 eliminated from detailed study is briefly discussed, and a basis for its removal is provided at the 

5 end of this section. In total, 18 alternatives to 

6 the proposed action were considered (see text 

7 box) and then narrowed to the 4 alternatives 

8 considered in Sections 2.2.2.1–2.2.2.4. The 

9 NRC staff evaluated the environmental 

10 impacts of these four alternatives and the 

11 no-action alternative and discusses them in 

12 depth in Chapter 4 of this SEIS. 

13 The GEIS presents an overview of some 

14 energy technologies but does not reach any 

15 conclusions about which alternatives are most 

16 appropriate. Because many energy 

17 technologies are continually evolving in 

18 capability and cost, and because regulatory 

19 structures have changed to either promote or 

20 impede development of particular alternatives, 

21 the analyses in this chapter may include 

22 updated information from the following 

23 sources:

24 • Energy Information Administration 

25 (EIA),

26 • other offices within the 

27 U.S. Department of Energy (DOE),

28 • U.S. Environmental Protection 

29 Agency (EPA),

30 • industry sources and publications, and

31 • information submitted by TVA in its ER. 

32 The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 

33 impacts across several impact categories: land use and visual resources, air quality and noise, 

34 geologic environment, water resources, ecological resources, historic and cultural resources, 

35 socioeconomics, human health, environmental justice, and waste management. Most 

36 site-specific issues (Category 2) have been assigned a significance level of SMALL, 

37 MODERATE, or LARGE. For ecological and historic and archaeological resources the impact 

38 significance determination language is specific to the authorizing legislation (e.g., Endangered 

39 Species Act and National Historic Preservation Act). The order of presentation of the 

40 alternatives is not meant to imply increasing or decreasing level of impact. Nor does it imply 

41 that an energy-planning decisionmaker would be more likely to select any given alternative.

42 In some cases, the NRC considers the environmental effects of locating a replacement power

43 alternative at the existing nuclear plant site. Selecting the existing plant site allows for the 

44 maximum use of existing transmission and cooling system infrastructure and minimizes the 

45 overall environmental impact. However, based on information gathered from TVA, SQN does 

46 not have a sufficient amount of land available for all the replacement power alternatives

47 because TVA would want to continue operating while the replacement alternative is being built 

Alternatives Evaluated in Depth:

• natural gas combined-cycle (NGCC)

• supercritical pulverized coal (SCPC)

• new nuclear

• combination of wind and solar

Other Alternatives Considered:

• wind power

• solar power

• conventional hydroelectric power

• geothermal power

• biomass energy

• municipal solid waste (MSW)

• wood waste

• ocean wave and current energy

• oil-fired power

• fuel cells

• coal-fired integrated gasification combined 

cycle (IGCC)

• delayed retirement

• demand-side management (DSM)

• purchased power
Alternatives Including the Proposed Action

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1 to prevent a gap in energy generation during the period of construction—which would likely take 

2 several years (TVA 2013). As a result, the NRC evaluated the impacts of locating replacement 

3 power facilities at other existing power plant sites within the TVA region of interest, which 

4 includes most of Tennessee and parts of Alabama, Georgia, Kentucky, Mississippi, 

5 North Carolina, and Virginia (TVA 2013). TVA also stated that replacement power alternatives 

6 could reasonably be located outside of the TVA region, specifically elsewhere within the 

7 Southeast Electric Reliability Corporation (SERC) transmission grid because electricity 

8 generated within SERC region could be efficiently routed back to the TVA region. Installing 

9 replacement power facilities at existing power plants and connecting to existing transmission 

10 and cooling system infrastructure would reduce the overall environmental impact.

11 To ensure that the alternatives analysis is consistent with State or regional energy policies, the 

12 NRC reviewed energy-related statutes, regulations, and policies within the TVA Region. As a 

13 result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 

14 as well as a combination that includes both of them.

15 The NRC considered the current generation capacity and electricity production within the State 

16 of Tennessee, as well as, where pertinent, the TVA region in the alternatives analysis. 

17 Tennessee relies on coal, natural gas, and nuclear power as its primary electric generation fuels 

18 (EIA 2012b). While the staff generally considers alternatives located within Tennessee, it 

19 acknowledges that alternatives could also be located elsewhere in the TVA region, or elsewhere 

20 in the SERC region.

21 At this time, the State of Tennessee has no regulations to encourage the increased production 

22 of energy from renewable resources such as wind, solar, biomass, and other alternatives to 

23 fossil and nuclear generation. TVA’s current renewable energy portfolio includes 

24 3,889 megawatts (MW) from hydroelectric, wind, solar, and methane gas sources within the 

25 TVA region. TVA also recently announced the addition of 1,625 MW of wind energy through the 

26 acquisition of eight additional purchased power contracts with Iowa, Kansas, North Dakota, 

27 South Dakota, and Illinois (TVA 2011b). An analysis of clean energy policy in the SERC region 

28 concluded that Tennessee has a variety of available renewable resources, including solar PV 

29 and a small hydroelectric potential (McLaren 2011). 

30 The remainder of this section describes the alternatives to license renewal that are evaluated in 

31 depth in Chapter 4 for potential environmental impacts. These include an NGCC alternative in 

32 Section 2.2.2.1, an SCPC alternative in Section 2.2.2.2, a new nuclear alternative in 

33 Section 2.2.2.3, and a combination wind and solar power alternative in Section 2.2.2.4. 

34 Table 2–1 summarizes key design characteristics of the alternative technologies evaluated in 

35 depth.
Alternatives Including the Proposed Action

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

2 Considered in Depth

NGCC Alternative SCPC Alternative New Nuclear 

Alternative

Combination 

Alternative

Summary 

of 

Alternative

Six 400-MWe units, 

for a total of 

2,400 MWe

Four SCPC units, for 

a total of 2,400 MWe

Two-unit nuclear plant, 

for a total of 2,400 MWe

2,350–3,150 2-MWe 

wind turbines, for a 

total of 

4,700–6,300 MWe 

(DOE 2008);

2,000–2,900 MWe 

installed solar PV

Location An existing power 

plant site (other than 

SQN) or brownfield 

site with available 

infrastructure in the 

TVA region; some 

infrastructure 

upgrades may be 

required; 

would require 

construction of a new 

or upgraded supply 

pipeline.

An existing power 

plant site (other than 

SQN) or brownfield 

site with available 

infrastructure in the 

TVA region; some 

infrastructure 

upgrades may be 

required.

An existing nuclear 

power plant site (other 

than SQN); 

some infrastructure 

upgrades may be 

required.

Spread across multiple 

sites throughout TVA

region; 

solar PV installed at 

developed sites and 

existing buildings

Cooling 

System

Closed-cycle with 

mechanical draft 

cooling towers; 

cooling water 

withdrawal 14.9 mgd; 

consumptive water 

use 11.4 mgd 

(NETL 2010a, 

2010b)

Closed-cycle with 

natural draft cooling 

towers; 

cooling water 

withdrawal 33.5 mgd; 

consumptive water 

use 26.6 mgd 

(NETL 2010a, 

2010c)

Closed-cycle with natural 

draft cooling towers; 

cooling water withdrawal 

48–62 mgd; 

consumptive water use 

45–48 mgd (NRC 2013)

N/A

Land 

Requirements

48 ac for the plant 

(NETL 2010b); 

8,640 ac for wells, 

collection site, 

pipeline (NRC 1996)

131 ac for the plant 

(NETL 2010a);

7,440–52,800 ac for 

coal mining and 

waste disposal 

(NRC 1996)

1,000 ac (TVA 2013); 

2,400 ac for uranium

mining and processing 

(TVA 2013)

Wind farms would 

require 1,410–1,890 ac 

(NRC 2013); 

standalone solar PV 

installations would 

require 

12,400–17,980 ac 

(Renné et al. 2008).

Work 

Force

2,880 during peak 

construction; 

120–180 during 

operations

2,880–6,000 during 

peak construction; 

360–480 during 

operations

5,000 during peak 

construction; 

540–720 during 

operations

200 during peak 

construction; 

50 during operations

Sources: Cited values derived or scaled from NETL 2010a, 2010b, 2010c; NRC 1996, 2013; Renné et al. 2008; 

TVA 2013

3 2.2.2.1 NGCC Alternative

4 Natural gas combined-cycle (NGCC) systems represent the largest majority of the total number 

5 of plants currently under construction or planned in the United States. The EIA projects that 

6 natural gas-fired generation will account for the largest single share of new generating capacity 
Alternatives Including the Proposed Action

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1 in the United States (37 percent) through 2040 (EIA 2013a). Factors that contribute to the 

2 current popularity of NGCC facilities include high capacity factors (ratio of actual output to 

3 potential output at full capacity, over a given period of time), low relative construction costs, low 

4 gas prices, and relatively low air emissions. Development of new NGCC plants may be affected 

5 by uncertainties about the continued availability and price of natural gas (though less so than in 

6 the recent past) and future regulations that may limit greenhouse gas (GHG) emissions. A 

7 gas-fired power plant, however, produces markedly fewer GHGs per unit of electrical output 

8 than a coal-fired plant of the same electrical output.

9 Combined-cycle power plants differ significantly from most coal-fired and all existing nuclear 

10 power plants. Combined-cycle plants derive the majority of their electrical output from a gas 

11 turbine and then generate additional power—without burning any additional fuel—through a 

12 second steam-turbine cycle. The exhaust gas from the gas turbine is still hot enough to boil 

13 water to steam. Ducts carry the hot exhaust to a heat recovery steam generator, which 

14 produces steam to drive a steam turbine and produce additional electrical power. The 

15 combined-cycle approach is significantly more efficient than any one cycle on its own; thermal 

16 efficiency (ratio of electrical power output to electrical power input) can exceed 50 percent 

17 versus 39 percent for conventional single-cycle facilities (NETL 2010a; Siemens 2007). In 

18 addition, because the natural gas-fired alternative derives much of its power from a gas-turbine 

19 cycle, and because it wastes less heat than the existing SQN units, it requires significantly less 

20 cooling water.

21 While nuclear reactors, on average, operate with capacity factors above 90 percent 

22 (SQN Units 1 and 2 operated at a 96 percent average capacity factor from 2008 to 2010 

23 (TVA 2013)), the staff expects that an NGCC alternative would operate with roughly an 

24 85 percent capacity factor. Nonetheless, the staff assumes that a similar-sized NGCC facility 

25 would be capable of providing adequate replacement power for the purposes of this NEPA

26 analysis. 

27 Typical power trains for large-scale NGCC power generation would involve one, two, or 

28 three combined-cycle units, available in a variety of standard sizes, mated to a heat-recovery 

29 steam generator. To complete the assessment of an NGCC alternative, the NRC assumes that 

30 appropriately sized units could be assembled to annually produce electrical power in amounts 

31 equivalent to SQN. For purposes of this review, the staff evaluated an alternative that consists 

32 of six parallel Advanced F Class units, 400 megawatts electric (MWe) each, equipped with 

33 dry-low-nitrogen-oxide combustors to suppress nitrogen oxide formation and selective catalytic 

34 reduction of the exhaust with ammonia for post combustion control of nitrogen oxide emissions. 

35 This alternative provides 2,400 MWe of capacity, replacing the full 2,400 MWe produced by 

36 SQN.

37 In its ER, TVA scaled from estimates in the 1996 GEIS of 0.11 ac/MW (110 acres per 1,000 MW 

38 for an NGCC plant) to calculate a land requirement for the NGCC alternative of approximately 

39 264 ac (107 ha) (TVA 2013). For the purposes of this analysis, NRC staff will use a scaling 

40 factor of 0.02 ac/MW, based on updated information from DOE sources (NETL 2010b). Using 

41 this updated scaling factor, a 2,400-MWe NGCC alternative would require approximately 

42 48 ac (19 ha) of land. Depending on the site location and availability of existing natural gas 

43 pipelines, a 100-ft wide (30.5-m wide) right-of-way may be needed for a new supply pipeline. 

44 The NGCC alternative may also require up to 8,640 ac (3,497 ha) of land for wells, collection 

45 stations, and pipelines to bring the gas to the plant (NRC 1996). Most of this land requirement 

46 would occur on land where gas extraction already occurs.

47 The NRC staff assumes that an NGCC alternative would utilize a closed-cycle cooling system

48 and be equipped with mechanical-draft cooling towers. The NGCC alternative would require 
Alternatives Including the Proposed Action

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approximately 14.9 mgd (0.65 m3 1 /s, 23 cubic feet per second (cfs)) of water for cooling and 

2 related processes (NETL 2010a, 2010b). Consumptive water use by the plant would be 

approximately 77 percent of the amount withdrawn, or about 11.4 mgd (0.5 m3 3 /s, 17.6 cfs) 

4 (NETL 2010a, 2010b).

5 While siting an alternative on the SQN site would allow for the fullest use of existing ancillary 

6 infrastructure, such as transmission and support buildings, and minimize the use of undisturbed 

7 land, space constraints on the SQN site preclude that option (TVA 2013). In its ER, TVA 

8 assumed that the NGCC alternative could be located outside the Tennessee Valley if the 

9 electricity could be efficiently routed to the SQN region (TVA 2013). The NRC determined that 

10 this assumption is valid, and for the purposes of this analysis also assumes that the NGCC 

alternative could be constructed at another existing nuclear power plant site or brownfield1 11 site 

12 with available infrastructure elsewhere in the TVA region or SERC region, which would mitigate 

13 construction impacts in a similar way to building the alternative at the SQN site. It is possible

14 that an NGCC alternative constructed at an existing power plant site would require some 

15 infrastructure upgrades, such as improved transmission lines or modifications to existing intake 

16 or cooling systems, but the NRC staff expects that these impacts would be smaller than those 

17 necessary to support an NGCC alternative constructed on an undeveloped site. 

18 Wherever the NGCC alternative is constructed, it is likely to require a new or upgraded pipeline 

19 to supply natural gas to the facility. Some of the natural gas supplied to this alternative is likely 

20 to come from Tennessee or from neighboring states, but the NGCC alternative is unlikely to 

21 directly trigger new natural gas development in Tennessee or the TVA region.

22 NGCC power plants are feasible, commercially available options for providing electric 

23 generating capacity beyond the current SQN license expiration dates. The overall 

24 environmental impacts of an NGCC alternative, as well as the environmental impacts of 

25 proposed SQN license renewal, are discussed in Chapter 4.

26 2.2.2.2 SCPC Alternative

27 Coal-fired generation historically has been the largest source of electricity in the United States; 

28 however, due to cost uncertainties associated with anticipated future environmental regulations 

29 (such as cap-and-trade and greenhouse emission regulations), projections for future coal-fired 

30 generation vary (EIA 2013a; NRC 2013). In its 2013 Annual Energy Outlook, the EIA projects 

31 that coal’s generation share could fall from 48 percent in 2008 to 35 percent in 2040, or as low 

32 as 27 percent in some projections (EIA 2013a). In Tennessee, 41 percent of electricity was 

33 generated using coal-fired power plants in 2010 (EIA 2012b). Baseload coal units have proven 

34 their reliability and can routinely sustain capacity factors of 85 percent or greater. Among the 

35 various boiler designs available, pulverized coal boilers producing supercritical steam (SCPC 

36 boilers) are the most likely variant for a coal-fired alternative given their generally high thermal 

37 efficiencies and overall reliability.

38 While nuclear reactors, on average, operate with capacity factors above 90 percent, the new 

39 SCPC coal-fired power plant would operate with roughly an 85 percent capacity factor. Despite 

40 the slightly lower capacity factor, an SCPC plant would be capable of providing adequate 

41 replacement power for a nuclear plant for the purposes of this NEPA analysis.

42 A myriad of sizes of pulverized coal boilers and steam turbine generators (STGs) are available; 

43 however, the NRC staff assumes that four equal-sized boiler/STG powertrains, operating 

44 independently and simultaneously, would likely be used to match the power output of SQN. To 

 

1 A brownfield site is an abandoned, idled, or under-used industrial and commercial facilities in which expansion or redevelopment is 

sometimes complicated by real or perceived environmental contamination (EPA 2011, NRC 2013).
Alternatives Including the Proposed Action

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1 complete this analysis, the NRC staff assumes that all powertrains would have the same 

2 features, operate at generally the same conditions, have similar impacts on the environment, 

3 and be equipped with the same pollution-control devices, such that once all parasitic loads 

4 (electric power consumed that does not contribute to the net electric yield) are overcome, the 

5 net power available would be equal to 2,400 MWe. The NRC staff assumes that 6 percent of an 

6 SCPC boiler’s gross capacity is needed to supply typical parasitic loads (plant operation plus 

7 control devices for criteria pollutants to meet New Source Performance Standards). Introducing 

8 controls for GHG emissions (i.e., carbon capture and sequestration (CCS)) would cause the 

9 parasitic load to increase to 27.6 percent of the boiler’s gross rated capacity (NETL 2010a). 

10 However, because of uncertainty regarding future GHG regulations and the limited real-world 

11 experience in CCS at utility-scale power plants, parasitic loads associated with CCS are not 

12 considered. Various bituminous coal sources are available to coal-fired power plants in 

13 Tennessee. EIA reports that, in 2009, Tennessee produced electricity from coal with heating 

14 values of 12,650 British thermal units per pound, sulfur content of 1.25 percent, and ash of 

15 8.87 percent (EIA 2010b). For the purpose of this evaluation, the staff assumes that coal 

16 burned in 2009 will be representative of coal that would be burned in a coal-fired alternative 

17 regardless of where it was located. Approximately 0.7 percent of the coal burned in Tennessee 

18 in 2009 came from mines in Tennessee. Wyoming, Illinois, and Kentucky supplied most of the 

19 remaining coal (EIA 2010b). Bituminous coals from Tennessee and Georgia mines have 

20 average carbon dioxide emission factors of 204.8 to 206.1 lb per million British thermal units of 

21 heat input, respectively (Hong and Slatick 1994). 

22 In its ER, TVA determined that the current 

23 SQN site was not viable to accommodate a 

24 coal-fired alternative with net generating 

25 capacity sufficient to meet the power 

26 production of SQN because of limited space 

27 on the SQN site (TVA 2013). The staff 

28 considers this assessment valid and the 

29 analysis of the impacts, in this SEIS, of the 

30 coal-fired alternative assumes that the SCPC 

31 coal-fired power plant would be sited at an 

32 existing power plant site or brownfield site 

33 with available infrastructure to take 

34 advantage of existing infrastructure. The site 

35 could be located in Tennessee or elsewhere 

36 in the TVA or SERC regions.

37 It is reasonable to assume that a coal-fired 

38 alternative would use supercritical steam 

39 (see text box). Supercritical steam 

40 technologies are increasingly common in 

41 new coal-fired plants. They are 

42 commercially available and feasible. 

43 Supercritical plants operate at higher 

44 temperatures and pressures than older 

45 subcritical coal-fired plants and, therefore, 

46 can attain higher thermal efficiencies. While 

47 supercritical facilities are more expensive to 

48 construct than subcritical facilities, they consume less fuel for a given output, reducing 

49 environmental impacts throughout the fuel life cycle. The NRC staff expects that a new 

Supercritical Steam

“Supercritical” refers to the thermodynamic 

properties of the steam being produced. Steam 

whose temperature and pressure is below water’s 

“critical point” (3,200 pounds per square inch 

absolute (psia) (221 bar] and 705 °F (374 °C)) is 

subcritical. Subcritical steam forms as water boils 

and both liquid and gas phases are observable in 

the steam. The majority of coal boilers currently 

operating in the United States produce subcritical 

steam with pressures around 2,400 psia (165 bar) 

and temperatures as high as 1,050 °F (566 °C). 

Above the critical point pressure, water expands 

rather than boils, and the liquid and gaseous 

phases of water are indistinguishable in the 

supercritical steam that results. More than 

150 coal boilers currently operating in the 

United States produce supercritical steam with 

pressures between 3,300 and 3,500 psia (228 to 

241 bar) and temperatures between 1,000 and 

1,100 °F (538 to 593 °C). Ultrasupercritical boilers 

produce steam at pressures above 3,600 psia 

(248 bar) and temperatures exceeding 1,100 °F 

(593 °C). There are only a few of these boilers in 

operation worldwide, none of which are in the 

United States.
Alternatives Including the Proposed Action

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1 supercritical coal-fired plant would operate at a heat rate of 8,721 British thermal units per 

2 kilowatt hour (EIA 2010a), or approximately 39 percent thermal efficiency. However, heat inputs 

3 could be less, depending on the coal source and whether fuel blending is practiced in order to 

4 remain compliant with emission limitations.

5 In its ER, TVA scaled from estimates in the 1996 GEIS of 1.7 ac per MW to calculate a land 

6 requirement for the SCPC alternative of approximately 4,080 ac (1,651 ha) (TVA 2013). For the 

7 purposes of this analysis, NRC staff will use an updated scaling factor of 0.05 ac per MW, 

8 based on updated information from DOE sources (NETL 2010a, 2010b). Using this updated 

9 scaling factor, a 2,400-MWe SCPC alternative would require approximately 131 ac (53 ha) of 

10 land. The 1996 GEIS estimates that up to 22,000 ac (8,900 ha) of land would be necessary for 

11 coal mining and processing for a 1,000-MWe coal-fired plant (22 ac per MW) (NRC 1996). 

12 A 2010 NETL study, however, estimated a much smaller scaling factor of 3.1 ac per MW 

13 (NETL 2010c). Because the NETL study was based on only one operating coal mine (Galatia 

14 Mine, Illinois), NRC staff will use a range of 7,440 ac (3,011 ha) to 52,800 ac (21,400 ha) of land 

15 for coal mining and processing for the SCPC alternative.

16 The NRC staff assumes that an SCPC alternative would utilize a closed-cycle cooling system

17 and be equipped with natural-draft cooling towers. The SCPC alternative would require 

approximately 34 mgd (1.5 m3 18 /s, 53 cfs) of water for cooling and related processes 

19 (NETL 2010a, 2010c). Consumptive water use by the plant would be approximately 80 percent 

of the amount withdrawn, or about 27 mgd (1.2 m3 20 /s, 42 cfs) (NETL 2010a, 2010c).

21 SCPC coal-fired power plants are currently commercially available and currently are feasible 

22 alternatives to SQN license renewal. The overall environmental impacts of a coal-fired 

23 alternative, as well as the environmental impacts of proposed SQN license renewal, are 

24 discussed in Chapter 4.

25 2.2.2.3 New Nuclear Alternative

26 In Tennessee, 15.9 percent of electricity was generated using nuclear power plants in 2010 

27 (EIA 2012b). As noted by EIA in its Annual Energy Outlook (EIA 2013a), nuclear generation is 

28 expected to grow by 14.3 percent from 2011 through 2040. The EIA projects that nuclear 

29 capacity will increase by 19 gigawatts (GW) (1 GW equals 1,000 MW) through 2040, including 

30 8.0 GW of expansions at existing plants and 11.0 GW of new capacity (EIA 2013a). A new 

31 nuclear power plant is likely to be similar to SQN in terms of capacity factor.

32 Several designs are possible for a new nuclear facility. However, a two-unit nuclear power plant 

33 similar to the existing SQN in output is most likely. Currently, four nuclear reactor designs have 

34 been certified, including the 1,300-MWe U.S. Advanced BWR, the 1,300-MWe System 80+ 

35 Design, the 600-MWe AP600 Design, and the 1,100-MWe AP1000 Design (NRC 2013). The 

36 new nuclear alternative would rely on a closed-cycle cooling system with natural-draft cooling 

37 towers, similar to the cooling system currently in place at SQN. 

38 In its ER, TVA determined that the current SQN site was not viable to accommodate a new 

39 nuclear alternative with net generating capacity sufficient to meet the power production of SQN 

40 because of insufficient space at the SQN site (TVA 2013). The NRC staff supports this 

41 assumption, and for the purposes of this analysis also assumes that the new nuclear alternative 

42 would most likely be constructed on a site that already hosts a nuclear power plant elsewhere in 

43 the TVA region or SERC region. This placement would allow the new nuclear alternative to take 

44 advantage of existing site infrastructure, including transmission lines and some support facilities. 

45 In February 2012, the NRC issued two combined licenses (COLs) for the construction and 

46 operation of two AP1000 reactors at the Alvin W. Vogtle Electric Generating Plant site in 

47 Waynesboro, Georgia (77 FR 12332; NRC 2013). In March 2012, NRC issued two COLs for 
Alternatives Including the Proposed Action

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1 the construction and operation of two new AP1000 reactors at the Virgil C. Summer Nuclear 

2 Station site in Jenkinsville, South Carolina (77 FR 21593; NRC 2013).

3 In its ER, TVA calculated a land requirement for the new nuclear alternative of approximately 

4 1,000 ac (405 ha) based on the sizes of TVA’s existing nuclear plant sites (Bellefonte, 

5 Sequoyah, and Watts Bar, which range from 600 to 1,500 ac (243 to 607 ha)) (TVA 2013). This 

6 estimate is consistent with the 2013 GEIS, which estimates a land requirement of 500 to 

7 1,000 ac (202 to 405 ha) for a new nuclear plant (NRC 2013). For the purposes of this analysis, 

8 NRC staff will use TVA’s estimate of 1,000 ac (405 ha). TVA also estimated that up to 2,400 ac 

9 (971 ha) of land would be affected by the uranium mining and processing during the life of the 

10 nuclear plant (TVA 2013). 

11 The NRC staff assumes that a new nuclear alternative would utilize a closed-cycle cooling 

12 system and be equipped with natural-draft cooling towers. Because SQN only operates in 

13 open-cycle and helper cooling modes, water consumption for the new nuclear alternative would 

14 be considerably greater than SQN (see Section 4.5.5.1). The new nuclear alternative would 

require approximately 62 mgd (2.7 m3 15 /s, 96 cfs) of water for cooling and related processes 

16 (NETL 2010a, 2010c). Consumptive water use by the plant would be approximately 80 percent 

of the amount withdrawn, or about 48 mgd (2.1 m3 17 /s, 74 cfs) (NETL 2010a, 2010c).

18 New nuclear power plants are commercially available and feasible alternatives to SQN license 

19 renewal. The overall environmental impacts of a new nuclear alternative, as well as the 

20 environmental impacts of proposed SQN license renewal, are discussed in Chapter 4. 

21 2.2.2.4 Combination Wind and Solar Alternative

22 The combination alternative consists of 4,700 to 6,300 MWe of total installed wind capacity and 

23 2,000 to 2,900 MWe of total installed solar PV capacity to provide the balance needed to 

24 replace SQN. The staff applied a capacity-factor-based approach to determining the relative 

25 amount of wind and solar power in this alternative. 

26 The overall environmental impacts of a combination wind and solar (PV) alternative, as well as 

27 the environmental impacts of proposed SQN license renewal, are discussed in Chapter 4. 

28 Wind Power Portion

29 The feasibility of wind as a baseload power source depends on the availability, accessibility, and 

30 constancy of the wind resource within the region of interest. Wind power, in general, cannot be 

31 stored without first being converted to electrical energy. Wind power installations, which may 

32 consist of several hundred turbines, produce variable amounts of electricity. SQN, however, 

33 produces electricity almost constantly. Because wind power installations deliver variable output 

34 when wind conditions change, wind power cannot substitute for existing baseload generation on 

35 a one-to-one basis.

36 The energy potential in wind is expressed by wind generation classes, which range from 1 (least 

37 energetic) to 7 (most energetic). Wind resources with wind speeds of at least 15.7 miles per 

38 hour (mph) (7.0 meters per second (m/s)), that is, Class 3 or better, are most desirable for 

39 utility-scale amounts of electricity. Utility-scale wind potential in the State of Tennessee and the 

40 surrounding TVA region is relatively low compared to other parts of the country, with the 

41 majority of the region rated at Class 1 or 2 (DOE 2012). A 2010 NREL report estimated a wind 

42 potential of 1,247 MWe in the TVA region, while DOE estimated approximately 3,219 MW in the 

43 seven states that comprise the TVA region (NREL 2011). TVA owns one small windfarm with 

44 three 660-kilowatt (kW) turbines on Buffalo Mountain near Oak Ridge, Tennessee, and 

45 purchases 27 MW of wind generated electricity from another windfarm on Buffalo Mountain 

46 (TVA 2011a). Due to lack of available resources, TVA has taken the approach of procuring 
Alternatives Including the Proposed Action

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1 wind power through power purchase agreements (PPAs) with other States that do have the 

2 available wind energy potential (TVA 2011b). TVA has entered into PPAs with seven windfarms 

3 for a total of 1,625 MW (TVA 2011b).

4 Wind power is a commercially available and feasible means of generating electricity. Although 

5 the TVA region has relatively low wind energy potential, other areas in the SERC region have 

6 higher potential wind resources (DOE 2012). A study by Archer and Jacobson (2007) indicates 

7 that an array of interconnected wind sites (19 in the study) spread across significant distances 

8 (with approximately 850 km (530 mi) distance from north to south and east to west) could 

9 provide 21 percent of installed capacity 79 percent of the time. While the sites in Archer and 

10 Jacobson’s study, in most cases, accessed higher power-class wind resources than are readily 

11 available onshore in the TVA region, the approach suggests that approximately 20 percent of 

12 the installed capacity in a series of interconnected wind installations could provide baseload 

13 power. Therefore, this study indicates that interconnecting windfarms, as assumed in this 

14 alternative, may provide a source of consistent baseload power. In this alternative, the staff 

15 considers a wind alternative that relies on numerous, interconnected wind installations scattered 

16 across the TVA or SERC region. This arrangement ensures that generators are sufficiently 

17 dispersed so that low-wind or no-wind conditions are unlikely to occur at all or most locations at 

18 any given time.

19 Wind farms currently operate at much lower capacity factors than nuclear power. For example, 

20 SQN operated at a 96-percent average capacity factor from 2008 to 2010 (TVA 2013). 

21 Currently, DOE estimates that wind turbine installations operate at 39 percent or lower capacity 

22 factors because of the variability of wind resources (DOE 2008). NREL uses a capacity factor 

23 range of 30 to 37 percent (NREL 2013; Tegen et al. 2013). Capacity factors are likely to 

24 increase as wind turbine technology advances and as operators become more experienced in 

25 maximizing output. According to a DOE report, capacity factors improved by 11 percent from 

26 2005 to 2006 (DOE 2008). The DOE report states that most common large turbines have a 

27 rated capacity of between 1 MW and 3 MW, with rotor diameters between 60 m and 90 m (197 

28 and 295 ft), tower heights between 60 m and 100 m (197 and 328 ft), and capacity factors 

29 between 30 and 40 percent (DOE 2008). For the purposes of this analysis, the staff will assume 

30 a capacity factor range of 30 to 40 percent. In the wind portion of this alternative, the staff 

31 considers a wind alternative that relies on numerous interconnected wind installations scattered 

32 across the TVA or SERC region, with an installed capacity between 4,700 MWe and 

33 6,300 MWe. Relying on commonly available 2-MWe turbines, 2,350 to 3,150 turbines would be 

34 required to replace SQN generation in conjunction with the solar portion of this alternative 

35 described below. 

36 Since wind turbines require ample spacing between one another to avoid air turbulence, the 

37 footprint of a utility scale wind farm could be quite large. Wind energy facilities require 

38 approximately 0.3 ac (0.12 ha) of land per MW (NRC 2013). Most of the wind farms would likely 

39 be located on open agricultural cropland, which would remain largely unaffected by the wind 

40 turbines. Once the installation of the turbines and the construction of support facilities are 

41 completed, land areas between the turbines can be used for other beneficial (nonintrusive) 

42 uses. During operations, only 5–10 percent of the total acreage within the wind farm is actually 

43 occupied by turbines, access roads, support buildings, and associated infrastructure while the 

44 remaining land area can be returned to its original condition or some other compatible use, such 

45 as farming or grazing.

46 This alternative assumes all wind power would be generated onshore because it is currently 

47 commercially available and a feasible means of generating electricity. While some offshore 

48 wind development is possible by 2024, no commercial offshore wind installations currently 

49 operate in the United States, despite more than a decade of development efforts. In the Atlantic 
Alternatives Including the Proposed Action

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1 Ocean, several commercial wind-power projects have been proposed, but none have yet 

2 received final approvals or begun construction. 

3 Solar Photovoltaic Portion

4 Solar energy potential is a function of average daily solar insolation and is reported either as 

5 direct normal radiation (without diffuse light) or total radiation (direct and diffuse light) 

6 (TVA 2011a). In PV systems, sunlight incident on special PV materials produces direct current 

7 (DC) electricity. An advantage of PV is that it is suitable for locations with low direct-sun 

8 irradiation. The potential for solar technologies to serve as reliable baseload power alternative 

9 depends on the value, constancy, and accessibility of the solar resource. Solar resources 

10 across the United States are good to excellent, with solar insolation levels ranging from about 

2.7 to 6.8 kilowatt hours per square meter per day (kWh/m2 11 /day) (NREL 2012). Tennessee 

receives approximately 4.5 to 5.0 kilowatt hours per square meter per day (kWh/m2 12 /day) of 

global radiation, compared to roughly 6.0 to 8.0 kWh/m2 13 /day in areas of the Southwest and 

14 West, such as California (NREL 2012). Other states within the TVA region receive 5.0 to 

5.5 kWh/m2 15 /day of global radiation (NREL 2012). A 2007 study which calculated the net PV 

16 energy density for each state concluded that solar resources in the TVA region are plentiful, with 

17 TVA region states ranking between 14th and 29th in PV energy density (Denholm and 

18 Margolis 2007; TVA 2011a).

19 Currently, TVA owns 14 PV installations, with a combined capacity of about 280 kW 

20 (TVA 2011b). TVA has taken a similar approach of procuring solar power as it has with wind 

21 power, through PPAs with other States that have available solar energy potential (TVA 2011b). 

22 TVA projects the acquisition of an additional 365 MW of solar capacity through PPAs by 2020 

23 (TVA 2011b). In TVA’s renewable portfolio projections, solar accounts for approximately 7 to 

24 10 percent net renewable capacity, approximately 185 to 365 MW, by the year 2029 

25 (TVA 2011b).

26 The PV technologies would generally be installed on building roofs at existing residential, 

27 commercial, or industrial sites; however, some solar installations may also be built at standalone 

28 solar sites. Land use impacts may vary depending on the amount of additional land required 

29 and the actual allocation of solar installations. The footprint of a utility scale standalone PV 

30 solar installation would be quite large, with approximately 12,400 to 17,980 ac (5,018 to 

31 7,276 ha) of land needed to support a 2,000- to 2,900-MW solar PV alternative (Renné 

32 et al. 2008). Installing PV solar technologies on building rooftops would reduce the amount of 

33 land required for standalone solar. A 2008 study found the PV rooftop potential solar capacity in 

34 the TVA region to be approximately 23,000 MW (Paidipati et al. 2008; TVA 2011a). Based on 

35 this, NRC staff assumes that sufficient rooftop space exists throughout the TVA or SERC 

36 regions to support installation of the solar PV portion of this alternative solely on existing 

37 structures, thus minimizing potential for land-use and terrestrial ecology impacts from solar PV 

38 installations. 

39 2.3 Alternatives Considered but Dismissed

40 Alternatives to SQN license renewal that were considered and eliminated from detailed study 

41 are presented in this section. These alternatives were eliminated because of technical, 

42 resource availability, or current commercial limitations. Many of these limitations would continue 

43 to exist when the current SQN licenses expire.
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1 2.3.1 Wind Power

2 The feasibility of wind power relies on the availability of the wind resource within the region of 

3 interest and access to transmission infrastructure. In recent years, wind power has increased in 

4 scale significantly, and the largest operating plant in the United States is a 1,020-MW facility 

5 located in Tehachapi Pass in Kern County, California. The advantages of wind power are the 

6 use of a renewable natural resource and no direct airborne emissions. Disadvantages are a 

7 large total land commitment (although much of the land surrounding individual wind turbines 

8 could be used for other purposes such as agriculture), a relatively low capacity factor, aesthetic

9 intrusion, and bird and bat casualties.

10 The energy potential in wind is expressed by wind generation classes, which range from 1 (least 

11 energetic) to 7 (most energetic). Wind resources with wind speeds of at least 15.7 mph 

12 (7.0 m/s), that is, Class 3 or better, are most desirable for utility-scale amounts of electricity. 

13 However, advances in wind energy technology development, specifically blade diameter, make 

14 areas previously considered “low” wind resources, such as areas with wind speeds of 13.4 mph 

15 (6 m/s), suitable for development (NREL 2011).

16 The majority of Tennessee and the TVA region is classified as a Class 1 or Class 2 region 

17 (NREL 2009). Approximately 29 MW of wind capacity is operating in the TVA region as of 2011, 

18 all of which is located within the State of Tennessee (DOE 2012). Based on the amount of 

19 available windy land area, the NREL estimates 309 MW of potential installed wind capacity for 

20 Tennessee, and 3,219 MW for the entire TVA region, with a gross capacity factor of 30 percent 

21 at 80-m (260-ft) heights above ground (NREL 2011). Although this does not address current 

22 cost and turbine design limitations, as stated previously, turbine technology improvements are 

23 leading to industry expectations to serve sites with lower wind speeds (NREL 2012).

24 The potential for energy storage could address the variable aspect of wind power, which is now 

25 one of the primary drivers behind renewed interest in energy storage. Storage provides one 

26 solution to provide firm capacity and energy, allowing intermittent generation to effectively 

27 replace baseload generation. As of 2009, only four energy storage technologies (sodium-sulfur 

28 batteries, pumped hydro, compressed air energy storage, and thermal storage) have a 

29 worldwide installed capacity that exceeds 100 MW (NREL 2012). 

30 As a result, the NRC staff does not consider new wind generation to be a reasonable 

31 standalone alternative to SQN license renewal. However, when combined with other renewable 

32 technologies, wind energy can contribute to a viable alternative. The NRC staff evaluated such 

33 a possible combination in Section 2.2.2.4.

34 2.3.2 Solar Power

35 Solar technologies, including PV and solar thermal (also known as concentrated solar power 

36 (CSP)), use the sun’s energy to produce electricity at a utility scale. In PV systems, special PV 

37 materials convert the energy contained in photons of sunlight to DC electricity that can be 

38 aggregated, converted to alternating current, and connected to the high-voltage transmission 

39 grid. Some PV installations, especially those located on existing buildings, provide power 

40 directly to consumers without first going onto the grid. The CSP technologies produce electricity 

41 by capturing the sun’s heat energy. The CSP facilities are typically grid connected, and owing 

42 to size and operational characteristics, are not located atop existing structures. Although some 

43 aspects of solar generation result in few environmental impacts, solar technology requires 

44 substantial land areas, and CSP technologies require roughly the same amount of water for 

45 cooling of the steam cycle as most other thermoelectric technologies.
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1 The potential for solar technologies to serve as reliable baseload power alternative to SQN 

2 depends on the value, constancy, and accessibility of the solar resource. Both PV and CSP are 

3 enjoying explosive growth worldwide, especially for various off-grid applications or to augment 

4 grid-provided power at the point of consumption; however, discrete baseload applications still 

5 have technological limitations. Solar power generation typically requires backup generation or 

6 other means of balancing its variable output. Further, PV installations have no ability to provide 

7 power at night, and they provide reduced levels of power on overcast days, during fog events, 

8 and when snow accumulates. While their generation during summer months is high when 

9 electricity consumption is high, their capacity to generate electricity in winter declines before the 

10 evening electricity demand peaks.

11 EIA reports the total solar generating capacity (CSP and solar PV) in the United States in 2011 

12 was 1,524 MW, 0.01 percent of the total nationwide generating capacity. Solar power produced 

13 1.818 million megawatt hours (MWh) of power in 2011, 0.04 percent of the nationwide 

14 production (EIA 2013b). The NRC staff is not aware of any CSP facilities in the United States 

15 that are not located in the Southwest, while many PV installations occur throughout the country. 

16 As a result, the NRC staff determined that a solar-powered alternative in the TVA region would 

17 rely on solar PV technology rather than CSP technology.

18 Because PV does not produce electricity at night and produces diminished amounts of power 

19 during particular weather conditions, the staff does not consider solar PV to provide a viable 

20 standalone alternative to license renewal. Load balancing or firming methods (using storage to 

21 remove the variability of available solar resources) would be necessary for solar to serve as a 

22 standalone alternative to SQN. Technology to achieve load balancing or firming methods is not 

23 yet feasible or commercially available, which is part of the reason why the NRC staff determined 

24 that this alternative is not reasonable. However, when combined with other renewable 

25 technologies, solar power can contribute to a viable alternative. The NRC staff evaluated such 

26 a possible combination in Section 2.2.2.4.

27 2.3.3 Conventional Hydroelectric Power

28 Currently, there are approximately 2,000 operating hydroelectric facilities in the United States. 

29 Hydroelectric technology captures flowing water and directs it to a turbine and generator to 

30 produce electricity (NRC 2013). There are three variants of hydroelectric power: 

31 run-of-the-river (diversion) facilities redirect the natural flow of a river, stream, or canal through a 

32 hydroelectric facility; store-and-release facilities block the flow of the river by using dams that 

33 cause water to accumulate in an upstream reservoir; and pumped storage facilities use 

34 electricity from other power sources to pump water to higher elevations during off-peak load 

35 periods to be released during peak load periods through the turbines to generate additional 

36 electricity. Store-and-release facilities affect large amounts of land behind the dam to create 

37 reservoirs, but can provide substantial amounts of power at capacity factors greater than 

38 90 percent. Power generating capacities of run-of-the-river facilities fluctuate with the flow of 

39 water in the river, and operation is typically constrained (and suspended entirely during certain 

40 periods) so as not to create undue stress on an aquatic ecosystem. Capacities of pumped 

41 storage facilities are dependent on the configuration and capacity of the elevated storage 

42 facility.

43 The EIA projects that hydropower will remain the leading source of renewable generation 

44 through 2040; however, there is little expected growth in hydropower capacity (EIA 2013). The 

45 potential for future construction of large hydropower facilities has diminished due to increased 

46 public concerns over flooding, habitat alteration and loss, and destruction of natural river 

47 courses (NRC 2013). 
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1 A comprehensive survey of hydropower resources in Tennessee was completed in 1997 by 

2 DOE’s Idaho National Engineering and Environmental Laboratory (INEEL) (now known as the 

3 Idaho National Laboratory). In the study, generating potential was defined by a model that 

4 considered the existing hydroelectric technology at developed sites, or applied the most 

5 appropriate technology to undeveloped sites, and introduced site-specific environmental 

6 considerations and limitations. Tennessee had limited hydroelectric potential, with a total 

7 generating potential of 138 MWe (INEEL 1997a). This potential was spread across 22 sites, 

8 one of which had the potential for 90 MWe of generation, or 65 percent of the total undeveloped 

9 hydropower potential of the Tennessee river basins. Most other states in the TVA region have 

10 similarly limited undeveloped potential (Conner et al. 1998), with the largest potential in Virginia, 

11 which has 617 MWe spread across 88 sites (INEEL 1997b).

12 More recently, EIA reported that, in 2010, conventional hydroelectric power (excluding pumped 

13 storage) was the principal electricity generation source among renewable sources in Tennessee 

14 (EIA 2012c). Approximately 2,624 MWe of hydroelectric capacity was installed in Tennessee as 

15 of 2010. Those installations provided 8,138 gigawatt hours (GWh) of electricity (EIA 2012c). 

16 Although hydroelectric facilities can demonstrate relatively high capacity factors, the small 

17 potential capacities and actual recent power generation of hydroelectric facilities in Tennessee, 

18 combined with the diminishing public support for large hydroelectric facilities because of their 

19 potential for adverse environmental impacts, supports the NRC staff’s conclusion that 

20 hydroelectric is not a feasible alternative to SQN.

21 2.3.4 Geothermal Energy

22 Geothermal technologies extract the heat contained in geologic formations to produce 

23 steam to drive a conventional steam-turbine generator. Geothermal energy facilities 

24 have demonstrated capacity factors of 90 to 98 percent, making geothermal energy 

25 clearly eligible as a source of baseload electric power (NRC 2013). However, as with 

26 other renewable energy technologies, the ultimate feasibility of geothermal energy 

27 serving as a baseload power replacement for SQN depends on the quality and 

28 accessibility of geothermal resources within or proximate to the region of interest—in this 

29 case, the TVA or SERC region. Most domestic geothermal resources exist in the 

30 western United States, with the greatest contribution of geothermal energy to electricity 

31 production occurring in California. As of October 2009, the United States had a total 

32 installed geothermal electricity production capacity of 3,153 MWe originating from 

33 geothermal facilities in eight states—Alaska, California, Hawaii, Idaho, Nevada, 

34 New Mexico, Utah, and Wyoming. Additional geothermal projects are being considered 

35 in 14 other states. Neither Tennessee nor the TVA region has adequate geothermal 

36 resources to support utility-scale electricity production (GEA 2010). NRC staff 

37 concludes, therefore, that geothermal energy does not represent a feasible alternative to 

38 SQN.

39 2.3.5 Biomass Energy

40 When used here, “biomass energy” includes crop residues, switchgrass grown specifically for 

41 electricity production, forest residues, methane from landfills, methane from animal manure 

42 management, primary wood mill residues, secondary wood mill residues, urban wood wastes, 

43 and methane from domestic wastewater treatment. The feasibility of using biomass fuels for 

44 baseload power depends on its geographic distribution, available quantities, constancy of 

45 supply, and energy content. Biomass energy conversion is accomplished using a wide variety 

46 of technologies, including direct burning, conversion to liquid biofuels, and biomass gasification. 

47 In a study completed in December 2005, Milbrandt of NREL documented the geographic 
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1 distribution of biomass fuels within the United States, reporting the results in metric tons (MT) 

2 available (dry basis) per year. Most counties in Tennessee have limited potential for biomass 

3 fuels, with the exception of Shelby County. Use of biomass fuels in Tennessee is also limited. 

4 Beyond the wood and wood waste considered in Section 2.3.7, generators in the State used 

5 biomass fuels to produce merely 2,000 MWh of electricity in 2010 (EIA 2012).

6 TVA has a cofiring methane facility at the Allen Fossil Plant and also purchases about 21 MW of 

7 non-wood waste biomass-fueled generation, including 9.6 MW of landfill gas generation and 

8 11 MW of corn milling residue generation (TVA 2011b). TVA’s Integrated Resource Plan (IRP) 

9 also includes up to 490 MW of biomass generation and landfill generation, some of which 

10 includes the conversion of existing coal-fired units to biomass-fired units and cofiring biomass 

11 with coal at existing coal plants (TVA 2011b). TVA is currently assessing the feasibility of 

12 converting coal-fired units to biomass fuel.

13 In the GEIS (NRC 2013), the NRC indicated that technologies relying on a variety of biomass 

14 fuels had not progressed to the point of being competitive on a large scale or of being reliable 

15 enough to replace a baseload plant such as SQN. After reevaluating current technologies, and 

16 after reviewing existing Statewide capacities and the extent to which biomass is currently being 

17 used to produce electricity, the NRC staff finds biomass-fueled alternatives are still unable to 

18 replace the SQN capacity and are not considered feasible alternatives to SQN license renewal.

19 2.3.6 Municipal Solid Waste

20 Municipal solid waste (MSW) combustors use three types of technologies—mass burn, modular, 

21 and refuse-derived fuel. Mass burning is currently the method used most frequently in the 

22 United States and involves no (or little) sorting, shredding, or separation. Consequently, toxic or 

23 hazardous components present in the waste stream are combusted, and toxic constituents are 

24 exhausted to the air or become part of the resulting solid wastes. Currently, approximately 

25 87 waste-to-energy plants operate in 25 states, processing 97,000 tons (88,000 MT) of MSW 

26 per day. Approximately 26 million tons (24 million MT) of trash were processed in 2008 by 

27 waste-to-energy facilities. With a reliable supply of waste fuel, waste-to-energy plants have a 

28 nationwide aggregate capacity of 2,720 MWe (compared to a 2,400 MWe capacity at SQN) and 

29 can operate at capacity factors greater than 90 percent (ERC 2010). 

30 The decision to burn municipal waste to generate energy is usually driven by the need for an 

31 alternative to landfills, rather than energy considerations. Regulatory structures that once 

32 supported MSW incineration no longer exist. For example, the Tax Reform Act of 1986 made 

33 capital-intensive projects, such as municipal waste combustion facilities, more expensive 

34 relative to less capital-intensive waste disposal alternatives, such as landfills. Additionally, the 

35 1994 Supreme Court decision C & A Carbone, Inc., et al. v. Town of Clarkstown, New York, 

36 struck down local flow control ordinances that required waste to be delivered to specific 

37 municipal waste combustion facilities rather than landfills that may have had lower fees. In 

38 addition, environmental regulations have increased the capital cost necessary to construct and 

39 maintain municipal waste combustion facilities.

40 Given the limited nationwide implementation of MSW-based generation to date (only 7 percent 

41 greater than the capacity of SQN), the small average installed size of MSW plants, the likelihood 

42 that additional stable streams of MSW are not likely to be available to support numerous new 

43 facilities, and the increasingly unfavorable regulatory environment, the NRC staff does not 

44 consider MSW combustion to be a reasonable alternative to SQN license renewal.
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1 2.3.7 Wood Waste

2 The use of wood waste to generate utility-scale baseload power is limited to those locations 

3 where wood waste is plentiful (NRC 1996). Wastes from pulp, paper, and paperboard industries 

4 and from forest management activities can be expected to provide sufficient, reliable supplies of 

5 wood waste as feedstocks to external combustion sources for energy generation. Beside the 

6 fuel source, the technological aspects of a wood-fired generation facility are virtually identical to 

7 those of a coal-fired alternative—combustion in an external combustion unit such as a boiler to 

8 produce steam to drive a conventional STG. Given constancy of the fuel source, wood waste 

9 facilities can be expected to operate at equivalent efficiencies and reliabilities. Costs of 

10 operation would depend significantly on processing and delivery costs. Wood waste 

11 combustors would be sources of criteria pollutants and GHGs, and pollution control 

12 requirements would be similar to those for coal plants. Unlike coal plants, there is no potential 

13 for the release of hazardous air pollutants (HAPs) such as mercury. Cofiring of wood waste with 

14 coal is also technically feasible. Processing the wood waste into pellets can improve the overall 

15 efficiency of such cofired units. 

16 Although cofired units can have capacity factors similar to baseload coal-fired units, such levels 

17 of performance are dependent on the continuous availability of the wood fuel. In Tennessee, 

18 2010 electricity generating capacity from wood waste was 185 MWe and produced 

19 914,000 MWh (EIA 2012). TVA has a cofiring wood waste facility at Colbert Fossil Plant and 

20 currently purchases about 70 MW of wood waste generation through PPAs (TVA 2011b). Given 

21 the limited capacity and modest actual electricity production, the NRC staff has determined that 

22 production of electricity from wood waste would not be a feasible alternative to SQN license 

23 renewal.

24 2.3.8 Ocean Wave and Current Energy

25 Ocean waves, currents, and tides represent kinetic and potential energies. Waves, currents, 

26 and tides are often predictable and reliable; ocean currents flow consistently, while tides can be 

27 predicted months and years in advance with well-known behavior in most coastal areas. The 

28 total annual average wave energy off the U.S. coastlines at a water depth of 60 m (197 ft) is 

29 estimated at 2,100 terawatt-hours (TWh) (2,100,000,000 MWh) (MMS 2006). In general, 

30 technologies that harness ocean wave energy are in their infancy and have not been used at a 

31 utility scale, though these technologies may become commercially available in the near future 

32 as more feasibility studies and prototype tests are conducted. 

33 Ocean current energy technology is similarly in its infancy. In relatively constant currents, 

34 ocean turbines can produce sufficient capacity factors for baseload demand (MMS 2006). Only 

35 a small number of prototypes and demonstration units have been deployed to date. 

36 The NRC staff is not currently aware of any plans to develop or deploy ocean wave and ocean 

37 current generation technologies on a scale similar to that of SQN. Consequently, due to 

38 relatively high costs and limited planned implementation the NRC staff concludes that ocean 

39 energy technologies are not feasible substitutes for SQN.

40 2.3.9 Oil-Fired Power

41 EIA projects that oil-fired plants will account for very little of the new generation capacity 

42 constructed in the United States during the 2008 to 2030 time period (EIA 2013a). In 2010, 

43 Tennessee generated 0.3 percent of its total electricity from oil (EIA 2012). 
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1 The variable costs of oil-fired generation tend to be greater than those of nuclear or coal -fired 

2 sources, and oil-fired generation tends to have greater environmental impacts than natural 

3 gas-fired generation. In addition, future increases in oil prices are expected to make oil-fired 

4 generation increasingly expensive (EIA 2013a). The high cost of oil has prompted a steady 

5 decline in its use for electricity generation. Thus, the NRC staff does not consider oil-fired 

6 generation as a reasonable alternative to SQN license renewal.

7 2.3.10 Fuel Cells

8 Fuel cells oxidize fuels without combustion and its environmental side effects. Power is 

9 produced electrochemically by passing a hydrogen-rich fuel over an anode and air (or oxygen) 

10 over a cathode and separating the two by an electrolyte. The only byproducts (depending on 

11 fuel characteristics) are heat, water, and carbon dioxide. Hydrogen fuel can come from a 

12 variety of hydrocarbon resources by subjecting them to steam reforming under pressure. 

13 Natural gas is typically used as the source of hydrogen.

14 Currently, fuel cells are not economically or technologically competitive with other alternatives

15 for electricity generation (EIA 2012). Fuel cell units are likely to be small in size (the EIA 

16 reference plant is 10 MWe). While it may be possible to use a distributed array of fuel cells to 

17 provide an alternative to SQN, it would be extremely costly to do so and would require many 

18 units and wholesale modifications to the existing transmission system. Accordingly, the NRC 

19 staff does not consider fuel cell technology to be a reasonable alternative to SQN license 

20 renewal.

21 2.3.11 Coal-Fired Integrated Gasification Combined Cycle

22 Integrated gasification combined cycle (IGCC) is an emerging technology for generating 

23 electricity with coal that combines modern coal gasification technology with both gas turbine and 

24 steam turbine power generation. Gasifiers, similar to those used in oil refineries, use heat 

25 pressure and steam to pyrolyze (thermally reform complex organic molecules without oxidation) 

26 coal to produce synthesis gases (generically referred to as syngas) typically composed of 

27 carbon monoxide, hydrogen, and other flammable constituents. After processing to remove 

28 contaminants and produce various liquid chemicals, the syngas is combusted in a combustion 

29 turbine (CT) to produce electric power. Separating the carbon dioxide from the syngas before 

30 combustion is also possible. Latent heat is recovered both from the syngas as it exits the 

31 gasifier and from the combustion gases exiting the CT and directed to a heat recovery steam 

32 generator feeding a conventional Rankine cycle STG to produce additional amounts of 

33 electricity. Emissions of criteria pollutants would likely be slightly higher than those from an 

34 NGCC alternative but significantly lower than those from the supercritical coal-fired alternative. 

35 Depending on the gasification technology employed, IGCC would use less water than SCPC 

36 units but slightly more than NGCC (NETL 2010a). Long-term maintenance costs of this 

37 relatively complex technology would likely be greater than those for a similarly sized SCPC or 

38 NGCC plant.

39 Only a few IGCC plants are operating at utility scale. Operating at higher thermal efficiencies 

40 than supercritical coal-fired boilers, IGCC plants can produce electrical power with fewer air 

41 pollutants and solid wastes than coal-fired boilers. To date, however, IGCC technologies have 

42 had limited application and have been plagued with operational problems such that their 

43 effective, long-term capacity factors are often not high enough for them to reliably serve as 

44 baseload units. Although IGCC technology may become more commonplace in the future, 

45 current operational problems that compromise reliability result in the dismissal of this technology 

46 as a viable alternative to SQN license renewal.
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1 2.3.12 Delayed Retirement

2 The retirement of a power plant ends that power plant’s ability to supply electricity. Delaying the 

3 retirement of a power plant enables that power plant to continue supplying electricity. TVA’s 

4 IRP, issued in March 2011, outlines TVA’s plan to retire 18 of its 59 coal-fired units by the end of 

5 2017 (TVA 2011b). Delayed retirement of these units would provide approximately 2,400 to 

6 4,700 MWe of capacity, or about 16 percent of its coal-fired generation. TVA’s decision to retire 

7 these coal plants was based on the age of the fleet, increasingly stringent air quality regulations, 

8 and the anticipation of new generating capacity from Watts Bar Nuclear Plant Unit 2 and a new 

9 combined-cycle plant at the John Sevier Fossil Plant (TVA 2011b).

10 Most retired units are dirtier and less efficient than new units. Often, units are retired because 

11 operation is no longer economical. In some cases, the cost of environmental compliance or 

12 necessary repairs and upgrades are too high to justify continued operation. As a result, the 

13 NRC staff does not consider delayed retirement a reasonable alternative to license renewal. 

14 2.3.13 Energy Efficiency and Demand Side Management

15 In its ER, TVA indicates that its energy efficiency and demand response (EEDR) program by 

16 itself would not be a reasonable alternative to license renewal (TVA 2013). While the NRC staff 

17 finds this position reasonable for purposes of this analysis, it notes that demand-side 

18 management (DSM) is an option for energy planners and decisionmakers—and it may be a 

19 potential consequence of a no action alternative—and so it is discussed in this section. 

20 As addressed in the GEIS, DSM measures are efforts designed to either reduce electricity 

21 demand at the retail level or alter the shape of the electricity load (NRC 2013). DSM programs 

22 can include incentives for equipment upgrades, improved codes and standards, rebates or rate 

23 reductions in exchange for allowing a utility to control or curtail the use of high-consumption 

24 appliances or equipment, training in efficient operation of building heating and lighting systems, 

25 direct payments in consideration for avoided consumption, or use of price signals to shift 

26 consumption away from peak times (NRC 2013).

27 In terms of overall ability to offset or replace an existing baseload power plant, DSM measures 

28 that reduce energy consumption, typically referred to as energy conservation and energy 

29 efficiency, are the most useful. Though often used interchangeably, energy conservation and 

30 energy efficiency are different concepts. Energy efficiency typically means deriving a similar 

31 level of service by using less energy, while energy conservation simply indicates a reduction in 

32 energy consumption. Conservation measures may include incentives to reduce overall energy 

33 consumption, while efficiency measures may include incentives to replace older, less efficient 

34 appliances, lighting, or heating and cooling systems. A variety of conservation or energy 

35 efficiency measures would likely be necessary to replace the capacity currently provided by 

36 SQN. 

37 TVA currently has an EEDR program, which outlines a variety of residential, commercial, and 

38 industrial programs, as well as education and outreach (TVA 2011a). TVA’s current power 

39 planning approach, outlined in its IRP, shows an increase in focus on the EEDR program. The 

40 IRP strategy reduces required energy and capacity needs by approximately 14,000 GWh and 

41 4,700 MW, respectively, by the year 2029, using a variety of power planning scenarios 

42 (TVA 2011b). In 2011, TVA commissioned a study from Global Energy Partners (GEP) to 

43 determine the potential for EEDR as a resource to help meet the TVA region’s future energy 

44 needs (EnerNOC 2011a). The 2012 update to the 2011 study projected potential cumulative 

45 annual energy savings of approximately 2.1 to 4.7 percent (3,061 to 6,993 GWh) of the region’s 

46 baseline energy forecast in 2015, and approximately 9.6 to 17.9 percent (17,343 to 
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1 32,474 GWh) of the baseline forecast in 2030 (EnerNOC 2012). GEP’s study notes that TVA’s 

2 energy efficiency and DSM programs are “off to a strong start,” and provides general 

3 recommendations to TVA to reach the projected potentials (EnerNOC 2011b). GEP’s energy 

4 efficiency recommendations include coordinating the distributor layer between TVA and energy 

5 end-users, maintaining a transparent stakeholder process, creating internal energy efficiency 

6 targets, pursuing light savings, creating targeted marketing messages, and expanding TVA’s 

7 knowledge of its customer base (EnerNOC 2011b). GEP’s DSM recommendations include 

8 expanding DSM programs to include smaller customers, focusing efforts on programs with the 

9 largest potential, providing incentives for voltage regulation programs, customers, and 

10 technologies (EnerNOC 2011b).

11 Because it is unlikely that demand reductions in the TVA region could be sufficiently increased 

12 to replace the SQN baseload capacity, the NRC staff did not consider DSM to be a reasonable 

13 alternative to license renewal.

14 2.3.14 Purchased Power

15 It is possible that replacement power may be imported from outside the SQN region of interest, 

16 which would have little or no measurable environmental impact in the vicinity of SQN; however, 

17 impacts could occur where the power is generated or anywhere along the transmission route, 

18 depending on the generation technologies used to supply the purchased power (NRC 2013).

19 As described in earlier sections, TVA is currently a party to numerous short-term and long-term 

20 PPAs, totaling 4,495 MW of generating capacity (TVA 2011b). For the PPAs that TVA has 

21 contracted, it is assumed that the supplier will either interconnect with the TVA transmission 

22 grid, or obtain a transmission path to the grid. Based on the PPAs TVA currently has in place 

23 with various transmission companies in other states, impacts from operation of other generators 

24 could occur within the TVA region, the SERC region, or outside both regions. TVA dismissed 

25 purchased power as a reasonable alternative for meeting load obligations if the SQN licenses 

26 are not renewed (TVA 2013). TVA acknowledged in its ER that PPAs have an inherent risk of 

27 power not being delivered and, based on its IRP, TVA must plan for the possibility of 

28 undelivered purchased capacity (TVA 2011b, 2013).

29 Purchased power would likely come from one or more of the other types of alternatives

30 considered in this chapter. As a result, operational impacts would be similar to the operational 

31 impacts of the alternatives considered in this chapter. Unlike the alternatives considered in this 

32 chapter, however, facilities from which power would be purchased would not likely be 

33 constructed solely to replace SQN. Purchased power may, however, require new transmission 

34 lines (which may require new construction), and may also rely on slightly older and less efficient 

35 power plants that operate at higher capacities than they currently operate. 

36 2.4 Comparison of Alternatives

37 In this SEIS, the NRC considers both the proposed action (license renewal of the SQN 

38 operating licenses); alternatives to the proposed action, including the no-action 

39 alternative (denial of renewed SQN licenses); and, alternatives to SQN license renewal 

40 that were considered and eliminated from detailed study, as described in the preceding 

41 sections. Table 2–1 in this chapter summarizes key design characteristics of the 

42 alternatives evaluated in depth. 

43 The environmental impacts of the proposed action are evaluated in Chapter 4 of this 

44 SEIS, along with the environmental impacts of the no-action alternative and each of the 

45 replacement power alternatives considered in depth above (the NGCC alternative, the 
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1 SCPC alternative, the new nuclear alternative, and the combination wind and solar 

2 alternative). Table 2–2 presents a summary comparison of the environmental impacts of 

3 the proposed action and alternatives that were evaluated in detail with respect to 

4 common resource areas. The NRC staff concluded that the environmental impacts of 

5 renewal of the operating licenses for SQN would be smaller than those of feasible and 

6 commercially viable alternatives. The no-action alternative, the act of shutting down 

7 SQN on or before its licenses expires, would have SMALL environmental impacts in 

8 most areas with the exception of socioeconomic impacts which would have SMALL to 

9 LARGE environmental impacts. Continued operations of SQN would have SMALL 

10 environmental impacts in all areas. The staff concluded that continued operation of the 

11 existing SQN is the environmentally preferred alternative.

12 Table 2–2. Summary of Environmental Impacts of Proposed Action and Alternatives

Impact Area 

(Resource)

SQN 

License 

Renewal 

(Propose

d Action)

Natural Gas 

Combined 

Cycle 

(NGCC)

Supercritical 

Pulverized 

Coal 

(SCPC) New Nuclear

Combination

(Wind and 

Solar) No-Action

Land Use SMALL SMALL SMALL to 

MODERATE

SMALL to 

MODERATE

SMALL to 

MODERATE SMALL

Visual 

Resources SMALL SMALL SMALL to MODERATE

SMALL to 

MODERATE

SMALL to 

MODERATE SMALL

Air Quality SMALL SMALL to 

MODERATE MODERATE SMALL SMALL SMALL

Noise SMALL SMALL SMALL SMALL SMALL SMALL

Geologic 

Environment SMALL SMALL SMALL SMALL SMALL SMALL

Surface Water SMALL SMALL SMALL SMALL SMALL SMALL

Groundwater SMALL SMALL SMALL SMALL SMALL SMALL

Terrestrial SMALL SMALL SMALL to 

MODERATE SMALL SMALL to MODERATE SMALL

Aquatic SMALL SMALL SMALL to 

MODERATE

SMALL to 

MODERATE SMALL SMALL

Special Status 

Species

NO 

EFFECT SEE NOTE1 SEE NOTE1 SEE NOTE1 SEE NOTE1 NO EFFECT

Historic and 

Cultural

SEE 

NOTE2

SMALL to 

MODERATE SMALL SMALL SMALL to LARGE SMALL

Socioeconomics SMALL SMALL to 

LARGE

SMALL to 

LARGE

SMALL to 

LARGE

SMALL to 

MODERATE

SMALL to 

LARGE

Human Health SMALL SMALL SMALL SMALL SMALL SMALL

Environmental 

Justice SMALL SEE NOTE3 SEE NOTE3 SEE NOTE3 SEE NOTE3 SEE NOTE4

Waste 

Management SMALL SMALL MODERATE SMALL SMALL SMALL
Alternatives Including the Proposed Action

2-23

Notes:

1 The magnitude of impacts could vary widely based on site selection and the presence or absence of special status 

species and habitats when the alternative is implemented; thus, the NRC staff cannot forecast a level of impact for 

this alternative. 2 The NRC staff concludes that license renewal would cause no adverse effect on historic properties. 3 This alternative would not have disproportionately high and adverse human health and environmental effects on 

minority and low-income populations in the vicinity of the SQN. 4 The No-Action alternative could disproportionately affect minority and low-income populations that may have 

become dependent on the public services in Hamilton County, Tennessee.

1 2.5 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 77 FR 12332. U.S. Nuclear Regulatory Commission. “Vogtle Electric Generating Plant, Units 3 

9 and 4; issuance of Combined Licenses and Limited Work Authorizations and Record of 

10 Decision.” Federal Register 77(40):12332. February 29, 2012.

11 77 FR 21593. U.S. Nuclear Regulatory Commission. “V.C. Summer Nuclear Station, Units 2 and 

12 3 Combined Licenses and Record of Decision.” Federal Register 77(69):21593–21594. 

13 April 10, 2012.

14 Archer CL, Jacobson MZ. 2007. Supplying baseload power and reducing transmission 

15 requirements by interconnecting wind farms. Journal of Applied Meteorology and 

16 Climatology 46(11):1701–1717. Available at 

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18 Beattie J. 2012. EPA easing emissions rules for demand response—generators. The Energy 

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24 7 October 2013).

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32 [DOE] U.S. Department of Energy. 2012. “Installed Wind Capacity by State.” 

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Alternatives Including the Proposed Action

2-24

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2 21 October 2013).

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4 Outlook 2010 with Projections to 2035. Washington, DC: EIA. April 9, 2010. 

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12 Outlook 2012. Washington, DC: EIA. August 2012. 203 p. Available at 

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14 21 October 2013).

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16 Washington, DC: EIA. March 2012. 5 p. Available at 

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19 2010. Washington, DC: EIA. March 2012. 244 p. Available at 

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22 Projections to 2040. DOE/EIA 0383 (2013). Washington, DC: EIA. April 26, 2013. Available at 

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24 [EIA] U.S. Energy Information Administration. 2013b. “SAS Output.” April 2012. Available at 

25 <http://www.eia.gov/electricity/annual/html/epa_01_02.html> (accessed 21 October 2013).

26 [EnerNOC] EnerNOC Utility Solutions Consulting. 2011a. Global Energy Partners’ Study 

27 Identifies Significant Energy Savings Potential for TVA Customers. Walnut Creek, CA: 

28 EnerNOC. 2 p. Available at 

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30 4 November 2013). 

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32 Study, Volume 1: Executive Summary. Walnut Creek, CA: EnerNOC. Report Number 1360. 

33 December 21, 2011. 552 p. Available at 

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35 4 November 2013).

36 [EnerNOC] EnerNOC Utility Solutions Consulting. 2012. Tennessee Valley Authority Energy 

37 Efficiency Potential Study, 2012 Update. Walnut Creek, CA: EnerNOC. 1360.2. 

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40 [EPA] Environmental Protection Agency. 2011. Glossary. Available at: <

41 http://www.epa.gov/superfund/programs/reforms/glossary.htm#b> (accessed 7 July 2014)

42 [ERC] Energy Recovery Council. 2010. The 2010 ERC Directory of Waste-To-Energy Plants. 

43 November 12, 2010. 32 p. Available at 

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45 21 October 2013).
Alternatives Including the Proposed Action

2-25

1 [GEA] Geothermal Energy Association. 2010. Section 2.1.—Active State Geothermal Projects, 

2 Figure 4: Developing Projects by State. In: U.S. Geothermal Power Production and 

3 Development Update—Special NYC Forum Edition. Washington, DC: GEA. January 2010. 

4 Available at <http://www.geo-energy.org/GEA_January_Update_Special_Edition_Final.pdf> 

5 (accessed 21 October 2013).

6 Hong BD, Slatick ER. 1994. Carbon Dioxide Emission Factors for Coal. Originally published in 

7 Energy Information Administration, Quarterly Coal Report, January–April 1994. 

8 DOE/EIA-0121(94/Q1). Washington, DC: EIA. August 1994. Available at 

9 <http://www.eia.doe.gov/cneaf/coal/quarterly/co2_article/co2.html> (accessed 

10 21 October 2013).

11 [INEEL] Idaho National Engineering and Environmental Laboratory. 1997a. U.S. Hydropower 

12 Resource Assessment for Tennessee. Idaho Falls, ID: INEEL. DOE-ID/10430(TN). July 1997. 

13 13 p. Available at <http://hydropower.inel.gov/resourceassessment/pdfs/states/tn.pdf> 

14 (accessed 7 October 2013).

15 [INEEL] Idaho National Engineering and Environmental Laboratory. 1997b. U.S. Hydropower 

16 Resource Assessment for Virginia. Idaho Falls, ID: INEEL. DOE-ID/10430(VA). 

17 December 1997. 12 p. Available at 

18 <http://hydropower.inel.gov/resourceassessment/pdfs/states/va.pdf> (accessed 

19 7 October 2013).

20 McLaren J. 2011. Southeast Regional Clean Energy Policy Analysis. Golden, CO: NREL. 

21 NREL/TP-6A20-49192. April 2011. Available at 

22 <http://www.nrel.gov/tech_deployment/state_local_activities/pdfs/49192.pdf> (accessed 

23 21 October 2013).

24 Milbrandt A. 2005. A Geographic Perspective on the Current Biomass Resource Availability in 

25 the United States. Golden, CO: NREL. NREL/TP-560-39181. December 2005. 70 p. Available at 

26 <http://www.nrel.gov/gis/biomass.html> (accessed 21 October 2013).

27 [MMS] Minerals Management Service. 2006. Technology White Paper on Wind Energy Potential 

28 on the U.S. Outer Continental Shelf. May 2006. 17 p. Available at 

29 <http://www.boem.gov/uploadedFiles/BOEM/Renewable_Energy_Program/

30 Renewable_Energy_Guide/

31 Technology%20White%20Paper%20on%20Wind%20Energy%20Potential%20on%20the%20

32 OCS.pdf> (accessed 21 October 2013).

33 [NETL] National Energy Technology Laboratory. 2010a. Cost and Performance Baseline for 

34 Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity. Revision 2. 

35 Pittsburgh, PA: DOE. DOE/NETL-2010/1397. November 2010. 626 p. Available at 

36 <http://www.netl.doe.gov/energy-analyses/pubs/BitBase_FinRep_Rev2.pdf> (accessed 

37 21 October 2013).

38 [NETL] National Energy Technology Laboratory. 2010b. Life Cycle Analysis: Natural Gas 

39 Combined Cycle (NGCC) Power Plant. DOE/NETL-403/110509. September 30, 2010. 151 p. 

40 Available at <http://www.netl.doe.gov/energy-analyses/pubs/NGCC_LCA_Report_093010.pdf>

41 (accessed 21 October 2013). 

42 [NETL] National Energy Technology Laboratory. 2010c. Life Cycle Analysis: Supercritical 

43 Pulverized Coal (SCPC) Power Plant. DOE/NETL-403/110609. December 2010. Available at 

44 <http://www.netl.doe.gov/energy-analyses/refshelf/PubDetails.aspx?Action=View&PubId=354>

45 (accessed 21 October 2013).
Alternatives Including the Proposed Action

2-26

1 [NETL] National Energy Technology Laboratory. 2013. Cost and Performance Baseline for 

2 Fossil Energy Plants, Volume 1, Bituminous Coal and Natural Gas to Electricity, Revision 2a. 

3 DOE/NETL 2010/1397. September 2013. Available at 

4 <http://www.netl.doe.gov/energy-analyses/pubs/BitBase_FinRep_Rev2.pdf> (accessed 

5 21 October 2013).

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

7 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Volumes 1 

8 and 2. May 1996. 1,204 p. Agencywide Documents Access and Management System (ADAMS) 

9 Nos. ML040690705 and ML040690738.

10 [NRC] U.S. Nuclear Regulatory Commission. 2002. Generic Environmental Impact Statement

11 on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the Decommissioning of 

12 Nuclear Power Reactors. Washington, DC: NRC. NUREG-0586, Volumes 1 and 2. 

13 November 30, 2002. 932 p. ADAMS Nos. ML023470327 and ML023500228.

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

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

16 Volumes 1, 2, and 3. June 30, 2013. 1,535 p. ADAMS Nos. ML13106A241, ML13106A242, and 

17 ML13106A244.

18 [NREL] National Renewable Energy Laboratory. 2010. “Energy Analysis—Energy Technology 

19 Cost and Performance Data.” July 2010. Available at 

20 <http://www.nrel.gov/analysis/tech_lcoe_documentation.html> (accessed 7 October 2013).

21 [NREL] National Renewable Energy Laboratory. 2011. “Estimates of Windy Land Area and 

22 Wind Energy Potential, by State, for Areas ≥ 30% Capacity Factor at 80m.” April 13, 2011. 

23 Available at <http://www.windpoweringamerica.gov/docs/wind_potential_80m_30percent.xlsx> 

24 (accessed 21 October 2013). 

25 [NREL] National Renewable Energy Laboratory. 2012. “Dynamic Maps, GIS Data, and Analysis 

26 Tools—Solar Maps.” September 3, 2013. Available at <http://www.nrel.gov/gis/solar.html>

27 (accessed 21 October 2013). 

28 [NREL] National Renewable Energy Laboratory. 2013. 2011 Renewable Energy Data Book. 

29 DOE/GO-102012-3598. February 2013. 128 p. Available at 

30 <http://www.nrel.gov/docs/fy13osti/54909.pdf> (accessed 21 October 2013).

31 Paidipati J, Frantzis L, Sawyer H, Kurrasch A. 2008. Rooftop Photovoltaics Market Penetration 

32 Scenarios. Golden, CO: NREL. NREL/SR-581-42306. February 2008. 105 p. Available at 

33 <http://www.nrel.gov/docs/fy08osti/42306.pdf> (accessed 31 October 2013).

34 Renné D, George R, Wilcox S, Stoffel T, Myers D, Heimiller D. 2008. Solar Resource 

35 Assessment. Golden, CO: NREL. NREL/TP-581-42301. February 2008. 54 p. Available at 

36 <http://www.nrel.gov/docs/fy08osti/42301.pdf> (accessed 7 October 2013).

37 [Siemens] Siemens Power Generation. 2007. Technical Data: Combined Cycle Power Plant 

38 Performance Data. Available at <http://www.energy.siemens.com/hq/pool/hq/power-generation/

39 power-plants/gas-fired-power-plants/combined-cycle-powerplants/

40 Siemens%20Combined%20Cycle%20Plants.pdf> (accessed 7 October 2013).

41 Tegen S, Lantz E, Hand M, Maples B, Smith A, Schwabe P. 2013. 2011 Cost of Wind Energy 

42 Review. NREL/TP-5000-56266. March 2013. 50 p. Available at 

43 <http://www.nrel.gov/docs/fy13osti/56266.pdf> (accessed 21 October 2013).

44 [TVA] Tennessee Valley Authority. 2011a. Environmental Impact Statement for TVA’s Integrated 

45 Resource Plan. Knoxville, TN: TVA. Volume 1. March 2011. 282 p. Available at
Alternatives Including the Proposed Action

2-27

1 <http://www.tva.gov/environment/reports/irp/archive/pdf/IRP_FEIS-V1_complete.pdf> (accessed 

2 21 October 2013).

3 [TVA] Tennessee Valley Authority. 2011b. Integrated Resource Plan, TVA’s Environmental & 

4 Energy Future. March 2011. 217 p. Available at 

5 <http://www.tva.gov/environment/reports/irp/archive/pdf/Final_IRP_complete.pdf> (accessed 

6 21 October 2013).

7 [TVA] Tennessee Valley Authority. 2013. Sequoyah Nuclear Plant, Units 1 and 2—License 

8 Renewal Application, Appendix E, Applicant’s Environmental Report, Operating License 

9 Renewal Stage. January 7, 2013. 783 p. ADAMS No. ML130240007, Parts 2–8 of 8.

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 Sequoyah Nuclear Plant, Units 1 and 2 (SQN). 

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 how they have shaped the 

6 environment are presented here. The facility and its operation are described in Section 3.1. 

7 The affected environment is presented in Sections 3.2 to 3.13.

8 3.1 Description of Nuclear Power Plant Facilities and Operation

9 SQN is a two-unit nuclear power plant located in Hamilton County, Tennessee. It began 

10 commercial operation in July 1981 (Unit 1) and June 1982 (Unit 2). Generally , the Nuclear 

11 Regulatory Commission (NRC) staff drew information about SQN’s facilities and operation from 

12 Tennessee Valley Authority’s (TVA) Environmental Report (ER) (TVA 2013n). 

13 3.1.1 External Appearance and Setting

14 The SQN site is approximately 18 miles (mi) (29 kilometers (km)) northeast of Chattanooga, 

15 Tennessee, and approximately 31 mi (50 km) south-southwest of the Tennessee Valley 

16 Authority (TVA) Watts Bar Nuclear Plant (WBN) site. The SQN site is approximately 630 acres 

17 (ac) (250 hectares (ha)). The power production portion of SQN is located on 525 ac (212 ha). 

18 SQN’s training center is located on the remaining 105 ac (42.5 ha) (TVA 2013n).

19 The SQN site is located on a peninsula on the western shore of Chickamauga Reservoir at 

20 Tennessee River Mile (TRM) 484.5. The town of Soddy-Daisy, Tennessee, is located 6 mi 

21 (10 km) west of site. Figure 3–1 and Figure 3–2 present 50-mi (80-km) and 6-mi (10-km) 

22 vicinity maps, respectively.

23 The SQN site’s main structures include two reactor buildings, a turbine building, an auxiliary 

24 building, a control building, a service and office building, a diesel generator building, an intake 

25 pumping station, an essential raw cooling water (ERCW) pumping station, two natural draft 

26 cooling towers, 161-kilovolt (kV) and 500-kV switchyards, a condensing water discharge and 

27 diffuser system, and an independent spent fuel storage installation (ISFSI). The site’s tallest 

28 structures are the two 459-ft cooling towers (TVA 2013n). 

29 The area of the SQN site completely enclosed by a security fence with access to the area 

30 controlled at a security gate is called the protected area. A plant security system monitors the 

31 protected area, as well as buildings within the protected area. Principal roadways near the SQN 

32 site are US 27 and Tennessee Route 319 (Hixson Pike). Sequoyah Access Road leads directly 

33 to the SQN site. The nearest occupied residence is 0.5 mi (0.8 km) north-northwest of the site 

34 boundary (TVA 2013n). 

35 The SQN exclusion area boundary (EAB) defines the area around the reactors where TVA has 

36 the authority to determine all activities, including exclusion or removal of personnel and property 

37 (NRC 2014). Figure 3–3 shows the general features of the facility, the protected area, and the 

38 EAB.
Affected Environment

3-2 

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

2 

3 Source: TVA 2013n
Affected Environment

3-3 

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

2 

3 Source: TVA 2013n
Affected Environment

3-4 

1 Figure 3–3. SQN General Site Layout

2 

3 Source: TVA 2013n

1. Yard Drainage Pond (Unlined) 

2. M etal Cleaning VVaste Pond (lined) 

3. Metal Cleaning 1/\/aste Pond (Unlined) 

4. Low Volume waste Treatment Pond (Lined) 

5. CCW Discharge Channel (Unlined) 

6. Diffuser Pond (Unlined) 

7. Cooling Tower Discharge Channel 

Legend 

"'k Site Center 

Protected Area 

CJ Settling Pond (Unlined) 

D Site Features 

c:J site 

c_- --~ Exclusion Area Boundary (EAB) 

(USDA 2008) 

•--=::::JI--IC:::::JI ______ Feet 

0 500 1,000 2,000 
Affected Environment

3-5 

1 3.1.2 Nuclear Reactor Systems

2 The nuclear reactor for each of the two SQN units is a Westinghouse pressurized-water reactor 

3 (PWR), producing a reactor core rated thermal power of 3,586 megawatts thermal (MWt). The 

4 nominal net electrical capacity for SQN is 2,400 megawatts electric (MWe). SQN uses a 

5 once-through cooling system, aided by periodic operation of cooling towers. The system

6 withdraws cooling water from and discharges to Chickamauga Reservoir (TVA 2013n).

7 The nuclear fuel is low-enriched (less than 5 percent by weight) uranium dioxide, with a 

8 maximum average burnup level of less than 62,000 megawatt-days/metric ton of uranium. 

9 Refueling and maintenance outages for SQN Units 1 and 2 are on a staggered 18-month 

10 schedule (TVA 2013n).

11 The containment for each reactor consists of a steel containment vessel with an ice condenser 

12 and a shield building. The steel containment vessel is a freestanding carbon steel structure 

13 composed of a cylindrical wall, a hemispherical dome, and a bottom liner plate encased in 

14 concrete. The ice condenser system, located inside the steel containment vessel, provides 

15 containment energy removal and pressure suppression for certain accident events. The system 

16 contains about two million pounds of ice located in 1,944 baskets. The shield building encloses 

17 the steel containment vessel. It is a reinforced concrete cylinder supported by a circular base 

18 concrete foundation resting on bedrock and covered with a spherical dome (TVA 2013n).

19 3.1.3 Cooling and Auxiliary Water Systems

20 As discussed previously, SQN uses pressurized-water reactors in the nuclear steam supply 

21 system. At SQN, water is withdrawn from the Chickamauga Reservoir portion of the 

22 Tennessee River to cool plant components and to condense the steam exiting the turbines to 

23 liquid water. Normally, the vast majority of withdrawn water is discharged back through SQN’s 

24 diffuser pond system and into the reservoir at a point 1.1 mi (1.8 km) downstream from the 

25 intake. The waste heat in the thermal discharge is dissipated to the atmosphere mainly by 

26 evaporation from the water body and, to a much smaller extent, by conduction, convection, and 

27 thermal radiation loss. 

28 The SQN cooling system functions to remove heat from the steam and transfers that heat to the 

29 environment. Excess heat is removed using a combination cooling system: a once-through

30 condenser circulating water (CCW) system that may be assisted by two natural-draft cooling 

31 towers (i.e., helper mode operation) (TVA 2013n). Helper mode operation is typically 

32 implemented when the mixing zone river temperature downstream of SQN’s discharge diffuser 

33 climbs to within about 1 °F (0.6 °C) of SQN’s National Pollutant Discharge Elimination System

34 (NPDES) permit limits. SQN also uses helper mode during low flow conditions to limit the 

35 upstream propagation of heat from the SQN discharge diffusers (NPDES-permitted Outfall 101) 

36 to the plant intake 1.1 mi (1.8 km) upstream. The number of cooling tower lift pumps (CTLPs) in 

37 operation controls the degree of cooling that can be achieved from helper mode (TVA 2013j). 

38 From an operations standpoint, helper mode is defined as full operation of one cooling tower 

39 and at least three CTLPs in service for each operating unit (TVA 2013n).

40 For each of the two turbine generator units, SQN’s CCW system can supply a theoretical 

maximum of 561,000 gallons per minute (gpm) (1,250 cubic feet per second (cfs) or 35.3 m3 41 /s) 

42 of water for the main condensers and water for the raw cooling water (RCW) system that 

43 supplies auxiliary systems. The CCW system is comprised of a total of six pumps housed in 

44 SQN’s CCW intake pump station located at the end of the intake channel, as depicted in 

45 Figure 3–3 (TVA 2013j, 2013n).
Affected Environment

3-6 

1 The ERCW system is designed to continuously supply cooling water to SQN systems and 

2 components necessary for plant safety. The eight supply and four associated screen-wash 

3 pumps of the ERCW system are housed in the ERCW intake pump station located at the top of 

4 the plant’s skimmer wall structure (see Figure 3–3). 

5 The SQN maximum surface water withdrawal rate from Chickamauga Reservoir is 

approximately 1,166,000 gpm (2,600 cfs (73.5 m3 6 /s)), or 1,680 mgd (TVA 2011c, 2011d). The 

7 plant’s consumptive use of water withdrawn is essentially zero when operated in open mode 

and could be as much as 31,250 gpm (70 cfs (1.98 m3 8 /s)) or 45 mgd in full helper mode 

9 (TVA 2013n).

10 Generally, the NRC staff drew information about SQN’s cooling and auxiliary water systems 

11 from the TVA’s ER (TVA 2013n) and responses to the NRC’s request for additional information 

12 (TVA 2013d-f, 2013j). Individual SQN systems that interact with the environment are further 

13 summarized below with a focus on facilities owned and operated by TVA.

14 3.1.3.1 Cooling Water Intake System

15 Both the CCW and ERCW systems are supplied from Chickamauga Reservoir using intake 

16 structures on the upstream end of the SQN site. An intake skimmer wall, situated approximately 

17 400 ft (122 m) into the reservoir, spans the entrance to the embayment leading to SQN’s CCW 

18 intake. The intake channel extends approximately 1,800 ft (550 m) from the skimmer wall to the 

19 CCW intake pump station (see Figure 3–4). The skimmer wall has a clear opening length of 

20 550 ft (167 m) and an opening height of 9.7 ft (3 m). The top of the opening is 641 ft (195 m) 

21 above mean sea level (MSL), which is approximately 34 ft (10 m) below minimum pool elevation 

22 of Chickamauga Reservoir (TVA 2013j, 2013n). Based on the design CCW flow rate, the staff 

23 determined that the average velocity through the skimmer wall opening is approximately 

24 0.47 foot per second (fps) (0.14 meters per second (m/s)). This is consistent with the original 

25 design velocity (i.e., 0.5 fps (0.15 m/s)), which TVA confirmed remains valid (TVA 2013j).

26 The skimmer wall is designed to allow withdrawal of cooler water from the lower depths of 

27 Chickamauga Reservoir (TVA 2013n). River water temperature stratification with depth is 

28 typical from late spring through early fall. In this case, the river stage (water elevation) can 

29 influence the location of the river thermocline (thin layer of water in which temperature changes 

30 more rapidly with depth than it does in the layers above or below) relative to the location of the 

31 withdrawal zone for SQN’s cooling water intake. In contrast, the vertical river temperature 

32 distribution is more uniform in the late fall, winter, and early spring. Under these conditions, 

33 river stage has little effect on the plant intake water temperature (TVA 2013j).

34 Dam hydropeaking operations (the practice of abruptly increasing dam discharge and river flow 

35 for added power generation during periods of high demand) temporarily increase river 

36 discharges and produce higher levels of turbulence that result in deeper mixing of warm surface 

37 water. This produces higher water temperatures in SQN’s cooling water withdrawal zone. 

38 When hydropeaking is deemed detrimental to SQN’s intake water temperature, TVA reduces or 

39 suspends hydropeaking operations to provide calmer, steadier flows in Chickamauga Reservoir, 

40 which tends to stabilize intake water temperature for SQN. Dam hydropeaking operations have 

41 less effect on plant intake water temperature in late fall through early spring when the vertical 

42 river temperature is more uniform than in late spring through early fall (TVA 2013j).
Affected Environment

3-7 

1 Figure 3–4. Location of SQN Cooling Water Supply Facilities and Surface Water Features

2 

3 Source: TVA 2013f

1. Yard Drainage Pond (Unlined) 

2. Metal Cleaning Waste Pond (Lined) 

3. Metal Cleaning Waste Pond (Unlined) 

4. Low Volume Waste Treatment Pond (Lined) 

5. CCW Discharge Channel (Unlined) 

6. Diffuser Pond (Unlined) 

7. Cooling Tower Discharge Channel 

Source: TVA 2013b 

Legend 

--CCW -Intake/Discharge Conduits 

--Cooling Tower Supply Piping 

-- 6-inch Waste Condensate Line 

- - - • 12-inch Waste Condensate Line --= =---== -------Feet 

--Submerged Slowdown Discharge 0 500 1,000 2,000 

- - - - Submerged Diffuser 

CJ Settling Pond (Unlined) 
Affected Environment

3-8 

1 Another engineered feature that affects cooling water intake temperatures is the presence of a 

2 submerged dam across the main river channel. This dam is situated approximately 1 mi 

3 (1.6 km) downstream from the intake skimmer wall (about 250 ft (80 m) upstream from the 

4 discharge diffusers). The dam is about 90 ft (27 m) thick and 900 ft (274 m) long, with its crest 

5 at 654 ft (199 m) above MSL or 13 ft (4 m) above the top of the skimmer wall opening 

6 (TVA 2013j, 2013n). The dam is designed to provide a subpool of cooling water for the CCW 

7 intake pumps in the event of a sudden drop in the Chickamauga Reservoir level 

8 (e.g., catastrophic water release from the downriver Chickamauga Dam). The submerged dam 

9 also serves to impound cooler water in the lower layer of Chickamauga Reservoir, making it 

10 available for SQN withdrawals. This has the effect of decreasing the potential for any water 

11 wedge buildup of discharge water emanating from the discharge diffusers extending upstream 

12 to the plant intake (TVA 2011c, 2013n). 

13 Condenser Circulating Water System. The CCW system is designed to condense steam that 

14 has passed through each turbine generator and to dissipate all rejected heat. Efficient 

15 operation of the turbine generators will limit the maximum temperature rise for water circulating 

16 through the steam condensers to about 29.5 °F (16.4 °C). Depending on the thermal conditions 

17 in Chickamauga Reservoir, there are three operational modes for controlling the temperature of 

18 SQN’s thermal discharge to the reservoir: open, helper, and closed. In open mode, the system 

19 operates as a once-through cooling system, and water exiting the CCW system is discharged 

20 directly to the reservoir after passing through SQN’s pond system. In helper mode, water 

21 exiting the CCW system is pumped to the cooling towers so that some of the heat can be 

22 transferred to the atmosphere before the water is returned to Chickamauga Reservoir. In 

23 closed mode, plant hydraulics return flow from the cooling tower(s) to the intake forebay by way 

24 of the cooling tower discharge (return) channel (see Figure 3–4). However, closed mode testing 

25 after plant startup determined that cooling tower performance is not sufficient for sustaining this 

26 mode without significant power derates (TVA 2013n). 

27 The CCW system consists of six circulating water pumps, a water intake structure and 

28 discharge lines, traveling screens, screen wash pumps, and associated piping, valves, and 

instrumentation. Each pump has a capacity of 187,000 gpm (417 cfs or 11.8 m3 29 /s). The 

30 nominal (design) CCW flow through the condensers with both SQN units in operation is about 

1,070,000 gpm (2,384 cfs (67.3 m3 31 /s) or about 1,541 mgd) (TVA 2013j, 2013n). 

32 The circulating water pumps are mounted vertically in the intake structure and discharge into 

33 six separate lines and then to two separate conduits, with one conduit supplying each unit’s 

34 main condenser. From the intake channel, water flows into the intake structure through racks 

35 designed to remove larger trash items, such as driftwood, plastic containers, etc. The flow then 

36 passes through six traveling screens (i.e., one for each pump) with a velocity of approximately 

37 2.08 fps (0.63 m/s). The traveling screens were replaced in February 2013 (TVA 2013d-f, 

38 2013j, 2013n). The traveling screens have 3/8-in. (0.95-cm) square openings and are designed 

39 to trap smaller trash and any larger-sized trash that may have passed through the trash racks. 

40 There are currently no fish return systems or any plans for structural or operational measures to 

41 reduce entrainment and impingement of fish and shellfish associated with the CCW intake 

42 structure (TVA 2013n). 

43 Upon discharge to the CCW discharge channel (see no. 5 in Figure 3.4) and ultimately through 

44 the diffuser pond system as further discussed below, the CCW flow can provide for dilution and 

45 dispersion of routine low-level radioactive liquid wastes. As discussed in Section 3.1.4, such 

46 low-level radioactive effluents are released only in small quantities and in accordance with 

47 applicable NRC and other Federal regulations (TVA 2011c, 2013n).
Affected Environment

3-9 

1 Raw Cooling Water (RCW) System. In addition to condenser cooling, the CCW system supplies 

2 water to the plant RCW system for use by auxiliary equipment. This includes pumps, which, in 

3 turn, supply cooling water to nonessential systems (i.e., systems not necessary for the safe 

4 shutdown of the reactor). Raw cooling water can also be supplied by gravity directly from the 

5 river by way of the condenser intake tunnels without the CCW pumps (TVA 2013n).

6 Cooling Tower Operation. In helper mode, control gates are lowered at the end of the CCW 

7 discharge channel (see no. 5 in Figure 3–4) and condenser discharge water is pumped into the 

8 cooling towers by the CTLPs, where part of the waste heat is rejected to the atmosphere. 

Four CTLPs are designed to deliver approximately 560,000 gpm (1,248 cfs or 35.2 m3 9 /s) of 

10 water to each cooling tower (TVA 2013j, 2013n). The original cooling tower pumping station 

11 included eight CTLPs. However, following operational damage, one of the CTLPs was 

12 abandoned, with the plant’s current design basis reflecting use of seven CTLPs. Control valves 

13 allow any of the lift pumps to supply flow to either one or both of the cooling towers. As a 

14 consequence, if five or more CTLPs are placed in service, the headers must be aligned through 

15 the control valves to supply flow to both cooling towers. After exiting the cooling towers, the 

16 treated flow enters the diffuser pond through a gate structure (TVA 2013j). 

17 From 2006 through 2009, cooling towers were in service an average of 112.7 days per year 

18 (TVA 2011c). For the period 2007–2011, helper-mode use averaged about 120 days a year. 

19 Between 2007 and 2013, SQN operated cooling towers an average of 125 equivalent days per 

20 year, with a minimum of 34 equivalent days in 2009 and a maximum of 197 equivalent days 

21 in 2008. TVA calculates equivalent days of cooling tower operation based on a summation of 

22 the number of hours where at least one CTLP is in service (TVA 2013j).

23 The cooling towers are designed to reject waste heat to the atmosphere, thereby cooling the 

24 CCW and controlling the temperature of the thermal discharge at the edge of the mixing zone 

25 established for SQN’s diffusers (NPDES Outfall 101) (TVA 2013n). Cooling tower operation is

26 used by TVA to comply with the conditions of the plant’s current NPDES permit 

27 (No. TN0026450) issued to TVA by the Tennessee Department of Environment and 

28 Conservation (TDEC), Division of Water Pollution Control. The permit imposes the following 

29 limitations at the edge of SQN’s diffuser mixing zone:

30 • the 24-hour downstream temperature must not exceed 30.5 °C (86.9 °F), 

31 except in cases when the 24-hour ambient river temperature exceeds 29.4 °C 

32 (84.9 °F). In these cases, the 24-hour downstream temperature can exceed 

33 30.5 °C (86.9 °F) when SQN is operated in helper mode (defined as full 

34 operation of one cooling tower and at least three CTLPs in service for each 

35 operating unit), but, in such situations, the hourly average downstream 

36 temperature must not exceed 33.9 °C (93.0 °F) without the consent of TDEC; 

37 • the maximum 24-hour average temperature rise is limited to 3.0 °C (5.4 °F) for 

38 April through October and 5.0 °C (9.0 °F) for November through March; the 

39 maximum hourly average temperature change is limited to 2.0 °C (3.6 °F) per 

40 hour.

41 SQN’s NPDES permit delineates the maximum extent of the mixing zone as an area 

42 750 ft (230 m) wide and extending 1,500 ft (457 m) downstream and 275 ft (85 m) upstream of 

43 the plant’s twin diffusers. The depth of the mixing zone varies linearly from the water surface 

44 275 ft (85 m) upstream of the diffusers to the top of the diffuser pipes and then extends to the 

45 bottom downstream of the diffusers. For closed-mode operation, the mixing zone also includes 

46 the area of the forebay to the CCW intake pump station. 
Affected Environment

3-10

1 The amount of cooling water loss caused by evaporation and drift from the cooling towers 

2 depends on such factors as flow volume, the temperature of the water delivered to the cooling 

3 towers, and local weather conditions. When operated in helper mode under design conditions 

4 (which TVA identifies as a “conservative upper-bounding scenario”), water losses to the 

5 atmosphere from evaporation and drift resulting from cooling tower operation can consume up 

to 31,250 gpm (70 cfs (1.98 m3 6 /s, or 45 mgd)) of water (TVA 2013n). 

7 Diffuser Pond and Discharge to River. Heated water is discharged either from the CCW 

8 discharge channel (when in open mode) or from the cooling towers (when in helper mode) 

9 directly into the diffuser pond (see no. 6 in Figure 3–4). From the diffuser pond, the wastewater

10 (including cooling tower blowdown during helper mode operations) and other permitted effluent 

11 sources are conveyed to the Chickamauga Reservoir through two corrugated metal diffuser 

12 pipes that extend under the pond’s diked embankment into the river channel. The upstream 

13 and downstream diffuser pipes are 17 ft (5.2 m) and 16 ft (4.9 m) in diameter, respectively, and 

14 the diffuser sections of the discharge pipes are installed in the 900-ft (274-m) wide navigation 

15 channel of the Chickamauga Reservoir. Each diffuser section is 350 ft (107 m) long and 

16 contains seventeen 2-in. (5.1-cm) diameter ports per foot of pipe length. The downstream 

17 diffuser pipe discharges across a section 0 to 350 ft (0 to 107 m) from the SQN side of the 

18 deeper main navigation channel. The diffuser section of the longer upstream diffuser pipe 

19 discharges across a section 350 to 700 ft (107 to 214 m) from the SQN side of the main channel 

20 (TVA 2011c, 2013n). Flow rate through SQN’s diffusers is controlled by the elevation difference 

21 between the water levels in the diffuser pond and in the Chickamauga Reservoir. At peak plant 

operation, each diffuser discharges about 1,250 cfs (35.3 m3 22 /s) of effluent to the river. When 

23 the discharges to the diffuser pond are reduced and the elevation difference between the pond 

24 and the reservoir is less than 4 ft (1.2 m), a gate automatically closes the downstream diffuser, 

25 permitting discharge only through the upstream diffuser. The diffuser pond will discharge to the 

26 river through the upstream diffuser whenever the pond level is greater than the reservoir level 

27 (TVA 2013n).

28 3.1.3.2 Essential Raw Cooling Water System

29 The ERCW system is a safety-related system (seismic Category 1 structure) used to supply 

30 cooling water to various heat loads in both the primary (radiological) and secondary 

31 (nonradiological) portions of each SQN unit. It is operated to provide a continuous flow of 

32 cooling water to those systems and components necessary for plant safety during normal 

33 operations, or under accident conditions. 

34 The ERCW intake pump station is located near the north end of the intake skimmer wall (see 

35 Figure 3–4). It is designed to be operable for all Chickamauga Reservoir levels, including the 

36 probable maximum flood and loss of the Chickamauga Dam. The estimated minimum river flow 

for the ERCW system to operate is only 45 cfs (1.27 m3 37 /s). To protect the intake from floating 

38 debris, a floating trash boom (shown in Figure 3–4) extends from a spit on the upstream end of 

39 the SQN site, around the ERCW intake pump station, to the skimmer wall to the south. The 

40 station houses eight ERCW pumps, four traveling water screens, four screen wash pumps, 

41 four strainers, and associated piping and valves. These components are divided between each 

42 of the plant’s two units. Each of the eight ERCW pumps are rated at 11,000 gpm (24.5 cfs 

(0.69 m3

/s)), and the screen wash pumps are each rated at 270 gpm (0.6 cfs (0.017 m3 43 /s)) 

44 (TVA 2011c, 2013n). While the ERCW system has a total of eight pumps, minimum combined 

45 safety requirements are met by only two pumps in operation per each of the plant’s two ERCW 

46 cooling trains.

47 Water withdrawn from the reservoir enters the pumping station through the 1⁄4-in. (0.64-cm) 

48 mesh traveling water screens at a velocity of <0.50 fps (<0.15 m/s) and into a corresponding 
Affected Environment

3-11

1 ERCW pump pit, each served by two ERCW pumps. The screens are designed to remove 

2 3/8-in. (0.95-cm) diameter and larger objects. A routine manual backwash of the traveling 

3 screens is performed four times per week, but may be performed on an unscheduled basis as 

4 needed. The ERCW pumping station supplies water to the SQN auxiliary building systems 

5 through four independent sectionalized supply headers. The return discharge from the various 

6 heat exchangers served by the ERCW system goes to a seismically qualified open basin with 

7 overflow capability, then flows by gravity to the cooling tower discharge channel (see no. 7 in 

8 Figure 3–4), and ultimately to the diffuser pond, where it provides a continuous source of return 

9 water for effluent dilution, including low-level radioactive liquid effluents (TVA 2013n).

10 3.1.4 Radioactive Effluent, Waste, and Environmental Monitoring Programs

11 As part of their normal operations and as a result of equipment repairs and replacements 

12 caused by normal maintenance activities, nuclear power plants routinely generate both 

13 radioactive and nonradioactive wastes. Nonradioactive wastes include hazardous and 

14 nonhazardous wastes. There is also a class of waste, called mixed waste, which is both 

15 radioactive and hazardous. The systems used to manage (i.e., treat, store, and dispose of) 

16 these wastes are described in this section. Waste minimization and pollution prevention 

17 measures commonly employed at nuclear power plants are also discussed in this section.

18 All nuclear plants were licensed with the expectation that they would release radioactive 

19 material to both the air and water during normal operation. However, NRC regulations require 

20 that radioactive gaseous and liquid releases from nuclear power plants must meet radiation 

21 dose-based limits specified in Title 10 of the Code of Federal Regulations (10 CFR) Part 20, 

22 “Standards for protection against radiation,” and the as low as is reasonably achievable 

23 (ALARA) criteria in Appendix I to 10 CFR Part 50. Regulatory limits are placed on the radiation 

24 dose that members of the public can receive from radioactive effluents released by a nuclear 

25 power plant. All nuclear power plants use radioactive waste management systems to control 

26 and monitor radioactive wastes.

27 The liquid, gaseous, and solid waste processing systems used by SQN collect and process, as 

28 needed, radioactive materials produced as a byproduct of plant operations. The radioactive 

29 liquid and gaseous effluents are processed to reduce the levels of radioactive material before 

30 discharge to the environment. This is to ensure that the dose to members of the public from 

31 radioactive effluents is reduced to levels that are ALARA in accordance with NRC regulations. 

32 The radioactive material removed from the effluents is converted into a solid form for eventual 

33 disposal at a licensed radioactive disposal facility.

34 SQN’s radiological environmental monitoring program (REMP) assesses the radiological impact, 

35 if any, to the public and the environment from radioactive effluents released during operations at 

36 SQN. The REMP measures the aquatic, terrestrial, and atmospheric environment for 

37 radioactivity, as well as the ambient radiation. In addition, the REMP measures background 

38 radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive material, 

39 including radon).

40 SQN’s Offsite Dose Calculation Manual (ODCM) contains the methods and parameters used to 

41 calculate offsite doses resulting from radioactive liquid and gaseous effluents. These methods 

42 are used to ensure that radioactive material discharges meet NRC and U.S. Environmental 

43 Protection Agency (EPA) regulatory dose standards. The ODCM also contains the 

44 requirements for the REMP (TVA 2013b).
Affected Environment

3-12

1 3.1.4.1 Liquid Waste Processing Systems and Effluent Controls

2 Radioactive liquids are processed as necessary by the liquid waste processing system (LWPS) 

3 for release to the environment into the Tennessee River/Chickamauga Reservoir. The layout of 

4 the LWPS consists of two main subsystems designed for collecting and processing the liquid 

5 waste. Provisions are made to sample and analyze the liquids to ensure the radiation levels are 

6 within NRC and EPA regulatory standards and are ALARA before being released. Based on the 

7 laboratory analysis, these wastes are either released under controlled conditions via the cooling 

8 water system or retained for further processing. The data from the analysis are used to ensure 

9 that the release conforms to the controls specified in the ODCM. The ODCM’s controls are 

10 based on the concentration of radioactive material in the liquid effluent and the projected dose

11 from the release.

12 The liquid waste is processed through a demineralizer system that removes soluble and 

13 suspended radioactive material using ion exchange and filtration processes before being 

14 released into the environment. Once the resin and filter media are expended, it is processed for 

15 disposal. The system has controls to prevent an inadvertent release. For example, at least two 

16 valves must be manually opened to permit the liquid waste to be released from the plant, and 

17 one of these valves is normally locked closed. In addition, an automatic control valve will stop 

18 the release if there is a high effluent radioactivity level signal.

19 Parts of the LWPS are shared by the two units. The following shared equipment is inside the 

20 auxiliary building:

21 • one sump tank and two pumps;

22 • one tritium drain collector tank (TDCT) with two pumps and one filter;

23 • one floor drain collector tank (FDCT) with two pumps and one strainer, 

24 monitor tank and two pumps;

25 • a chemical drain tank and pump;

26 • two hot shower drain tanks (HSDT) and pump;

27 • a spent resin storage tank (SRST);

28 • a cask decontamination tank with two pumps and two filters;

29 • auxiliary building floor and equipment drain sump and two pumps;

30 • a passive sump;

31 • a radwaste demineralizer system; and

32 • associated piping, valves, and instrumentation.

33 Waste liquids high in tritium content are routed to the TDCT, while liquids low in tritium content 

34 are routed to the FDCT. All liquid wastes are processed before being released into the 

35 environment.

36 Waste water enters the liquid waste disposal system from equipment leaks and drains, valve 

37 leakoffs, pump seal leakoffs, tank overflows, and other sources, including draindown of the 

38 chemical and volume control system holdup tanks. The waste is processed through the 

39 radwaste demineralizer and then prepared for release through one of two release tanks.

40 The liquid collected in the TDCT contains boric acid and fission product activity. The liquid is 

41 processed as necessary to remove fission products so the water may be reused in the reactor

42 coolant system or discharged to the environment.
Affected Environment

3-13

1 Nontritiated water is sampled and processed as necessary for discharge to the Tennessee 

2 River/Chickamauga Reservoir. Sources include floor drains, equipment drains containing 

3 nontritiated water, certain sample room and radiochemical laboratory drains, hot-shower drains, 

4 and other nontritiated sources. If the activity is below regulatory release limits, the tank contents 

5 may be discharged without further treatment other than filtration. Otherwise, the tank contents 

6 are processed through the radwaste demineralizer system.

7 The SRST stores the used demineralizer resins. The resin is held in this tank for a period of 

8 time to allow for the decay of short-lived isotopes. The resin is periodically removed for 

9 disposal.

10 The use of these radioactive waste systems and the procedural requirements in the ODCM 

11 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 

12 dose standards.

13 Dose estimates for members of the public are calculated based on radioactive liquid effluent 

14 release data and aquatic transport models. TVA’s annual radioactive material release report 

15 contains a detailed presentation of the radioactive liquid effluents released from SQN, Units 1 

16 and 2, and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive 

17 effluent release data: 2008 through 2012 (TVA 2009a, 2010a, 2011b, 2012a, 2013a). A 5-year 

18 period provides a data set that covers a broad range of activities that occur at a nuclear power 

19 plant, such as refueling outages, routine operation, and maintenance activities that can affect 

20 the generation of radioactive effluents. The NRC staff compared the data against NRC dose

21 limits and looked for indication of adverse trends (e.g., increasing dose levels) over the period 

22 from 2008 through 2012.

23 The following summarizes the calculated doses from radioactive liquid effluents released during 

24 2012:

25 • The total-body dose to an offsite member of the public from SQN’s 

radioactive liquid effluents was 1.27×10−2 26 millirem (mrem) 

(1.27×10−4 27 millisievert (mSv)), which is well below the 6 mrem (0.06 mSv) 

28 dose criterion in Appendix I to 10 CFR Part 50 for a site having two reactor

29 units.

30 • The organ (child liver) dose to an offsite member of the public from SQN’s 

radioactive liquid effluents was 1.28×10−2 mrem (1.28×10−4 31 mSv), which is 

32 well below the 20 mrem (0.2 mSv) dose criterion in Appendix I to 

33 10 CFR Part 50 for a site having two reactor units.

34 The NRC staff’s review of SQN’s radioactive liquid effluent control program showed that 

35 radiation doses to members of the public were controlled within the NRC’s and EPA’s radiation 

36 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 

37 40 CFR Part 190. No adverse trends were observed in the dose levels.

38 Routine plant refueling and maintenance activities currently performed will continue during the 

39 license renewal term. Based on the past performance of the radioactive waste system to 

40 maintain doses from radioactive liquid effluents within NRC and EPA radiation protection 

41 standards, similar performance is expected during the license renewal term.

42 3.1.4.2 Gaseous Waste Processing System and Effluent Controls

43 The gaseous waste processing system (GWPS) is designed to remove fission product gases 

44 from the reactor coolant and minimize the amount of radioactivity released into the environment. 

45 The GWPS is a shared system serving both units. It consists of two waste-gas compressor 

46 packages, nine gas decay tanks, and the associated piping, valves, and instrumentation. 
Affected Environment

3-14

1 Gaseous wastes are generated from the following: gases removed from the reactor coolant and 

2 purging of the volume control tank before a cold shutdown of the reactor, displacing of cover 

3 gases caused by the accumulation of liquids in storage tanks, purging of some equipment, 

4 sampling and gas analyzer operation. The reduction of the levels of radioactivity is 

5 accomplished by internal recirculation of the gases within piping systems and temporary storage 

6 in gas decay tanks. The recirculation of the gases and the temporary storage (at least 60 days) 

7 in tanks allows time for radioactive decay to reduce the level of radioactivity.

8 Periodically, small quantities of radioactive gases are released into the atmosphere, in a 

9 controlled and monitored manner, through plant vents on the shield building, auxiliary building, 

10 turbine building, and service building. The radioactive gaseous waste sampling and analysis 

11 program specifications supplied in the ODCM address the gaseous release type, sampling 

12 frequency, minimum analysis frequency, type of activity analysis, and lower limit of detection 

13 (i.e., sensitivity) for the radiation monitor.

14 The use of these radioactive waste systems and the procedural requirements in the ODCM 

15 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 

16 dose standards.

17 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 

18 release data and atmospheric transport models. TVA’s annual radioactive material release 

19 report contains a detailed presentation of the radioactive gaseous effluents released from SQN 

20 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 

21 release data: 2008 through 2012 (TVA 2009a, 2010a, 2011b, 2012a, 2013a). A 5-year period 

22 provides a data set that covers a broad range of activities that occur at a nuclear power plant, 

23 such as refueling outages, routine operation, and maintenance activities that can affect the 

24 generation of radioactive effluents. The NRC staff compared the data against NRC dose limits 

25 and looked for indication of adverse trends (e.g., increasing dose levels) over the period of 2008 

26 through 2012. The following summarizes the calculated doses from radioactive gaseous 

27 effluents released during 2012:

28 • The air dose at the site boundary from gamma radiation in gaseous effluents 

from SQN was 3.91×10−3 millirad (mrad) (3.91×10−5 29 milligray (mGy)), which is 

30 well below the 20 mrad (0.2 mGy) dose criterion in Appendix I to 

31 10 CFR Part 50 for a site having two reactor units.

32 • The air dose at the site boundary from beta radiation in gaseous effluents 

from SQN was 1.52×10−3 mrad (1.52×10−5 33 mGy), which is well below the 

34 40 mrad (0.4 mGy) dose criterion in Appendix I to 10 CFR Part 50 for a site 

35 having two reactor units.

36 • The dose to an organ (child bone) from radioactive iodine, radioactive 

particulates, and carbon-14 from SQN was 3.35×10−1 mrem (3.35×10−3 37 mSv), 

38 which is well below the 30 mrem (0.3 mSv) dose criterion in Appendix I to 

39 10 CFR Part 50 for a site having two reactors.

40 The NRC staff’s review of the SQN’s radioactive gaseous effluent control program showed that 

41 radiation doses to members of the public were controlled within the NRC’s and EPA’s radiation 

42 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 

43 40 CFR Part 190. No adverse trends were observed in the dose levels.

44 Routine plant refueling and maintenance activities currently performed will continue during the 

45 license renewal term. Based on the NRC’s review of past performance of the radioactive waste 

46 system to maintain doses from radioactive gaseous effluents within NRC and EPA radiation 

47 protection standards, similar performance is expected during the license renewal term.
Affected Environment

3-15

1 3.1.4.3 Solid Waste Processing

2 Solid low-level radioactive waste (LLRW) is generated by the removal of radioactive material 

3 from liquid waste streams, filtration of gaseous effluents, and removal of contaminated material 

4 from various reactor areas. Solid wastes are processed by the solid waste system. The waste 

5 is divided into two categories: dry active waste (DAW) and wet active waste (WAW). The DAW 

6 and WAW inputs are products of plant operation and maintenance. The DAW is further 

7 subdivided into compactible and noncompactible wastes. Solid compactible wastes include 

8 paper, clothing, rags, mop heads, rubber boots, and plastic. Noncompactible wastes include 

9 tools, mop handles, lumber, glassware, pumps, motors, valves, and piping. The WAW is 

10 primarily composed of spent resins. Sources for spent resins are the SRST and the radwaste 

11 demineralizer system.

12 A waste packaging area is provided for receiving, sorting, and compacting DAW. Dry active 

13 waste is collected from throughout the plant and brought to the waste processing area for final 

14 packaging. The waste may also be sent to a contracted broker or processor for any or all of the 

15 stages involving processing, packaging, and subsequent disposal.

16 Wet waste that is suitable for disposal is transferred from a shielded storage tank to a large 

17 container called a liner. The wet waste is pushed through a piping system using a combination 

18 of reactor system water and pressurized nitrogen. When the liner is filled, the water is removed 

19 and the waste is stabilized to eliminate freestanding water, as required by licensed disposal 

20 facilities. The disposable liner is placed in a reusable shielded cask mounted on a truck or 

21 trailer bed for transport to a temporary onsite storage facility or to a licensed disposal facility.

22 Transportation and disposal of solid radioactive wastes are performed in accordance with the 

23 applicable requirements of 10 CFR Part 71 and Part 61, respectively. In 2012, 10 waste 

24 shipments were made from SQN to treatment facilities for processing and disposal. The total 

volume and activity of DAW shipped off site in 2012 was 60.4 cubic meters (m3 25 ) 

(2,133 cubic feet (ft3 26 )) and 0.26 curies (Ci) (9,620 megabecquerel (MBq)), respectively 

27 (TVA 2013a). Routine plant operation, refueling outages, and maintenance activities that 

28 generate solid radioactive waste will continue during the license renewal term. Similar levels of 

29 solid radioactive waste are expected to be generated and shipped for disposal during the 

30 license renewal term.

31 3.1.4.4 Radioactive Waste Storage

32 Low-level radioactive waste is classified as Class A, Class B, Class C, or greater than Class C. 

33 Class A includes both DAW and WAW. Classes B and C are normally WAWs. The majority of 

34 LLW generated at SQN is Class A waste and is shipped to an offsite vendor for volume 

35 reduction, packaging, and then shipped to a licensed Class A disposal facility. Classes B and C 

36 wastes make up a low percentage by volume of the total LLW generated at SQN. Classes B 

37 and C wastes are currently stored in an onsite storage facility at SQN until they are disposed of 

38 at a licensed disposal facility.

39 SQN’s onsite storage facility was designed to contain packaged radioactive waste generated at 

40 SQN and Watts Bar Nuclear Plant (WBN) Unit 1. The total current radioactive waste inventory 

of the SQN onsite storage facility, as of August 2012, is 895 ft3 (25 m3 41 ) and 689 Ci 

(2.55×107 42 MBq). The applicant states that although TVA may apply to the NRC for approval to 

43 transport LLW from WBN Unit 2 to SQN in the future, there are no long-term plans to construct 

44 additional onsite storage facilities to accommodate Classes B and C radioactive waste during 

45 the license renewal term.

46 The applicant has, by procedure, limited the total storage capacity of SQN’s onsite storage 

facility to 88,500 Ci (3.27×109 47 MBq). The applicant concludes that for the 20-year license 
Affected Environment

3-16

1 renewal term, even assuming that TVA decides to transport LLW from WBN Unit 2 to SQN at 

2 similar annual volumes as currently generated at WBN Unit 1, adequate storage capacity for 

3 LLW will be available during the license renewal term.

4 SQN stores its spent nuclear fuel in a spent fuel pool and also maintains an independent spent 

5 fuel storage installation (ISFSI) on site. The ISFSI is used to safely store spent fuel in licensed 

6 and approved dry cask storage containers on site. The installation and monitoring of this facility 

7 is governed by NRC requirements in 10 CFR Part 72, “Licensing Requirements for the 

8 Independent Storage of Spent Nuclear Fuel, High-Level Radioactive Waste, and 

9 Reactor-Related Greater Than Class C Waste.” The SQN ISFSI would remain in place until the 

10 U.S. Department of Energy (DOE) takes possession of the spent fuel and removes it from the 

11 site for permanent disposal or processing. Expansion of the onsite spent fuel storage capacity 

12 may be required during the license renewal term if DOE does not take responsibility for the 

13 permanent storage and disposal of the spent fuel. The SQN ISFSI is located within the existing 

14 protected area boundary, southeast of the Unit 2 Reactor Building. The ISFSI storage pad 

15 consists of eight sections, which is sufficient to store 90 HI-STORM 100 storage systems 

16 (TVA 2013b).

17 3.1.4.5 Radiological Environmental Monitoring Program

18 TVA conducts a REMP to assess the radiological impact, if any, to the public and the 

19 environment from operations at SQN. 

20 To determine the amount of radioactivity in the environment before the operation of SQN, a

21 preoperational REMP was initiated in 1971 and operated until Unit 1 began operation in 1980. 

22 Measurements of the same types of radioactive materials that are measured currently were 

23 assessed during the preoperational phase to establish normal background levels for various 

24 radionuclides in the environment. The knowledge of preexisting radionuclide patterns in the 

25 environment permits a determination, through comparison and trending analyses, of any impact 

26 on the environment due to SQN operation. The determination of impact from the plant during 

27 the operating phase also utilizes data from control stations (i.e., monitoring stations far from the 

28 plant that monitor ambient background radiation levels). The data from environmental samples 

29 taken at control stations are compared against the data from indicator stations (i.e., monitoring 

30 stations located near the plant) to determine the potential radiological impact of operations at 

31 SQN. 

32 The REMP measures the aquatic, terrestrial, and atmospheric environment for radioactivity, as 

33 well as the ambient radiation by sampling air, water, milk, foods, soil, fish, and shoreline 

34 sediment. In addition, the REMP measures background radiation (i.e., cosmic sources, global 

35 fallout, and naturally occurring radioactive material, including radon). The radiation detection 

36 devices and analysis methods used to determine the radioactivity in environmental samples are 

37 very sensitive to small amounts of radioactivity. The REMP supplements the radioactive

38 effluent monitoring program by verifying that any measurable concentrations of radioactive 

39 materials and levels of radiation in the environment are not higher than those calculated using 

40 the radioactive effluent release measurements and transport models. 

41 In addition to the REMP, SQN has an onsite groundwater (GW) protection program designed to 

42 monitor the onsite plant environment for detection of leaks from plant systems and pipes 

43 containing radioactive liquid (TVA 2013b). Information on the GW protection program is 

44 contained in Section 3.5.2 of this document. 

45 The NRC staff reviewed 5 years of annual radiological environmental monitoring data: 2008 

46 through 2012 (TVA 2009b, 2010b, 2011a, 2012b, 2013b). A 5-year period provides a data set 

47 that covers a broad range of activities that occur at a nuclear power plant, such as refueling 
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1 outages, routine operation, and maintenance activities that can affect the generation and 

2 release of radioactive effluents into the environment. The NRC staff looked for indication of 

3 adverse trends (e.g., buildup of radioactivity levels) over the period of 2008 through 2012.

4 The NRC staff’s review of TVA’s data showed no indication of an adverse trend in radioactivity 

5 levels in the environment. The data showed that there was no measurable impact to the 

6 environment from operations at SQN.

7 3.1.4.6 Reasonably Foreseeable Radiological Projects at SQN

8 The applicant stated in its ER that SQN has been selected by DOE for irradiation services for 

9 the production of tritium. Tritium production at SQN was studied in DOE’s environmental impact 

10 statement (EIS) for tritium production in a commercial light water reactor (DOE 1999). The 

11 production of tritium at SQN could require the addition of employees (fewer than 10 employees 

12 per unit), as well as additional plant modifications. TVA has not specified the plant modifications 

13 at this time. The DOE expects that the production of tritium at SQN would generate irradiated 

14 tritium-producing burnable absorber rod (TPBAR) assemblies, nonradioactive waste, and some 

15 additional LLW that would be transported off site for processing and disposal (DOE 1999). To 

16 date, SQN has not produced tritium for the DOE. Before the production of tritium at SQN, TVA 

17 would need to submit license amendment applications to the NRC. The NRC would perform a 

18 safety evaluation and an environmental assessment to determine whether the proposed action 

19 meets NRC’s safety and radiological requirements. If approved by the NRC, TVA could then 

20 proceed with the production of tritium.

21 TVA is also coordinating with DOE on projects regarding the use of other types of nuclear fuel 

22 associated with DOE’s disposition of nuclear materials pursuant to U.S. nuclear nonproliferation 

23 policies. The DOE’s National Nuclear Security Administration may modify the scope of the 

24 surplus plutonium disposition program to consider the option of using alternative methods of 

25 disposing of surplus plutonium. If this program moves forward, DOE, with TVA as a cooperating 

26 agency, will prepare an EIS to analyze the potential environmental impacts of the disposal of 

27 plutonium through the use of mixed oxide fuel (MOXF) in reactors operated by TVA, including 

28 SQN. Fabricating MOXF entails mixing plutonium oxide with depleted uranium oxide, 

29 manufacturing the fuel into pellets, and loading the pellets into fuel assemblies for use in nuclear 

30 reactors. If DOE decides to dispose of surplus plutonium as nuclear fuel in this manner, 

31 thorough evaluations would need to be made by the NRC and TVA before MOXF is used at 

32 SQN. In addition, TVA would need to submit license amendment applications to the NRC for 

33 the use of MOXF (TVA 2013n). The NRC would perform a safety evaluation and an 

34 environmental review to determine whether the proposed action meets NRC’s safety and 

35 radiological requirements.

36 3.1.5 Nonradioactive Waste Management Systems

37 Like any other industrial facility, nuclear power plants generate wastes that are not 

38 contaminated with either radionuclides or hazardous chemicals. These wastes include trash, 

39 paper, wood, and sewage.

40 SQN has a nonradioactive waste management program to handle its nonradioactive hazardous 

41 and nonhazardous wastes. The waste is collected in central collection areas within the plant 

42 and managed in accordance with SQN’s procedures. The waste materials are received in 

43 various forms and packaged to meet regulatory requirements before final disposition at an 

44 offsite facility licensed to receive and manage the waste. Listed below is a summary of the 

45 types of waste materials generated and managed at SQN.
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1 • SQN’s hazardous waste generator classification ranges from conditionally 

2 exempt small quantity generator to small quantity generator. The amount of 

3 hazardous wastes generated are only a small percentage of the total wastes 

4 generated—consisting of paints and paint-related materials, spent and 

5 shelf-life expired chemicals, laboratory chemical wastes, and project-specific 

6 wastes.

7 Hazardous wastes from SQN are transferred to TVA’s permitted hazardous 

8 waste storage facility (HWSF) in Muscle Shoals, Alabama, which serves as a 

9 central collection point for all TVA-generated hazardous wastes. From this 

10 central collection site, the waste is shipped to an approved licensed facility for 

11 disposition.

12 • Special nonhazardous wastes such as asbestos, sandblast grit, alum sludge, 

13 resin, and sand from water treatment systems are transported to the licensed 

14 Rhea County Landfill. Special wastes such as oily debris, desiccant, resin, 

15 nondestructive examination chemicals, and nonhazardous batteries are 

16 transferred to TVA’s permitted HWSF and then shipped to a licensed facility 

17 for disposition.

18 • Universal wastes, such as batteries, lighting wastes, oil, scrap metal, 

19 aluminum cans, plastic bottles, cardboard, paper, and wooden pallets are 

20 collected and shipped to licensed recycling facilities approved by TVA. 

21 • General plant trash is collected in dumpsters and transported to a 

22 State-licensed regional landfill permitted to accept solid wastes. General 

23 trash typically consists of garbage, paper, plastic, packing materials, leather, 

24 rubber, glass, soft drink and food cans, dead animals and fish, floor 

25 sweepings, ashes, wood, textiles, and scrap metal. The waste is disposed of 

26 in a State-permitted landfill.

27 TVA holds a State of Tennessee permit (TDEC permit number DML 331050021) for an onsite 

28 construction and demolition landfill. This landfill is permitted to accept nonhazardous, 

29 nonradioactive solid wastes including scrap lumber, bricks, sandblast grit, crushed metal drums, 

30 glass, wiring, nonasbestos insulation, roofing materials, building siding, scrap metal, concrete 

31 with reinforcing steel and similar construction and demolition wastes generated at the SQN site. 

32 The landfill is approximately 18 ac in size, but, because there is currently no need to use the 

33 landfill, it has not received any waste for at least 10 years. The landfill permit is still active and 

34 TDEC inspects the landfill quarterly. Instead of using its onsite landfill, SQN sends its 

35 construction and demolition wastes to an offsite State-permitted landfill.

36 Sanitary sewage from all plant locations is collected and pumped off site to the Moccasin Bend 

37 publicly owned treatment works for processing and disposal (TVA 2013n).

38 3.1.6 Utility and Transportation Infrastructure

39 Existing utility and transport infrastructure characteristics for SQN are briefly described in the 

40 following subsections.

41 3.1.6.1 Electricity

42 Electrical service to SQN is supplied by generating stations within TVA’s distribution network. 

43 The adjacent 500-kV and 161-kV switchyards provide independent offsite power to SQN Units 1 

44 and 2 from the grid as needed. Both switchyards and all the high-voltage lines would remain in 
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1 service if SQN Units 1 and 2 were decommissioned. There are no other lines from SQN that 

2 connect to the grid or other outside sources of power (TVA 2013f).

3 3.1.6.2 Fuel

4 SQN has five underground diesel fuel oil storage tank assemblies encased in concrete 

5 foundations. Each assembly consists of four interconnected tanks with a combined capacity of 

6 68,000 gallons (gal) (17,000 gal/tank). In accordance with TDEC’s underground storage tank 

7 program regulations 0400-18-01, SQN is subject to and complies with the petroleum release 

8 response, remediation, and risk management requirements (TVA 2013f). 

9 3.1.6.3 Water

10 Systems designed to provide cooling water at SQN are described in Section 3.1.3. In addition 

11 to water needed for cooling, SQN requires water for sanitary purposes and for everyday use by

12 personnel (e.g., drinking, showering, cleaning, laundry, toilets, and eyewashes). SQN does not 

13 use onsite GW for plant or potable water use. Instead, TVA contracts with Hixson Utility District 

14 to access potable and fire protection water at SQN. Hixson Utility District draws GW from an 

15 aquifer at Cave Springs, approximately 8 mi (13 km) southwest of the SQN site. No wastewater

16 treatment occurs on the SQN site (TVA 2013n).

17 3.1.6.4 Transportation Systems

18 SQN has extensive paved surfaces, including roads and parking lots, connecting power plant 

19 infrastructure. Local transportation systems, including roadway access, are detailed in 

20 Section 3.10.6 of this SEIS. Norfolk Southern Corporation is the operator of the 

21 southwest–to–northeast rail line running near the SQN site through Soddy–Daisy. A railroad 

22 spur runs from the Norfolk Southern line to SQN just outside the EAB (TVA 2013n).

23 3.1.6.5 Power Transmission Systems

24 TVA is the owner and operator of the power transmission line systems that were constructed for 

25 the purpose of connecting SQN to the transmission grid. SQN Unit 1 is connected to the 

26 500-kV transmission network, and SQN Unit 2 is connected to the 161-kV transmission system. 

27 The two systems are interconnected at SQN through a 1,200-megavolt ampere, 500–161-kV 

28 intertie transformer bank on the SQN site (TVA 2013n). 

29 In scope transmission lines for the NRC’s license renewal environmental review are limited to 

30 those transmission lines that connect the nuclear plant to the switchyard where electricity is fed 

31 into the regional distribution system (NRC 2013c). For SQN, the 500-kV and 161-kV 

32 switchyards, adjacent to Units 1 and 2 within the protected area of SQN, serve this purpose 

33 (TVA 2013f). The two switchyards and the 500–161-kV intertie transformer bank are located on 

34 the SQN site (TVA 2013n). The two switchyards and the intertie transformer bank are the only 

35 transmission lines considered in scope for license renewal. 

36 3.1.7 Nuclear Power Plant Operations and Maintenance

37 Maintenance activities conducted at SQN include inspection, testing, and surveillance to 

38 maintain the current licensing basis (CLB) of the facility and to ensure compliance with 

39 environmental and safety requirements. Various programs and activities currently exist at SQN 

40 to maintain, inspect, test, and monitor the performance of facility equipment. These 

41 maintenance activities include inspection requirements for reactor vessel materials, boiler and 

42 pressure vessel inservice inspection and testing, and maintenance of water chemistry.

43 Additional programs include those carried out to meet technical specification (TS) surveillance 

44 requirements, those implemented in response to the NRC generic communications, and various 
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1 periodic maintenance, testing, and inspection procedures. SQN must periodically discontinue 

2 the production of electricity for outages supporting refueling, periodic in-service inspection and 

3 testing, and maintenance activities. The SQN reactor units are on staggered 18-month refueling 

4 cycles (TVA 2013n). 

5 3.2 Land Use and Visual Resources

6 3.2.1 Land Use

7 The SQN site comprises two peninsulas totaling 630 ac (253 hectares (ha)). The larger 

8 peninsula is 525 ac (212 ha) and includes the power block and support facilities (buildings, 

9 parking lots, and roads) surrounded primarily by grass fields. The smaller peninsula is 105 ac 

10 (42 ha) and includes the training center surrounded by a mix of mostly evergreen and deciduous 

11 forest habitat. No commercial, institutional, residential, or public recreational areas occur within

12 the SQN EAB (see Figure 3–3). Similarly, no public railroads or major highways occur within 

13 the SQN EAB. Two rural county roads, Igou Ferry and Stone Sage, run adjacent to and 

14 sometimes cross the western boundary of SQN’s property (see Figure 3–3). A private-use 

15 helipad is located on the site (TVA 2013n). Figure 3–3 shows the SQN site boundary and key 

16 features.

17 The Tennessee River creates the southern and eastern boundaries of the SQN site. This 

18 portion of the river is currently dammed, creating the Chickamauga Reservoir. The SQN site is 

19 located at Tennessee River Mile (TRM) 484.5, approximately 6 mi (10 km) east of Soddy-Daisy. 

20 Land not owned by TVA bounds the northern and western portions of the site. Several new 

21 housing subdivisions have been developed adjacent to and near the site boundaries since SQN 

22 began operation (TVA 2013n).

23 Land use is primarily rural within the vicinity of SQN (TVA 2013n). The TVA (2013n) ER 

24 determined that the largest amount of land cover within a 6-mi (10-km) radius of SQN was 

25 deciduous forest (30 percent), followed by pasture or hay (18 percent), open water (13 percent), 

26 and developed land (13 percent). The area within a 50-mi (80-km) radius of SQN includes 

27 mostly forested and agricultural lands, with pockets of developed areas (Fry et al. 2011).

28 The SQN site is located in Hamilton County, one of the most populated counties in Tennessee. 

29 The county population grew 8 percent from 2000 to 2008, with an estimated population of 

30 336,463 in 2010 (CHCRPA 2009). The most common land uses (based on parcel land-use 

31 activity and zoning) within Hamilton County include agriculture (60 percent), residential 

32 (31 percent), and manufacturing and industrial (7 percent) (TVA 2013n). Within developed 

33 areas, the majority of the area is suburban (42 percent), followed by rural (30 percent), 

34 transitional (rural to suburban development, 23 percent), and urban (6 percent) 

35 (CHCRPA 2005).

36 Tennessee Code 13-3-301 requires Chattanooga–Hamilton County to develop a land-use plan 

37 for the future. In accordance with this State requirement, the Chattanooga–Hamilton County 

38 Regional Planning Agency (CHCRPA) has adopted an active land-use plan and advisory guide 

39 entitled Comprehensive Plan 2030. The goal of the 2030 Comprehensive Plan “is to provide 

40 guidance in creating desirable and diverse communities in Hamilton County and to encourage 

41 and provide for new development opportunities while protecting neighborhoods, infrastructure, 

42 and the environment” (CHCRPA 2005). In addition, the CHCRPA is responsible for continuing 

43 to implement its zoning and land-use development strategies, whereby every parcel of land in 

44 the county carries a zoning designation (CHCRPA 2005).
Affected Environment

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1 3.2.2 Visual Resources

2 The SQN site is situated on a relatively flat area adjacent to the shore of the Tennessee River. 

3 Predominant features at the SQN site include the two reactor buildings, a turbine building, an 

4 auxiliary building, a control building, a service and office building, a diesel generator building, an 

5 intake pumping station, an ERCW pumping station, two natural draft cooling towers, 161-kilovolt 

6 (kV) and 500-kV switchyards, a condensing water discharge and diffuser system, and an 

7 independent spent fuel storage installation (TVA 2013n).

8 The tallest structures on site are the two cooling towers at approximately 459 ft (140 m) high 

9 (TVA 2013n). A visible plume of condensation rising up from the cooling towers can be seen 

10 when the cooling towers are operating. The height and visibility of the plume depend on 

11 weather conditions such as temperature, humidity, and wind speed. The plume is typically 

12 several hundred feet tall and can be seen from several miles away. The rolling and forested 

13 terrain of Hamilton County provides significant visual screening in the immediate vicinity of 

14 SQN.

15 3.3 Meteorology, Air Quality, and Noise

16 3.3.1 Meteorology and Climatology

17 The SQN site is located within the Tennessee River Valley, with the Cumberland Plateau to the 

18 west and the Appalachian Mountains to the east. The valley, known as the Great Valley, is 

19 oriented in a northeasterly-to-southwesterly direction. The local topography within the 

20 Great Valley is complex, characterized by a number of minor ridges and valleys with a similar 

21 northeast-to-southwest orientation. The regional climate is characterized as humid subtropical. 

22 Because of the moderating influences of the surrounding terrain, extreme heat or cold outbreaks 

23 are uncommon. The summer months of June through September are quite warm and are 

24 characterized by frequent afternoon thunderstorms (NCDC 2013a). The winter months of 

25 December through February are cool and characterized by alternating periods of warming and 

26 cooling from mid-latitude, low-pressure systems and associated fronts passing through the area; 

27 minimum temperatures during this time are usually near freezing, but temperatures below zero 

28 are rarely observed (NCDC 2013a). The regional climate is influenced by the position of the 

29 semipermanent high-pressure system, known as the Bermuda High. During the summer 

30 months, the Bermuda High is situated off of the Atlantic Coast and draws moisture 

31 northwestward from the Atlantic and Gulf of Mexico, resulting in the observed warm and moist 

32 summers. During the winter months, the Bermuda High shifts southeastward as the jet stream 

33 moves southward; low-pressure systems and fronts accompany the jet stream and pass through 

34 the area (NOAA 2013).

35 The NRC staff obtained climatological information with 30-year averages (1981–2010) for the 

36 Chattanooga, Tennessee, first-order National Weather Service (NWS) station. This station is 

37 approximately 15 mi (24 km) south-southeast of the SQN site and can be used to characterize 

38 the region’s climate because of its nearby location, comparable elevation, and long period of 

39 record. Additionally, TVA maintains a SQN meteorological facility that consists of a 

40 91-m (300-ft) tower that is instrumented at three levels for wind and temperature measurements 

41 (TVA 2013n). Dewpoint, temperature and precipitation are also measured by a separate 

42 10-m (33-ft) tower (TVA 2013n). Recent meteorological observations from the SQN site were 

43 made available to the staff (TVA 2013e, 2013f). These data were evaluated in context of the 

44 longer climatological record from the Chattanooga NWS station.

45 The prevailing wind direction at the Chattanooga NWS station is from the south during most of 

46 the year, except during the winter months, when it is generally from the north (NCDC 2013a). In 
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1 the absence of any large-scale weather systems, low-level winds at the SQN site tend to more 

2 closely follow the orientation of the Tennessee River Valley, with daytime south-southwesterly 

3 upslope winds and nighttime north-northeasterly downslope winds (TVA 2013e, 2013f). The 

4 mean annual wind speed at the Chattanooga NWS station is 5.0 mph (2.2 m/s) and mean 

5 monthly wind speed ranges from 4.0 mph (1.8 m/s) in August to 6.5 mph (2.9 m/s) in March 

6 (NCDC 2013a). Average wind speeds at the SQN site tend to be slightly lower, but exhibit the 

7 same seasonal trend (TVA 2013e). A peak 3-second wind gust of 69 mph (30.8 m/s) was 

8 recorded in April of 2011 at the Chattanooga NWS station (NCDC 2013a).

9 The mean annual temperature at the Chattanooga NWS station is 60.8 °F (16.0 °C), with a 

10 mean monthly temperature ranging from a low of 40.5 °F (4.7 °C) in January to a high of 80.0 °F 

11 (26.7 °C) in July (NCDC 2013a). Recent temperature observations taken at the SQN site are 

12 consistent with these values (TVA 2013h). Extreme temperatures in Chattanooga range from a 

13 maximum of 107 °F (41.7 °C) in June and July of 2012 to a minimum of −10°F (−23.3 °C) in 

14 January of 1985 (NCDC 2013a).

15 Normal annual liquid precipitation measured at the Chattanooga NWS station is 52.48 in. 

16 (1,333 mm) (NCDC 2013a). The wettest year from the most recent 30-year period of record 

17 was 1994, with 73.70 in. (1,872 mm) (NCDC 2013a); the driest year from the same period was 

18 2007, with 38.62 in. (981 mm) (NCDC 2013a). Monthly precipitation amounts tend to be evenly 

19 distributed throughout the year and range from an average of 3.28 in. (83 mm) in October to 

20 5.00 in. (127 mm) in November (NCDC 2013a). Precipitation trends from recent observations 

21 made at the SQN site (TVA 2013g) are consistent with precipitation observations at 

22 Chattanooga, although precipitation amounts are generally lower at the SQN site. Snowfall is 

23 not common in the region; average annual snowfall at the Chattanooga NWS site is 3.9 in. 

24 (9.9 cm) (NCDC 2013a), with a maximum monthly snowfall of 20.0 in. (50.8 cm) recorded in 

25 March 1993.

26 Thunderstorms are observed normally on 55 days throughout the year, with the majority 

27 occurring during the summer months of May through August (NCDC 2013a). Severe weather 

28 can occur in the form of hail and tornadoes. In the past 13 years, there have been 77 large-hail 

29 events (greater than 0.75-in. (1.9-cm) diameter) reported in Hamilton County; however, many of 

30 the hail reports are associated with the same storm (NCDC 2013b). In the past 13 years, 

31 19 tornado events have been reported in Hamilton County, including 1 tornado classified as an 

32 EF4 (166–200 mph (74.2–89.4 m/s) 3-second wind gust) on the Enhanced Fujita Scale 

33 (NCDC 2013b). Thirteen of the tornado events, including the EF4 tornado, were associated 

34 with a tornado outbreak on April 27, 2011 (NCDC 2013b).

35 3.3.2 Air Quality

36 Under the Clean Air Act (CAA), the EPA has set primary and secondary National Ambient Air 

37 Quality Standards (NAAQS) for six common criteria pollutants to protect sensitive populations

38 and the environment. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), 

39 nitrogen dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). PM is 

40 further categorized by size—PM10 (diameter between 2.5 and 10 micrometers (μm)) and PM2.5

41 (diameter of 2.5 μm or less).

42 The EPA designates areas of “attainment” and “nonattainment” with respect to the NAAQS. 

43 Areas that have insufficient data to determine designation status are denoted as 

44 “unclassifiable.” Areas that were once in nonattainment, but are now in attainment, are called 

45 “maintenance” areas; these areas are under a 10-year monitoring plan to maintain the 

46 attainment designation status.
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1 Air quality designations are generally made at the county level. For the purpose of planning and 

2 maintaining ambient air quality with respect to the NAAQS, EPA has created Air quality control 

3 regions (AQCRs). Air quality control regions are intrastate or interstate areas that share a 

4 common airshed (40 CFR 81). The SQN site is located in Hamilton County, Tennessee; this 

5 county, along with several counties in Georgia, are part of the Chattanooga Interstate AQCR 

6 (40 CFR 81.42). With regard to the NAAQS criteria pollutants, Hamilton County is designated 

7 as unclassified or in attainment with respect to CO, Pb, SO2, NO2, and PM10 standards 

(40 CFR 81.343). Hamilton County was an Early Action Compact 2 8 (EAC) area with respect to 

9 the 1997 8-hour ozone standard and demonstrated attainment to the standard on April 15, 2008 

10 (73 FR 17897). Hamilton County is designated as nonattainment with respect to the 1997 PM2.5

11 annual standard (40 CFR 81.343). 

12 States have primary responsibility for ensuring attainment and maintenance of the NAAQS. 

13 Under section 110 of the CAA (42 U.S.C. 7401) and related provisions, states are to submit 

14 State Implementation Plans (SIPs) that provide for the timely attainment and maintenance of the 

15 NAAQS to EPA for approval. On February 8, 2012, EPA approved and promulgated TDEC’s 

16 revisions to the SIP in support of PM2.5 attainment demonstration (77 FR 6467). Subsequently, 

17 on December 14, 2012, EPA strengthened the air quality standards for PM2.5. EPA will make 

18 final designations with regard to the new PM2.5 standards by December 2014 (EPA 2012d).

19 TVA maintains a synthetic minor operating permit (Source ID: 4706504150) for sources of air 

20 pollution at the SQN site (TVA 2013f, 2013i). A synthetic minor source has the potential to emit 

21 air pollutants in quantities at or above the major source threshold levels but has accepted 

22 federally enforceable limitations to keep the emissions below such levels. Permitted sources 

23 include two cooling towers, insulator saws, a carpenter shop, as well as emissions from 

24 abrasive blasting, auxiliary boilers, and several emergency/blackout diesel generators 

25 (TVA 2013f).

26 As a condition of the operating permit, TVA is required to submit an annual compliance 

27 certification to the Chattanooga–Hamilton County Air Pollution Control Bureau (CHCAPCB), 

28 which includes estimated air pollutant emissions (TVA 2013n). The SQN site has been in 

29 compliance with the requirements set forth in the air permit, and there are no reported violations 

30 in the last 5 years (EPA 2012d). Air emissions from the cooling towers, insulator saws, 

31 carpenter shop, and abrasive blasting are primarily PM; total PM emissions from these sources 

32 range from 5.8 tons/yr (2009) to 33.8 tons/yr (2008) over the 5-year period from 2007 to 2011 

33 (TVA 2013d). Air emissions from permitted combustion sources, including the auxiliary boilers 

34 and diesel generators, are listed in Table 3–1 (TVA 2013d, 2013f, 2013k). Greenhouse gas 

35 (GHG) emissions from operation of SQN are discussed in Section 4.15.3, Greenhouse Gas 

36 Emissions and Climate Change.

 

2 The Early Action Compact program allows states to submit agreements pledging to meet the 1997 8-hour ozone standard earlier 

than required. This is a voluntary program, and states had to meet a number of criteria and milestones (EPA 2012b).
Affected Environment

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1 Table 3–1. Air Emission Estimates for Permitted Combustion Sources at SQN

Year NOx (t) (a) CO (t) (a) SOx (t) (a) PM2.5 (t) (a) PM10 (t) (a) VOC (t) (a) CO2e (t) (a)

2007 13.3 3.5 0.218 0.23 0.24 0.34 (b)620.0

2008 11.3 3.0 0.186 0.20 0.20 0.29 (b)530.0

2009 13.3 3.5 0.219 0.23 0.24 0.34 697.7

2010 10.5 2.8 0.005 0.18 0.19 0.27 538.2

2011 11.2 3.0 0.006 0.20 0.20 0.29 574.2

(a) To convert t to MT, multiply by 0.91.

(b) Value not provided by TVA; estimated in accordance with Tier 1 calculation methodology found in § 98.33 of 

40 CFR Part 98, Subpart C by NRC staff based on hours of operation of combustion sources for 2007 and 2008.

Key: NOx = nitrogen oxides; CO = carbon monoxide; SOx = sulfur oxides; PM2.5 = particulate matter with a 

diameter of 2.5 μm or less; PM10 = particulate matter with an aerodynamic diameter between 2.5 and 10 μm; 

VOC = volatile organic compounds; CO2e = carbon dioxide equivalent

Sources: TVA 2013d, 2013f, 2013k

2 The EPA promulgated the Regional Haze Rule (RHR) to improve and protect visibility in 

3 National Parks and Wilderness Areas from haze, which is caused by numerous, diverse sources 

4 located across a broad region (40 CFR 51.308–309). Specifically, 40 CFR 81 Subpart D lists 

5 mandatory Class I Federal Areas where visibility is of important value. The RHR requires states 

6 to develop SIPs to reduce visibility impairment at Class I Federal Areas. The TDEC submitted 

7 its Regional Haze SIP for Tennessee to EPA on April 4, 2008. On April 24, 2012, EPA 

8 published a final rule granting limited approval of TDEC’s Regional Haze SIP (77 FR 24392). 

9 The Cohutta Wilderness Area in Georgia is the closest Class I Federal Area to the SQN site; it 

10 is approximately 40 mi (64 km) southeast of SQN. Because of limited source emissions, 

11 distance from the site, and prevailing wind direction, no adverse impacts on Class I areas are 

12 anticipated from SQN operation.

13 3.3.3 Noise

14 Noise is unwanted sound and can be generated by many sources. Sound is described in terms 

15 of amplitude (perceived as loudness) and frequency (perceived as pitch). Sound pressure 

16 levels are typically measured by using the logarithmic decibel scale. A-weighting (denoted by 

17 decibels adjusted (dBA)) is widely used to account for human sensitivity to frequencies of sound 

18 (i.e., less sensitive to lower and higher frequencies and most sensitive to sounds between 1 and 

19 5 kHz), which correlates well with a human’s subjective reaction to sound (ASA 1983, 1985). 

20 Table 3–2 presents common noise sources and their respective sound levels. Nuclear power 

21 generation is an industrial process that can generate noise. Noise sources at the SQN site 

22 include fans, turbine generators, transformers, cooling towers, compressors, emergency 

23 generators, main steam-safety relief valves, and emergency sirens (TVA 2011c). As a major 

24 industrial facility, SQN noise emissions can reach 65–75 dBA levels on site, which attenuate

25 with distance (TVA 2013f). Most of these noise sources are not audible at the site boundary or 

26 are intermittent and considered a minor nuisance. There is scattered residential development in 

27 the vicinity of the SQN site; the nearest resident lives 0.5 mi (0.8 km) from the central point of 

28 the reactors (TVA 2013f). Noise sources in the vicinity of the SQN site include river and lake 

29 traffic, road traffic, dogs barking, insects, and power lines (TVA 2013f). The SQN emergency 

30 sirens, when activated, are meant to be heard off site to alert the nearby communities of a 

31 possible emergency. Offsite noise levels may sometimes exceed the 55-dBA level that EPA
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1 uses as a threshold level to protect against excess noise during outdoor activities (EPA 1974). 

2 However, according to EPA this threshold does “not constitute a standard, specification, or 

3 regulation,” but was intended to provide a basis for state and local governments in establishing 

4 noise standards (EPA 1974). The Federal Housing Administration has established noise 

5 assessment guidelines and finds that noise of 65 dBA or less is acceptable (HUD 2013). 

Beyond local ordinances, there are no Federal regulations3 6 for public exposures to noise 

7 (EPA 2012a).

8 Table 3–2. Common Noise Sources and Sound Levels

Source Sound Pressure Level (dBA)

Jet Plane (at 100 ft distance) 130

Diesel truck (at 30 ft distance) 100

Food blender (at 3 ft distance) 90

Car (50 mph at 50 ft distance) 65

Conversation 55

Threshold of hearing 0

Sources: MMSHT 2013; SFU undated

9 3.4 Geologic Environment

10 This section describes the current geologic environment of the SQN site and vicinity, including 

11 landforms, geology, soils, and seismic conditions.

12 Physiography and Geology

13 The SQN site is in the Valley and Ridge physiographic province (TVA 2013a), which is 

14 characterized by a sequence of folded and faulted northeast-trending sedimentary rocks that 

15 form a series of ridges and alternating valleys. The topography is the result of the folding and 

16 faulting of the rocks in combination with differential rates of erosion. More erosion-resistant 

17 rocks form the ridges, while less resistant rocks form the valleys. In general, the ridges consist 

18 of quartz-rich, coarser-grained rocks like sandstones and conglomerates, while the valleys 

19 contain limestone and shale rocks. 

20 The SQN site is located in a broad northeast-southwest trending valley that contains the 

21 Chickamauga Reservoir. The site is on a peninsula on the west bank of the Chickamauga 

22 Reservoir. Most of the plant is at an elevation of 705 ft (215 m) above MSL. Where not 

23 occupied by the Chickamauga Reservoir, land north and south of the site forms a broad, rolling 

24 plain with elevations that range between about 800 ft (244 m) and 900 ft (274 m) above MSL. 

25 At 5 mi (8 km) west of the SQN site, the elevation of the land rapidly rises up from the valley 

26 floor to approximately 1,600 ft (488 m) above MSL to form the Cumberland Plateau (TVA

27 2013a). East of the site, on the other side of the Chickamauga Reservoir, a terrain of small hills 

28 rises to approximately 900 ft (274 m) above MSL. This hilly terrain continues to the opposite 

29 side of the valley, approximately 8 mi (13 km) distant.

 

3 In 1972 Congress passed the Noise Control Act of 1972 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 remains unfunded (EPA 2014).
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1 The bedrock beneath the valley is made up of geologic units containing limestone, dolomite, 

2 shale, and sandstone, with limestone and dolomite being the most abundant rock type. The 

3 primary geologic units from oldest to youngest include the Conasauga Group, Copper Ridge 

4 Dolomite, Knox Group, the Chickamauga Limestone, and the Newman Limestone. In the TVA

5 ER (TVA 2013), the Knox Group and Conasauga Group are referred to as ”formations”. 

6 However, to be consistent with the public literature, in this SEIS, they will be called “groups”. 

7 The bedrock geologic units generally strike northeast/southwest and dip towards the southeast 

8 at approximately 20 degrees (Haugh 2002). As a result of the folding and thrust faulting of 

9 these units, the same geologic units will be repeatedly encountered in the bedrock in an 

10 east-west direction (Haugh 2002, TVA 2013a).

11 Immediately underlying SQN, the bedrock is composed of several hundred feet of interbedded

12 limestone and shale that make up the Conasauga Group. For this group, shales dominate the 

13 rock assemblage. The Conasauga Group is also part of a now eroded anticline (upward fold or 

14 arch) with steep eastward dipping beds (Figure 3–5). The eastward dip of the Conasauga 

15 Group beds ranges from 60 degrees to near vertical (Julian 2007). The nearest thrust fault to 

16 the site is the Kingston Thrust Fault, which occurs approximately 2,000 ft (610 m) northwest of 

17 the plant site. This fault is not considered to be active and was formed approximately 

18 250 million years ago in association with the creation of the Appalachian Mountains. Along this 

19 fault, the Conasauga Group is in contact with the Knox Group (Figure 3–5) (TVA 2013a). 
Affected Environment

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1 Figure 3–5. Site Geologic Formations and Structure

2 Source: Modified from Julian 2007

D Conasauga Group 

D Chickamauga Limestone 

D KnoxGroup 

Formation Contact 

Thrust Fault 

Fault 

2000 - Chickama;uga / 

Knox Group 

Section A -A' 

(not to scale) 

Knox Group 2000 

7 

Conasauga Group 
Affected Environment

3-28

1 Soils

2 At SQN, where the Conasauga Group is not in direct contact with plant structures, it is overlain 

3 by structural fill or by soils. Within the main plant site, much of the soil was removed during 

4 plant construction. The soils were formed from clayey alluvium and from the shale and 

5 limestone of the Conasauga Group. The soils tend to have a high clay content and to be fine 

6 grained (silt, loam, or clay). Depth to bedrock ranges from 3 to 34 ft (1 to 10 m) (Julian 2007;

7 TVA 2013a; USDA 2013).

8 Seismic Setting

9 The SQN site is located in the “East Tennessee Seismic Zone.” The East Tennessee Seismic 

10 Zone is an approximately 46-mi (75-km) wide, 218-mi (350-km) long region of seismicity located 

11 in the southern Appalachians that extends from NE Alabama and NW Georgia to NE of 

12 Knoxville, Tennessee. It is the second most active seismic zone east of the U.S. Rocky 

13 Mountains. The East Tennessee Seismic Zone has not recorded historical earthquakes greater 

14 than a magnitude of 5 (Hatcher et al. 2012). The largest recorded earthquake in this seismic 

15 zone was a magnitude 4.6 that occurred in 1973 near Knoxville, Tennessee. Sensitive 

16 seismographs have recorded hundreds of earthquakes too small to be felt in this seismic zone. 

17 Small, non-damaging earthquakes occur about once a year (USGS 2013a). The site is located 

18 in an area that could experience strong shaking from earthquakes, but the damage associated 

19 with them would be light. Should a strong earthquake occur, well-designed ordinary structures 

20 might experience slight to moderate damage, but poorly built structures could experience 

21 considerable damage (FEMA 2013, USGS 2013b, USGS 2013c, Wood and Ratliff 2011). The 

22 The NRC requires every nuclear power plant to be designed for site-specific ground motions 

23 that are appropriate for its location. 

24 3.5 Water Resources

25 3.5.1 Surface Water Resources

26 3.5.1.1 Site Description and Surface Water Hydrology

27 Local Hydrology and Drainage

28 The SQN site is situated on a peninsula on the western shore of Chickamauga Reservoir, part 

29 of the Tennessee River System, at Tennessee River Mile (TRM) 484.5.

30 Chickamauga Reservoir lies within the Upper Tennessee River Basin, based on the 

31 U.S. Geological Survey (USGS) established boundary between the upper and lower portions of 

32 the basin at TRM 465 in Chattanooga, Tennessee. The Upper Tennessee River Basin 

encompasses approximately 21,390 mi2 (55,400 km2 33 ), and includes the entire drainage area of 

34 the Tennessee River and its tributaries upstream from the USGS gauging station at 

35 Chattanooga, Tennessee. It comprises parts of four states including Tennessee, 

36 North Carolina, Virginia, and Georgia. The Upper Tennessee River Basin contains some of the 

37 most rugged terrain in the eastern United States, including the Great Smoky Mountains range 

38 (Hampson et al. 2000; TVA 2013n). Below Chattanooga, the Tennessee River travels a 

39 generally U-shaped course through the Lower Tennessee River Basin, which encompasses the 

40 remaining portions of Tennessee, Georgia, Alabama, Mississippi, and Kentucky that drain to it. 

41 The Tennessee River ultimately has its confluence with the Ohio River at Paducah, Kentucky 

42 (TVA 2013n).

43 Specific to the SQN site, Chickamauga Reservoir extends approximately 59 river miles 

44 upstream from Chickamauga Dam at TRM 471 to Watts Bar Dam at TRM 529.9. The reservoir 

has a drainage area of 20,790 mi2 (53,820 km2 45 ), a shoreline length of 784 mi (1,262 km), a 
Affected Environment

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volume of 628,000 acre-feet (774.6 million m3 1 ), and a surface water area of 35,400 ac 

2 (14,326 ha) at a normal maximum pool elevation of 682.5 ft (208 m) above MSL behind 

3 Chickamauga Dam. The reservoir ranges from 700 ft (213 m) to 1.7 mi (2.7 km) wide 

4 (TVA 2011c, 2013n). In the vicinity of SQN, the reservoir is approximately 3,000 ft (910 m) wide 

5 with water depths ranging between 12 and 50 ft (3.6 and 15 m) at normal maximum pool 

6 elevation (TVA 2011d).

7 The SQN site directly interacts and is connected with Chickamauga Reservoir through modified 

8 embayments and a discharge pond system that support plant operations. These features are 

9 depicted in Figure 3–4. In summary, on the north end of the main plant site, they include the 

10 unlined plant intake embayment (forebay) where the ERCW system intake pump station and the 

11 CCW system intake pump station (see Section 3.1.3) and associated intake channel are 

12 located. In the central portion of the main plant complex, the unlined CCW discharge channel 

13 receives heated condenser water and other effluents (see no. 5 in Figure 3–4) and drains to the 

14 unlined diffuser pond (no. 6 in Figure 3–4). As part of this system, several smaller ponds also 

15 collect and convey plant stormwater and other wastewaters from plant systems in accordance

16 with SQN’s current Tennessee-issued NPDES permit (No. TN0026450). The largest of these is 

17 an unlined yard drainage pond (no. 1 in Figure 3–4) which overflows and drains by gravity 

18 directly to the diffuser pond. Next are two former metal cleaning waste ponds (nos. 2 and 3 in 

19 Figure 3–4), which are regulated at an NPDES internal monitoring point (internal outfall 107). 

20 These ponds discharge to the lined, low volume waste treatment pond (no. 4 in Figure 3–4), 

21 which, in turn, discharges via NPDES internal outfall 103 to the diffuser pond (no. 6 in 

22 Figure 3–4). Ultimately, thermal effluents (including cooling tower blowdown when the plant 

23 operates in helper mode) and other wastewaters collected in SQN’s diffuser pond system are 

24 discharged through the plant’s submerged diffuser structure (NPDES outfall 101) into 

25 Chickamauga Reservoir. SQN’s diffuser structure is detailed in Section 3.1.3.1 of this SEIS. 

26 However, should SQN operate in closed-cycle mode, the cooling tower discharge (return) 

27 channel (no. 7 in Figure 3–4) would convey cooling water circulated through the cooling towers 

28 back to the intake embayment rather than to the diffuser pond. Finally, a separate settling pond 

29 yard (no. 8 in Figure 3–4), that is used to dewater dredged sediments, discharges via NPDES 

30 outfall 118 to the intake embayment rather than to the diffuser pond system (TVA 2011c, 2013d, 

31 2013e, 2013f, 2013n). 

32 It is noted that there are no GW monitoring requirements imposed by the plant’s NPDES permit 

33 as it relates to the use of SQN’s ponds. SQN’s NPDES permit is further discussed in 

34 Section 3.5.1.3. 

35 Regional Hydrology and Flow Regulation

36 The Tennessee River system is regulated by a series of 49 active dams and reservoirs

37 managed by TVA, including Chickamauga Reservoir, which lies between the Watts Bar and 

38 Chickamauga Dams. TVA operates the Tennessee River system to provide year-round 

39 navigation, flood-damage reduction, power generation, improved water quality, water supply, 

40 recreation, and economic growth (Bohac and Bowen 2012; TVA 2011c). System-wide flows are 

41 measured at Chickamauga Dam, located near Chattanooga, Tennessee, as it provides the best 

42 indication of flow for the upper half of the Tennessee River system (TVA 2013i). The average 

43 annual flow of the Tennessee River at the Chickamauga Dam is approximately 32,500 cfs 

(918 m3 44 /s, or 21,000 mgd) (TVA 2011c, 2013n). TVA's Watts Bar Nuclear Plant (WBN) is also 

45 located on Chickamauga Reservoir at TRM 528, approximately 31 mi (50 km) north-northwest 

46 and upstream of SQN (TVA 2013n). The average annual flow at Watts Bar Dam is 

approximately 27,500 cfs (777 m3 47 /s, or 17,800 mgd) (NRC 2013a).
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1 In total, the flow of the main stem Tennessee River in the vicinity of SQN and through 

2 Chickamauga Reservoir is controlled by releases from Watts Bar and Chickamauga Dams and, 

3 to a lesser extent, inflow from the Hiwassee River. The SQN site is approximately 15 TRM 

4 downstream from the Hiwassee River’s confluence with the Tennessee River at TRM 499. The 

5 Hiwassee River discharge accounts for the bulk of the increase in Tennessee River flow 

6 between Watts Bar Dam and Chickamauga Dam. The Hiwassee River discharge into the 

7 Tennessee River is largely controlled by releases from the Ocoee 1 Dam on the Ocoee River 

8 and Apalachia Dam on the Hiwassee River. The Ocoee River empties into the Hiwassee River 

9 downstream of Apalachia Dam. As noted by TVA and the NRC staff’s review of archived river 

10 flow and stage data, regulated inflow to Chickamauga Reservoir from the Hiwassee River is 

11 small, ranging from about 5 to 15 percent, as compared to the contribution of the main stem 

12 Tennessee River (TVA 2013d-f, 2013j). 

13 Within this highly regulated hydrologic environment, the Tennessee River Basin is one of the 

14 wettest regions in the United States. The long-term average annual precipitation and runoff

15 from 1894 to 1993 were 51 and 22 inches, respectively. Average monthly rainfall and runoff 

16 maximum is in March and the minimum is in October. The major flood season in the Tennessee 

17 Valley is from December to mid-April with the highest frequency of storms in March. Dormant 

18 vegetation and ground conditions favor a high rate of runoff during this time period. 

19 Nevertheless, natural flow (i.e., the estimated flow that would have occurred had there been no 

20 dams) in the Tennessee River for the Chickamauga Reach (i.e., the stretch of the river now 

21 encompassed by Chickamuaga Reservoir) for the period 1903 to 1993 averaged 34,300 cfs 

(969 m3 22 /s, or 22,170 mgd). The estimated minimum natural flow occurred in 1998 at 15,700 cfs 

(444 m3

/s, or 10,150 mgd), with the maximum of 51,400 cfs (1,450 m3 23 /s, or 33,200 mgd) in 1929 

24 (Miller and Reidinger 1998). A comparison of these estimates of natural flow with observed 

25 values at Watts Bar and Chickamauga Dams indicates that flow regulation operations closely 

26 mimic natural flow on an annualized basis.

27 In summary, the water levels and flow rates in Chickamauga Reservoir are actively regulated as 

28 part of the Tennessee River and reservoir system. The current TVA policy for reservoir 

29 operations was implemented in May 2004. The policy specifies flow requirements for 

30 (1) individual reservoirs that are designed to prevent dryout of the riverbed downstream and 

31 (2) system-wide operation to meet downstream needs. TVA releases enough water to augment 

32 natural inflows in order to provide the weekly average minimum flows at Chickamauga Dam 

33 according to the minimum operations guide, which is based on the amount of water stored in the 

34 reservoirs. When water must be released to meet downstream flow requirements, a fair share 

35 of water is drawn from each reservoir, resulting in some drawdown from each source. 

36 Furthermore, TVA enhances recreational opportunities by restricting the drawdown of tributary 

37 storage reservoirs during the summer (June 1 through Labor Day). During this period, under 

38 normal operations, just enough water is released from these reservoirs to meet downstream 

39 flow requirements. TVA works to keep the water levels in these reservoirs as close as possible 

40 to each reservoir’s “flood guide level”—a guideline that reflects how much storage space each 

41 reservoir needs to hold back potential flood waters (TVA 2013i, 2013n). 

42 Floodplain Hydrology

43 Through regulation, changes in water levels within the Tennessee River system are minimized, 

44 a situation which greatly reduces the frequency of flooding. Chickamauga, along with Watts Bar 

45 and Ft. Loudon-Tellico, are the three main stem reservoirs on the Upper Tennessee River. TVA

46 management of these reservoirs is designed, in part, to reduce the flood crest at Chattanooga

47 (TVA 2011d, 2013p). The flood insurance rate map for the SQN site and vicinity identifies the 

48 100-year flood elevation at 686 ft (209 m) above MSL (FEMA 2002). All SQN buildings, 

49 including safety-related structures, are above this elevation, with plant grade at 705 ft (215 m) 
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1 above MSL. The original licensing basis flood water-surface elevation for SQN was updated in 

2 2002 to account for Tennessee River dam safety modifications. The CLB probable maximum 

3 flood (at stillwater-surface elevation) for SQN is 719.6 ft (219.3 m) above MSL (TVA 2011d). 

4 Since 2008, TVA has been working on updating, validating, and verifying its legacy hydrology 

5 and hydraulic models. TVA submitted a license amendment request for SQN (TVA 2012d) to 

6 the NRC on August 10, 2012, to raise the licensing-basis flood stillwater-surface elevation to 

7 722 ft (220 m) above MSL. The NRC staff is currently reviewing TVA’s request. By 

8 March 2015, TVA is scheduled to submit a reevaluated flood hazard assessment for SQN in 

9 response to the NRC’s 10 CFR 50.54(f) letter (NRC 2012). The requirement established in 

10 NRC’s 10 CFR 50.54(f) letter for a reevaluated flood hazard assessment is part of the 

11 Fukushima lessons learned effort.

12 3.5.1.2 Surface Water Use

13 Surface water withdrawals from the Tennessee River and reservoir system are regulated under 

14 Section 26a of the TVA Act (1933). TVA evaluates water intake structure permit requests for 

15 environmental impacts to determine the volume of water that can be withdrawn. The conditions 

16 for the withdrawal take into account operation of the river system and impact on the river 

17 environment. Water withdrawal permit holders are required to report annual usage as a 

18 condition of their permits, except for small residential irrigation users who are exempt from 

19 reporting requirements. These data are used in tracking existing withdrawals and evaluating 

20 proposed increases in withdrawals from the Tennessee River system (TVA 2013h, 2013n). 

21 SQN itself does not have a Section 26a permit as TVA is not required to issue permits to 

22 TVA-owned and -operated facilities (TVA 2013j). However, the plant’s surface water

23 withdrawals are voluntarily reported to the State of Tennessee in accordance with the 

24 Tennessee Water Resources Information Act of 2002. Tennessee requires entities, except for 

25 some exempted users, withdrawing 10,000 gallons per day (gpd) (37,500 Lpd) or more of 

26 surface or GW to register the withdrawal with the State on an annual basis (TCA 69-7-3; 

27 TDEC 2013a). 

28 Table 3–3 summarizes SQN’s surface water withdrawals for the period 2008 to 2012. As 

29 described in Section 3.1.3 of this SEIS, all primary cooling and auxiliary cooling water needs for

30 plant operation are provided by intake structures in communication with Chickamauga 

31 Reservoir. Nominal water demand by the CCW system and the ERCW system require SQN 

withdrawals from Chickamauga Reservoir at a peak rate of 2,600 cfs (73.5 m3 32 /s, or 1,680 mgd)

33 (see Section 3.1.3). 

34 Table 3–3. SQN Reported Annual Water Withdrawals and Return Discharges to 

35 Chickamauga Reservoir

Year SQN Withdrawals (mgy) SQN Discharges (mgy)

2008 612,850 567,345

2009 612,850 528,855

2010 573,123 561,156

2011 579,576 582,888

2012 505,541 536,101

Average 576,788 555,269

Note: Data in this table showing discharge exceeding withdrawal in a given year may be indicative of

inflow from sources other than withdrawal from the Tennessee River (e.g., stormwater or utility water) or 

measurement inaccuracies.

Sources: TVA 2013d, 2013e, 2013f
Affected Environment

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1 Based on the NRC staff’s review of TVA’s Water Withdrawal Registration reports submitted to 

2 the State, SQN continuously withdraws water at a fairly constant rate. Specifically, during the 

3 past 5-year period, withdrawals from Chickamauga Reservoir to support SQN operations have 

averaged 576,788 mgy (2,183 million m3 4 /y). This is equivalent to a withdrawal rate of 2,445 cfs 

(69.1 m3 5 /s, or 1,580 mgd). 

6 For the once-through cooling system at SQN, the condenser flow rate is nearly equal to the 

7 surface water withdrawal rate, and the consumption rate is much less than closed-cycle 

8 systems with continuous cooling tower operation. Consequently, the volume of water returned 

9 to Chickamauga Reservoir from SQN plant cooling operations is nearly equal to or slightly less 

10 than the volume withdrawn. There is some consumptive use of water because of evaporation 

11 and drift during cooler tower operation in helper mode. During full helper mode operations, 

consumptive water use could be as much as 31,250 gpm (70 cfs (1.98 m3 12 /s)) or 45 mgd, as 

13 further discussed in Section 3.1.3. This consumptive use is less than 3 percent of the 

14 continuous water withdrawal by the plant. 

15 3.5.1.3 Surface Water Quality and Effluents

16 Water Quality and Standards

17 TDEC is authorized by the EPA to regulate pollutants discharged from point sources into 

18 Tennessee surface waters under the NPDES permit program. In particular, TDEC administers 

19 this program for industrial, municipal, State, and Federal facilities discharging pollutants directly 

20 to surface waters, including the Tennessee River. TDEC also sets water quality standards

21 within the State, establishes pollutant treatment and control requirements, and reviews 

22 monitoring reports to protect the desired and designated uses of the water bodies.

23 TDEC has established criteria to protect Chickamauga Reservoir water quality for its designated 

24 uses including domestic and industrial water supply, fish and aquatic life, recreation, livestock 

25 watering and wildlife, irrigation, and navigation (TNR 1200-04-04). Under Section 303(d) of the 

26 Clean Water Act (CWA) (officially, the Federal Water Pollution Control Act) of 1972, the State of 

27 Tennessee biennially assesses the water quality of streams and develops a list of impaired 

28 waters. These are waters that do not meet water quality standards. The law requires priority 

29 rankings for waters on the list and the development of total maximum daily loads (TMDLs) of 

30 pollutant for these waters.

31 Chickamauga Reservoir is not listed on TDEC’s 2008, 2010, or 2012 Section 303(d) lists for 

32 impaired waters. However, nine listed impaired waters that discharge to Chickamauga 

33 Reservoir between TRM 529.9 and TRM 478 are listed because of various causes, ranging from 

34 high E. coli levels to channel alteration and siltation. They include Watts Bar Reservoir, Little 

35 Richland Creek, the Hiwassee River embayment of Chickamauga Reservoir, Roaring Creek,

36 Possum Creek, an unnamed tributary to Chickamauga Reservoir, Savannah Creek, Wolftever

37 Creek, and Rogers Branch. Most notably, the Hiwassee River embayment of Chickamauga 

38 Reservoir is listed as impaired for fish consumption because of mercury, primarily attributable to 

39 atmospheric deposition and industrial sources. Upstream of SQN, Watts Bar Reservoir is listed 

40 as impaired for fish consumption because of polychlorinated biphenyls (PCBs) from industrial 

41 sources, as well as mercury and chlordane contamination in sediments. The Emory River Arm 

42 of Watts Bar Reservoir is identified as impaired for arsenic, coal ash deposits, and aluminum, as 

43 well as mercury, PCBs, and chlordane (TDEC 2010, 2014; TVA 2013n). The Emory River Arm 

44 is the area of the reservoir most affected by the ash spill that occurred at TVA’s Kingston Fossil 

45 Plant in 2008 (NRC 2013; TVA 2013g).

46 TVA has conducted its Vital Signs Monitoring Program on Chickamauga Reservoir in alternate 

47 years since 1994. This program uses metrics to evaluate the ecological health of TVA 
Affected Environment

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1 reservoirs including chlorophyll concentration, sediment contamination, and dissolved oxygen. 

2 Values of good, fair, or poor are assigned to each metric. Table 3–4 summarizes the 2011 

3 values for monitoring sites in the deep, still area near the Chickamauga Dam (forebay, 

4 TRM 472.3), midreservoir (TRM 490.5), the Hiwassee River embayment (Hiwassee 

5 River Mile 8.5), and at the upstream end of the reservoir (inflow, TRM 518 and 527.4). Based 

6 on the metric evaluation, the overall ecological health condition of Chickamauga Reservoir rated 

7 fair in 2011. Ecological health scores tend to be lower in most Tennessee River reservoirs 

8 during years with low flows, because chlorophyll concentrations are typically higher and 

9 dissolved oxygen levels are lower near the bottom. In 2011, the individual metrics scored good 

10 or fair at all sites except for chlorophyll in the forebay and mid-reservoir stations, which rated 

11 poor (TVA 2013c, 2013n). 

12 Table 3–4. Ecological Health Indicators for Chickamauga Reservoir, 2011

Monitoring Locations Dissolved Oxygen Chlorophyll Sediment

Forebay Good Poor Fair

Mid-Reservoir Good Poor Fair

Hiwassee River Embayment Good Good Fair

Inflow Not Measured Not Measured Not Measured

Sources: TVA 2013c, 2013n 

13 Thermal and Chemical Effluent Regulation

14 Industrial wastewater, cooling water, and stormwater discharges from SQN are governed by a 

15 TDEC-issued NPDES permit (No. TN0026450). SQN’s current NPDES permit for plant 

16 operations was issued to TVA by TDEC with an effective date of March 1, 2011; the permit 

17 expired on October 31, 2013 (TVA 2013n). However, TVA submitted a permit renewal 

18 application to TDEC on May 2, 2013 (Alexander 2014). Therefore, the current permit remains in 

19 effect (i.e., administratively continued) pending issuance of a new permit. TVA expects that 

20 TDEC will issue a renewed permit in 2016 (TVA 2013j). Further, TVA expects that the renewed 

21 permit will include language indicating that continued NPDES permit coverage also constitutes 

22 State water quality certification under Section 401 of the CWA (TVA 2013j, 2013n). 

23 TVA’s current permit sets effluent limits and monitoring requirements for the plant’s discharges 

24 covering five external and two internal outfall (internal monitoring point) locations. The outfalls 

25 discharge industrial wastewater (mainly cooling water) or comingled cooling water with 

26 stormwater. As noted in Section 3.5.1.1, effluents collected from the yard drainage pond, 

27 former metal cleaning waste ponds, low volume waste treatment pond, CCW discharge 

28 channel, cooling tower blowdown basin (including liquid radioactive effluents), and stormwater 

29 are discharged from the diffuser pond through the plant’s submerged diffusers (outfall 101) in

30 the Tennessee River (TVA 2013d-f, 2013n). However, the metal cleaning waste ponds no 

31 longer receive process wastewater, which included boiler cleaning and various piping cleaning 

32 wastes. The permanent piping to the metal cleaning waste ponds from SQN has been 

33 disconnected, and TVA may pursue decommissioning of the ponds through the NPDES permit 

34 process (TVA 2013j).

35 The NPDES permit for SQN identifies outfall 101 for the release of cooling water and associated 

36 effluents to the Tennessee River (Chickamauga Reservoir) through the plant’s discharge

37 diffusers. The compliance point for water temperature is at the downstream end of the diffuser 

38 mixing zone in accordance with the permitted thermal criteria and defined mixing zone, as 

39 previously described in Section 3.1.3.1. To restate, SQN’s NPDES permit delineates the 

40 maximum extent of the mixing zone as an area 750 ft (230 m) wide and extending 1,500 ft 
Affected Environment

3-34

1 (457 m) downstream and 275 ft (85 m) upstream of the plant’s twin diffusers. The depth of the 

2 mixing zone varies linearly from the water surface 275 ft (85 m) upstream of the diffusers to the 

3 top of the diffuser pipes and then extends to the bottom downstream of the diffusers. For 

4 closed-mode operation, the mixing zone also includes the area of the intake forebay to the CCW 

5 intake pump station.

6 The mixing zone geometry is based on a physical model study of the discharge diffusers, which 

7 examined the thermal effluent over a wide range of plant and river conditions, including reverse 

8 flows in Chickamauga Reservoir (TVA 2013n). Conditions favoring a larger mixing zone with 

9 higher temperatures include: (1) low river flow, (2) high ambient river water temperatures, 

10 (3) active upriver heat transport processes, and (4) high temperature thermal discharges to the 

river. When river flow is less than 25,000 cfs (706 m3 11 /s), heat from the thermal discharge has 

12 been observed to migrate upstream to the SQN intake, resulting in intake water temperatures 

13 above ambient (Hopping et al. 2009). Nevertheless, NPDES permit limits and conditions 

14 governing SQN’s thermal discharge via outfall 101 effectively dictate how TVA manages flow 

15 through Chickamauga Reservoir. TVA currently avoids scheduling daily average releases from 

Chickamauga Dam at rates below 6,000 cfs (169 m3 16 /s, or 3,880 mgd) when both SQN units are 

in operation, and 3,000 cfs (84.7 m3 17 /s, or 1,940 mgd) when one SQN unit is in operation.

18 Part III(F) of SQN’s NPDES permit specifies requirements related to monitoring thermal 

19 compliance for outfall 101 in accordance with CWA Section 316(a). Ranges for the daily 

20 average flow past SQN are defined wherein special field surveys are required to verify the 

21 adequacy of TVA’s measurements of ambient river temperature and the adequacy of SQN’s

22 diffuser mixing zone. TVA operates the Chickamauga Reservoir to meet these NPDES permit 

23 requirements (TVA 2013j). 

24 As of July 2013, SQN had operated in compliance with the requirements of Part III(F) of the 

25 current NPDES permit. Based on the current operating policy for the TVA reservoir system, the 

daily average river flow past the SQN site can be as low as 3,000 cfs (84.7 m3 26 /s, or 1,940 mgd). 

In practice, the river flow past SQN rarely drops below a daily average of 6,000 cfs (169 m3 27 /s, or 

3,880 mgd). TVA has not released less than 6,200 cfs (175 m3 28 /s, or 4,000 mgd) of water from 

29 Chickamauga Dam since January 2007 (TVA 2013j).

30 Furthermore, there have been no NPDES thermal violations since SQN began operation. 

31 Under the current NPDES criteria, operating conditions for the river and the plant are primarily 

32 managed for two of the limits―the 24-hour average maximum downstream temperature and the 

33 24-hour average maximum downstream temperature rise (TVA 2013j).

34 Boyington et al. (2013) is TVA’s most recent study that has been performed to establish the 

35 validity of the numerical model prediction of temperature in the mixing zone as required by the 

36 current NPDES permit. Using samples from 1982 to 2012 for the calibration study, TVA 

37 demonstrated that the existing model continues to provide acceptable estimates for the mixing 

38 zone temperatures, with the average discrepancy of 0.38 °F (0.21 °C) for river temperatures 

39 above 75 °F (23.9 °C).

40 The NRC staff also reviewed 5 years of NPDES Discharge Monitoring Reports for SQN as 

41 submitted by TVA to TDEC. Specifically monitored are daily maximum upstream ambient 

42 temperature (Station 14, TRM 490.4), daily maximum temperature rise from upstream to 

43 downstream (TRM 483.4, mixing zone compliance model) of SQN, daily maximum rate of 

44 temperature change, outfall 101 flow and water quality (temperature, pH, total suspended solids

45 (TSS), oil and grease, and chlorine), CCW trench and channel extractable hydrocarbons, 

46 outfall 103 flow and water quality (pH, TSS, oil and grease), outfall 107 flow and water quality 

47 (pH, TSS, oil and grease, copper, and iron), outfall 110 flow and water quality (temperature, pH, 

48 TSS, oil and grease, and chlorine), outfalls 116 and 117 floating debris and oil and grease, and 
Affected Environment

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1 outfall 118 flow and water quality (dissolved oxygen, TSS, and settleable solids). Other than 

2 two pH exceedances in the low volume waste treatment pond (internal outfall103) on 

3 July 8, 2009, and October 1, 2010, no exceedances of effluent limitations were identified. 

4 Violations for a missed sampling during biocide/corrosion treatment on October 25, 2009, and a 

5 late report during a chlorine leak at the ERCW intake on August 20, 2010, occurred during the 

6 period of review (TVA 2013d-f, 2013j). 

7 3.5.2 Groundwater Resources

8 This section describes the current GW resources of the SQN site and vicinity. 

9 3.5.2.1 Site Description and Hydrogeology

10 The valley containing SQN can have from 0 to 300 ft (0 to 100 m) of unconsolidated material 

11 (regolith and soils) on top of soluble carbonate bedrock. This unconsolidated material is usually 

12 composed of insoluble chert and clay residuum formed by the in-situ chemical weathering of the 

13 carbonate bedrock. Groundwater flow in this unconsolidated material is recharged by water 

14 from local precipitation. Where thicker than 50 ft (15 m), the unconsolidated material can serve

15 as a storage reservoir and supply water to the underlying bedrock (Haugh 2002).

16 Some of the geologic units that underly the valley are also aquifers which are used as sources 

17 of water. These geologic units are the Copper Ridge Dolomite, the Knox Group, the 

18 Chickamauga Limestone, and the Newman Limestone (herein after referred to as aquifers). 

19 Water movement through these aquifers is largely through interconnected fractures, joints, and 

20 bedding planes that have been enlarged by chemical weathering (Lloyd and Lyke 1995). West 

21 of the site, these aquifers are recharged with water by direct infiltration (from rain or snow) 

22 through the overlying soils and by infiltration from streams that flow along the base of the 

23 Cumberland Plateau Escarpment. Most recharge to these aquifers occurs during the winter and 

24 spring months (Haugh 2002). In general, GW in these aquifers flows towards the Chickamauga 

25 Reservoir, with some of the GW flowing into wells, streams, and springs (Haugh 2002). 

26 Chickamauga Reservoir is likely another source of water for these aquifers when they outcrop 

27 beneath the reservoir, but this is not considered to be a source of recharge for the area on the 

28 west side of the reservoir around SQN (Haugh 2002).

29 The SQN site is underlain by the Conasauga Group. Neither the Conasauga Group nor the 

30 overlying soil would be considered an aquifer. The high clay content of the shale beds in the 

31 Conasauga Group make it a poor water producer (Julian 2007, TVA 2013a), while both the high 

32 clay content and shallow depth of the soils make them poor sources of GW. 

33 The source of GW in the SQN soil and in the Conasauga Group is from on-site precipitation or 

34 from the Chickamauga Reservoir. Chickamauga Reservoir surrounds the SQN site on the 

35 north, east, and south. Groundwater levels move up or down as Chickamauga Reservoir water 

36 levels move up or down (Julian 2007). When water levels rise in either the reservoir, intake, or 

37 discharge channels, water moves from these water bodies into the Conasauga Group and the 

38 soil. When water levels in the reservoir, intake, or discharge channels are lowered, GW in the 

39 Conasauga Group and the soil flows into these channels and the reservoir. Overall, GW flow 

40 direction in the soil and Conasauga Group at SQN is towards the reservoir (Julian 2007; 

41 TVA 2013a).

42 The beds of the Conasauga Group are nearly vertical. For GW within the Conasauga Group to 

43 flow westward or eastward from SQN, it would need to cross the low-permeability shale beds 

44 contained within the Conasauga Group (TVA 2013a). As a result, little if any GW movement is 

45 expected within the Conasauga Group in a west or east direction. Instead, GW within the 

46 Conasauga Group is expected to move parallel to the bedding planes (between the shale beds) 
Affected Environment

3-36

1 and within small fractures in a northeast or southeast direction and into Chickamauga Reservoir

2 (Julian 2007; TVA 2013a). West of SQN, the Conasauga Group is in contact with the Knox 

3 Group Aquifer. However, the potential for GW to move laterally across bedding planes is so low 

4 that significant GW movement from the Conasauga Group into the Knox Group is considered to 

5 be very unlikely. 

6 3.5.2.2 Groundwater Use

7 In the area around the SQN site, well yields are dependent on the local rock type (limestone or 

8 shale) and the location of joints, fractures, and faults. Well yields can be variable, ranging from 

9 less than one to several hundred gallons per minute. Where the conditions are favorable, the 

10 aquifer system is capable of supplying significant quantities of GW. In addition to supplying 

11 many small springs, the aquifer system also supplies Cave Springs, which is the second largest 

spring in East Tennessee. The average discharge for this spring is 17.5 cfs (0.5 m3 12 /s) 

13 (Haugh 2002). The primary GW user of this aquifer system is the Hixson Utility District, which is 

14 a local supplier of public water. Their well fields are located approximately 5.5 mi (8.9 km) and 

15 8.5 mi (14 km) southwest of SQN.

16 There are no GW supply wells on the SQN site or within a 1-mile (1.6-km) radius (from the plant 

17 center point) of the site. The Hixson Utility District supplies SQN with water for all plant potable 

18 water needs. In 2011, the SQN average monthly consumption of potable water was 

19 3.3 million gal (12.5 million L), or approximately 110,295 gpd (417,512 Lpd) (TVA 2013a). 

20 Potable water for the residential area around SQN is also supplied by Hixson Utility District 

21 (TVA 2013a). 

22 3.5.2.3 Groundwater Quality

23 The GW aquifers around SQN consist largely of dolomite and limestone rock. The GW quality 

24 in these aquifers is characterized as calcium bicarbonate and calcium magnesium bicarbonate 

25 (Pavlicek 1996). It is generally satisfactory for municipal supplies (TVA 2013a). Water obtained 

26 by these aquifers and delivered via the Hixson Utility District is of high quality (Chattanooga 

27 Times Free Press 2013, Hixson Utility District 2013, TAUD 2013). As discussed in 

28 Section 3.5.2.1, the Conasauga Group is not a good producer of GW at SQN. However, the 

29 little data on GW quality that is available states that the water at SQN in the Conasauga Group 

30 is generally good (TVA 2013a).

31 Tritium concentrations in GW above background levels have been detected near some of the 

32 plant structures at SQN. Tritium has been detected near the Unit 1 Refueling Water Storage 

33 Tank and near the Unit 2 Reactor Building. No ongoing leaks of tritium have been identified. 

34 Groundwater data from many wells and geoprobe borings, and data on past water spills, 

35 suggest the source of the tritium in the GW is from past inadvertent water spills that occurred on 

36 the land surface. These accidental spills were of limited areal extent and occurred close to the 

37 plant buildings. Eight water spills occurred from 1981 to 2006. Spills occurred near the 

38 Condensate Demineralizer Waste Evaporator Building, the Additional Equipment Building, the 

39 Auxiliary Building, the Refueling Water Storage Tank Moat Drain, and the Modularized Transfer 

40 Demineralization System (Julian 2007) (see Figure 3–6).
Affected Environment

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1 Figure 3–6. Locations of Inadvertent Liquid Releases Containing Tritium 

2 Source: Modified from Julian 2007 and TVA 2011b

.. .c~ .. -=~ ........... F~t 

0 62.5 125 250 

m Inadvertent Release Areas 
Affected Environment

3-38

1 Groundwater containing tritium greater than background has been detected in four wells located 

2 very close to plant structures. Their tritium concentrations are well below the EPA primary 

3 drinking water standard (DWS) of (20,000 pCi/L) (TVA 2013c). These wells monitor GW quality 

4 in the structural fill and soil. In addition to these wells, another well also located close to plant 

5 structures, but completed in the top of the underlying Conasauga Group, has tritium values that 

6 exceed background concentrations (Julian 2007). In this well (W-10), tritium has been detected 

7 at a concentration of 26,780 pCi/l (sample collected on May 1, 2013) (TVA 2013c). This 

8 exceeds the EPA DWS for tritium. In December 2011, water from this well was analyzed to 

9 determine the ratio of tritium (hydrogen-3) to helium-3 in the GW. From these ratios, the tritium 

10 was calculated to have last been in contact with the atmosphere 14 years (plus or minus 

11 6 years) ago (TVA 2013c). This age agrees reasonably well with the record of past spills and 

12 supports TVA’s assertion the source of tritium is from historical water spills and not from 

13 ongoing activities.

14 TVA is actively involved in monitoring the extent of contamination. In 2007, the nuclear power 

15 industry began implementing its “Industry Ground Water Protection Initiative” (NEI 2007). Since 

16 2008, the NRC staff has been monitoring implementation of this initiative at licensed nuclear 

17 reactor sites. The initiative identifies actions to improve management and response to 

18 instances in which the inadvertent release of radioactive substances may result in low but 

19 detectible levels of plant-related materials in subsurface soils and water. Results from SQN GW

20 monitoring are reported annually to the NRC (TVA 2010, 2011a, 2012, 2013b). 

21 3.6 Terrestrial Resources

22 3.6.1 SQN Ecoregion

SQN lies within the ridge and valley ecoregion, which occupies 44,589 km2 (17,216 mi2 23 ) of land 

24 from the southeastern corner of New York to northeastern Alabama. The ridge and valley 

25 ecoregion is long and narrow, extending 1,600 km (995 mi). Roughly parallel ridges and 

26 lowland valleys characterize most of the area and are the result of extreme folding and faulting 

27 geological events. The predominant land cover in the ecoregion includes forests (56 percent), 

28 agricultural land (30 percent), and developed areas (9 percent). Although developed land is 

29 less prominent than forests and agricultural land, from 1973 to 2000, the percent of developed 

30 land has increased 1.4 percent, while the percent of forested and agricultural land has 

31 decreased (USGS 2012).

32 3.6.2 SQN Site and Vicinity

33 The SQN site is located along the Chickamauga Reservoir. The primary terrestrial habitats on 

34 the site include forests, grasslands, wetlands, and scrub-shrub habitats (see Table 3–5 and 

35 Figure 3–7).

36 The SQN site is composed of two peninsulas. The larger peninsula is mostly developed and 

37 includes the plant buildings and infrastructure surrounded primarily by grass fields. A small strip 

38 of forested habitat borders the Chickamauga Reservoir. The smaller peninsula consists mostly 

39 of a mix of evergreen and deciduous forest habitat.
Affected Environment

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1 Table 3–5. Primary Land Cover on the SQN Site

Land Cover Percent

Developed or Cleared Land Cover

Barren (rocks, sand, clay) 31

Developed (open) 2

Developed (improvements) 6

Undeveloped Land Cover

Forest (Deciduous) 6

Forest (Evergreen) 10

Forest (Mixed) 7

Grassland 17

Scrub-shrub 9

Open Water 8

Pasture 2

Wetlands 1

Note: Total percentage does not add to 100 because of rounding.

Source: TVA 2013n
Affected Environment

3-40

1 Figure 3–7. Land Cover at the SQN Site

2 

3 Source: TVA 2013n

4 3.6.2.1 Summary of Past SQN Surveys and Reports Within the Site and Vicinity

5 The TVA (1974) conducted site surveys of the SQN site and vicinity as part of the construction 

6 permit application for SQN Units 1 and 2. These initial site surveys included an assessment of 

7 terrestrial plant communities. The TVA (1974) review did not specify survey methodology, 
Affected Environment

3-41

1 although TVA (2013n) assumed that the surveys were conducted on site with additional data 

2 extracted from a 1969 Bradley–Hamilton County survey (TVA 1969).

3 In 2010, TVA staff and contractors (TVA staff) conducted a walkdown of the site to identify 

4 general plant populations along fence rows, roadsides, and lawns (TVA 2011c). The TVA 

5 walkdown also noted birds and other wildlife observed. In addition, TVA staff conducted a 

6 desktop review of natural areas (such as wildlife management areas). On March 27, 2013, TVA 

7 staff conducted a follow-up study and surveyed nest sites within 6 mi (10 km) of SQN 

8 (TVA 2013f).

9 These surveys are the primary sources for describing the terrestrial resources at SQN. To 

10 supplement such surveys, the NRC staff conducted an environmental site visit and a desktop 

11 review of other natural resource databases and surveys within the vicinity of SQN, such as 

12 FWS 2013a, Henry 2011, and TDEC 2013b. 

13 3.6.2.2 Vegetation

14 Common Vegetation

15 Before construction, 93 percent of the SQN property was forested, including 54 percent pine, 

16 32 percent pine–hardwood, and 7 percent hardwood (TVA 1974). The remaining portions of the 

17 peninsula included pasture (3 percent), old field (2 percent), and transmission right-of-ways 

18 (2 percent) (TVA 1974). Construction of the SQN plant converted approximately 525 ac

19 (212 ha) of terrestrial habitat, including mixed hardwood forest, pine forest, pasture, and old 

20 fields, into buildings, parking lots, landscaped areas, and other industrial uses. Both before and 

21 after construction of the SQN plant, agricultural and private land development activities have 

22 disturbed forests and other vegetation at and surrounding the plant (TVA 2013n).

23 TVA (1974) concluded that common tree assemblages on the SQN site include evergreens, 

24 such as shortleaf pine (Pinus echinata) and Virginia pine (Pinus virginiana), and hardwoods, 

25 such as oaks (Quercus spp.), hickories (Carya spp.), beech (Fagus spp.), and other typical 

26 ridge and valley deciduous species. During the January 2010 SQN site walkdown, TVA 

27 observed similar common tree species, such as shortleaf pine and Virginia pine (TVA 2013n). 

28 TVA also recorded common flowering plant and grass species, including Japanese honeysuckle 

29 (Lonicera japonica), trumpet creeper (Campsis radicans), various unnamed lawn species, and 

30 weedy species such as crabgrass (Digitaria spp.). TVA (2011c) concluded that the types of 

31 plants currently existing on the SQN site are typical of hardy species that can tolerate

32 environmental conditions near industrial facilities. 

33 As part of the ER for the 2009 power uprate (TVA 2009c), TVA characterized common invasive 

34 species found on the SQN site. Observed invasive species included Chinese privet (Ligustrum 

35 sinense), Japanese honeysuckle, Japanese stilt grass (Microstegium vimineum), multiflora rose 

36 (Rosa multiflora), and Chinese bush clover or sericea lespedeza (Lespedeza cuneata).

37 TVA (1974) conducted a field survey of dominant vegetation within the vicinity of SQN. The 

38 studies indicated that dominant tree species included the following: white oak (Q. alba), post 

39 oak (Q. stellata), black oak (Q. velutina), southern red oak (Q. falcata), shagbark hickory 

40 (Carya ovata), mockernut hickory (Carya tomentosa), yellow poplar (Liriodendron tulipifera), and 

41 American beech (F. grandifolia).

42 Wetlands

43 TVA (2013n) determined the presence of wetlands on the SQN site and in the vicinity of SQN by 

44 examining U.S. Department of Agriculture (USDA) land cover maps and National Wetland 

45 Inventory maps. Wetlands compose approximately 1 percent of the SQN site. The majority of 

46 the wetlands occur on the edge of the site adjacent to the Chickamauga Reservoir. The
Affected Environment

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1 U.S. Fish and Wildlife Service (FWS) (FWS 2013a) classifies these wetlands as lacustrine, 

2 which means that the wetlands occur in a topographic depression or a dammed river channel; 

3 trees, shrubs, or other persistent vegetation is less than 30 percent of the areal coverage; and 

4 the total area exceeds 8 ha (20 ac). In addition to the lacustrine wetlands, a single, 0.88-ac 

5 (0.35-ha) wetland occurs on the north side of the SQN site. The FWS (2013a) classifies this

6 wetland as palustrine scrub or shrub, or a nontidal wetland with woody vegetation that includes 

7 woody shrubs, young trees, or trees with stunted growth. The FWS (2013a) also classifies 

8 several onsite ponds as palustrine (nontidal), unconsolidated bottom, and permanently flooded 

9 habitats. These ponds are described in the aquatic resources section of this SEIS.

10 Additional wetlands occur within the vicinity (6 mi (10 km)) of SQN, including freshwater forested 

11 and scrub-shrub wetlands and freshwater emergent wetlands (FWS 2013a; TVA 2013n). These 

12 wetlands primarily occur along the Chickamauga Reservoir or its tributaries.

13 State-Listed Vegetation

14 This section discusses plant species protected only by the State, and Section 3.8 discusses 

15 those species protected under the Endangered Species Act of 1973, as amended (ESA), alone 

16 or in combination with the State. Table 3–6 identifies the 23 plants that are considered 

17 threatened or endangered by the State of Tennessee within Hamilton County. Within 6 mi 

18 (10 km) of SQN, one State endangered, one State threatened, and five species of special 

19 concern have been identified (TDEC 2013b; TVA 2011c). Plant species of special concern

20 include species or subspecies that are uncommon or have unique or very specific habitat 

21 requirements or scientific value. The seven species identified within 6 mi (10 km) of SQN are 

22 described below, including where the species was observed in relation to SQN.
Affected Environment

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1 Table 3–6. State-listed Plant Species in Hamilton County

Scientific Name Common Name

State of 

Tennessee 

Status Habitat

Nonvascular Plants

Lejeunea sharpii Sharp’s lejeunea Endangered Calcareous bluffs, rock 

& logs of wet sinks

Vascular Plants

Clematis fremontii Fremont’s virgin’s-bower Endangered Limestone barrens

Clematis glaucophylla White-leaved leatherflower Endangered Wooded stream banks

Delphinium exaltatum Tall larkspur Endangered Glades and barrens

Diamorpha smallii Small’s stonecrop Endangered Sandstone outcrops

Diervilla lonicera Northern bush-honeysuckle Threatened Rocky woodlands and 

bluffs

Diervilla sessilifolia var.

rivularis Mountain bush-honeysuckle Threatened Dry cliffs and bluffs

Gratiola floridana Florida hedge-hyssop Endangered Wooded swamps

Lilium canadense Canada lily Threatened Rich woods and seeps

Lilium philadelphicum Wood lily Endangered Dry openings, 

powerlines

Lonicera flava Yellow honeysuckle Threatened Rocky woods and 

thickets

Lysimachia fraseri Fraser’s loosestrife Endangered Dry open woods

Nestronia umbellula Nestronia Endangered Upland woods

Phemeranthus mengesii Menge’s fameflower Threatened Dry rock ledges

Phemeranthus teretifolius Roundleaf fameflower Threatened Dry sandy rock 

outcrops

Ribes curvatum Granite gooseberry Threatened Rocky woods

Sabatia capitata Cumberland rose gentian Endangered Dry open woods, 

powerlines

Silphium laciniatum Compass plant Threatened Barrens

Silphium pinnatifidum Southern prairie-dock Threatened Barrens

Solidago ptarmicoides Prairie goldenrod Endangered Barrens

Stylisma humistrata Southern morning-glory Threatened Dry piney woods

Trillium lancifolium Narrow-leaved trillium Endangered Alluvial woods and 

moist ravines

Trillium rugelii Southern nodding trillium Endangered Rich mountain woods

Source: TDEC 2013b 

2 Southern Prairie-Dock (Silphium pinnatifidum)

3 Southern prairie-dock, a State threatened species, was identified in 2011 on private property 

4 less than 4 mi (6 km) from SQN (TVA 2013f). Southern prairie-dock grows in areas exposed to 

5 full sun and with average to poor soil. This perennial plant is relatively tall and grows as high as 

6 3 m (10 ft). When in bloom, southern prairie-dock can be identified by its large flower heads 

7 with yellow ray and disc flowers (USDA 2004).
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1 Tall Larkspur (Delphinium exaltatum)

2 Tall larkspur, a State endangered species, was observed historically from an area less than 6 mi 

3 (10 km) from SQN; the last sighting was in 1939 (TVA 2011c). Tall larkspur is a herbaceous 

4 perennial plant that belongs to the buttercup family. In Tennessee, primary habitat includes 

5 ridge and valley cedar barrens on thin cherty loam over limestone (dolomite). However, the 

6 plant has also been observed within oak-cedar woods, mixed pine-cedar woodlands, and 

7 disturbed areas (e.g., powerlines, roadsides, and pastures) that provide similar habitat as 

8 barrens (NatureServe 2013f).

9 Pink Lady’s Slipper (Cypripedium acaule)

10 Pink lady’s slipper, a species of special concern, was observed in 2007 approximately 6 mi 

11 (10 km) from SQN (TVA 2011c). Pink lady’s slipper is an orchid that requires bees for 

12 pollination. This species lives in a variety of habitats, including mixed hardwood coniferous

13 forests of pine and hemlock and in deep humus and acidic but well-drained soil near birch and

14 other deciduous trees (USDA 2011).

15 Fragrant Bedstraw (Galium uniflorum)

16 Fragrant bedstraw, a State species of concern, was identified in 1997 approximately 6 mi 

17 (10 km) from the SQN site (TVA 2011c). Fragrant bedstraw is a perennial forb.

18 Gibbous Panic-grass (Sacciolepis striata)

19 Gibbous panic-grass, a species of special concern, was identified approximately 1.5 mi (2 km) 

20 from SQN in 1985 (TVA 2011c). Gibbous panic-grass grows within wetlands, although suitable 

21 habitat does not occur on the SQN site (TVA 2013n).

22 Ovate-Leaved Arrowhead (Sagittaria platyphylla)

23 Ovate-leaved arrowhead, a species of special concern, was observed in 1980 approximately

24 6 mi (10 km) from SQN (TVA 2011c). Ovate-leaved arrowhead is a rhizomatous aquatic plant. 

25 It can grow up to 5 ft (1.5 m) (NBII and ISSG 2006).

26 American Ginseng (Panax quinquefolius)

27 American ginseng, a commercially exploited State species of concern, was observed in 2007 

28 approximately 6 mi (10 km) from the SQN site (TVA 2011c). This perennial plant grows 

29 primarily in moist woods under a closed canopy (NatureServe 2013f).

30 3.6.2.3 Wildlife

31 Common Wildlife

32 The SQN site provides several types of terrestrial habitats for birds, mammals, and other 

33 wildlife. For example, shoreline along the Chickamauga Reservoir is used extensively by birds 

34 and waterfowl. During periods of reservoir drawdown, exposed mudflats along the shoreline 

35 provide several important food sources for birds, such as aquatic invertebrates (Henry 2011). 

36 Plant communities that develop along the shoreline also provide an important source of food 

37 and refuge for birds. The combination of food, protection, and other resources available make 

38 the Chickamauga Reservoir an important habitat for many birds and wildlife. In addition, the 

39 reservoir is part of the Mississippi flyway, an important stopover location for many birds, 

40 including sandhill cranes (Grus canadensis) (TVA 2013n; TWRA 2013b).

41 Farther inland, wetlands occur within continually or regularly flooded areas, which provides food 

42 and shelter for a variety of birds, amphibians, and wildlife. Forested areas also occur on the 

43 SQN site, as described above. Because of the limited size of the SQN site and surrounding 
Affected Environment

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1 development, most wildlife species that occur on the SQN site are those that are relatively 

2 tolerant of semiurban conditions.

3 Several important terrestrial habitats occur within the vicinity of SQN. As described above, this 

4 area is part of the Mississippi flyway, used by migrating birds as important stopover points 

5 during long seasonal migrations. High-quality bird habitats within the region surrounding SQN 

6 include Soddy Mountain, Hiwassee National Wildlife Refuge, Harrison Bay State Park, and 

7 Chester Frost Park (Henry 2011; TVA 2013n; TWRA 2013b).

8 Another relatively unique and important habitat within 6 mi (10 km) of SQN is three caves 

9 (TVA 2011c). Caves provide a unique habitat because of the combination of geologic 

10 requirements and environmental conditions created inside caves. The Tennessee cave 

11 salamander (Gyrinophilus palleucus) typically occurs within caves in Hamilton County.

12 Table 3–7 describes the most common or abundant birds, mammals, reptiles, and amphibians 

13 on the SQN site and within the vicinity.

14 Table 3–7. Most Common or Abundant Wildlife on or Within the Vicinity of the SQN Site

Birds

Passerines (Songbirds)

American crow

(Corvus brachyrhynchos)

northern cardinal

(Cardinalis cardinalis)

American robin

(Turdus migratorius)

sedge wren

(Cistothorus platensis)

eastern bluebird

(Sialia sialis)

tree swallow

(Tachycineta bicolor)

marsh wren

(Cistothorus palustris)

Waterfowl (Ducks and Geese)

black duck

(Anas rubripes)

hooded merganser

(Lophodytes cucullatus)

Canada goose

(Branta canadensis)

mallard

(Anas platyrhynchos)

gadwall

(Anas strepera)

wood duck

(Aix sponsa)

green-winged teal

(Anas crecca)

Birds of Prey (Eagles, Hawks, Ospreys, and Vultures)

bald eagle

(Haliaeetus leucocephalus)

red-tailed hawk

(Buteo jamaicensis)

black vulture

(Coragyps atratus

sharp-shinned hawk

(Accipiter striatus)

broad-winged hawk

(Buteo lineatus)

turkey vulture

(Cathartes aura)

osprey

(Pandion haliaetus)
Affected Environment

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Other Nonpasserine Birds

great blue heron

(Ardea herodias)

sandhill crane

(Grus canadensis)

gull

(Larus spp.)

turkey

(Meleagris gallopavo)

killdeer

(Charadrius vociferous)

whooping crane

(Grus americana)

Mammals

coyote

(Canis latrans)

least shrew

(Cryptotis parva)

eastern cottontail

(Sylvilagus floridanus)

North American beaver

(Castor canadensis)

eastern mole

(Scalopus aquaticus)

striped skunk

(Mephitis mephitis)

eastern Virginia opossum

(Didelphis virginiana) 

whitetail deer

(Odocoileus virginianus)

hispid cotton rat

(Sigmodon hispidus)

Reptiles and Amphibians

American toad

(Bufo americanus)

Tennessee cave salamander

(Gyrinophilus palleucus)

Fowler’s toad

(Bufo fowleri)

upland chorus frog

(Pseudacris feriarum)

northern cricket frog

(Acris crepitans)

Sources: Henry 2011; TVA 2009c, 2011c, 2013n, 2013f; TWRA 2013b, 2013c, 2013d, 

2013e

1 State-Listed and Other Important Wildlife

2 This section discusses bird, mammal, and reptile species protected only by the State, the Bald 

3 and Golden Eagle Protection Act, and the Migratory Bird Treaty Act. Section 3.8 discusses 

4 those species protected under the ESA alone or in combination with the State.

5 Birds

6 Table 3–8 identifies the three birds that are considered threatened or endangered by the State 

7 of Tennessee within Hamilton County.

8 Neither the Bachman’s sparrow (Aimophila aestivalis) nor the Bewick’s wren (Thryomanes 

9 bewickii) are likely to occur at SQN because of a lack of available habitat.
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1 Table 3–8. State-Listed Bird Species in Hamilton County

Scientific Name Common Name State of 

Tennessee Status Habitat

Aimophila aestivalis Bachman’s sparrow Endangered

Dry open pine or oak woods; 

nests on the ground in dense 

cover

Falco peregrinus peregrine falcon Endangered

Varied habitats, including 

farmlands, marshes, river 

mouths, and cities; often nests 

on ledges

Thryomanes bewickii Bewick’s wren Endangered

Brushy areas, thickets and 

scrub in open country, open and 

riparian woodlands

Source: TDEC 2013b 

2 Peregrine falcons (Falco peregrinus) are medium-sized hawks and have the potential to occur 

3 at or near SQN. The FWS removed the peregrine falcon from the Federal list of endangered 

4 species in 1999 (64 FR 46542). However, it is still considered endangered by the State of 

5 Tennessee (TDEC 2013b). Peregrine falcons are present in a variety of habitats, including 

6 large cities. They eat birds and small mammals. Peregrine falcons nest in loose material on a 

7 cliff or the ledge of a building in an area with a protective overhang. They prefer sites that are 

8 100 ft (30 m) or higher (TWRA 2013c). A nest in Hamilton County was active below 

9 Chickamauga Dam until 2007 (TWRA 2013c). Because peregrine falcons are present along the 

10 Tennessee River and known to nest on ledges, there is a potential for them to be present at the 

11 SQN site. In April 2013, the NRC staff observed that TVA had taken steps to ensure permanent 

12 structures, including buildings and equipment regarded as suitable falcon nesting sites, were 

13 equipped with structures that would deter nest building.

14 The State of Tennessee lists seven bird species in Hamilton County as “deemed in need of 

15 management” (TDEC 2013b). Of these seven species, barn owls (Tyto alba), sharp-shinned 

16 hawks (Accipiter striatus), and bald eagles (Haliaeetus leucocephalus) have been observed 

17 along the Chickamauga Reservoir near the SQN site. Bald eagles are also protected under the 

18 Bald and Golden Eagle Protection Act and are discussed later in this section.

19 The State of Tennessee lists four additional Hamilton County bird species as “deemed in need 

20 of management” (TDEC 2013b) that have not been observed on the SQN site or within 6 mi 

21 (10 km):

22 • Swainson’s warbler (Limnothylpis swainsonii), 

23 • least bittern (Ixobrychus exilis), 

24 • king rail (Rallus elegans), and

25 • golden-winged warbler (Vermivora chrysoptera).

26 Species Protected Under the Bald and Golden Eagle Protection Act

27 The Bald and Golden Eagle Protection Act of 1940, as amended (16 U.S.C. §668-668c), 

28 prohibits anyone from taking bald or golden eagles (Aquila chrysaetos), including their nests or 

29 eggs, without a permit issued by the FWS. The Act defines the word “take” to mean, among 

30 other things, to pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, destroy, 

31 molest, or disturb (50 CFR 22.3). The Act defines the word “disturb” to mean, among other 
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1 things, to take action that (1) causes injury to an eagle or (2) decreases its productivity or nest 

2 abandonment, by substantially interfering with breeding, feeding, or sheltering behavior 

3 (50 CFR 22.3).

4 Bald eagles have been observed downstream of the SQN site near Harrison Bay State Park 

5 and Chester Frost Park, as well as other locations along the Tennessee River and its tributaries 

6 (eBird 2013; TWRA 2013d). A bald eagle nest was observed approximately 1 mi (1.6 km) from 

7 the site during 2006. Although the nest was not present during the survey completed in 2013, it 

8 is possible that in the future a pair of bald eagles will nest near the site (TVA 2013f).

9 Species Protected Under the Migratory Bird Treaty Act

10 The Migratory Bird Treaty Act of 1918, as amended (16 U.S.C. §§703–712, herein referred to as 

11 MBTA), is administered by the FWS. The Act prohibits anyone from taking native migratory 

12 birds, their eggs, feathers, or nests. The MBTA defines “take” to mean to pursue, hunt, shoot, 

13 wound, kill, trap, capture, or collect, or any attempt to carry out these activities (50 CFR 10.12). 

14 However, “take” does not include habitat destruction or alteration. All Tennessee State listed 

15 species shown in Table 3–8 are protected under the MBTA.

16 Mammals

17 Three mammals are listed by the State of Tennessee as being “deemed in need of 

18 management”: the Allegheny woodrat (Neotoma magister), the smoky shrew (Sorex fumeus), 

19 and the southeastern shrew (S. longirostris). This classification is analogous to the category 

20 “special concern” discussed above for plants. None of these mammals have been reported 

21 near the SQN site (TVA 2013f).

22 Reptiles

23 The eastern slender glass lizard (Ophisaurus attenuatus longicaudus) is listed by the State as 

24 “deemed in need of management.” A legless lizard, it is approximately 13 in. (33 cm) from the 

25 head to the base of the tail, or up to 41.9 in. (106 cm) including the tail (NPS 2013). The 

26 eastern slender glass lizard is rarely seen. They are found in dry soil or on dry grassy areas 

27 (VDGIF 2013), often in open areas such as powerline right-of-ways, fields, and open woods 

28 (NPS 2013), and occasionally in vacant lots or farms (TWRA 2013e). They burrow in sandy 

29 soils and live in old rodent burrows or under grass mats (VDGIF 2013).

30 3.6.3 Transmission Line Corridors

31 Section 3.1.6.5 describes the transmission lines under consideration in this SEIS as those that 

32 connect the nuclear power plant to the switchyard where electricity is fed in to the regional 

33 distribution system (NRC 2013c). For SQN, the 500-kV and 161-kV switchyards serve this 

34 purpose (TVA 2013f). The switchyards are adjacent to Units 1 and 2 and within the protected 

35 area of SQN (see Figure 3–3). Therefore, the above discussion of the affected terrestrial 

36 environment for the SQN site is representative of the affected environment for these 

37 transmission lines.

38 3.7 Aquatic Resources

39 3.7.1 Description of the Tennessee River

40 The only aquatic community in the vicinity of the SQN site is the Tennessee River. The 

Tennessee River drains an area of approximately 105,000 km2 (40,540 mi2 41 ) in portions of 

42 Virginia, North Carolina, Tennessee, Georgia, Alabama, Mississippi, and Kentucky. TVA

43 constructed a series of impoundments from the 1920s through the 1960s that altered the 
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1 character of the Tennessee River Valley (TVA 2013n). Chickamauga Dam, completed in 1940 

2 by TVA, impounded the river to create the Chickamauga Reservoir, which is proximate to the 

3 SQN site (TVA 1974). A total of 49 dams and reservoirs in the Tennessee and Cumberland 

4 watersheds are owned or operated by TVA, 9 of which are located on the main stem of the 

5 Tennessee River (TVA 2013n).

6 According to Etnier and Starnes (1993), “Tennessee has the richest freshwater fauna of any of 

7 the United States” and further, that “the richest fish fauna are from the Tennessee and 

8 Cumberland drainages.” Parmalee and Bogan (1998) find that the Tennessee River and its 

9 tributaries “harbored the most diverse and abundant assemblage” of freshwater mussels known 

10 in historic times. Impoundment of the river and the subsequent habitat loss, pollution, and 

11 introduced species have greatly altered the diversity of the mussels and fish, however, and 

12 changed the ecosystem processes in the Tennessee River system (White et al. 2005). White

13 et al. (2005) provide examples of these processes, including the loss of “shallow shoals, large 

14 snags and accumulations of woody debris,” which affect benthic ecosystem processes and 

15 make the water chemistry of the river more dependent on releases from upstream. 

16 The assemblage of organisms living in the river has changed in response to the impoundments 

17 that have produced conditions that allow nonnative species to invade and proliferate. Species 

18 that were not able to adapt to the new conditions have been and are being decimated, 

19 extirpated, or driven to extinction. According to Parmalee and Bogan (1998), only one-third of 

20 the 130 species of freshwater mussels known to occur or to have occurred in Tennessee are 

21 considered stable. For example, all 11 species of the unionid mussel genus Epioblasma that 

22 inhabited the shoal and riffle areas in the Tennessee River and its tributaries are now extinct 

23 (Parmalee and Bogan 1998). Parmalee and Bogan attribute these extinctions directly or 

24 indirectly to impoundment. According to Neves and Angermeier (1990), obligatory riverine

25 species, those that require riverine habitat for at least part of their life history, typically do not 

26 survive in reservoirs. Further, Neves and Angermeier (1990) report that even though fish 

27 sampling on the Tennessee River was not extensive in the years before construction of the 

28 dams began (late 1930s), enough surveys were conducted to document the adverse effects of 

29 impoundment on native fish species. For example, fish surveys conducted before and after the 

30 impoundment of Melton Hill Reservoir, located in East Tennessee upstream of the Watts Bar 

31 Dam on the Clinch River, demonstrate a shift in the fauna—species requiring shoal and riffle 

32 habitats that were present before impoundment were no longer present in the postimpoundment 

33 surveys. Such adverse impacts have been extensive, and Neves and Angermeier found that 

34 “[t]here is little doubt that the integrity of the resident fish fauna of these rivers [the Tennessee 

35 River and its tributaries] and their associated drainages has been and will be compromised by 

36 such extensive alterations of habitat.” 

37 White et al. (2005) summarized one aspect of the problem as follows: 

38 Because reservoirs create ecosystem conditions that did not exist previously in 

39 the basin, conceptually these are “new” ecosystems...Although most species 

40 occurred in the system prior to impoundment the dominant species now are 

41 those adapted to the new set of environmental conditions. 

42 Further, the impoundments created good reservoir fisheries for sport and commercial fishermen. 

43 This, in turn, contributed to the change in composition of the aquatic biota. According to Etnier 

44 and Starnes (1993), resource managers and others, whether purposely or accidentally, 

45 introduced other species (including nuisance species) into the system. These species include 

46 carp (various species, including Cyprinus carpio, Ctenopharyngodon idella, and

47 Hypophthalmichthys spp.), striped bass (Monrone saxatilis), yellow perch (Perca flavescens), 

48 and possibly the threadfin shad (Dorosoma petenense) (Etnier and Starnes 1993). Nuisance 

49 species (i.e., nonnative species whose introduction causes, or is likely to cause, economic or 
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1 environmental harm) include Eurasian water milfoil (Myriophyllum spicatum), spiny leaf naiad 

2 (Najas minor), hydrilla (Hydrilla verticillata), zebra mussels (Dreissena polymorpha), and Asiatic 

3 clams (Corbicula fluminea) (TWRA 2008). These species and their potential effect on the native 

4 aquatic biota are discussed in detail later in this section.

5 3.7.2 Description of Chickamauga Reservoir 

6 The SQN site is on the western shore of the Chickamauga Reservoir at Tennessee 

7 River Mile (RM) 484.5. The Chickamauga Reservoir extends approximately 59 mi (95 km) from 

8 Chickamauga Dam (Tennessee RM 471) to Watts Bar Dam (Tennessee RM 529.9). 

9 The characteristics of the reservoir at different locations (e.g., water velocity, water depth and 

10 temperature, substrate, aquatic vegetation) determine, to a large degree, the types of and 

11 relationships among the organisms in these locations. Reservoirs on the Tennessee River main 

12 stem are divided into three functional zones based on hydrology and limnology characteristics: 

13 riverine, transitional, and lacustrine (White et al. 2005). The riverine zone in Chickamauga 

14 Reservoir is located at the inflow of Watts Bar Dam, upstream of the SQN site. This zone has 

15 characteristics similar to those of a river, although the flows are variable depending on releases 

16 from upstream dams. The riverine zone tends to have higher turbidity, swifter water velocities, 

17 and sand and gravel river bottoms. The transitional zone in Chickamauga Reservoir is located 

18 midreservoir, and has slower water velocity, and bottom substrates that are mixed sand, gravel, 

19 and organic deposits. The lacustrine zone, also called the forebay, is a lake-like area where 

20 water amasses behind a downstream dam (Chickamauga Dam). The bottom substrate of 

21 lacustrine zones in the Chickamauga Reservoir is commonly composed of clay deposits with 

22 low organic content. 

23 The SQN site is located where the Chickamauga Reservoir changes from a transitional zone to 

24 a lacustrine zone. TVA (Simmons 2011) characterized substrates in the sampling areas 

25 upstream and downstream of the site in the autumn of 2009. The three most dominant 

26 substrate types upstream of the site (centered at Tennessee RM 490.5) were silt (51.2 percent), 

27 mollusk shell (18.4 percent), and bedrock (8.8 percent). The downstream sites (centered at 

28 Tennessee RM 482.0) were composed of mollusk shells (27.6 percent), silt (19.9 percent), and 

29 clay (16.4 percent). However, TVA (Simmons 2011) reported that the overall average water 

30 depths at the sampling sites upstream and downstream of the SQN site were similar. Depths at 

31 the sampling locations ranged from 27 to 44.7 ft (8.2 to 13.6 m) at the downstream transects 

32 and 26.1 to 34.9 ft (8.0 to 10.6 m) at the upstream transect. Actual depths in the river at these 

33 locations range from 7.4 to 78.5 ft (2.3 to 23.9 m) at the downstream transect and 6.4 to 55.2 ft 

34 (2.0 to 16.8 m) at the upstream transect (Simmons 2011). Most TVA impoundments suffer 

35 depletion of dissolved oxygen and have characteristics similar to eutrophic lakes, which renders 

36 the environment inhospitable to many species, including many freshwater mussels. In summer 

37 and autumn of 2011, dissolved oxygen readings tended to be higher at the downstream 

38 sampling location than at the upstream location (Simmons 2011), which would not be the case if 

39 the SQN effluent was depleting dissolved oxygen levels and encouraging eutrophication. 

40 3.7.2.1 Habitat and Biological Communities

41 The following sections describe the habitat and aquatic organisms of Chickamauga Reservoir in 

42 the vicinity of the SQN site. Figure 3–8 depicts a typical food web for this location and illustrates 

43 the connectivity of aquatic resources.
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1 Figure 3–8. Typical Food Web for the Chickamauga Reservoir (Showing Fish by Trophic 

2 Group)

3 Plankton

4 Plankton are small plants or animals that float, drift, or weakly swim in the water column of any 

5 body of water. There are two main categories of plankton: phytoplankton and zooplankton. 

6 Phytoplankton contain chlorophyll and require sunlight to live and grow. Zooplankton are small 

7 microscopic animals. In addition to other ecological services, phytoplankton and zooplankton 

8 form the basis of many aquatic food webs. Many types of zooplankton feed on phytoplankton 

9 and then become the primary source of food for other invertebrates and larval fish (White 

10 et al. 2005). As a result, plankton plays key ecosystem roles in the distribution, transfer, and 

11 recycling of nutrients and minerals. 

12 In general, the density of plankton in Chickamauga Reservoir increases from upstream to 

13 downstream during normal water flows (TVA 1990). Tennessee main stem reservoirs have a 

14 spring diatom (a type of phytoplankton) peak in late March to early April. White et al. (2005) 

15 report that water velocity and turbidity are high in the upper part of each reservoir and, as a 

16 result, primary productivity (growth of phytoplankton) is low. Further downstream in the 

17 reservoir, water velocity and turbidity decrease and primary productivity may be high during the 

18 early spring if enough nitrogen and phosphorus are available for algae growth. By early 

19 summer, the nitrogen and phosphorus concentrations are usually too low to measure in the 

20 water column, and less algal growth occurs. By midsummer the dominant phytoplankton are 

21 green algae, diatoms, and cyanobacteria (White et al. 2005). Because very little primary or 

22 secondary production occurs in the bottom sediments, most of the fixed carbon (i.e., inorganic 

23 carbon that has been fixed by photosynthesis into organic compounds and typically is part of 
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1 living organisms and detritus) likely moves through the dams or is metabolized in the water 

2 column.

3 Smaller zooplankton (including small planktonic crustaceans such as Bosmina longirostris and 

4 Daphnia retrocurva) quickly consume the spring diatom peak. In turn, these smaller 

5 zooplankton are consumed by other organisms including larger zooplanktonic crustaceans, 

6 such as copepods, or by mollusks, aquatic insects, and various larval fish.

7 Surveys of phytoplankton and zooplankton were conducted between 1980 and 1985 

8 (Dycus 1986), in 1986, 1987, and 1988 with altered protocols (TVA 1989), in 1989 (TVA 1990), 

9 and, most recently, in 2011 (TVA 2012c). The 2011 study characterized phytoplankton in the 

10 vicinity of the SQN site and found that cyanophytes (formerly known as blue-green algae) were 

11 the numerically dominant taxa in the summer, comprising 96 to 99 percent of the 

12 67 phytoplankton species identified. Diatoms (bacillariophytes) were the numerically dominant 

13 taxa in autumn and the group with the greatest biovolume in both summer and autumn 

14 (TVA 2012c). Cryptophytes (mostly genus Cryptomonas) were the next dominant 

15 phytoplankton taxa in autumn. The 2011 study identified 35 zooplankton taxa, of which 

16 cladocerans, copepods, and rotifers were the dominant groups (TVA 2012c).

17 The TVA surveys conducted in the 1980s noted reduced phytoplankton cell densities (but not 

18 changes in the composition of the plankton community) in samples taken downstream of the 

19 diffuser at Tennessee RM 483.4. These reductions occurred during times when the plant 

20 entrained at least 10 percent of the river flow and had a buoyant heated discharge (Dycus 1986; 

21 TVA 1989). TVA (1989) suggested that this reduction was likely due to the withdrawal and 

22 subsequent discharge of water drawn from below the skimmer wall. This water has lower 

23 phytoplankton cell densities, which are lowered further due to passage through the plant. The 

24 discharge water has reduced cell densities where it is reintroduced into the reservoir.

25 These observations were supported in the 2011 study (TVA 2012c), which showed a reduction 

26 in phytoplankton density in the vicinity of the discharge structure (Tennessee RM 483.4) but no 

27 changes in community composition. The study also showed that just over 2 mi (3 km)

28 downstream from the diffuser, at Tennessee RM 481.1, the levels increased to be similar to 

29 those found at the upstream sampling location (Tennessee RM 490.5). Reductions in 

30 zooplankton have also been observed. These reductions are, in part, due to passage through 

31 the SQN cooling system (which is harder on the softer-bodied zooplankton than it is on the 

32 phytoplankton, such as diatoms). TVA (2012c) postulates that the reduction in zooplankton and 

33 phytoplankton at the site is partially due to the complex hydrology of the area caused by the 

34 original channel morphology and complicated by the addition of the dam across the main river 

35 channel.

36 Aquatic Macrophytes

37 Aquatic macrophytes include vascular aquatic plants (i.e., plants with true stems, roots, and 

38 leaves), mosses, and some large algae. Tennessee Wildlife Resources Agency (TWRA 2008) 

39 reports that introduced or nonnative species of aquatic macrophytes make up the most 

40 abundant aquatic plant species in the Tennessee River, which include exotic or nonnative 

41 species such as Eurasian water milfoil, spiny leaf naiad, and hydrilla. In addition, alligatorweed 

42 (Alternanthera philoxeroides), a vascular plant that roots in bottom sediments, and Asian 

43 spiderwort (Murdannia keisak) have been found in Chickamauga Reservoir (TWRA 2008). 

44 Aquatic plants provide benefits (e.g., food and cover) for waterfowl, fish, and smaller organisms 

45 and reduce wave action, filter sediments suspended in the water, add oxygen to the water, and 

46 help protect shorelines from erosion. TVA (Scott 1993) monitored the population trends of fish 

47 and aquatic macrophytes in Chickamauga Reservoir and observed temporal changes in fish 
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1 populations, including an increase in abundance of certain species. Fish species positively 

2 affected by increased vegetation include midwater species that feed on insects (e.g., bluegill 

3 (Lepomis macrochirus), brook silverside (Labidesthes sicculus), yellow bass (Morone 

4 mississippiensis), black crappie (Pomoxis nigromaculatus), warmouth (Lepomis gulosus), 

5 golden shiner (Notemigonus crysoleucas), and yellow perch). Fish species that feed in the 

6 shallow, silted overbank areas decline in abundance as the vegetation in these areas increases. 

7 These species include freshwater drum (Aplodinotus grunniens), channel catfish (Ictalurus 

8 punctatus), smallmouth buffalo (Ictiobus bubalus), spotted sucker (Minytrema melanops), and 

9 carp (Scott 1993). Scott observes that the responses of the fish populations to changes in 

10 aquatic vegetation are more complex than simple correlations, however, and that the fish 

11 communities have been destabilized due to highly variable water conditions such as rate of 

12 spring warming, discharges, turbidity, and water level fluctuations that affect not only aquatic 

13 macrophytes but also planktonic food webs, fish spawning times and success, and interspecific 

14 competition among early life stages of fish species.

15 TVA (2013n) reported that rooted aquatic macrophytes were not abundant near the SQN site 

16 until Eurasian water milfoil was established in Chickamauga Reservoir. Eurasian water milfoil 

17 was introduced into Watts Bar Reservoir (upstream of Chickamauga Reservoir) around 1953 

18 and expanded into Chickamauga Reservoir in 1961. Spiny leaf naiad became the most 

19 common submerged aquatic macrophyte during the 1980s (TVA 2013n). Aquatic macrophyte 

20 coverage in Chickamauga Reservoir was less than 100 hectares (ha) (247 ac) between 1970 

21 and 1975 and increased to nearly 2,800 ha (6,920 ac) between 1982 and 1988 (Scott 1993; 

22 TVA 2013n). The coverage of spiny leaf naiad in the reservoir correlates negatively with water 

23 flow levels, and increased in several drought years occurring during the 1982 to 1988 period 

24 (Scott 1993; TVA 2013n; TWRA 2008). Increased water flows caused a decrease in vegetation 

25 to 155 ha (383 ac) by 1992 (TVA 2013n), but vegetation increased again to 1,400 ac (567 ha) 

26 by 2007 (TVA 2007). TVA (2007) reports the dominant aquatic plant on Chickamauga 

27 Reservoir was the spiny leaf naiad, a species that grows in shallow water areas of the reservoir 

28 (e.g., embayments, sloughs, and overbank areas). 

29 TVA (Simmons 2011) conducted the initial and most recently published survey of aquatic 

30 macrophyte coverage in the vicinity of the SQN site in autumn 2009 during a shoreline habitat 

31 study. TVA assessed the percentage of aquatic macrophytes in the shallow areas along both 

32 shorelines of eight line-of-sight transects across the Chickamauga Reservoir. The transects 

33 were sited between Tennessee RM 481.1 and 483.6, downstream of the SQN site, and from 

34 Tennessee RM 487.9 to 491.1, upstream of the SQN site. No aquatic macrophytes were 

35 observed in the upstream sampling area (Tennessee RM 487.9 to 491.1). At the downstream 

36 sampling areas (Tennessee RM 481.1 to 483.6), slightly fewer than half of the locations had 

37 aquatic macrophytes. The average percentage of macrophytes was 2 percent along the left 

38 descending bank and 5 percent along the right descending bank (TVA 2012c).

39 TVA plans to continue sampling habitats in the vicinity of the SQN site every 3 years in autumn 

40 unless there are significant changes to the river system as based on the initial characterization 

41 (in 2009), in which case the sampling would occur the next autumn (TVA 2012c).

42 Macroinvertebrates 

43 Invertebrates are animals that do not have a true backbone. Macroinvertebrates are typically 

44 invertebrates large enough to see with the human eye and include animals such as flatworms; 

45 roundworms; leeches; crustaceans; aquatic life stages of insects; and mollusks such as snails, 

46 clams, and mussels. Macroinvertebrates perform a variety of ecosystem services and are an 

47 important food source for other aquatic organisms, including some fish. Their distribution 

48 depends partly on their habitat (e.g., substrate type, amount of cover, food availability, dissolved 
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1 oxygen levels, flow patterns, and water temperature). The term “benthic macroinvertebrates” 

2 refers to macroinvertebrates that live all or part of their life near, on, or in the bottom of streams 

3 or reservoirs. Researchers use studies of benthic macroinvertebrate abundance and 

4 distribution to detect major environmental changes because these animals do not migrate 

5 rapidly and, in general, do not make major changes in location.

6 White et al. (2005) find that transitional zones of the main stem Tennessee reservoirs have 

7 greater diversity and density of benthic invertebrates than riverine or lacustrine zones. The 

8 transition zone is dominated by worms that feed on subsurface deposits. The primary insects in 

9 the transition zones are the larvae of mayflies, caddisflies, and chironomids (midges). The 

10 lacustrine zone has less organic matter, as discussed previously, and the tubificid worms are 

11 the primary feeders on sediment deposits and filters. Mayfly and chironomid larvae are the 

12 most common insects. Filter-feeding mollusks (e.g., fingernail clams (family Sphaeriidae), 

13 Asiatic clams (family Corbiculidae), and some unionid mussels (native freshwater mussels)) are 

14 found in the lacustrine zone, although unionid mussels are found in much greater densities in 

15 the riverine zone. 

16 TVA performed studies of macroinvertebrates before the start of operations at SQN, Units 1 

17 and 2 (i.e., from 1971 to 1978), and following the start of operations (i.e., from 1980 to 1985) 

18 (Dycus 1986). Studies were conducted at an upstream control site at Tennessee RM 490.5 

19 (midchannel) and at three downstream sites, Tennessee RM 483.4 (right descending channel 

20 margin), Tennessee RM 482.6 (left descending channel margin), and Tennessee RM 478.2 

21 (midchannel). TVA (Dycus 1986) reports that results of the studies between 1971 and 1985 

22 show no evidence of decline in the community and that spatial and temporal differences are 

23 associated with factors other than the operation of SQN. At one location, a macroinvertebrate 

24 community appeared to be stressed, although TVA attributed that stress to habitat limitations. 

25 Because no changes were observed in the macroinvertebrate community, TVA decided not to 

26 continue the studies after the early 1985 sampling season.

27 In 1999, TVA reinitiated surveys of benthic macroinvertebrates as part of its annual monitoring 

28 program to verify that balanced indigenous populations were being maintained at TVA’s thermal 

29 plants with alternative thermal limits (TVA 2013n). Sample locations for benthic 

30 macroinvertebrates are located upstream (Tennessee RM 490.5) and downstream 

31 (Tennessee RM 482.0). Table 3–9 provides a comparison of the data from the two sampling 

32 locations during the four most recent sampling years, 2008 to 2011 (Shaffer et al. 2010; 

33 Simmons 2011; Simmons and Baxter 2009; TVA 2012c). From 2008 to 2011, the density of 

34 organisms is higher at the upstream locations, and this difference appears to be largely driven 

35 by the high upstream density of Chironomidae (midges) as densities of most other taxa are 

36 higher at the downstream sampling location. According to TVA (2013n), lower densities and 

37 numbers of macroinvertebrates were found in sampling near the SQN site than were found in 

38 other sampling locations in Chickamauga Reservoir.

39 Mollusks, a subset of macroinvertebrates, include snails, freshwater clams, and mussels. The 

40 Tennessee River is home to both introduced and native mussel and clam species. 

41 Approximately 130 of nearly 300 species of freshwater mussels in the United States live, or are 

42 known to have lived, in waters within Tennessee (Parmalee and Bogan 1998). Stressors such 

43 as farming, strip mining, industry, hydropower dam construction, and commercial exploitation 

44 have greatly reduced species distributions and abundances (Parmalee and Bogan 1998).
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1 Table 3–9. Average Mean Density Per Square Meter of Benthic Taxa Collected at 

2 Downstream and Upstream Sites Near SQN

Taxa

Downstream Upstream

2008 2009 2010 2011 2008 2009 2010 2011

TRM 

482.0

TRM 

482.0

TRM 

482.0

TRM 

481.3

TRM 

490.5

TRM 

490.5

TRM 

490.5

TRM 

490.5

Turbellaria

Planariidae (flatworms) 5 0 0 4 0 0 0 0

Annelida

Oligochaeta (segmented worms) 133 15 30 150 93 18 8 154

Hirudinea (leeches) 35 0 10 27 3 7 2 3

Crustacea

Amphipoda 57 0 0 3 12 0 0 0

Insecta

Ephemeroptera (mayflies) 15 39 33 26 2 23 25 11

Trichoptera (caddisflies) 15 0 0 10 0 0 0 5

Diptera Chironomidae (midges) 238 164 125 264 352 285 505 348

Gastropoda (snails) 17 13 7 0 3 5 5 5

Bivalvia (mussels and clams)

Unionidae (mussels) 2 2 0 0 0 0 0 2

Corbiculidae (≤10 mm (0.4 in.)) 48 40 17 (a)382 5 50 (a)67 Corbiculidae (>10 mm (0.4 in.)) 13 11 18 0 12 2

Sphaeriidae (fingernail clams) 8 26 13 74 20 27 85 168

Dreissenidae (zebra mussels) 8 9 0 0 0 3 0 0

Density of total organisms 594 319 253 558 487 385 682 696

Total area sampled (m2 (11 ft2)) 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6

(a) TVA 2012c did not designate sizes of Corbicula fluminea 

TRM = Tennessee River Mile

Sources: Shaffer et al. 2010; Simmons 2011; Simmons and Baxter 2009; TVA 2012c 

3 Mussels spend their entire juvenile and adult lives buried, either partially or completely, in the 

4 substrate. Although mussels are able to change their position and location, they rarely move 

5 more than a few hundred yards during their lifetime unless dislodged. Individuals from some 

6 species of freshwater mussels live for more than 100 years (Parmalee and Bogan 1998). 

7 Freshwater mussels filter organic particles and microorganisms (e.g., protozoans, diatoms, and 

8 bacteria) from the water. Native freshwater mussels have a unique reproductive cycle. Males 

9 release sperm into the water, where they are carried into the female mussel’s body via tubes in 

10 the gills, where they fertilize the eggs. The fertilized eggs develop into small larvae, called 

11 glochidia, that release into the water. If the glochidia do not encounter a passing fish and attach 

12 to its gills or body, they fall to the bottom and die a short time later. The glochidia that attach to 

13 a fish’s gills remain on that fish for 1 to 6 weeks before falling off and beginning their growth into 

14 adulthood. Each mussel species has particular species of fish that serve as hosts for the 

15 glochidia (Parmalee and Bogan 1998). The survival of freshwater mussel species depends not 
Affected Environment

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1 only on the environmental conditions for the mussel, but on the survival and health of the host 

2 fish populations.

3 The numbers of native mussels have been declining since the early 1940s when TVA filled the 

4 Chickamauga and Watts Bar reservoirs. Parmalee et al. (1982) studied aboriginal shell 

5 middens in the Chickamauga Reservoir (Tennessee RM 495 to 528). The five most abundant 

6 species during the Middle Woodland (A.D. 1) to Late Woodland Mississippian times 

7 (approximately A.D. 600 to 1600) included the currently endangered dromedary pearly mussel 

8 (Dromus dromas), spike mussel (Elliptio dilatatus), mucket (Actiononaias ligamentina), 

9 elephant-ear (E. crassidens), and rough pigtoe (Pleurobema plenum). Together these species 

10 composed about 66 percent of the community surveys at 16 prehistoric aboriginal sites along 

11 the Chickamauga Reservoir. Watters (2000) points to impoundments, dredging, snagging, and 

12 channelization as having long-term detrimental effects on freshwater mussels. The 

13 impoundments result in silt accumulation, loss of shallow water habitat, stagnation, 

14 accumulation of pollutants, and nutrient-poor water.

15 As a result of the loss of diversity in mussel species, the State of Tennessee created a 

16 freshwater mussel sanctuary in the riverine zone of Chickamauga Reservoir immediately below 

17 Watts Bar Dam. The mussel sanctuary extends 16 km (10 mi) from Tennessee RM 520.0 to 

18 Tennessee RM 529.9 (NRC 2013a). Mussel harvesting is illegal in this area. 

19 TVA observed unionid mussels and snails in the annual monitoring surveys in the vicinity of the 

20 SQN site (Table 3–10). Two unionid mussels were identified in 2008 and 2009 at the sampling 

21 location downstream of the site at Tennessee RM 482 (Simmons and Baxter 2009), and 

22 two unionid mussels were identified at the upstream survey location in 2011 (TVA 2012c). 

23 Aquatic snails are routinely found in the annual monitoring survey as shown in Table 3–10. 

24 Invasive mussels were also identified including the Asiatic clam and zebra mussel (Dreissena 

25 polymorpha) but their numbers not quantified.

26 Additional field surveys were conducted between June 28 and July 9, 2010, to document the 

27 number and diversity of the unionid mussels and snails, along with their habitat conditions in the 

28 vicinity of SQN in areas that could be affected by plant operations and in areas beyond those 

29 affected areas (Third Rock 2010a, 2010b). Reconnaissance dives (timed searches) were made 

30 in specific areas within 1 to 2 mi (1.6 to 3.2 km) of the plant. The dives identified eight survey 

31 sites. At each site, four 100-m (328-ft) long sampling transects were set up perpendicular to the 

32 bank. Densities of both mussels and snails were reported to be low throughout the survey area. 

33 Sampling resulted in the identification of 280 mussels from 11 species. The most abundant 

34 were the threehorn wartyback mussel (Obliquaria reflexa), which comprised almost 69 percent 

35 of the individuals observed; the pink heelsplitter (Potamilus alatus) with 13 percent; and the 

36 pimpleback (Quadrula pustulosa) with 7 percent. Invasive, nonnative zebra mussel numbers 

37 were not recorded, although the authors indicate that zebra mussels “were prevalent and 

38 attached to the majority of the live mussels recorded in the survey.” Of the 280 unionid mussels 

39 observed, approximately half (136) were infested with zebra mussels that covered between 5 

40 and 15 percent of the surface area of the live unionid mussels, and, in some cases, zebra 

41 mussels covered 50 percent of the surface area of a given unionid mussel.

42 Four species of snails, consisting of 281 individuals, were identified during the survey. The 

43 most abundant was the olive mysterysnail, which comprised 49 percent; the sharp hornsnail 

44 with 42 percent; the silty hornsnail with 5 percent; and the pointed campeloma with 4 percent 

45 (Third Rock 2010b). 
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1 Table 3–10. Results of the Native Mussel and Snail Survey Near the SQN Site in 2010

Taxonomic Class and

Scientific Name Common Name Number of Individuals

Percent 

of Total

Mussels

Obliquaria reflexa threehorn wartyback 192 69

Potamilus alatus pink heelsplitter 35 13

Quadrula pustulosa pimpleback 19 7

Pyganodon grandis giant floater 13 5

Anodonta suborbiculata flat floater 9 3

Megalonaias nervosa washboard 4 1

Leptodea fragilis fragile papershell 5 2

Amblema plicata threeridge 1 <1

Truncilla truncate deertoe 1 <1

Elliptio crassidens elephant-ear 1 <1

Snails

Vivaparus subpurpureus olive mysterysnail 137 49

Pleurocera acuta sharp hornsnail 119 42

Pleurocera canaliculata silty hornsnail 14 5

Campeloma decisum pointed campeloma 11 4

Source: Third Rock 2010b 

2 Densities of both snails and mussels were generally low with mean densities in quantitative 

3 samples ranging from zero to 0.7 mussels per square meter and 0.008 to 1 snail per square 

4 meter. Densities were higher at sites 5 (immediately above discharge), 6 (in the mixing zone), 

5 and 7 (downstream of the mixing zone) than they were further upstream or further downstream 

6 of the discharge. This may have been influenced by the substrate in the vicinity of the sampling 

7 transects. The substrate at site 5, where the greatest number of mussels were observed, was 

8 predominately a mix of sand/cobble/gravel substrates. The remaining locations had substrates 

9 of silt over either clay or sand or silt over a combination of clay and sand (Third Rock 2010b).

10 Fish 

11 The fish populations in the Tennessee River have changed and are changing considerably as a 

12 result of human-initiated activities (e.g., impoundment of the river and introduction of nonnative 

13 species). Etnier et al. (1979) and Neves and Angermeier (1990) both indicate that the 

14 Tennessee River was poorly studied prior to impoundment, especially for small fish. In 1977 

15 and 1978, Etnier et al. (1979) examined samples of over 49,000 fish specimens collected by 

16 TVA field crews between 1937 and 1943, prior to impoundment of the river. Based on an 

17 analysis of those specimens and a comparison with more recent observations, Etnier et al. 

18 (1979) conclude that “many changes have occurred in the Tennessee River fish fauna 

19 coincident with main channel impoundments,” including the disappearance of species in 

20 response to drastic alteration of the Tennessee River system. Fish species extirpated from the 

21 Tennessee River system include the lake sturgeon (Acipenser fulvescens), the shovelnose 

22 sturgeon (Scaphirhynchus platorynchus), and the silvery minnow (Hybognathus nuchalis) 

23 (Etnier et al. 1979).

24 Fish populations in the Chickamauga Reservoir near the SQN site have been sampled fairly 

25 consistently over the past 50 years. Considerable data are available on fish abundance and 
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1 diversity in the vicinity of the SQN site. Rotenone studies were initiated in various coves in 

2 Chickamauga Reservoir in 1947 and continued throughout the reservoir through 1959 

3 (excluding 1948 and 1953) and then began again in 1970 and continued through 1993, at which 

4 time they were conducted biennially until 1999. Rotenone is a toxic chemical that kills fish and 

5 allows for the collection and identification of fish when added to water in a cove or other limited 

6 area. It is detoxified with the release of another chemical. Rotenone sampling sites were 

7 located approximately 10 mi (16.1 km) upstream or 6 mi (9.7 km) downstream of the SQN site 

8 (Baxter 2000). Although the purpose of the rotenone sampling was to understand the density of 

9 forage, sport, and commercially valued fish species, it also provided a characterization of the 

10 fish community and occurrence data for fish in the reservoir. However, rotenone sampling is 

11 known to underestimate the number of certain species such as common carp (Cyprinus carpio), 

12 smallmouth buffalo, flathead catfish (Pylodictis olivaris), white crappie (Pomoxis annularis), and 

13 sauger (Sander canadensis) (Baxter 2000; Wilson and Sawyer 1994).

14 The rotenone sampling study results were used to identify trends in fish populations. For 

15 example, threadfin shad populations showed dramatic declines in 1978, 1979, 1982, 1984, and 

16 1989 (Baxter 2000). Threadfin shad are susceptible to extensive winter kills (Etnier and 

17 Starnes 1993; Loar et al. 1978), and estimates of numbers killed in Chickamauga Reservoir, as 

18 in other reservoirs and lakes, vary dramatically depending on winter water temperatures. Baxter 

19 (2000) attributed the increased population estimates for centrarchids such as warmouth, redear 

20 sunfish (Lepomis microlophus), bluegill, and largemouth bass (Micropterus salmoides) to the 

21 large increase in aquatic macrophytes between 1980 and 1988. In particular, warmouth and 

22 bluegill are known to find habitat and protection in areas of vegetative and sometimes dense 

23 cover (e.g., debris or weedbeds) (Etnier and Starnes 1993). Other species, however, such as 

24 the freshwater drum, may be displaced to areas not inhabited by macrophytes (Baxter 2000;

25 Wilson and Sawyer 1994).

26 In 1986, data obtained by the rotenone studies and TWRA creel surveys of Chickamauga 

27 Reservoir caused concern from TWRA and the Tennessee Division of Water Pollution Control 

28 regarding the possible declining populations of specific fish species in Chickamauga Reservoir. 

29 The species, including sauger, white crappie, white bass (Morone chrysops), and channel 

30 catfish, were the subjects of additional analyses and studies conducted by TVA in following 

31 years (Buchanan 1994; Buchanan and McDonough 1990; Hevel and Hickman 1991; Hickman 

32 and Buchanan 1995; Peck and Buchanan 1991), and each species is discussed later in this 

33 section.

34 In 1942, TVA sampled using rotenone and gillnets. Gillnets were also used during 

35 preoperational monitoring between 1971 and 1978 in the vicinity of the SQN site. TVA sampled 

36 quarterly using gillnets and trap nets at locations upstream (Tennessee RM 495), below 

37 Tennessee RM 473, and adjacent to the site (Tennessee RM 483.6) (Dycus 1986; 

38 Simmons 2010a). TVA conducted additional monitoring after the start of SQN operations (from 

39 1980 to 1985) using standard gillnets at approximately the same locations (Dycus 1986; 

40 Simmons 2010a). TVA used experimental gillnets, which are composed of panels with varying 

41 mesh sizes to capture a variety of species, during a study in 1986 between Tennessee 

42 RM 482.7 and Tennessee RM 487.6 (Simmons 2010a).

43 TVA began evaluating the ecological health of fish communities in the reservoir using the 

44 Reservoir Fish Assemblage Index methodology in 1993 (TVA 2012c). This annual survey uses 

45 gillnets and electrofishing from boats and is conducted primarily at monitoring stations located at 

46 the inflow (Tennessee RM 529), upper end (Tennessee RM 518 and 527.4), transition zone, 

47 (Tennessee RM 490.5), and forebay zone (Tennessee RM 472.3) of the reservoir and in the 

48 embayment of the Hiwassee River (Hiwassee RM 8.5). In 1990, TVA added an additional 
Affected Environment

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1 sampling site at Tennessee RM 482.0, just downstream of the SQN site, to assess the effects of 

2 site discharge on fish (TVA 2013n). 

3 Table 3–11 is a list of species by family that were identified during the sampling studies that ran 

4 from 1999 to 2011. Fifty-three species from 13 families are present in the vicinity of the SQN 

5 site. Tables 3–12 (electrofishing) and 3–13 (gillnetting) provide the percentage of the catch 

6 composed of each of the most dominant species at each sampling location (upstream of the site 

7 at Tennessee RM 490.5 or downstream of the site at Tennessee RM 482) during the most 

8 recent 10 years of sampling (2002 to 2011). As expected, variations exist between 

9 electrofishing and gillnetting results, as smaller fish escape gillnets. Bluegill was the numerically 

10 dominant species caught during electrofishing at both upstream and downstream sample sites 

11 for the past 11 years (TVA 2013n), followed by the gizzard shad (Dorosoma cepedianum) 

12 (Table 3–12). Other numerically dominant species include the redbreast sunfish, redear 

13 sunfish, spotted bass, and largemouth bass. Results from gillnet samples indicated the gizzard 

14 shad was the numerically dominant species at both upstream and downstream sample sites. 

15 Other numerically dominant species include the yellow bass, blue catfish, spotted bass, redear 

16 sunfish, black crappie, skipjack herring, channel catfish, redear sunfish, and drum (Table 3–13). 

17 Table 3–11. Species Identified During Sampling Studies in the Vicinity of the SQN Site 

18 From 1999 to 2011

Family Scientific Name Common Name

Acipenseridae Acipenser fulvescens lake sturgeon

Atherinopsidae Labidesthes sicculus brook silverside

Menidia audens Mississippi silverside

Menidia beryllina inland silverside

Catostomidae Hypentelium nigricans northern hog sucker

Ictiobus bubalus smallmouth buffalo

Ictiobus niger black buffalo

Minytrema melanops spotted sucker

Moxostoma duquesnei black redhorse

Moxostoma erythrurum golden redhorse

Centrarchidae Ambloplites rupestris rock bass

hybrid Lepomis spp. hybrid sunfish

hybrid Micropterus sp. hybrid bass

Lepomis auritus redbreast sunfish

Lepomis cyanellus green sunfish

Lepomis gulosus warmouth

Lepomis macrochirus bluegill

Lepomis megalotis longear sunfish

Lepomis microlophus redear sunfish

Micropterus dolomieu smallmouth bass

Micropterus punctulatus spotted bass

Micropterus salmoides largemouth bass

Pomoxis annularis white crappie

Pomoxis nigromaculatus black crappie
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Family Scientific Name Common Name

Clupeidae Alosa chrysochloris skipjack herring

Dorosoma cepedianum gizzard shad

Dorosoma petenense threadfin shad

hybrid Dorosoma sp. hybrid shad

Cyprinidae Campostoma oligolepis largescale stoneroller

Cyprinella spiloptera spotfin shiner

Cyprinella whipplei steelcolor shiner

Cyprinus carpio common carp

Gambusia affinis western mosquitofish

Notemigonus crysoleucas golden shiner

Notropis atherinoides emerald shiner

Pimephales notatus bluntnose minnow

Pimephales vigilax bullhead minnow

Hiodontidae Hiodon tergisus mooneye

Ictaluridae Ictalurus furcatus blue catfish

Ictalurus punctatus channel catfish

Pylodictis olivaris flathead catfish

Lepisosteidae Lepisosteus oculatus spotted gar

Lepisosteus osseus longnose gar

Moronidae hybrid Morone (chrysops × sax.) hybrid striped × white bass

Morone chrysops white bass

Morone mississippiensis yellow bass

Morone saxatilis striped bass

Percidae Perca flavescens yellow perch

Percina caprodes logperch

Sander canadensis sauger

Sander vitreum walleye

Petromyzontidae Ichthyomyzon castaneus chestnut lamprey

Sciaenidae Aplodinotus grunniens freshwater drum

Sources: Shaffer et al. 2010; Simmons 2011; TVA 2012c

1 Another way to view the differences between the upstream and the downstream sites is to 

2 examine the percentages of fish in each location based on their trophic groups (see Table 3–14) 

3 for the trophic groups and the fish species in each group). In 2011, insectivores and omnivores 

4 dominated the fishery ecosystem both upstream and downstream of the SQN site in both 

5 summer and autumn (TVA 2012c, Table 3.7). In general, upstream and downstream locations 

6 exhibited fairly similar proportions of fish in each trophic level, regardless of season, with the 

7 exception of planktivores, which were significantly more abundant in downriver locations in 

8 autumn. The planktivore trophic group includes threadfin shad, which are schooling fish with 

9 patchy distribution, and the random capture of a school can strongly influence abundance 

10 estimates. 
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Table 3–12. Percent Composition of the Dominant Species Caught Upstream (Tennessee RM 490.5) and Downstream of the 

SQN Site (Tennessee RM 482) by Electrofishing, 2002 Through 2011

Species(a) 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

up down up down up down up down up down up down up down up down up down up down

brook silverside 1.2 1.9 1.6 2.0 1.8 1.1 0.80 1 0 0 0 0 3.9 0 1.0 0.43 0 0.21 0 0

Mississippi silverside 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6.8 35

inland silverside 0 0 0 0 1.4 0 0.64 0.23 0.81 4.2 0.36 0.36 0 1.9 3.6 4.5 32 46 0 0

redbreast sunfish 3.5 4.3 9.4 4.2 5.8 6.1 10 17 8.8 7.7 11 12 1.9 7.8 3.9 3.6 0.91 0.36 4.7 0.92

bluegill 32 31 31 25 30 30 39 25 23 34 28 36 54 58 40 51 35 20 43 12

longear sunfish 1.2 1.4 4.4 4.2 1.8 0.77 1.9 1.4 2.0 1.2 1.6 1.6 0.08 1.6 1.5 0.21 0.96 0.50 0 0.08

redear sunfish 6.3 8.6 7.3 14 10 8.3 5.1 9.2 5.7 12 5.3 7.1 3.2 7.2 5.1 8.5 3.3 3.3 3.5 1.3

spotted bass 5.4 6.0 3.4 6.1 6.6 3.2 3.5 3.4 3.3 3.3 2.3 1.6 1.1 1.7 1.9 2.8 1.0 0.57 1.4 0.42

largemouth bass 5.0 5.5 2.4 3.2 5.4 4.5 5.6 2.3 0.54 2.5 2.1 3.6 1.6 1.8 5.0 6.2 0.57 2.4 1.7 1.6

smallmouth bass 2.6 1.4 1.9 0.29 2.4 0.55 3.8 0.11 2.3 0.0 0.61 0.18 0.62 0.17 0.62 1.2 0.24 0.036 0.87 0.040

black crappie 1.5 0.52 3.1 0.58 3.1 0.55 0.48 0.68 1.6 0.22 0.24 0.18 0.62 0.25 4.1 2.6 0.91 1.1 1.4 1.9

gizzard shad 14 29 14 18 12 16 19 23 35 21 30 19 28 9.0 15 11 17 16 31 26

threadfin shad 12 0 2.7 0 0.68 1.8 1.1 3.0 7.9 0.55 0.12 0.36 0.23 1.8 9.0 0.32 0.05 0 1.2 17

common carp 0.62 0.52 0.97 0.29 0.54 0.88 0.16 0.23 0 0 0.49 0 0 0.17 0.31 0.32 0.10 0.21 0.05 0.27

spotfin shiner 0.62 0 3.1 2.9 0.27 0.11 0.16 0 0.81 4.2 1.1 3.6 0.46 1.7 2.6 1.6 0.29 0.50 0.22 0.46

emerald shiner 4.8 3.3 2.4 14 8.4 20 3.3 8.1 3.1 2.8 4.4 7.1 0.23 0.33 0.18 0 0 0 0 0

golden shiner 1.4 0.17 4.0 0.87 0.81 0.33 0.16 1.8 1.2 0.44 3.0 0 1.1 0.92 1.2 0.75 0.24 0.57 0.22 0.34

bluntnose minnow 0 0 1.9 0 0.68 0.33 0.32 0.11 0.14 3.3 0.36 0.18 0 1.2 1.1 0.85 0.24 1.6 0.11 0.54

channel catfish 1.5 2.2 0.32 0.87 1.4 1.6 0 0.68 0.54 0.33 0.12 2.1 0.23 1.5 0.84 1.3 0.14 0.57 0.65 0.19

logperch 0.09 0.34 0.65 1.3 0.41 0.11 0.48 0.68 0.54 1.6 0.85 0 0.31 0.33 0.04 0 4.6 2.2 0.05 0 

freshwater drum 0.62 0.34 0.81 0.73 2.6 1.4 0.32 0.34 0.41 0.22 1.1 0 0.15 0.50 0.70 0.64 0.19 0.43 0.76 0.27

other species 5.4 3.8 4.8 1.6 4.6 1.8 3.0 1.6 1.8 1.1 7.2 4.1 2.7 1.9 2.2 2.2 2.3 2.6 2.4 1.7

Columns may not add to 100 due to rounding. (a)Species are ordered alphabetically by family name (not shown) and then by scientific name (not shown). 

Sources: Shaffer et al. 2010; Simmons 2011; TVA 2012c
3-62

Affected Environment

Table 3–13. Percent Composition of the Dominant Species Caught Upstream (Tennessee RM 490.5) and Downstream of the 

SQN Site (Tennessee RM 482) by Gillnetting, 2002 Through 2011

Species(a) 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

up down up down up down up down up down up down up down up down up down up down

spotted sucker 0 3.7 1.2 3.4 1.1 0.63 1.6 0.47 0.40 0.70 0.93 0 0 0.52 0.65 0 0.96 1.8 2.9 0.82

bluegill 0 0 0 2.7 1.1 3.1 4.0 0.94 3.2 3.5 0.93 3.5 0 0 1.3 4.3 0.96 0.92 0.72 0.82

longear sunfish 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.0 0 0

redear sunfish 4.5 2.5 19 11 10 5.0 6.3 4.2 15 4.9 3.7 1.3 7.2 0 21 8.6 6.2 3.7 11 0.82

largemouth bass 0 0 1.2 1.4 0 2.5 0 0.94 1.6 0.70 2.8 0.88 2.8 2.1 1.9 3.6 0.96 0.4 0 0.82

smallmouth bass 1.5 2.5 0 8.1 0 0 0 0 0.40 0 0 0.44 0 0 0 0.71 0 0.92 0 0.82

spotted bass 16 42 2.8 5.4 9.6 11 14 9.9 4.0 6.3 2.2 5.3 1.1 23 10 12 0.96 5.1 6.5 4.1

black crappie 6.1 1.2 3.2 0.68 5.3 2.5 3.2 0.94 7.2 9.2 17 9.2 12 10 5.2 7.9 6.7 2.8 12 7.4

skipjack herring 11 3.7 8.4 4.7 15 9.4 5.6 8.0 12 15 10 7.9 0 0 0 0 2.9 0.92 8.6 1.6

gizzard shad 9.1 3.7 28 20 21 30 19 41 25 23 24 32 44 38 25 25 39 52 40 63

golden shiner 0 0 0 0.68 0.53 9.4 0 0 0 1.4 0.62 0.44 0 0 0.65 4.3 5.3 0.46 0.72 0

blue catfish 0 2.5 10 8.1 8.0 5.0 13 11 0.40 11 2.2 14 3.9 6.3 1.9 14 3.3 8 5.8 10

channel catfish 2.3 11 5.6 10 3.7 4.4 4.8 6.1 1.6 9.9 0.62 3.5 1.1 2.6 3.2 7.9 0 1.8 5 3.3

flathead catfish 2.3 3.7 1.6 2.0 2.1 1.3 1.6 3.8 0 2.1 0.31 1.8 2.2 1.0 1.9 0 1.9 1.4 0.72 2.5

white bass 3.0 0 0 0 0 0 0 1.4 3.2 0 0.62 0 1.1 1.6 0.65 1.4 4.8 2.8 1.4 0.82

yellow bass 35 1.2 13 12 16 11 20 8.5 22 6.3 28 14 20 7.3 20 7.1 24 12 2.9 1.6

striped bass 1.5 3.7 0 0 0.53 0.63 0 0 0 0 0 0 0 0 0 0 0 0 0 0

sauger 3.0 7.4 0.40 1.4 1.1 0 0.79 0 0.40 0 0 0 0 0.52 3.2 0 0 0 0 0

freshwater drum 2.3 7.4 2.8 6.8 2.7 3.1 4.8 2.4 2.4 2.1 4.4 2.6 3.3 3.7 1.3 2.1 1.4 1.8 0 0.82

other species 2.3 3.7 2.0 2.0 2.1 1.3 0.8 0.5 0.8 4.9 1.6 3.5 0.6 2.6 1.4 1.4 0.5 1.8 1.7 0.8

Columns may not add to 100 due to rounding. (a)Species are ordered alphabetically by family name (not shown) and then by scientific name (not shown).

Sources: Shaffer et al. 2010; Simmons 2011; TVA 2012c 
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1 Table 3–14. Percent of Fish in Each Trophic Group by Season and Location in 2011

Diet

Summer 2011

Percent

Autumn 2011

Percent

Upstream Downstream Upstream Downstream

Benthic Invertivores 2.6 1.7 1.3 0.8

Herbivores 0 0 0.1 0

Insectivores 52 52 46 48

Omnivores 36 35 33 30

Piscivores 8.8 11 8.2 5.2

Planktivores 0.1 0.1 1.1 16

Source: Table 3 of TVA 2012c 

2 Fish Egg and Larval Studies

3 Between 1981 and 1985, TVA (Dycus 1986) conducted studies as part of entrainment

4 monitoring after the start of SQN operations. As part of this monitoring, samples of fish eggs 

5 and larvae were collected at transects near the diffuser (Tennessee RM 482.7), near the plant 

6 (Tennessee RM 484.8), at the skimmer wall, and in the intake channel. In addition, entrainment 

7 monitoring was conducted during a 12-week period from April through June 2004 (Baxter and 

8 Buchanan 2010). 

9 During the sampling in 1985, 99.5 percent of all fish eggs collected were freshwater drum eggs. 

10 Eggs were first observed in mid-April (3 weeks earlier than in previous years) and were present 

through the season (i.e., until August 27). Peak density of 4,430 eggs per 1,000 m3 11 was 

12 observed on June 17 at the transect closest to the diffuser (Dycus 1986). The majority of fish 

13 larvae collected in 1985 were clupeid (shad) larvae (61 percent in 1985 as compared to 

14 79 percent in 1984 and 74 percent in 1983). Lepomis, or sunfish larvae, were next in 

15 abundance (17 percent), followed by freshwater drum (15 percent), and temperate bass larvae 

16 (Morone) (4 percent). 

Average density of total fish larvae for the season was 2,169 per 1,000 m3 17 of water at the plant 

and 2,108 per 1,000 m3 18 of water at the diffuser transects. Densities were lower by a factor of 4 

at the skimmer wall and intake. The peak seasonal density was 9,671 larvae per 1,000 m3 19 of 

20 water at the plant transect on May 6. Freshwater drum dominated peak densities at the 

21 skimmer wall (82 percent) and in the intake basin (85 percent), while clupeid larvae dominated 

22 peak densities at the plant (86 percent) and diffuser transects (72 percent) (Dycus 1986).

23 Ichthyoplankton sampling in 2004 occurred from April 20 through July 12 (Baxter and 

24 Buchanan 2010). Results were similar to those from the 1980s; most were freshwater drum 

25 eggs (98.8 percent), and they were collected during all 12 sampling periods. Peak densities 

occurred on May 25 with 24,367 per 1,000 m3 of water and June 2 with 1,594 per 1,000 m3 26 of 

27 water. Average seasonal densities were slightly less in the intake channel (549 drum eggs per 

1,000 m3 of water) than those observed in the reservoir samples (652 drum eggs per 1,000 m3 28

29 of water). 

30 During sampling in 2004, the majority of fish larvae collected were clupeids (87.9 percent) 

31 followed by Morone spp. (white and yellow bass) at 5.5 percent, freshwater drum (3.2 percent), 
Affected Environment

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and centrarchids (3.1 percent). Average density for the season was 2,639 per 1,000 m3 1 in the 

intake and 3,946 per 1,000 m3 2 in the reservoir samples. 

3 Commercially and Recreationally Important Fish Species

4 The continued operation of SQN may directly or indirectly affect commercially, recreationally, 

5 and biologically important species. TVA and TWRA allow commercial fishing on Chickamauga 

6 Reservoir. 

7 The most recent report on commercial fishing indicates small numbers of paddlefish (Polyodon 

8 spathula) have been harvested in the Chickamauga Reservoir. Summaries of 2008 to 2012 

9 commercial roe harvest from Chickamauga Reservoir are provided in Table 3–15. Table 3–16 

10 summarizes nonroe harvest for 2008 through 2012. The majority of fish caught for commercial 

11 use include catfish (blue, channel, and flathead (Ictalurus spp. and Pylodictis olivaris)), buffalo 

12 (Ictiobus spp.), and carp (bighead, silver, and common (Hypophthalmichthys spp. and Cyprinus

13 carpio)). Freshwater drum, gar (Lepisosteus sp.), and a small number of snapping turtles 

14 (Chelydra serpentina) were also taken (Black 2010).

15 Table 3–15. Commercial Harvest Rates for Paddlefish From Chickamauga Reservoir: 

16 2008 to 2012

Paddlefish

Chickamauga Reservoir

2008/2009 2009/2010 2010/2011 2011/2012

Number 169 201 971 1,667

Roe (eggs) (lb) 99 54 1,384 4,725

Flesh (lb) 2,029 1,801 14,541 15,019

Sources: TVA 2013d, 2013e, 2013f

17 Chickamauga Reservoir is a popular location for recreational fishing. In 2011, Chickamauga 

18 Reservoir ranked first among lakes in the State of Tennessee in terms of angling effort (number 

19 of hours spent angling) and number of fish caught. In addition, Chickamauga Reservoir had the 

20 second highest number of fish caught per hour of any reservoir in Tennessee. Table 3–17 

21 shows the number of fish caught recreationally during the last 5 years (Black 2008, 2009, 2010, 

22 2011, 2012) based on the annual creel survey of the entire Chickamauga Reservoir by the State 

23 of Tennessee. Because the data are reported for the entire reservoir, some fish listed in 

24 Table 3–17 were not observed in the gillnet or electrofishing sampling results reported in 

25 Table 3–12 and Table 3–13. For each year from 2007 through 2011, the most frequently caught 

26 fish species was bluegill, followed by largemouth bass, blue catfish, black crappie, and yellow 

27 bass. Drum, striped bass, and black bass are frequently released. Crappie, yellow perch, and 

28 catfish are less likely to be released (Black 2008, 2009, 2010, 2011, 2012).
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1 Table 3–16. Commercial Harvest Rates for Nonroe Fish and Turtles From Chickamauga 

2 Reservoir From 2008 to 2011

Species Common Name

Chickamauga Reservoir 

Total Weight (lb)(a)

2008(a) 2009(a) 2010 2011

Alosa chrysochloris shad (skipjack 

herring) 317 0 NR NR

Aplodinotus grunniens freshwater drum 6,674 7,456 4,276 445

Chelydra serpentina snapping turtle 70 349 NR NR

Cyprinus carpio common carp 2,536 3,944 775 NR

Hypophthalmichthys molitrix and H. 

nobilis silver or bighead carp 331 63 NR NR

Ictalurus furcatus and I. punctatus blue or channel 

catfish 147,104 244,035 95,414 37,639

Ictiobus bubalus buffalo fish 14,641 5,525 12,002 160

Lepisosteus sp. gar 67 881 25 NR

Morone mississippiensis yellow bass 10 0 NR NR

Multiple species catfish 1,289 13,814 7,975 NR

Pylodictis olivaris flathead catfish 2,806 9,132 2,226 NR

NR = not reported

(a) Black 2010; Ganus 2013
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1 Table 3–17. Number of Fish Caught in Annual Creel Surveys of the Chickamauga 

2 Reservoir

Species

Common 

Name

Chickamauga

2007 2008 2009 2010 2011

Centrarchidae

Lepomis gulosus warmouth 1,192 609 42 6,150 4,804

Lepomis macrochirus bluegill 573,417 490,803 332,956 370,552 375,262

Micropterus dolomieu smallmouth 

bass 18,821 17,921 18,631 19,578 11,446

Micropterus punctulatus spotted bass 72,874 69,585 48,309 63,156 34,147

Micropterus salmoides largemouth 

bass 238,006 223,018 226,986 344,798 262,997

Pomoxis annularis white crappie 54,654 31,070 20,934 63,400 57,561

Pomoxis nigromaculatus black crappie 201,365 114,294 138,077 208,103 156,174

Pomoxis nigromaculatus blacknose 

crappie 662 48 3,594 2,364 1,091

Others

Alosa chrysochloris skipjack herring 3,812 0 0 0 0

Alosa pseudoharengus alewife 185 0 0 0 0

Cyprinus carpio common carp 92 0 0 0 0

Notemigonus crysoleucas golden shiner 196 1,340 0 0 730

Esox masquinongy × lucius tiger muskie 100 0 0 0 0

Ictalurus furcatus blue catfish 167,105 156,086 160,927 206,950 158,383

Ictalurus punctatus channel catfish 54,917 67,755 38,180 56,770 17,565

Pylodictis olivaris flathead catfish 10,751 11,100 5,596 5,686 7,833

Lepisosteus osseus longnose gar 0 92 0 0 0

Hybrid striped bass × white 

bass Cherokee bass 40 64 0 0 0 

Morone chrysops white bass 52,626 93,407 67,490 53,282 40,623

Morone mississippiensis yellow bass 159,219 142,693 82,770 148,053 143,234

Morone saxatilis striped bass 7,789 18,489 9,646 22,672 9,422

Aplodinotus grunniens freshwater drum 36,095 65,696 24,906 33,219 40,718

Perca flavescens yellow perch 0 0 105 0 1,228

Sander canadensis sauger 1,666 22,784 22,806 11,533 5,996

Polyodon spathula paddlefish 137 0 0 166 123

Sources: Black 2008, 2009, 2010, 2011, 2012

3 Biologically Important Fish Species

4 This section describes biologically important species, their relationship to the aquatic habitat 

5 near the SQN site, and their interactions with each other. Discussion includes species that are 

6 numerically dominant, thermally sensitive, use the area as spawning or nursery grounds, 

7 migrate past the site to spawn, have recreational or commercial value, are important links in the 

8 local food web, or are critical to the ecosystem. 
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1 Gizzard Shad (Dorosoma cepedianum). Gizzard shad are prolific spawners. An average size 

2 female gizzard shad produces about 300,000 eggs per year. Gizzard shad deposit their eggs in 

3 substrate (e.g., boulders, logs, or debris). The eggs adhere to the substrate and hatch in 2 to 

4 3 days. Gizzard shad typically spawn from mid-May to mid-June in Tennessee (Etnier and 

5 Starnes 1993). After spawning, gizzard shad larvae migrate away from the shoreline to the 

6 limnetic zone (open water). Garvey and Stein (1998) observed that larval gizzard shad always 

7 emerged in the limnetic zone before larval threadfin shad. As larvae, gizzard shad feed 

8 primarily on zooplankton. As juveniles, gizzard shad are strictly planktivores (i.e., feeding on 

9 plankton). Once they reach 2.5 to 3.5 cm (0.98 to 1.4 in.) in total length, gizzard shad become 

10 omnivores and feed on detritus in addition to zooplankton and phytoplankton (Stein et al. 1995). 

11 Threadfin Shad (Dorosoma petenense). Threadfin shad are smaller than gizzard shad (less 

12 than 8.5 in. (22 cm)) and usually live for only 2 to 3 years. Spawning occurs along the shoreline 

13 in the spring and possibly in autumn (Etnier and Starnes 1993). After hatching, the larvae move 

14 into the limnetic zone (open water away from the shore) (Armstrong et al. 1998). Threadfin 

15 shad synchronize their spawning time and spawn in groups a few hours after sunrise. 

16 Ecologists believe the synchronous behavior allows predator avoidance and rapidly strengthens 

17 populations that may have been depleted during the winter (Etnier and Starnes 1993). Both the 

18 young and adult are planktivores, eating about half their diet from phytoplankton and half from 

19 zooplankton (Etnier and Starnes 1993). Threadfin shad are not cold tolerant and are 

20 susceptible to large winter die-offs when temperatures drop. Sublethal effects such as feeding 

21 cessation can begin at 10 °C (50 °F). Inactivity occurs at 6 to 7°C (43 to 45 °F), and death at 4 

22 to 5 °C (39 to 41 °F), although death has been reported at temperatures as high as 12 °C (54 °F) 

23 (Etnier and Starnes 1993).

24 Bluegill (Lepomis macrochirus). Bluegill is one of the sunfish species found around the SQN 

25 site. Bluegill are both a forage and a game fish. The young are abundant and provide prey for 

26 bass. Bluegill frequent shallow water with vegetative cover, submerged wood, or rocks. They 

27 spawn from late spring into summer. Like other sunfish, male bluegill construct nests in shallow 

28 water on varied substrates (although they prefer gravel) and guard the eggs until hatching 

29 occurs. Young sunfish frequent weed beds or other heavy cover. Bluegill eat a varied diet, 

30 including midge larvae and microcrustaceans (Etnier and Starnes 1993). Etnier and Starnes 

31 (1993) report that bluegill select larger prey when abundant but become less selective as the 

32 abundance of their preferred prey decreases. Because juvenile bluegill are prey for largemouth 

33 bass, the population of bluegill can affect the largemouth bass population. 

34 Black Bass (Micropterus spp.). Black bass include largemouth bass (Micropterus salmoides), 

35 smallmouth bass (M. dolomieu), and spotted bass (M. punctulatus). Largemouth bass and 

36 spotted bass inhabit lower velocity portions of streams and larger lakes and reservoirs. In 

37 reservoirs, smallmouth bass prefer steep rocky slopes along submerged river and creek 

38 channels. Smallmouth and spotted bass spawn in April or early May, and largemouth bass 

39 spawn from late April to June. Black bass construct nests in coarse gravel at depths less than 

40 1 m (3.3 ft) near the margins of streams or lakes (smallmouth bass) or in other types of gravel or 

41 firm substrates (spotted bass and largemouth bass) along the shallow margins of lakes. For all 

42 three species, the males guard the nests until the fry have hatched. For smallmouth bass, 

43 hatching requires about 4 to 6 days; fry swim up from the nest 5 to 6 days later. The fecundity 

44 of females varies with the size of the fish, but they may produce from 2,000 to 145,000 eggs. 

45 Young bass feed on zooplankton, insects, and small fish, and are cannibalistic (Etnier and 

46 Starnes 1993). Smallmouth and spotted bass feed primarily on small fish, crayfish, and aquatic 

47 insects. Largemouth bass prey on bluegill, redear sunfish, shad, minnows, crayfish, and 

48 amphibians (Mettee et al. 1996). Gizzard shad are reported by numerous sources to be 

49 preferred by largemouth bass and other piscivores over bluegill or other Lepomis species 
Affected Environment

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1 (Aday et al. 2003). Gizzard shad grow too large to be the primary prey for largemouth bass; 

2 thus, largemouth bass likely switch to other prey (Aday et al. 2003).

3 The TWRA has been stocking Florida black bass fingerlings into Chickamauga Reservoir since 

4 2000. The goal of this stocking program is to encourage hybridization and introgression of the 

5 stocked fish with those native to the Tennessee River system. Florida largemouth bass are a 

6 subspecies of largemouth bass and they have greater size and longevity compared to the 

7 largemouth bass found in the Tennessee River (TWRA 2013f). Over 250,000 Florida 

8 largemouth bass were stocked in Chickamauga Reservoir in the spring of 2013 (TWRA 2013a).

9 Interactions Between Shad, Bluegill, and Largemouth Bass. Multiple ecological interactions 

10 occur between sunfish and shad, which, in some cases, are stimulated by the timing of the 

11 increase in reservoir water levels and spring warming.

12 Larval gizzard shad can be a strong competitor with other fish, such as bluegill, for zooplankton 

13 in reservoirs because of their high numbers, feeding preference for smaller zooplankton (based 

14 on their mouth size), and the timing of their appearance. Many factors may influence the timing, 

15 abundance, and size of the shad larvae and so intensify or mitigate the competition for 

16 zooplankton. Such factors include the relative timing of hatching of the bluegill larvae, water 

17 fluctuations (e.g., spring reservoir water levels), temperature (specifically the timing of spring 

18 warming), primary productivity, and turbidity (Garvey and Stein 1998). Hatchery experiments 

19 conducted by Garvey and Stein (1998) show that gizzard shad, when introduced 2 weeks 

20 before the introduction of bluegill, depleted the zooplankton and affected the growth of the 

21 bluegill but not their survival. When both species were introduced simultaneously, the 

22 abundance of zooplankton declined only slightly with only a small effect on bluegill growth and 

23 survival.

24 Aday et al. (2003) conjecture that other indirect effects (e.g., serving as an alternative prey for

25 largemouth bass) may have a greater influence on the size structure of the bluegill population 

26 than competition between bluegill and shad larvae for zooplankton. Gizzard shad appear to be 

27 preferred by largemouth bass and other piscivores over bluegill or other Lepomis species (Aday 

28 et al. 2003). Aday et al. (2003) indicate that gizzard shad may grow too rapidly and ultimately 

29 become too large of a prey for largemouth bass. 

30 In addition, timing of increased spring reservoir water levels can affect the nesting sites and 

31 forage areas for bluegills and other sunfish, including the largemouth bass. This, in turn, can 

32 affect shad competition for zooplankton as well as the number of adult largemouth bass that will 

33 prey upon the shad.

34 Armstrong et al. (1998) examined the similarities and differences between gizzard shad and 

35 threadfin shad larvae and found that they were ecologically similar, especially in terms of diet, 

36 taxonomy, prey-size selection, and mouth structure, which relates to prey selection. Threadfin 

37 shad and gizzard shad larvae likely compete when resources are limiting, although spatial and 

38 temporal distribution of the larvae differ once they move into the limnetic zone of the reservoir 

39 (Armstrong et al. 1998). 

40 Black and White Crappie (Pomoxis nigromaculatus and P. annularis). Both black and white 

41 crappie are popular sport and food fishes. The white crappie inhabits slow-moving streams and 

42 lakes and is tolerant of turbidity. The black crappie prefers clear waters and is more abundant 

43 in natural lakes, although it does well in less turbid reservoirs. Spawning for both occurs from 

44 April to June. In general, black and white crappie spawn in shallow, protected areas 

45 (e.g., coves and deeper overflow pools near vegetation (black crappie), brush, and overhanging 

46 banks). Hatching requires 2 to 5 days depending on the water temperature. Adult males guard 

47 the nests until the fry have dispersed. Females contain from 10,000 to 160,000 mature eggs 
Affected Environment

3-69

1 and spawn repeatedly in the nests of several males over the season. Young crappie feed on 

2 small invertebrates, including microcrustaceans and small insects, but prey progressively more 

3 on fish as they mature. Adults feed heavily on forage fish (e.g., shad) but they also consume 

4 microcrustaceans and other plankton (Etnier and Starnes 1993; Mettee et al. 1996).

5 In the 1980s, the adult white crappie population appeared to be declining. TVA (Buchanan and 

6 McDonough 1990) conducted a study from 1986 through 1989 to determine the status of the 

7 white crappie in Chickamauga Reservoir and to determine if the operation of SQN was a 

8 contributing factor to the decline. The study investigated larval fish, young-of-the-year, and 

9 adult fish. The decline in white crappie population was substantiated. The more recent 

10 gillnetting and electrofishing studies between 1999 and 2012 (TVA 2012c) both upstream and 

11 downstream of the plant reveal a larger number of black crappie than white. Factors correlating 

12 with the decline of the white crappie population in the study in the late 1980s include an 

13 increased density of aquatic macrophytes and competition between species (Buchanan and 

14 McDonough 1990). Based on the distribution of crappie in the reservoir, the lack of apparent 

15 attraction to the thermal discharge, and the identification of preferred spawning habitat distant 

16 from the SQN site, those authors attributed no connection to the operation of SQN.

17 White and Yellow Bass (Morone chrysops and M. mississippiensis). White and yellow bass are 

18 important game fish in the Chickamauga and Watts Bar reservoirs. Yellow bass school and 

19 avoid flowing water habitats more so than the white bass (Etnier and Starnes 1993). Both 

20 species spawn in midwater, although the yellow bass can migrate into large streams or 

21 tributaries to spawn. Spawning runs for white and yellow bass occur in mid-February and in 

22 April and May, respectively. The eggs of both species drift to the bottom and are adhesive. 

23 White and yellow bass larvae hatch in 2 days and in 4 to 6 days, respectively. Rather than 

24 being passively transported downstream with the river flow, the larvae of white bass in the 

25 Tennessee River appear to use areas of low velocity as refuge or stay near the bottom of the 

26 river. Juveniles eat small invertebrates (e.g., cladocerans, copepods, and midge larvae) (Etnier 

27 and Starnes 1993). Adults are aggressive predators and feed on threadfin and gizzard shad 

28 (Mettee et al. 1996), silverside, and occasionally young sunfish (Etnier and Starnes 1993). In

29 some populations, adult yellow bass continue to feed heavily on aquatic insects (Etnier and 

30 Starnes 1993).

31 Emerald Shiner (Notropis atherinoides). The emerald shiner was observed more frequently at 

32 the sampling site upstream from the SQN site (Tennessee RM 490.5) prior to 2008; very few 

33 have been found since 2008. A similar decrease in the emerald shiner population was 

34 observed in the vicinity of the Watts Bar Nuclear site (NRC 2013a), although the timing of the 

35 decline indicated that the operation of the Watts Bar plant was not likely the cause. Crowder 

36 (1980) documented cases of dramatic reductions in emerald shiner populations in other 

37 locations. In several cases, competition with another fish species (alewife (Alosa 

38 pseudoharengus)) contributed to the decline. Alewife have not been found in Chickamauga 

39 Reservoir, but other clupeids (e.g., gizzard shad and threadfin shad) are prolific in the reservoir. 

40 Short et al. (1998) identified a decline in water quality as the impetus for reduced emerald shiner 

41 populations.

42 Freshwater Drum (Aplodinotus grunniens). Freshwater drum are common in large rivers and 

43 reservoirs and prefer backwaters and areas with slow current. They are an important part of the 

44 commercial fishery in the larger rivers and reservoirs of Tennessee. Freshwater drum are 

45 broadcast spawners and spawn large numbers of eggs (40,000 to 60,000 per female) in 

46 midwater at water temperatures in the range of 18 to 20 °C (64 to 68 °F) (Etnier and 

47 Starnes 1993). Spawning in this stretch of the Tennessee River typically occurs in late spring, 

48 although it can also continue into the late summer (TVA 2012c). The eggs are pelagic and float 

49 until they hatch, within 1 to 2 days (Etnier and Starnes 1993). The larvae are small, about 
Affected Environment

3-70

1 3.2 mm (0.13 in.) long at hatching, and grow rapidly; they are considered juveniles a few weeks 

2 later when 1.5 cm (0.60 in.) long. The larvae feed on other fish larvae, especially shad and 

3 younger drum. Individuals are 10 to 12 cm (4 to 5 in.) long by autumn, at which time they begin 

4 to feed on zooplankton, small crustaceans (e.g., amphipods), and aquatic insects. Freshwater 

5 drum grow rapidly with the young-of-the-year reaching 10 to 12 cm (4 to 5 in.) (Becker 1983). 

6 Sauger (Sander canadensis). Sauger inhabit large, often turbid rivers and have been 

7 successful in many reservoirs (Etnier and Starnes 1993). They spawn from April through May, 

8 commonly over rubble and gravel in tailwaters (Etnier and Starnes 1993). In Chickamauga 

9 Reservoir, spawning occurs approximately 13 km (8 mi) downstream of Watts Bar Dam 

10 (TVA 1989) at Hunter Shoals (Hevel and Hickman 1991). Eggs adhere to rubble and gravel 

11 immediately after spawning, but soon become nonadhesive and may be widely dispersed in 

12 currents. Larger females can produce over 100,000 eggs annually, but most produce 20,000 to 

13 60,000 eggs. Larvae feed on cladocera, copepods, and midge larvae. Juveniles switch to a 

14 diet almost exclusively of fish, primarily gizzard and threadfin shad in the Tennessee River 

15 Basin (Etnier and Starnes 1993), although they are also known to feed on young walleye 

16 (Sander vitreum), sauger, white bass, crappie, and yellow perch (Mettee et al. 1996).

17 In an effort to understand the population dynamics of sauger in Chickamauga Reservoir, TVA

18 used standard and experimental gillnets during special studies conducted from 1993 to 1994 in 

19 the upper 24 km (14.9 mi) of the reservoir (Hickman and Buchanan 1995). Hickman and 

Buchanan concluded that an instantaneous minimum discharge of 8,000 cfs (227 m3 20 /s) was 

21 necessary and sufficient to ensure appropriate conditions for successful sauger reproduction. 

22 Hickman and Buchanan (1995) also concluded that the thermal variance instituted for SQN 

23 discharge from November through March had no adverse impact on the sauger population in 

24 Chickamauga Reservoir and, further, that the sauger did not show an attraction to or an 

25 avoidance of the diffuser area and the thermal plume. Based on tagging studies and returns by 

26 fishermen, sauger appear to move through Watts Bar Dam into the upstream reservoir, although 

27 in low numbers (3 to 9 percent during the 1993 and 1994 study (Hickman and Buchanan 1995)). 

28 Catfish (Ictalurus spp.). Catfish in the Chickamauga Reservoir include the blue catfish 

29 (I. furcatus) and channel catfish (I. punctatus). Catfish are both recreationally and commercially 

30 important species. Members of the family Ictaluridae spawn in summer and deposit their eggs 

31 in depressions or nests constructed in natural cavities and crevices in rivers. Male catfish 

32 display territorial behavior after spawning and aggressively defend their eggs. Catfish are 

33 opportunistic feeders and eat aquatic insect larvae, crayfish, mollusks, and small fish (live and 

34 dead) (Etnier and Starnes 1993; Mettee et al. 1996).

35 Paddlefish (Polyodon spathula). Paddlefish are large fish (generally greater than 40 in. (1 m)

36 and 44 to 66 lb (20 to 30 kg)) with a life span that may exceed 20 years. They spawn in swift 

37 water over gravel bars in the spring. Although female paddlefish do not spawn every year, they 

38 do produce large numbers of eggs (more than 500,000 eggs) during spawning. Paddlefish are 

39 commercially fished in Chickamauga Reservoir (Table 3–15) for both meat and roe (eggs). 

40 Juvenile paddlefish are reportedly susceptible to impingement on cooling water intake screens 

41 (Etnier and Starnes 1993).

42 Nonindigenous Species 

43 Five nonindigenous species were collected during the sampling studies between 1999 and 2011 

44 (TVA 2012c). Redbreast sunfish, yellow perch, and striped bass are considered valuable sports 

45 and commercial fishing species. The common carp and inland silversides are considered 

46 aquatic nuisance species. 
Affected Environment

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1 Redbreast sunfish (Lepomis auritus). Redbreast sunfish, native to the Atlantic slope drainages, 

2 were introduced intentionally for sport fishing and are considered an invasive species. 

3 Redbreast sunfish have been found in the vicinity of the SQN site. This species may have 

4 caused the decline or extirpation of many native longear sunfish populations through direct 

5 competition (Etnier and Starnes 1993), although longear sunfish still occur in the Chickamauga 

6 Reservoir (TWRA 2008).

7 Yellow perch (Perca flavescens). Yellow perch have been introduced into many states, 

8 including Tennessee, from their native range in the middle Mackenzie drainage in Canada 

9 through the northern states east of the Rocky Mountains and to the Atlantic Slope drainages 

10 south to South Carolina. They were introduced in the late 1800s for food and sport fishing. 

11 Yellow perch are known to compete for food resources with trout and are valuable prey for 

12 walleye (TWRA 2008). Yellow perch have been found in the vicinity of the SQN site.

13 Striped bass (Morone saxatilis). Etnier and Starnes (1993) characterize striped bass as “an 

14 extremely important game and commercial species.” Striped bass in North American inland 

15 waters are offspring of the anadromous striped bass that became land-locked when the Santee 

16 River in South Carolina was impounded in the 1940s. The eggs of the striped bass must remain 

17 suspended in the current until the larvae hatch (1 to 3 days). As a result, the impoundment of 

18 the Tennessee River eliminated most, if not all, reproduction, and the striped bass in 

19 Chickamauga Reservoir are introduced from hatcheries (Etnier and Starnes 1993).

20 Inland silverside (Menidia beryllina). Inland silversides are native to coastal and freshwater 

21 habitats from Massachusetts to Mexico. They were not found in the Tennessee River until 

22 1991, when first collected from the Kentucky Reservoir. In 2004, the first individuals were 

23 collected in the Chickamauga Reservoir at the upstream sampling location near the SQN site 

24 (Simmons 2010a). By 2010, inland silversides made up over 32 percent of the fish caught 

25 during electrofishing upstream of the SQN site (Tennessee RM 490.5) and 46 percent of the fish 

26 caught during electrofishing at the downstream site (Tennessee RM 482). Percentages at both 

27 sites dropped to zero by 2011, although large numbers of Mississippi silversides (M. audens) 

28 were reported from the electrofishing surveys. M. audens is reported to be a synonym for 

29 M. beryllina (ITIS 2013) and is considered to be the same species, so the zeros no doubt 

30 represent a reporting difference rather than a disappearance of inland silversides. In the last 

31 2 years, the inland silverside has been the numerically dominant species in the downstream 

32 electrofishing samples. Inland silversides introduced in Oklahoma almost completely replaced 

33 brook silversides; however, more time is needed to understand the impact on the brook 

34 silverside populations in the Tennessee River, as well as on other species with similar 

35 ecological niches (TWRA 2008).

36 Carp (Cyprinus carpio, Ctenopharyngodon idella, and Hypophthalmichthys spp.). Carp are 

37 nonnative fish introduced into North America from Eurasia. Carp are considered invasive 

38 species and have clearly changed the population dynamics of Tennessee River aquatic 

39 communities. Several species of carp are present in Tennessee River aquatic communities. 

40 Common carp have been present for over 100 years and currently exist in all reservoirs, 

41 including the vicinity of the SQN site. Grass carp (Ctenopharyngodon idella) have been 

42 introduced throughout much of the United States for biological control of nuisance aquatic 

43 plants, but were not identified in the sampling studies in the vicinity of the SQN site. Grass carp 

44 primarily inhabit the lower portions of the river system. Silver carp (Hypophthalmichthys 

45 molitrix) and bighead carp (H. nobilis) have been found in parts of Chickamauga Reservoir 

46 (Black 2010) but were not identified in the sampling studies in the vicinity of the SQN site. Carp 

47 are detrimental to the native fauna and negatively affect water quality. They are highly tolerant 

48 of poor water-quality conditions, and researchers expect them to continue to spread throughout 

49 the Tennessee River system.
Affected Environment

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1 Carp are important commercial fish, and the grass carp has a recreational value in some 

2 Tennessee River reservoirs such as Guntersville Reservoir. These fish tend to frequent deep 

3 water (up to 6 m (20 ft) deep). They are omnivores that feed on the bottom (mostly in mud) and 

4 eat worms; insect larvae; plankton; vascular plants; and, occasionally, small fish (Etnier and 

5 Starnes 1993; Mettee et al. 1996). Carp increase the turbidity of the water as they feed and 

6 spawn, decreasing light penetration and primary productivity and covering the eggs of other fish 

7 species with silt, both of which are detrimental environmental effects. Spawning occurs in the 

8 spring, in flooded fields or along the shore of the reservoir, and the eggs are small and

9 adhesive. Female carp may produce over 2,000,000 eggs in a given season and may release 

10 600,000 or more in a given spawning period (Etnier and Starnes 1993). Carp are long-lived fish 

11 species (20 years) and reach sizes of 23 to 36 kg (50 to 80 lb) (Etnier and Starnes 1993).

12 State-Listed Aquatic Species 

13 The State of Tennessee has identified species that occur near the SQN site for special 

14 protection. Table 3–18 lists those species that are present in Hamilton County and protected by 

15 the State of Tennessee. The list includes one amphibian, two fish, five freshwater mussels, and 

16 one crustacean. Some of these species (all five mussels and the snail darter) are also 

17 Federally protected under the ESA. This section discusses those species protected only by the 

18 State, and Section 3.8 discusses those species protected under the ESA alone or in 

19 combination with the State. The species protected only by the State include a crustacean, the 

20 Chickamauga crayfish (Cambarus extraneus); one fish, the highfin carpsucker (Carpiodes 

21 velifer); and an amphibian, the Tennessee cave salamander (Gyrinophilus palleucus).
Affected Environment

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1 Table 3–18. State-Listed Protected Aquatic Species Present in Hamilton County, TN

Scientific Name

Common 

Name

State of 

Tennessee 

Status

Federal 

Status Habitat

Crustacean

Cambarus 

extraneus

Chickamauga 

crayfish

Threatened None Springs & small- to 

medium-sized streams under 

rocks or in vegetation; South 

Chickamauga Creek 

watershed, Hamilton County

Mussels

Dromus dromas dromedary 

pearly mussel

Endangered Endangered Medium-large rivers with 

riffles and shoals with 

relatively firm rubble, gravel 

and stable substrates

Lampsilis abrupta pink mucket Endangered Endangered Generally a large river 

species, preferring 

sand-gravel or rocky 

substrates with moderately 

strong currents

Plethobasus 

cooperianus

orangefoot 

pimpleback 

pearlymussel

Endangered Endangered Large rivers in 

sand-gravel-cobble 

substrates in riffles and 

shoals in deep flowing water

Pleurobema 

plenum

rough pigtoe Endangered Endangered Medium-to-large rivers in 

sand, gravel and cobble 

substrates of shoals

Quadrula 

intermedia

Cumberland 

monkeyface

Endangered Endangered Shallow riffle and shoal 

areas of headwater streams 

and bigger rivers, in coarse 

sand/gravel substrates 

Tennessee River system

Fish

Carpiodes velifer highfin 

carpsucker

Deemed in 

Need of 

Management

None Large rivers, mostly in 

Tennessee River drainage

Percina tanasi snail darter Threatened Threatened Sand and gravel shoals of 

moderately flowing, 

vegetated, large creeks

Amphibian

Gyrinophilus 

palleucus

Tennessee 

cave 

salamander

Threatened None Aquatic cave obligate; cave 

streams and rimstone pools; 

Central Basin, Eastern 

Highland Rim and 

Cumberland Plateau

Sources: FWS 2013b; TDEC 2013b 
Affected Environment

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1 Crustacean

2 Chickamauga crayfish are threatened in the State of Tennessee but not Federally listed. They 

3 have a very small range and are found in the South Chickamauga Creek basin in Hamilton 

4 County and in Walker and Whitfield Counties in Georgia. They prefer moderately flowing 

5 shallow streams; are usually found under rocks or in leaf litter debris; and are omnivorous 

6 scavengers that eat aquatic vegetation, small fish, snails, and aquatic insects (Georgia Museum 

7 of Natural History 2008). South Chickamauga Creek enters the Tennessee River downstream 

8 of Chickamauga Dam. For this reason, Chickamauga crayfish would not be affected by 

9 operation of SQN and are not discussed further in this SEIS.

10 Fish 

11 The State deems the highfin carpsucker, the smallest carpsucker in Tennessee, as “in need of 

12 management” for Hamilton County. They live in areas of gravel substrate in relatively clear 

13 medium-to-large rivers. Highfin carpsuckers are more susceptible to impoundment and siltation 

14 than other carpsuckers and, in Tennessee, are known to persist in the Nolichucky, French 

15 Broad, Clinch, Hiwassee, Sequatchie, and Duck River systems (Etnier and Starnes 1993). In 

16 2004, TVA found a single individual approximately 5 mi (8 km) upstream from the intake of the 

17 SQN plant during an electrofishing survey (TVA 2013d-f).

18 Amphibians

19 Tennessee cave salamanders are listed as threatened. They are found only in the southern 

20 Appalachian Mountains of Tennessee, Georgia, and Alabama. They inhabit limestone caves 

21 with subterranean waters (SREL 2013). No caves are present on the SQN site. For this 

22 reason, the Tennessee cave salamander would not be affected by operation of SQN and is not 

23 discussed further in this SEIS. 

24 Reintroductions 

25 The State of Tennessee and various partner groups are working to reintroduce the lake 

26 sturgeon into the upper Tennessee River watershed (TWRA 2013f). Since 2000, the TWRA

27 has stocked over 125,000 lake sturgeon (Tennessee Aquarium 2013) into rivers including the 

28 French Broad, Holston, and Tennessee rivers downstream of Douglas and Cherokee 

29 Reservoirs (TWRA 2013f). In addition, the Tennessee Aquarium introduced approximately

30 100 lake sturgeon into Nickajack Reservoir between 2010 and 2011 (TWRA 2013a). The 

31 sampling studies conducted by TVA between 1999 and 2011 identified a single lake sturgeon, 

32 collected in 2003 by gillnet, from the sampling site located upstream of the SQN intake at 

33 Tennessee RM 490.5 (TVA 2012c).

34 Lake sturgeon are considered endangered by the State of Tennessee, but are not Federally 

35 listed by the Fish and Wildlife Service. Lake sturgeon are large fish that can reach 4 m (13 ft) 

36 and 310 lb (141 kg). They are slow to mature; first spawning occurs between 14 and 25 years 

37 for females and 12 and 20 years for males. Lake sturgeon are considered to be the longest 

38 lived North American freshwater fish, with a maximum age estimate of 154 years, although 

39 populations in Tennessee would be expected to have a smaller size and shorter life span than 

40 those farther north (Etnier and Starnes 1993). 

41 3.8 Special Status Species and Habitats

42 This section addresses species and habitats that are Federally protected under the ESA and the 

43 Magnuson–Stevens Fishery Conservation and Management Act, as amended 

44 (16 U.S.C. §1801–1884, herein referred to as Magnuson–Stevens Act). The ESA, along with 

45 the Magnuson–Stevens Act, put requirements on Federal agencies such as the NRC. The 
Affected Environment

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1 terrestrial and aquatic resource sections of this SEIS (Sections 3.6 and 3.7, respectively) 

2 discuss other species and habitats protected by other Federal acts and the State of Tennessee

3 that do not put requirements on the NRC.

4 3.8.1 Species and Habitats Protected Under the Endangered Species Act

5 The FWS and the National Marine Fisheries Service (NMFS) jointly administer the ESA. The 

6 FWS manages the protection of, and recovery effort for, listed terrestrial and freshwater 

7 species, and NMFS manages the protection of and recovery effort for listed marine and 

8 anadromous species. This section describes the action area and considers those species that 

9 could occur in the action area under both FWS’s and NMFS’s jurisdictions. Section 4.8 

10 assesses potential impacts to Federally listed species and habitats that could result from the 

11 proposed action and alternatives, and Appendix C describes the NRC’s consultation with FWS 

12 pursuant to section 7 of the ESA.

13 3.8.1.1 Action Area

14 The implementing regulations for section 7(a)(2) of the ESA define “action area” as all areas 

15 affected directly or indirectly by the Federal action and not merely the immediate area involved 

16 in the action (50 CFR 402.02). The action area effectively bounds the analysis of 

17 ESA-protected species and habitats because only species that occur within the action area may 

18 be affected by the Federal action.

19 For the purposes of the ESA analysis in this SEIS, the NRC staff considers the action area to be 

20 the SQN site (described in Sections 3.1 and 3.6) and the Chickamauga Reservoir (described in 

21 Section 3.7) from the point of river water intake at the site (at Tennessee River Mile (TRM) 

22 485.1) and extending 4.1 mi (6.6 km) downstream to TRM 481.0. This area of the reservoir 

23 corresponds to the area over which the thermal plume extends during the summer 

24 measurement period (as discussed in Section 4.7). The NRC staff expects all direct and 

25 indirect effects of the proposed action to be contained within these areas.

26 The NRC staff recognizes that while the action area is stationary, Federally listed species can 

27 move in and out of the action area. For instance, a migratory fish species could occur in the 

28 action area seasonally as it travels up and down the river past SQN. Similarly, a flowering plant 

29 known to occur near, but outside, of the action area could appear within the action area over 

30 time if its seeds are carried into the action area by wind, water, or animals. Thus, in its analysis, 

31 the NRC staff considers not only those species known to occur directly within the action area, 

32 but those species that occur near the action area. The staff then considers whether the life 

33 history of each species makes the species likely to move into the action area where it could be 

34 affected by the proposed SQN license renewal.

35 Within the action area, Federally listed terrestrial species could experience impacts such as 

36 habitat disturbance associated with refurbishment or other ground-disturbing activities, cooling 

37 tower drift, collisions with cooling towers and transmission lines, exposure to radionuclides, and 

38 other direct and indirect impacts associated with station, cooling system, and in-scope 

39 transmission line operation and maintenance (NRC 2013d). The proposed action has the 

40 potential to affect Federally listed aquatic species in several ways: impingement or entrainment

41 of individuals into the cooling system; alteration of the riverine environment through water level 

42 reductions, changes in dissolved oxygen, gas supersaturation, eutrophication, and thermal 

43 discharges from cooling system operation; habitat loss or alteration from dredging; and 

44 exposure to radionuclides (NRC 2013d).
Affected Environment

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1 3.8.1.2 Species and Habitats Under the FWS’s Jurisdiction

2 Table 3–19 identifies the species under FWS’s jurisdiction that may occur within Hamilton 

3 County. Hamilton County includes approximately 369,000 ac (149,000 ha) of varying land uses 

4 and habitat types. Thus, a Federally listed species that occurs within Hamilton County does not 

5 necessarily occur within the action area. The NRC staff uses this geographical range as a 

6 starting point for its analysis because Federally listed species distribution and critical habitat

7 information is readily available at the county level. Additionally, the action area is a small area 

8 of land near the center of and wholly contained within the geographical boundaries of the 

9 county. Following the table, descriptions of each species include a determination of whether 

10 each species occurs in the action area based on the species’ habitat requirements, life history, 

11 and available occurrence information.

12 The NRC compiled the list of species in Table 3–19 from the FWS’s Endangered Species 

13 Program online database (FWS 2014); correspondence between the NRC and the FWS 

14 (FWS 2013b, 2013c; NRC 2013g); information from TVA’s ER (TVA 2013n) and Natural 

15 Heritage Database (TVA 2013j); and available scientific studies, surveys, and literature.

16 The NRC staff did not identify any candidate species or proposed or designated critical habitats 

17 within the action area.
Affected Environment

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1 Table 3–19. Federally Listed Species in Hamilton County, TN

Species(a) Common Name Federal 

Status Habitat

Mammals

Myotis grisescens gray bat Endangered limestone karst areas within the 

southeastern United States

Myotis septentrionalis northern long-eared bat Protected Hardwood forests; caves and 

mines with cool, moist air

Myotis sodalis Indiana bat Endangered

Hardwood forests and 

hardwood-pine forests; oldgrowth forest; agricultural lands, 

and old fields

Fish

Percuba tanasi snail darter Threatened

Sand and gravel shoals of 

moderately flowing, vegetated, 

large creeks

Freshwater Mussels

Dromus dromas dromedary pearlymussel Endangered

Medium to large rivers with 

riffles and shoals with relatively 

firm rubble, gravel, and stable 

substrates

Lampsilis abrupta pink mucket Endangered

Generally a large river species, 

preferring sand-gravel or rocky 

substrates with moderate to 

strong currents

Plethobasus cooperianus orangefoot pimpleback Endangered

Large rivers in sand-gravelcobble substrates in riffles and 

shoals in deep flowing water

Pleurobema plenum rough pigtoe Endangered

Medium to large rivers in sand, 

gravel, and cobble substrates of 

shoals

Plants

Isotria medeoloides small whorled pogonia Threatened Hardwood or conifer-hardwood 

forest floors near stream beds

Scutellaria montana large-flowered skullcap Threatened

Mid- to late-successional forests 

dominated by oak and pine 

trees

Spiraea virginiana Virginia spiraea Threatened

Floodplains, riverbanks, and 

other riparian habitat in the 

southern Appalachian 

Mountains

(a) The NRC preliminarily considered two additional species—the Cumberland monkeyface (Quadrula intermedia; 

Federally endangered) and the white fringeless orchid (Platanthera integrilabia; candidate for Federal listing)—in 

its early correspondence with FWS (NRC 2013g). However, the NRC staff determined that these species do not 

occur within Hamilton County, and thus, would not occur within the action area based on historical and known 

occurrence information and habitat requirements.

Sources: FWS 2013b, 2013c, 2014; NRC 2013g; TVA 2013j, 2013n 
Affected Environment

3-78

1 Gray Bat (Myotis grisescens) 

2 The FWS listed the gray bat as endangered in 1976 (40 FR 17590). No critical habitat has been 

3 designated for this species. White nose syndrome, human disturbance, water impoundments, 

4 and other activities resulting in loss of habitat are factors that have contributed to this species’ 

5 decline. Unless otherwise indicated, information on this species below is derived from the 

6 FWS’s Gray Bat Recovery Plan (Brady et al. 1982).

7 The gray bat is the largest Myotis species with a wingspan of 40 to 46 mm (1.7 to 1.8 in.), and it 

8 is distinguishable from other bat species by its unicolor dorsal fur, which is dark gray after 

9 molting in July and August and chesnut brown to russet between moltings. The species mainly 

10 inhabits five states in the southeastern United States (Alabama, Arkansas, Kentucky, Missouri, 

11 and Tennessee) and is also found in small numbers as far north as Illinois and as far south as 

12 northwestern Florida. Distribution of the species has always been patchy, but fragmentation 

13 and isolation of populations has increased as the species has become more in danger of 

14 extinction. 

15 Gray bats migrate seasonally between hibernating and maternity caves. Upon arrival at 

16 hibernating caves in September through early October, adults mate and enter hibernaculum. 

17 Adults emerge beginning in late March, at which time they migrate to summer habitat. Mortality 

18 is typically high during this time because fat reserves and food supplies are low. Summer 

19 colonies occupy traditional home ranges that include a maternal cave and several roost caves 

20 typically located along a river or reservoir. Hibernating females store sperm until spring, and 

21 give birth to one pup in late May or early June. Females raise young in maternity colonies. 

22 Gray bats possess very specific microclimate requirements and are limited to limestone karst 

23 areas, typically within 1 km (0.6 mi) of rivers or reservoirs. Foraging territories may include 

24 lands farther from water. Brady et al. (1982) indicates that because of its habitat requirements, 

25 the species is restricted to fewer than five percent of available caves, and in 1982, 95 percent of 

26 the known population hibernated in only nine caves each winter. In 1982, the gray bat 

27 population was estimated to include 1,575,000 individuals, of which 300,000 individuals were 

28 located in Tennessee. Mitchell and Martin (2002) estimated the population to have risen to 

29 2.3 million bats by 2001.

30 In a final environmental statement for operation of Watts Bar 2 in Rhea County (located 31 mi 

31 [50 km] north of SQN), the NRC (2013b) found that gray bats are known to roost in two caves 

32 near the Watts Bar 2 site. The gray bat has also been documented within the Chickamauga 

33 and Chattanooga National Military Park according to a FWS (2012) press release announcing 

34 the discovery of white-nose syndrome in a park cave. The Military Park includes lands in 

35 Hamilton County, Tennessee, and Catoosa, Dade, and Walker Counties, Georgia. Three caves 

36 exist near the action area (within 6 mi (10 km) of the SQN site): Posey Cave, Havens Cave, 

37 and Harrison Bluff Cave (TVA 2013a). However, none of these caves are associated with 

38 occurrences of Federally listed species (TVA 2013a, 2013b). Additionally, during the NRC 

39 staff’s environmental site audit, TVA provided NRC staff with records for review from its Natural 

40 Heritage Database, which included detailed occurrence information on Federally listed species, 

41 State-listed species, and other special status species throughout the TVA power service area. 

42 The NRC reviewed database records of species and habitat occurrences within a 6-mi (10-km) 

43 radius of the SQN site and found that TVA (2013b) has not identified the gray bat within this 

44 area.

45 Given the available information, the NRC staff concludes that the gray bat is unlikely to occur 

46 within the action area. 
Affected Environment

3-79

1 Northern Long-Eared Bat (Myotis septentrionalis) 

2 The FWS published a proposed rule to list the northern long-eared bat as endangered 

3 throughout its range on December 2, 2013 (78 FR 72058). The FWS did not propose to 

4 designate critical habitat for the species because it found that such habitat is “not determinable 

5 at this time” (78 FR 61046). White nose syndrome, wind energy development, and loss of 

6 habitat specifically linked to surface coal mining in prime summer habitat are factors that have 

7 contributed to this species’ decline. Unless otherwise indicated, information on this species is 

8 derived from the FWS’s Federal Register notice for the proposed rule to list the species 

9 (78 FR 61046).

10 The northern long-eared bat is a medium-sized bat that is distinguished from other Myotis

11 species by its long ears, which average 0.7 in. (17 mm) in length. This bat inhabits 39 states in 

12 the eastern and north central United States and all Canadian provinces west to the southern 

13 Yukon Territory and eastern British Columbia. Populations tend to be patchily distributed and 

14 are typically composed of small numbers. More than 780 winter hibernacula have been 

15 recorded in the United States (11 in Tennessee), most of which contain only a few (1 to 3) 

16 individuals. The FWS recognizes four United States populations, and northern long-eared bats 

17 inhabiting Tennessee are considered part of the Southern population. The northern long-eared 

18 bat is less common in the southern portion of its range than in the northern portion of the range. 

19 Thompson (2006) considers the species common within Tennessee, and in 2010, individuals 

20 were caught in summer mist-net surveys as well as observed in 11 caves during Tennessee 

21 hibernacula censuses. The proximity of these occurrences to the SQN site is unknown because 

22 survey locations are not provided in the proposed rule or otherwise published.

23 In summer, northern long-eared bats roost alone or in small colonies under the bark of live or 

24 dead trees; in caves or mines; or in man-made structures, such as barns, sheds, and other 

25 buildings. The species opportunistically roosts in a variety of trees, including several species of 

26 oaks, maples, beech, and pine. Northern long-eared bats forage both in-flight and on the 

27 ground and eat a variety of moths, flies, leafhoppers, caddisflies, and beetles. The species 

28 breeds from late July to early October, after which time it will migrate to winter hibernacula. 

29 Northern long-eared bats are short-distance migrators and will travel 35 to 55 mi (56 to 89 km) 

30 from summer roosts to winter hibernacula. Hibernating females store sperm until spring, and 

31 give birth to one pup approximately 60 days after fertilization. Females raise young in maternity 

32 colonies of up to 30 individuals.

33 The action area does not contain suitable habitat for hibernation. As indicated in the description 

34 of the gray bat, three caves exist near the action area, but none of the caves are associated 

35 with occurrences of Federally listed species (TVA 2013a, 2013b). For roosting and foraging, 

36 over half of the action area is developed or composed of unsuitable habitat types. The 

37 remainder of the action area includes approximately 278 ac (113 ha) of suitable habitat types: 

38 150 ac (60 ha) of forest habitat of various types; 120 ac (50 ha) of grasslands or agricultural 

39 lands; and 8 ac (3 ha) of wooded wetlands (TVA 2013a). However, none of the available FWS

40 records indicate occurrences of hibernacula, maternity colonies, or individual northern long41 eared bats in the action area or in the larger geographical area of Hamilton County. 

42 Additionally, during the NRC staff’s environmental site audit, TVA provided NRC staff with 

43 records for review from its Natural Heritage Database, which included detailed occurrence 

44 information on Federally listed species, State-listed and other special status species throughout 

45 the TVA power service area. The NRC reviewed database records of species and habitat 

46 occurrences within a 6-mi (10-km) radius of the SQN site and found that TVA (2013b) has not 

47 identified northern long-eared bat hibernacula, maternity colonies, or individuals within this area.
Affected Environment

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1 Given the available information, the NRC staff concludes that the northern long-eared bat is 

2 unlikely to occur within the action area.

3 Indiana Bat (Myotis sodalis)

4 The FWS listed the Indiana bat as endangered in 1967 (32 FR 4001). The FWS designated 

5 critical habitat for the Indiana bat in 1976 (41 FR 41914) to include 11 caves and 2 mines in 

6 six states including a cave in Blount County, Tennessee. No critical habitat for this species 

7 occurs in Hamilton County.

8 The Indiana bat is an insectivorous, migratory bat that inhabits the central portion of the eastern 

9 United States and hibernates colonially in caves and mines. The decline of Indiana bats is 

10 attributed to urban expansion, habitat loss and degradation, human-caused disturbance of 

11 caves or mines, insecticide poisoning, and white nose syndrome (FWS 2007, 2011).

12 During summer months, reproductive female bats tend to roost in colonies under slabs of 

13 peeling tree bark or cracks within trees in forest fragments, often near agricultural areas 

14 (FWS 2007). Colonies may also inhabit closed-canopy, bottomland deciduous forest; riparian 

15 habitats; wooded wetlands and floodplains; and upland communities (FWS 2007). Maternity 

16 colonies typically consist of 60 to 80 adult females (Whitaker and Brack 2002). Colonies occupy 

17 multiple trees for roosting and rearing young (Watrous et al. 2006) and, once established, 

18 usually return to the same areas each year (FWS 2007). Nonreproductive females and males 

19 do not roost in colonies during the summer; they may remain near the hibernacula or migrate to 

20 summer habitat (FWS 2007). High-quality summer habitat includes mature forest stands 

21 containing open subcanopies, multiple moderate- to high-quality snags, and trees with 

22 exfoliating bark (Farmer et al. 2002). In summer, bats forage for insects along forest edges, 

23 riparian areas, and in semiopen forested habitats. In the winter, Indiana bats rely on caves for 

24 hibernation. The species prefers hibernacula in areas with karst (limestone, dolomite, and 

25 gypsum) and may also use other cave-like locations, such as mines.

26 The FWS’s Indiana Bat Recovery Plan (FWS 2007) indicates that Indiana bats are distributed 

27 across 21 Tennessee counties. Thirty-four winter hibernacula (21 extant, 7 of uncertain status, 

28 and 6 historic) are located throughout these counties. Three extant maternity colonies occur in 

29 Blount and Monroe Counties. Additionally, adult males and/or nonreproductive females have 

30 been captured during summer surveys within 9 of the 21 counties. In 2007, the FWS estimated 

31 that Tennessee’s total population of Indiana bats was 8,906 individuals (FWS 2009). According 

32 to more recent estimates based on winter surveys conducted in January and February of 2013, 

33 the FWS (2013d) estimate that the Tennessee population of Indiana bats is currently 

34 15,537 individuals.

35 The action area does not contain suitable habitat for hibernation. As indicated in the description 

36 of the gray bat, three caves exist near the action area, but none of the caves are associated 

37 with occurrences of Federally listed species (TVA 2013j, 2013n). For roosting and foraging, 

38 over half of the action area is developed or composed of unsuitable habitat types. The 

39 remainder of the action area includes approximately 278 ac (113 ha) of suitable habitat types: 

40 150 ac (60 ha) of forest habitat of various types; 120 ac (50 ha) of grasslands or agricultural 

41 lands; and 8 ac (3 ha) of wooded wetlands (TVA 2013n). However, none of the available FWS

42 records indicate occurrences of hibernacula, maternity colonies, or individual Indiana bats in the 

43 action area or in the larger geographical area of Hamilton County. Additionally, during the NRC 

44 staff’s environmental site audit, TVA provided NRC staff with records for review from its Natural 

45 Heritage Database, which included detailed occurrence information on Federally listed species 

46 throughout the TVA power service area. The NRC reviewed database records of species and 

47 habitat occurrences within a 6-mi (10-km) radius of the SQN site and found that TVA (2013j) 

48 has not identified Indiana bat hibernacula, maternity colonies, or individuals within this area.
Affected Environment

3-81

1 Given the available information, the NRC staff concludes that the Indiana bat is unlikely to occur

2 within the action area.

3 Snail Darter (Percina tanasi) 

4 The FWS listed the snail darter as endangered in 1975 (40 FR 47505) and reclassified the 

5 species as threatened in 1984 after additional populations were identified in several 

6 Tennessee River tributaries and reservoirs (FWS 2013e). The FWS designated critical habitat

7 for the species in the Little Tennessee River at the time of listing. However, creation of 

8 Tellico Dam destroyed the darter’s entire critical habitat area, and the FWS rescinded the critical 

9 habitat designation upon reclassifying the species as threatened in 1984 (FWS undated d).

10 Snail darters inhabit larger creeks where they frequent sand and gravel shoal areas in low 

11 turbidity water. They are also found in deeper portions of rivers and reservoirs where current is 

12 present (Etnier and Starnes 1993). The FWS believes the snail darter originally inhabited the 

13 main stem of the Tennessee River and possibly ranged from the Holston, French Broad, 

14 Lower Clinch, and Hiwassee rivers downstream within the Tennessee drainage to northern 

15 Alabama (FWS undated d). However, impoundments have fragmented much of the species’ 

16 range (Etnier and Starnes 1993). The FWS (2013e) has records of the snail darter occurring in 

17 Chickamauga Reservoir in Hamilton, Meigs, and Rhea Counties in 1976 (before the 

18 construction of SQN). TVA has not collected the species during its stream samplings of 

19 tributaries to the Tennessee River within Chickamauga Reservoir in the available data years 

20 (1995–2009) (Simmons 2010b). The NRC staff’s review of records from the TVA (2013j) 

21 Natural Heritage Database also did not identify information that would suggest the species 

22 occurs in vicinity of the plant. Furthermore, the snail darters’ habitat requirements make it 

23 unlikely to occur in the portion of Chickamauga Reservoir within the action area.

24 Given the available information, the NRC staff concludes that the snail darter is unlikely to occur 

25 within the action area.

26 Dromedary Pearlymussel (Dromus dromas) 

27 The FWS listed the dromedary pearlymussel as endangered in 1976 (41 FR 24062). The FWS 

28 has not designated critical habitat for this species.

29 The dromedary pearlymussel is a medium-sized freshwater mussel with a yellowish green shell 

30 that has two sets of broken green rays. Juveniles and adults inhabit riffles on sand and gravel 

31 substrates with stable rubble within small to medium streams that have low turbidity and high to 

32 moderate gradients. Individuals have also been observed in slower waters and to depths of 

33 5.5 m (18 ft). The species has as many as 11 glochidial (larval) hosts. The fantail darter 

34 (Etheostoma flabellare) is a known host, and laboratory studies indicate that the following 

35 species may also be hosts: banded darter (E. zonale), tangerine darter (Percina aurantiaca), 

36 logperch (P. caprodes), gilt darter (P. evides), black sculpin (Cottus baileyi), greenside darter 

37 (E. blennioides), snubnose darter (E. simoterum), blotchside logperch (P. burtoni), channel 

38 darter (P. copelandi), and Roanoke darter (P. roanoka) (FWS undated a).

39 Dromedary pearlymussels, which were historically widespread in the Cumberland and 

40 Tennessee River systems, have been eliminated from the majority of the species’ historic 

41 riverine habitat because of impoundments. Only three reproducing populations are thought to 

42 exist: one in the upper Clinch River, Tennessee; one in the Powell River, Tennessee; and one 

43 in Virginia above Norris Reservoir (NatureServe 2013a).

44 TVA’s (2013j) Natural Heritage Database records indicate that one dromedary pearlymussel 

45 individual was identified near the mouth of Soddy Creek (approximately 2.4 mi (4 km) upstream 

46 of the action area) in a 1918 publication by A.E. Ortmann. The most recent observation of a 
Affected Environment

3-82

1 dromedary pearlymussel in Chickamauga Reservoir occurred during a September 1983 survey; 

2 it was observed in a mussel bed near the reservoir inflow at TRM 520.0 to 520.8, approximately 

3 35 mi (56 km) upstream of the action area (Baxter et al. 2010). In 2010, Third Rock 

4 Consultants, LLC (Third Rock 2010a) conducted a survey to document the existing mollusk 

5 community and habitat conditions in Chickamauga Reservoir near SQN in both areas that may 

6 be affected by plant operations and those that would not be affected by operations. The 

7 dromedary pearlymussel was not identified during this survey, and TVA (2013j) reports that the 

8 Chickamauga Reservoir adjacent to SQN is not suitable habitat to sustain a breeding population 

9 of the species. Table 3–20 summarizes known dromedary pearlymussel occurrences in and 

10 near the action area.

11 Given the available information, the NRC staff concludes that the dromedary pearlymussel is 

12 unlikely to occur within the action area.

13 Pink Mucket (Lampsilis abrupta) 

14 The FWS designated the pink mucket mussel as endangered in 1976 (41 FR 24062). The FWS 

15 has not designated critical habitat for this species.

16 Pink muckets are medium-sized freshwater mussels with smooth, yellow to yellow-green shells 

17 and faint green rays. The species inhabits sand and gravel substrates in medium to large rivers 

18 with strong currents, and it can also survive in impounded, but flowing waters. Confirmed 

19 suitable glochidial hosts include the largemouth bass (Micropterus salmoides), spotted bass 

20 (M. punctulatus), smallmouth bass (M. dolomieu), and walleye (Stizostedion vitreum). 

21 Additionally, sauger (S. canadense) and freshwater drum (Aplodinotus grunniens) may act as 

22 hosts (FWS undated b).

23 Historically, this species was distributed in 25 rivers and tributaries in the Mississippi, Ohio, 

24 Cumberland, and Tennessee Rivers (NatureServe 2013c). The species is now likely extirpated 

25 from Ohio, Pennsylvania, and New York (NatureServe 2013c). It has also been mostly 

26 extirpated from Tennessee, though a few localized, but stable populations remain in the 

27 Cumberland River and the Tennessee River below Pickwick Dam (Parmalee and Bogan 1998). 

28 Occasional individuals also occupy several small- to medium-sized tributaries of large rivers 

29 including the Holston, French Broad, and Upper Clinch rivers (Parmalee and Bogan 1998). A 

30 1963 survey identified a pink mucket mussel in the Tennessee River at Houseboat Cove of 

31 Harrison Bay State Park between TRM 477 and 483 (TVA 2013j). The location range of this 

32 record overlaps with the action area for about a 2-river-mile (3.2-river-kilometer) stretch, which 

33 means that this historic sighting could have occurred within the most downstream portion of the 

34 action area. TVA’s Natural Heritage Database contains no other records indicating any more 

35 recent occurrences of the species within 6 mi (10 km) of the SQN site, and the pink mucket was 

36 not observed during a 2010 mussel survey conducted by Third Rock Consultants, LLC 

37 (Third Rock 2010a). Upstream of the action area, TVA has found the pink mucket in the vicinity 

38 of the Watts Bar Nuclear Plant site during mussel surveys in 10 data years between 1983 and 

39 1997, though the number of specimens in a single year has never amounted to more than 10 

40 (NRC 2013b). Additionally, a single pink mucket individual was found between TRM 526 and 

41 527 (roughly 42 river mi upstream of the action area) in a September 2010 survey 

42 (Third Rock 2010b). Table 3–20 summarizes known pink mucket occurrences in and near the 

43 action area.

44 The available information (the historical sighting of one individual that may have occurred within 

45 the downstream portion of the action area) does not indicate the current-day presence of the 

46 species within the action area. However, given that the species has been consistently observed 

47 in studies in the Chickamauga Reservoir upstream of the action area, the NRC staff considered 

48 whether the species could move into the action area when attached to a host fish. Of the known 
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1 and potential host species, all but the walleye occur both up and downstream of SQN (see 

2 Section 4.7), and could, thus, transport pink mucket glochidia into the action area. However, the 

3 results of the 2010 mussel survey (Third Rock 2010a) indicate that the silty substrate conditions 

4 in the action area are not suited for pink mucket. Therefore, the species, which currently does 

5 not occur in the action area, is unlikely to successfully colonize the action area if it were to be 

6 transported into it. This assumption is supported by the fact that while the species has been 

7 consistently observed in small numbers in studies upstream of the action area since the 1980s, 

8 it has not appeared in the action area.

9 Given the available information, the NRC staff concludes that the pink mucket is unlikely to 

10 occur within the action area.

11 Orangefoot Pimpleback (Plethobasus cooperianus) 

12 The FWS listed the orangefoot pimpleback as endangered in 1976 (41 FR 24062). The FWS 

13 has not designated critical habitat for this species.

14 The orangefoot pimpleback is a round freshwater mussel with a thick light-brown to chestnut or 

15 dark-brown shell that grows up to 4 in. (10 cm) in size. It inhabits sand, gravel, or cobble 

16 substrates of medium to large rivers (Cummings and Mayer 1992). Its glochidial host is 

17 unknown (Mirarchi et al. 2004; Parmalee and Bogan 1998).

18 Historically, the species inhabited the Ohio, Wabash, Cumberland, lower Clinch, and Tennessee 

19 rivers. Within the Tennessee River, the species is believed to occur in nine Tennessee 

20 counties, including Hamilton County (FWS 2013g). The largest remaining population occurs in 

21 a short reach of the Tennessee River below Pickwick Dam (FWS 1997), which lies 133 river mi 

22 (214 river km) downstream of Chickamauga Dam. The species was not observed during 

23 Third Rock Consultants, LLC’s 2010 mussel survey (Third Rock 2010a) near SQN, and TVA’s 

24 Natural Heritage Database contains no records indicating the occurrence of the species within 

25 6 mi (10 km) of the SQN site. This information suggests that the species does not occur within 

26 the action area.

27 The NRC also considered whether the orangefoot pimpleback glochidia could move into the 

28 action area when attached to a host fish. Glochidia could possibly attach to a host fish below 

29 Pickwick Dam (where the closest population of orangefoot pimpleback is known to occur; see 

30 Table 3–20), although the host would not be able to travel the 133 river mi (214 river km) 

31 upstream to Chickamauga Reservoir because of the occurrence of six dams (many of which do 

32 not have fish ladders) between the known population and the action area. It is also unlikely that 

33 a host fish would carry glochidia downstream because no known populations occur upstream of 

34 the action area within Chickamauga Reservoir. In 2013, the NRC evaluated the potential for the 

35 orangefoot pimpleback to occur near Watts Bar Nuclear Plant, which lies approximately 

36 45 river mi (72 river km) upriver of SQN and found that, based on both historic and recent 

37 surveys, the species does not occur near that plant (NRC 2013b).

38 Given the available information, the NRC concludes that the orangefoot pimpleback is unlikely 

39 to occur within the action area. 

40 Rough Pigtoe (Pleurobema plenum) 

41 The FWS listed the rough pigtoe mussel as endangered in 1976 (41 FR 24062). The FWS has 

42 not designated critical habitat for this species.

43 The rough pigtoe is a medium-sized freshwater mussel with a yellowish brown to light brown 

44 shell with faint green rays. It inhabits sand, gravel, and cobble substrate within medium to large 

45 rivers. Its glochidial host is unknown (FWS undated c).
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1 Historically, this species occurred in the Ohio, Cumberland, and Tennessee River drainages in 

2 nine states. Within Tennessee, the species is currently known to occur downstream of the 

3 Pickwick, Wilson, and Guntersville Dams on the Tennessee River and in the Clinch River 

4 (NatureServe 2013d). Available records indicate no historic or recent occurrences of the rough 

5 pigtoe in the action area. The species was not identified during the 2010 mussel survey near 

6 SQN (Third Rock 2010a). Additionally, TVA’s Natural Heritage Database contains no records 

7 indicating the occurrence of the species within 6 mi (10 km) of the SQN site. In 2013, the NRC 

8 (2013b) evaluated the results of 15 native mussel surveys to determine the potential for the 

9 rough pigtoe to occur near Watts Bar Nuclear Plant (upstream of the action area). The NRC 

10 identified three instances of specimen collection between TRM 520.0 and 528.9 (two individuals 

11 in 1983, two individuals in 1984, and one individual in 1985). No individuals were identified in 

12 seven additional surveys of the mussel beds upstream of the action area from 1985 to 1997 or 

13 in 2010. The NRC (2013b) concluded that the rough pigtoe was no longer present in the vicinity 

14 of the Watts Bar Nuclear Plant. Thus, the potential for individuals to move into the action area 

15 from upstream is not present. Table 3–20 summarizes known rough pigtoe occurrences in and 

16 near the action area.

17 Given the available information, the NRC staff concludes that the rough pigtoe is unlikely to 

18 occur within the action area.
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1 Table 3–20. Known Occurrences of Federally Listed Mussels in and Near the Action Area

Species

Upstream of the 

Action Area Action Area

Downstream of the 

Action Area

dromedary pearlymussel 1 individual in 1918 

near the mouth of 

Soddy Creek approx. 

2.4 mi upstream 

(TVA 2013j) 

1 individual in 1983 in 

mussel bed at 

TRM 520.0–520.8 

(Baxter et al. 2010)

No known occurrences No known occurrences

pink mucket 63 individuals over 

10 data years 

(1983–1997) from 

TRM 520–529.2 

(summarized in 

NRC 2013b) 

1 individual in 2010 in 

mussel bed survey at 

TRM 526–527 

(Third Rock 2010b)

1 individual in 1963 at 

Houseboat Cove of 

Harrison Bay State 

Park between 

TRM 477 and 483 

(TVA 2013j) 

Localized, stable 

population inhabits 

Tennessee River 

below Pickwick Dam 

(Parmalee and 

Bogan 1998)

orangefoot pimpleback No known occurrences No known occurrences Largest remaining 

population of the 

species inhabits a 

short reach of the 

Tennessee River 

below Pickwick Dam 

(FWS 1997)

rough pigtoe 5 individuals over 

3 data years 

(1983–1985) from 

TRM 520–529.2 

(summarized in 

NRC 2013b)

No known occurrences No known occurrences

Sources: Baxter et al. 2010; FWS 1997; NRC 2013b; Parmalee and Bogan 1998; Third Rock 2010b; TVA 2013j

2 Small Whorled Pogonia (Isotria medeoloides) 

3 The FWS listed the small whorled pogonia as endangered in 1982 (47 FR 39827) and 

4 reclassified it as threatened in 1994 (59 FR 50852). The FWS has not designated critical 

5 habitat for this species (FWS 2013h).

6 The small whorled pogonia is a small, herbaceous, perennial orchid. Its primary range extends 

7 through the Atlantic seaboard states, although it also occurs at the southern end of the 

8 Appalachian chain in the Blue Ridge Mountains. The species generally grows in young and 

9 maturing stands of mixed deciduous or mixed deciduous/coniferous forests that are in second10 or third-growth stages of succession. The species inhabits areas with sparse to moderate 

11 ground cover, a relatively open understory, or areas in proximity to logging roads, streams, or 
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1 other features that create long-persisting breaks in the forest canopy. Throughout its range, the 

2 small whorled pogonia is associated with understories containing red maple (Acer rubrum) and 

3 oak species (Quercus spp.) (FWS 1992). Habitat destruction, disease, and predation by deer 

4 and rabbits threaten the species’ continued existence (FWS 1992, 2008).

5 The FWS (2013h) identifies Carter and Hamilton Counties as the only Tennessee counties in 

6 which the small whorled pogonia is known or believed to occur. However, TVA has not 

7 identified the species as occurring on the SQN site (TVA 2013n), and the NRC staff did not 

8 identify any information in its review of TVA’s Natural Heritage Database that would indicate 

9 historic or recent occurrences of the species within 6 mi (10 km) of the SQN site (TVA 2013f).

10 Given the available information, the NRC staff concludes that the small whorled pogonia is 

11 unlikely to occur within the action area.

12 Large-Flowered Skullcap (Scutellaria montana) 

13 The FWS listed the large-flowered skullcap as endangered in 1986 (51 FR 22521). Subsequent 

14 discovery of additional populations led the FWS to reclassify the species as threatened in 2002 

15 (67 FR 1662).

16 The large-flowered skullcap is a member of the mint family (Lamiaceae). It is a perennial herb 

17 that ranges from 12 to 20 in. (30 to 50 cm) tall. The plant flowers from mid-May to early June 

18 and produces mature fruit in June or early July (FWS 1996). Mature fruit consists of four seed19 containing nutlets, which are expelled from the calyx (CPC 2010). Large-flowered skullcap is a 

20 mid- to late-successional species that typically inhabits slopes, ravines, and stream banks that 

21 are rocky, well-drained, and slightly acidic (FWS 1996). 

22 The species is known or believed to occur in four Tennessee counties, including 

23 Hamilton County, and nine Georgia counties (FWS 2013f). The FWS (1996) reports three 

24 populations of the species in Hamilton County on private lands on White Oak Mountain, 

25 Chestnut Ridge, and Walden Ridge. Additionally, TVA manages several habitat protection 

26 areas (HPAs) that contain populations of large-flowered skullcaps (TVA 2013n):

27 • Chigger Point TVA HPA lies across Chickamauga Reservoir approximately 

28 1.0 mi (0.6 km) to the east of the action area. It includes 15 ac (6 ha) of 

29 steeply wooded shoreline.

30 • Ware Branch Bend TVA HPA lies 2.6 mi (4.2 km) northwest of the action 

31 area. It contains 42 ac (17 ha) of steep, rocky shoreline.

32 • Murphy Hill TVA HPA lies 4.7 mi (7.6 km) northeast of the action area. It 

33 encompasses 194 ac (79 ha) and includes a steep bluff that runs along the 

34 river front.

35 In total, TVA has identified 16 populations of large-flowered skullcaps in these locations, which 

36 range from 1.0 to 6.0 mi (0.6 to 10 km) away from the action area (TVA 2013n). TVA maintains 

37 a formal monitoring program for these populations.

38 TVA has no records of the large-flowered skullcap occurring within the action area (TVA 2013j, 

39 2013n). However, because the species is known to occur near the action area, the NRC staff 

40 considered whether the species could colonize habitat within the action area over time. 

41 Because the species is not mobile, colonization of the action area would occur through seed 

42 dispersal and subsequent germination in suitable habitat. Nutlets, however, are not adapted to 

43 long-distance dispersal and likely fall less than 5 m (16 ft) from the parent plant 

44 (NatureServe 2013b). Those nutlets that travel farther from being washed downslope by 

45 rainwater or carried by small animals only have a remote chance of dispersal beyond the 
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1 existing population (NatureServe 2013b). Given that seeds from the nearest known population 

2 would have to travel a distance of at least 1.0 mi (0.6 km) and across Chickamauga Reservoir to 

3 occur in the action area, successful seed dispersal is unlikely.

4 Thus, the NRC staff concludes that the large-flowered skullcap is unlikely to occur within the 

5 action area.

6 Virginia Spiraea (Spiraea virginiana) 

7 The FWS listed the Virginia spiraea as threatened in 1990 (55 FR 24241). The FWS has not 

8 designated critical habitat for this species.

9 The Virginia spiraea is a perennial shrub in the rose family. It grows 3 to 10 ft (0.9 to 3 m) tall 

10 and blooms from late May through July, although vegetative reproduction is more common than 

11 seed dispersal (Ogle 1992). Because of this, most occurrences are thought to represent a 

12 single genetic type, which means that there are about as many genetically distinct individuals as

13 there are extant populations (NatureServe 2013e). The species is typically found in disturbed 

14 areas along rocky rivers and stream banks (Ogle 1992).

15 Historically, the species occurred within the Appalachian (Cumberland) Plateau and Blue Ridge 

16 physiographic regions of Pennsylvania and Ohio, south to Georgia and Tennessee 

17 (NatureServe 2013e). NatureServe (2013e) reports that an estimated 61 extant populations 

18 exist within seven states, and 17 of the extant populations occur in Tennessee. The FWS

19 Recovery Plan (Ogle 1992) does not include Hamilton County in the species’ historical or 

20 present range; however, the FWS’s (2013i) current species profile includes Hamilton and nine 

21 other Tennessee counties as being among those where the plant is known or believed to occur. 

22 TVA has not identified the species as occurring on the SQN site (TVA 2013n), and the NRC 

23 staff did not identify any information in its review of TVA’s Natural Heritage Database that would 

24 indicate historic or recent occurrences of the species within 6 mi (10 km) of the SQN site 

25 (TVA 2013j).

26 Given the available information, the NRC staff concludes that the Virginia spiraea is unlikely to 

27 occur within the action area.

28 3.8.1.3 Species and Habitats Under NMFS’s Jurisdiction

29 As discussed in Section 3.7, Chickamauga Reservoir does not contain marine or anadromous 

30 fish species. Therefore, no species or habitats under NMFS’s jurisdiction occur within the action 

31 area.

32 3.8.2 Species and Habitats Protected Under the Magnuson–Stevens Act

33 NMFS has not designated essential fish habitat in the Chickamauga Reservoir. Therefore, this 

34 section does not contain a discussion of any species or habitats protected under the 

35 Magnuson–Stevens Act.

36 3.9 Historic and Cultural Resources

37 This section discusses the cultural background and the known historic and archaeological 

38 resources found on and in the vicinity of SQN. The discussion is based on a review of recent 

39 historic and archaeological resource studies and other background information on the region 

40 surrounding SQN. In addition, a records search was performed at TDEC to obtain the most 

41 up-to-date information about historic and cultural resources in the region. 

42 The National Historic Preservation Act of 1966, as amended (NHPA), requires Federal agencies 

43 to consider the effects of their undertakings on historic properties, and renewing the operating 
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1 license of a nuclear power plant is an undertaking that could potentially affect historic properties. 

2 Historic properties are defined as resources eligible for listing in the National Register of Historic 

3 Places (NRHP). The criteria for eligibility are listed in the 36 CFR Part 60.4 and include 

4 (1) association with significant events in history; (2) association with the lives of persons 

5 significant in the past; (3) embodiment of distinctive characteristics of type, period, or 

6 construction; and (4) sites or places that have yielded, or are likely to yield, important 

7 information.

8 The area of potential effect (APE) is the area at the SQN site, the transmission lines up to the 

9 first substation and immediate environs that may be affected by the license renewal decision, 

10 and land-disturbing activities associated with continued reactor operations. The APE may 

11 extend beyond the immediate environs in instances in which land-disturbing maintenance and 

12 operations activities during the license renewal term could potentially have an effect.

13 3.9.1 Cultural Background

14 This section discusses the cultural history of the SQN site and the surrounding area. 

15 In addition, the cultural history of the State of Tennessee and the Tennessee River Valley has 

16 been described in other NRC EISs, including the following:

17  Generic Environmental Impact Statement for License Renewal of Nuclear 

18 Plants, Supplement 21, Regarding Browns Ferry, Units 1, 2 and 3, 

19 June 2006, and

20  Final Environmental Impact Statement: Related to the Operation of 

21 Watts Bar Nuclear Plant, Unit 2 (Supplement 2, Docket Number 50-391, 

22 Tennessee Valley Authority) (NUREG-0498) May 30, 2013. 

23 The SQN site and surrounding area are rich in cultural history and contain significant cultural 

24 resources. For 12,000 years, humans have occupied the Tennessee River valleys and 

25 surrounding areas. The record indicates prehistoric occupation of the area was approximately 

26 as follows: 

27  Paleo-Indian (12,000 to 8000 B.C.), 

28  Archaic (8000 to 1200 B.C.), 

29  Woodland (1200 B.C. to A.D. 1000), and

30  Mississippian (A.D. 1000 to 1500) (NRC 2013b). 

31 In addition, the prehistoric period and archaeological record in the region are described in the 

32 TVA’s ER for SQN (TVA 2013n).

33 Spanish explorers first made contact with indigenous peoples living in the area now known as 

34 Hamilton County during the 16th century. During this time, the Cherokee were living in eastern 

35 Tennessee, western North Carolina, and northern Georgia. In the late 1700s and early 1800s, 

36 various treaties were established between the U.S. Government and the Cherokee that included 

37 lands along the Tennessee River. According to regional historians, some of the treaty land 

38 could have included the SQN site (NRC 2013b).

39 Euro-American settlers began moving into the region in large numbers in the early 19th century, 

40 and Hamilton County was established in 1819. Settlers staked claims for farmsteads and small 

41 port towns, and many ferry crossings were established along the Tennessee River. Because of 

42 these developments, the U.S. Government removed the Cherokee from the area in 1838, which 

43 led to the intensification of Euro-American settlement in the region (TVA 2013n). TVA was 
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1 established in the 1930s, and the Chickamauga Reservoir was completed in 1940, after which

2 the surrounding area was flooded below the 693-ft (211-m) contour level (TVA 2013n). 

3 3.9.2 Historic and Cultural Resources

4 The following sources of information were used to identify historic and cultural resources on the 

5 SQN site and the surrounding area:

6  TVA ER (TVA 2013n);

7  environmental audit at SQN that included a cultural resources records review 

8 and a cultural resources field tour by NRC staff (NRC 2013m);

9  NRC meeting with the Tennessee Historical Commission and site file query 

10 with Division of Archaeology, Tennessee Department of Environment and 

11 Conservation (NRC 2013e);

12  phone call to the Tennessee Historical Commission on May 22, 2013, for 

13 additional information on the Igou Cemetery within the APE (NRC 2013l);

14  scoping and consultation letters—see Appendices C and D for a complete list 

15 (NRC 2013i, 2013j);

16  request for additional information (RAI) responses from TVA dated 

17 July 23, 2013 (TVA 2013f);

18  NRC phone call with TVA on August 13, 2013, to clarify responses to cultural 

19 resource RAI (NRC 2013k);

20  TVA ER revisions (TVA 2013c);

21  TVA cultural resource compliance reports (publicly available at the 

22 Tennessee Historical Commission): 

23 – 2013 Phase I Cultural Resources Survey of the TVA Sequoyah Nuclear 

24 Plant, Hamilton County, Tennessee: Revised Final Report, TRC 

25 Environmental Corporation; 

26 – 2009 Phase I Cultural Resource Survey of the Proposed Improvements to 

27 the TVA Sequoyah Nuclear Power Plant, Hamilton County, Tennessee, 

28 prepared by TRC Environmental Corporation; 

29 – 2010 Phase I Cultural Resources Survey of the TVA Sequoyah Nuclear 

30 Plant, Hamilton County, Tennessee, prepared by TRC Environmental 

31 Corporation; and

32 – 1973 Archaeological Investigations of the Sequoyah Nuclear Plant Area 

33 by Calabrese, Hood, and Leaf. 

34 3.9.2.1 Cultural Resource Investigations at SQN

35 TVA’s ER (TVA 2013n) describes all of the cultural resource investigations that have been 

36 conducted on the SQN site between 1936 and 2013 and identifies cultural resources found 

37 within the APE. The earliest TVA cultural resources surveys at what is now the SQN site 

38 occurred in 1936 and 1937, before construction of the Chickamauga Dam and reservoir. 

39 Surveys at the SQN site conducted prior to 1983 may not meet the Secretary of the Interior’s 

40 Historic Preservation Professional Qualification Standards, which define the minimum education

41 and experience required for the identification, evaluation, registration, and treatment and 

42 preservation of archaeological and historic resources. 
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1 Early surveys and literature reviews show that southern portions of the SQN site were owned by 

2 a General Samuel Igou, who established a homestead and ferry crossing connecting roads on 

3 the east and west banks of the Tennessee River near the SQN site. The 1936 TVA cultural 

4 resource investigation confirmed that there was no active ferry at the time of the survey. 

5 A family cemetery was also established by Igou on what is now the SQN site. Today, TVA 

6 maintains the Igou Cemetery and allows access only by special request. In addition, the McGill 

7 Cemetery was identified in the northern portion of the SQN site during the mid-1930s surveys. 

8 All 11 graves in the McGill Cemetery were subsequently relocated to a nearby cemetery across 

9 the river, prior to 1983. Early surveys also revealed that a Union Army camped in this area 

10 during the Civil War (TVA 2013n).

11 In 1937, TVA surveyed properties in the SQN area to generate a land acquisition map for the 

12 Chickamauga Dam and reservoir. The survey generated a land map identifying public and 

13 private roads, structures, fields, orchards, fences, property boundaries, and cemeteries. 

14 At least 14 residences and 2 cemeteries were identified within what are now the SQN site 

15 boundaries. In 1938, TVA recorded the names and location of each burial. These cemetery 

16 reports were the last cultural resource investigations involving the SQN site until 1973, when 

17 surveys were conducted for the construction of SQN (TVA 2013n). These surveys confirmed 

18 the findings from the earlier surveys that identified the Igou and McGill Cemeteries and Igou 

19 ferry crossing and homestead.

20 The most recent cultural resource investigations were conducted in 2009 for a proposed SQN 

21 steam generator replacement project and in 2010 in preparation for the license renewal of SQN 

22 Units 1 and 2. The 2009 investigation determined that no cultural resources would be affected 

23 by the proposed steam generator replacement project, as the affected areas had been 

24 extensively disturbed by the construction of SQN (TVA 2013n). The 2010 investigation, which 

25 surveyed the entire SQN site, reported one new archaeological site (Site 40HA549) and three 

26 isolated finds (TVA 2013n). Site 40HA549 was characterized by two unbroken Early or Middle 

27 Archaic projectile points and was determined ineligible for listing in the National Register of 

28 Historic Places (NRHP); the Tennessee Historical Commission concurred with this finding 

29 (TVA 2013n). In addition, the 2010 survey confirmed the condition of previously recorded 

30 archaeological sites on the SQN property. In 2013, TVA revised its 2010 survey of SQN 

31 property to correct information related to new information about Site 40HA22, which is 

32 discussed below (TVA 2013c). 

33 3.9.2.2 Cultural Resources Located within SQN

34 Site 40HA20 was first recorded in 1936 and was described as a Late Woodland or Early 

35 Mississippian mound complex. Cultural resource investigations completed in 1973 documented 

36 that Site 40HA20 had been destroyed by the construction of SQN Unit 1 and Unit 2. The 2010 

37 cultural resources investigation confirmed that Site 40HA20 was destroyed during construction 

38 (TVA 2013n).

39 Site 40HA22 was first recorded and tested in 1913. It was first described as an undisturbed 

40 mound on the SQN site measuring 52 ft (16 m) in diameter and 7.5 ft (2.3 m) in height with 

41 midden materials documented in the surrounding cultivated field. Early excavation into the top 

42 of the mound encountered eight human burials, with the disturbed remnants of a ninth found to 

43 the side of the mound. In 1936, the mound was still visible and ceramic fragments were noted 

44 on the surface. Cultural resource investigations completed in 1973 documented that 

45 Site 40HA22 had been destroyed by the construction of SQN Units 1 and Unit 2 (TVA 2013n). 

46 The 2010 cultural resources investigation confirmed that Site 40HA22 was destroyed during 

47 construction (TVA 2013n). However, during the April 2013 NRC environmental audit, 

48 Site 40HA22 was found to be partially intact and incorrectly identified as within the SQN 
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1 property boundary (NRC 2013k). In September 2013, after discussion with the NRC, TVA 

2 reopened Section 106 consultation with the Tennessee State Historic Preservation Office

3 (SHPO) and submitted revisions to its previous 2010 cultural resource survey and an updated 

4 site form to the Tennessee Division of Archaeology, the keeper of archaeological records for the 

5 State of Tennessee (TVA 2013m). TVA also reinitiated consultation with tribes (TVA 2013n). 

6 The mound has been reassessed to be approximately 30 ft (9 m) in diameter with a depression 

7 several feet across and likely to include human remains (TRC 2013). Fire-cracked rock, a 

8 byproduct of the use of hot rocks for cooking and heating purposes, and chert artifacts were 

9 also identified surrounding the mound (TRC 2013). There has been no formal eligibility 

10 determination of the site for the NRHP, although TVA believes the site is eligible (TVA 2013c).

11 Site 40HA549 was found and recorded during the 2010 cultural resources investigation and is 

12 described as a prehistoric period short-term open habitation. Two unbroken Early or Middle 

13 Archaic projectile points and one small quartz flake were found during shovel tests. Three 

14 isolated finds were also discovered. TVA determined the site and isolates were ineligible for 

15 listing in the NRHP; the Tennessee Historical Commission concurred in May 2010 (TVA 2013n).

16 Site HS-2, identified during the 2010 cultural resources investigation, is the previously 

17 mentioned Igou Cemetery (TVA 2013n). TVA determined Site HS-2 to be ineligible for listing in 

18 the NRHP; the Tennessee Historical Commission concurred in May 2010 (TVA 2013n). The 

19 2010 cultural resources investigation confirmed that all the burials at the former McGill 

20 Cemetery site identified before construction of SQN were relocated to the McGill Cemetery 

21 No. 2 across the Tennessee River. The NRC staff contacted the Tennessee Historical 

22 Commission to discuss the eligibility determinations for sites within the APE. The Tennessee 

23 Historical Commission confirmed Site HS-2 (Igou Cemetery) was not eligible for listing in the 

24 NRHP (NRC 2013l).

25 In summary, the NRC performed a confirmatory analysis and queried the Division of 

26 Archaeology of the Tennessee Department of Environment and Conservation to identify cultural 

27 resources present at the SQN site. Table 3–21 lists the cultural resources recorded within the 

28 SQN site. Section 4.9.1 provides a status on cultural resources consultation. No cultural 

29 resources were identified as being listed in the NRHP within the APE; however, Site 40HA22 is 

30 located near the SQN site boundary and is potentially eligible for listing in the NRHP. 

31 Site 40HA22 is located on TVA-controlled lands and, as such, will be treated by TVA staff as 

32 eligible for the NRHP (TVA 2013c). On September 23, 2013, the Tennessee SHPO concurred 

33 that there are no sites eligible for listing on the NRHP within the SQN plant boundary 

34 (TVA 2013l). All human remains, either historic or ancient, in the State of Tennessee are 

35 protected by Tennessee State law. The Igou Cemetery (HS-2) is located in the southern area of 

36 the SQN site and is protected by several State statutes. The Tennessee Code Annotated 

37 (T.C.A.) 39-17-311 is the primary statute providing protection for the historic cemetery, which is 

38 maintained by TVA.
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1 Table 3–21. Cultural Resources Within the SQN Site

Site

Located on the

SQN Site Description NRHP

40HA20 Yes Late Woodland/Early Mississippian 

Mound Complex Destroyed/Not Eligible

40HA22 No Burial Mound Potentially Eligible

40HA549 Yes Two Complete Early/Middle Archaic 

Projectile Points and a Quartz Flake Not Eligible

HS-2 Yes Igou Cemetery (Historic) Not Eligible/Protected by 

State Statutes

2 3.10 Socioeconomics

3 This section describes current socioeconomic factors that have the potential to be directly or 

4 indirectly affected by changes in operations at SQN. SQN, and the communities that support it, 

5 can be described as a dynamic socioeconomic system. The communities supply the people, 

6 goods, and services required to operate the nuclear power plant. Power plant operations, in 

7 turn, supply wages and benefits for people and dollar expenditures for goods and services. The 

8 measure of a community’s ability to support SQN operations depends on its ability to respond to 

9 changing environmental, social, economic, and demographic conditions.

10 3.10.1 Power Plant Employment and Expenditures

11 The socioeconomic region of influence (ROI) is defined by the areas where SQN employees 

12 and their families reside, spend their income, and use their benefits, thus affecting the economic 

13 conditions of the region. SQN employs a permanent workforce of approximately 

14 1,141 employees (TVA 2013n). Approximately 84 percent of SQN employees reside in a 

15 two-county area in southeastern Tennessee dominated by Hamilton County and Chattanooga, 

16 including Rhea County. Most of the remaining 16 percent of the workforce are spread among 

17 24 other counties in Alabama, Georgia, and Tennessee, and among five other states, with 

18 numbers ranging from 1 to 30 employees per county (TVA 2013n). Given the residential 

19 locations of SQN employees, the most significant effects of continued plant operations are likely 

20 to occur in Hamilton and Rhea Counties. The focus of the socioeconomic impact analysis in 

21 this SEIS is, therefore, on the impacts of continued SQN operations on these two counties, also 

22 termed the ROI. Table 3–22 summarizes the SQN workforce geographic distribution.

23 SQN purchases goods and services to facilitate its operations. While specialized equipment 

24 and services are procured from a wider region, some proportion of the goods and services used 

25 in plant operations are acquired from within the ROI. These transactions fuel a portion of the 

26 local economy, as jobs are provided and additional local purchases are made by plant suppliers.

27 Refueling outages at SQN typically have occurred at 18-month intervals. During refueling 

28 outages, site employment typically increases by an average of 750 temporary contract workers 

29 for approximately 30 to 33 days (TVA 2013n). Outage workers are drawn from all regions of the 

30 country; however, the majority would be expected to come from Tennessee, Georgia, and other 

31 southeastern states.
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1 Table 3–22. 2010 SQN Employee Residence by County

County/State Number of Employees Percentage of Total

Hamilton, TN 893 78

Rhea, TN 70 6

Other TN (17 other counties) 102 9

Alabama (3 counties) 18 2

Georgia (4 counties) 50 4

Other States (5 other states) 8 1

Total 1,141 100

Source: TVA 2013n. Includes TVA and permanent contract workers.

2 3.10.2 Regional Economic Characteristics

3 This section presents information on employment and income in the ROI. The two-county SQN 

4 ROI is predominantly rural. Hamilton County is home to Chattanooga, a regional transportation 

5 hub in southeast Tennessee. Nearly 26 percent of the county is urbanized (USDA 2013). 

6 Agricultural and forested land makes up the majority of the land use In Rhea County, and urban 

7 lands make up about 7 percent of the total county land area (USDA 2013).

8 3.10.2.1 Employment and Income

9 From 2000 to 2012, the civilian labor force in the SQN ROI increased 3.5 percent to just over 

10 180,000. The number of employed persons declined by about 1 percent over the same period, 

11 to over 166,000. Consequently, the number of unemployed people in the ROI has increased 

12 nearly 130 percent in the same period, to over 13,900, or about 7.7 percent of the current 

13 workforce – up from 3.5 percent in 2000 (BLS 2013).

14 In 2011, the health care and social assistance industry made up the largest sector of the 

15 economy in terms of employment (10.7 percent), followed by manufacturing (10.1 percent), 

16 retail trade (9.6 percent), accommodations and food services (8.1 percent), and finance and 

17 insurance industry (7.7 percent) (BEA 2013). A list of selected major employers in the ROI is 

18 given in Table 3–23. SQN’s 1,141 full-time employees are included in the TVA total, which is 

19 the third largest employer in the ROI, as shown in the table.

20 Estimated income information for the SQN ROI and Tennessee is presented in Table 3–24. 

21 According to the U.S. Census Bureau’s (USCB’s) 2007–2011 American Community Survey 

22 (ACS) 5-Year Estimates, people living in Hamilton County had median household and per capita 

23 incomes above the State average, while Rhea County had median household and per capita 

24 incomes lower than the State average. The same trend is evident for families and individuals 

25 living below the official poverty level. The relative lack of economic development in rural Rhea 

26 County contributes to higher than average poverty and lower than average median incomes 

27 compared to the more economically developed Chattanooga in Hamilton County.
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1 Table 3–23. Major Employers of the SQN ROI in 2012

Employer Industry

Full-Time 

Employees

Hamilton County Dept. of Education Elementary & Secondary Schools 4,480

BlueCross BlueShield of Tennessee Health Care Financing 4,282

Tennessee Valley Authority Utility – Electric Service 4,180

Erlanger Health System Hospital 3,176

Memorial Health Care System Health Care 3,171

Unum Insurance 2,800

McKee Foods Corporation Mfr. Cakes & Cookies 2,650

Volkswagen Chattanooga Mfr. Automobiles 2,459

LA-Z-Boy Chair Company Sofas, Sleepers, Recliners 2,350

City of Chattanooga Government 2,251

Amazon.com.dedc LLC Distribution Center 1,879

Hamilton County Government Government 1,763

Pilgrim’s Pride Corporation Poultry Slaughtering & Processing 1,500

CIGNA HealthCare Health Services 1,350

Astec Industries, Inc. Mfr. Asphalt & Construction Equipment 1,348

Roper Corporation Mfr. Cooking Products 1,200

The University of TN at Chattanooga University 1,153

Parkridge Medical Center, Inc. Healthcare – Hospital 1,135

Sources: CACC 2013; SEIDA 2012

2 Table 3–24. Estimated Income Information for the SQN ROI in 2011

Hamilton Rhea Tennessee

Median household income (dollars)(a) 45,826 36,934 43,989

Per capita income (dollars)(a) 26,924 17,860 24,197

Individuals living below the poverty level (percent) 15.9 20.3 16.9

Families living below the poverty level (percent) 12.0 14.7 12.7

(a) In 2011 inflation adjusted dollars

Source: USCB 2013b

3 3.10.2.2 Unemployment

4 Unemployment rates in the SQN ROI have mirrored State and national trends from 2007 to 

5 2012. Table 3–25 illustrates the unemployment rates for the SQN ROI counties compared to 

6 State and SQN ROI rates.

7 The effects of the recent economic recession (often referred to as the Great Recession that 

8 began in December 2007 and lasted to June 2009) on employment are visible in the 

9 two counties, the ROI, and the State. Rhea County has had consistently higher unemployment 

10 rates than its urban neighbor, Hamilton County, through this period. As a whole, the ROI 

11 experienced slightly less unemployment than the State during the recent economic recession.
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1 Table 3–25. 2007−2012 Annual Unemployment Rates in the SQN ROI

ROI Counties 2007 2008 2009 2010 2011 2012

Hamilton 4.1 5.8 9.1 8.6 8.2 7.5

Rhea 6.1 8.1 13.7 12.5 11.6 10.5

ROI 4.3 6.0 9.5 8.9 8.5 7.7

Tennessee 4.9 6.7 10.5 9.8 9.2 8.0

Source: TDLWD 2013; for consistency all values not seasonally adjusted.

2 3.10.3 Demographic Characteristics

3 According to the 2010 Census, an estimated 472,684 people lived within 20 mi (32 km) of SQN, 

4 which equates to a population density of 376 persons per square mile (TVA 2013n). This 

5 translates to a Category 4, “least sparse” population density using the generic environmental 

6 impact statement (GEIS) measure of sparseness (greater than or equal to 120 persons per 

7 square mile within 20 mi). An estimated 1,080,361 people live within 50 mi (80 km) of SQN with 

8 a population density of 138 persons per square mile (TVA 2013n). Because Chattanooga is 

9 located within 50 mi (80 km) of SQN, this translates to a Category 3 density, using the GEIS

10 measure of proximity (one or more cities with 100,000 or more persons and less than 

11 190 persons per square mile within 50 mi) (NRC 2013d). Therefore, SQN is located in a high 

12 population area based on the GEIS sparseness and proximity matrix.

13 Table 3–26 shows population projections and percent growth from 1970 to 2060 in the 

14 two-county SQN ROI. The population in the ROI has increased over the previous two decades 

15 (2000 and 2010). Based on State forecasts (UT 2012), the population is expected to continue 

16 to increase at a moderate rate.

17 Table 3–26. Population and Percent Growth in SQN ROI Counties 1970–2010, 2012 

18 (estimated), and Projected for 2020–2060

Year

Hamilton County Rhea County

Population Percent growth Population Percent growth

1970 254,236 – 17,202 – 

1980 287,740 13.2 24,235 40.9

1990 285,536 -0.8 24,344 0.4

2000 307,910 7.8 28,400 16.7

2010 336,463 9.3 31,809 12.0

2012 345,545 2.7 32,247 1.4

2020 352,163 4.7 35,062 10.2

2030 355,597 1.0 37,252 6.2

2040 353,136 -0.7 38,843 4.3

2050 354,605 0.4 40,517 5.1

2060 355,092 0.1 42,248 4.6

Sources: Population data for 1970–1990 (State of Tennessee 1996); population data for 2010, population data for 

2000–2010 and projections for 2020–2040 by Tennessee State Data Center (UT 2012); 2012 (USCB 2013f); 

2050–2060 calculated.
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1 The 2010 Census demographic profile of the two-county ROI population is presented in 

2 Table 3–27. According to the 2010 Census, minorities (race and ethnicity combined) comprised 

3 26.3 percent of the total two-county population. The minority population is mostly comprised of 

4 Black or African-American residents.

5 Table 3–27. Demographic Profile of the Population in the SQN Socioeconomic Region of 

6 Influence in 2010

Hamilton Rhea ROI

Total Population 336,463 31,809 368,272

Race (percent of total population, not Hispanic or Latino)

White 72.0 92.1 73.7

Black or African-American 20.1 1.9 18.5

American Indian & Alaska Native 0.2 0.4 0.3

Asian 1.7 0.4 1.6

Native Hawaiian & Other Pacific Islander 0.0 0.0 0.0

Some other race 0.1 0.1 0.1

Two or more races 1.4 1.3 1.4

Ethnicity

Hispanic or Latino 14,993 1,187 16,180

Percent of total population 4.5 3.7 4.4

Minority population (including Hispanic or Latino ethnicity)

Total minority population 94,309 2,506 96,815

Percent minority 28.0 7.9 26.3

Source: USCB 2013e

7 3.10.3.1 Transient Population

8 Within 50 mi (80 km) of SQN, colleges and recreational opportunities attract daily and seasonal 

9 visitors who create a demand for temporary housing and services. In 2012, approximately 

10 42,032 students attended colleges and universities within 50 mi (80 km) of SQN (NCES 2013a).

11 Based on the 2007−2011 ACS estimates, approximately 27,650 seasonal housing units are 

12 located within 50 miles (80 kilometers) of SQN. Of those, 2,517 are located in the SQN 

13 two-county ROI. Table 3–28 presents information about seasonal housing for the counties 

14 located all or partly within 50 mi (80 km) of SQN.
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1 Table 3–28. 2007-2011 Estimated Seasonal Housing in Counties Located Within 50 Mi of 

2 SQN

County(a) Total Housing Units

Vacant Housing Units: for 

Seasonal, Recreational, or 

Occasional Use Percent

Alabama

DeKalb 30,942 924 3.0

Jackson 24,794 569 2.3

County Subtotal 55,736 1,493 2.7

Georgia

Catoosa 26,473 293 1.1

Chattooga 10,990 127 1.2

Dade 7,242 232 3.2

Fannin 16,156 4,726 29.3

Floyd 40,444 166 0.4

Gilmer 16,422 3,132 19.1

Gordon 22,095 206 0.9

Murray 15,973 115 0.7

Walker 29,942 693 2.3

Whitfield 39,420 229 0.6

County Subtotal 225,157 9,919 4.4

North Carolina

Cherokee 17,360 4,517 26.0 Tenn essee

Tennessee

Bledsoe 5,691 521 9.2

Bradley 41,208 169 0.4

Coffee 23,277 212 0.9

Cumberland 27,743 1,955 7.0

Franklin 18,635 1,050 5.6

Grundy 6,427 310 4.8

Hamilton 150,379 1,750 1.2

Loudon 21,467 295 1.4

McMinn 23,270 389 1.7

Marion 12,962 290 2.2

Meigs 5,601 508 9.1

Monroe 20,581 1,118 5.4

Polk 7,962 391 4.9

Rhea 14,266 767 5.4

Roane 25,604 642 2.5

Sequatchie 6,257 230 3.7

Van Buren 2,660 210 7.9

Warren 17,754 161 0.9

White 11,449 753 6.6

County Subtotal 443,193 11,721 2.6
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County(a) Total Housing Units

Vacant Housing Units: for 

Seasonal, Recreational, or 

Occasional Use Percent

Total 741,446 27,650 3.7

(a) Counties within 50 mi (80 km) of SQN with at least one block group located within the 50-mi (80-km) radius. A 

block group is defined by the U.S. Census Bureau as a statistical division generally containing 600 to 3,000 people.

Source: USCB 2013a

1 3.10.3.2 Migrant Farm Workers

2 In the 2002 Census of Agriculture, farm operators were asked for the first time whether or not 

3 they hired migrant workers. Migrant farm workers are individuals whose employment requires 

4 travel to harvest agricultural crops. These workers may or may not have a permanent 

5 residence. Some migrant workers follow the harvesting of crops, particularly fruit, throughout 

6 rural areas of the United States. Others may be permanent residents near SQN and travel from 

7 farm to farm harvesting crops.

8 Migrant workers may be members of minority or low-income populations. Because they travel 

9 and can spend a significant amount of time in an area without being actual residents, migrant 

10 workers may be unavailable for counting by census takers. If uncounted, these workers would 

11 be “underrepresented” in USCB minority and low-income population counts.

12 Table 3–29 supplies information about migrant farm workers and temporary farm labor (less 

13 than 150 days) within 50 mi (80 km) of SQN. Approximately 9,400 farm workers were hired to 

14 work for less than 150 days and were employed on 3,557 farms within 50 mi (80 km) of SQN. 

15 The county with the highest number of temporary farm workers (1,190) on 460 farms was 

16 DeKalb County, Alabama (USDA 2012). A total of 312 farms, in the 50-mi radius of SQN, 

17 reported hiring migrant workers in the 2007 Census of Agriculture. Warren County, Tennessee, 

18 reports the most farms with migrant farm labor (64 farms) (USDA 2012).
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1 Table 3–29. Migrant Farm Workers and Temporary Farm Labor in Counties Located 

2 Within 50 Mi of SQN

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)

Alabama

DeKalb 550 460 1,190 27

Jackson 261 229 594 12

County Subtotal 811 689 1,784 39

Georgia

Catoosa 65 55 117 5

Chattooga 45 42 77 1

Dade 44 34 107 2

Fannin 39 30 80 1

Floyd 127 96 310 2

Gilmer 118 82 184 16

Gordon 146 107 298 2 

Murray 48 33 115 3

Walker 108 81 D 14

Whitfield 78 59 184 3 

County Subtotal 818 619 1,472 49

North Carolina

Cherokee 64 60 199 7

Tennessee

Bledsoe 148 121 395 12

Bradley 196 155 457 16

Coffee 184 150 481 9 

Cumberland 154 140 431 9

Franklin 226 187 518 18

Grundy 80 71 254 5 

Hamilton 100 86 133 3

Loudon 151 124 263 12

McMinn 199 171 443 21

Marion 81 73 202 3

Meigs 81 76 D 0

Monroe 175 145 387 22

Polk 44 35 79 4

Rhea 63 59 231 7

Roane 98 82 178 1

Sequatchie 33 26 54 1

Van Buren 30 29 D 1 

Warren 361 286 1,017 64

White 203 173 397 9

County Subtotal 2,607 2,189 5,920 217

Total 4,300 3,557 9,375 312

(a) Counties within 50 mi (80 km) of SQN with at least one block group located within the 50-mi radius

(b) Table 7. Hired farm Labor—Workers and Payroll: 2007 D = Data not disclosed by USDA

Source: 2007 Census of Agriculture — County Data (USDA 2012)
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1 3.10.4 Housing and Community Services

2 This section presents information regarding housing and local public services, including 

3 education and water supply.

4 3.10.4.1 Housing

5 The socioeconomic ROI is dominated by Hamilton County, which is part of the Chattanooga 

6 metropolitan area. The size of the Chattanooga area weighs heavily on the housing statistics, 

7 and Rhea County is considerably more rural and less like the ROI averages in terms of housing 

8 statistics. Table 3–30 lists the total number of occupied and vacant housing units, vacancy 

9 rates, and median value in the two-county ROI. Based on USCB’s 2007–2011 ACS 5-Year 

10 Estimates, there were nearly 165,000 housing units in the socioeconomic region, of which 

11 nearly 97,000 were occupied. The median values of owner-occupied housing units in the ROI 

12 range from $151,000 in Hamilton County to about $104,000 in Rhea County. The vacancy rate 

13 also varied considerably between the two counties, from 10.9 percent in Hamilton County to 

14 16.2 percent in Rhea County (USCB 2013c).

15 Table 3–30. Housing in the SQN ROI (2007−2011, 5-year estimate)

Hamilton 

County Rhea County ROI

Total housing units 150,379 14,266 164,645

Owner occupied units 88,103 8,598 96,701

Median value (dollars) 151,000 103,800 146,910

Owner vacancy rate (percent) 2.4 0.9 2.3

Renter occupied units 45,927 3,351 49,278

Median rent (dollars/month) 695 536 684

Rental vacancy rate (percent) 9.8 7.4 9.6

Total vacant housing units 16,349 2,317 18,666

Percent vacant 10.9 16.2 11.3

Source: USCB 2013c

16 3.10.4.2 Education

17 Three public school districts serve Hamilton and Rhea counties: the Hamilton County Schools, 

18 Rhea County Schools, and the Dayton School District (NCES 2013b). Table 3–31 lists the 

19 school system enrollments based on National Center for Education Statistics (NCES) data.

20 Table 3–31. Public School System Statistics, 2010–11 School Year

County District Schools

Total 

Enrollment

Hamilton Hamilton County 76 42,589

Rhea Rhea County 7 4,303 

Rhea Dayton 1 777 

ROI Total 84 47,669 

Source: NCES 2013b
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1 3.10.4.3 Public Water Supply

2 The SQN ROI includes Hamilton and Rhea counties, which is where 84 percent of SQN workers 

3 reside. The discussion of public water supply systems is limited to major municipal water 

4 systems in the local area. Table 3–32 provides information on municipal water supply systems 

5 located near SQN. In aggregate, these systems are operating at approximately 72 percent of 

6 design capacity. The source of potable water at SQN is GW supplied by the Hixson Utility 

7 District water system. 

8 Table 3–32. Local Public Water Supply Systems 

Water System

Capacity 

(mgd)

Usage 

(mgd)

Population 

Served

Eastside Utility District 15.31 9.90 46,011

Hixson Utility District 9.22 7.74 56,117

Mowbray Mountain Utility District 0.46 0.42 3,938

Sale Creek Utility District 0.37 0.23 1,730

Savannah Valley Utility District 5.60 2.44 19,338

Signal Mountain Water System 2.34 0.94 7,869

Soddy-Daisy–Falling Water Utility District 5.97 1.81 10,840

Tennessee-American Water Company 45.14 37.38 179,191

Union Fork-Bakewell Utility District 0.80 0.48 4,372

Walden Ridge Utility District 2.10 1.58 7,037

Source: TVA 2013n

9 3.10.5 Tax Revenues

10 Per Section 13 of the TVA Act of 1933, as amended, TVA makes payments in lieu of taxes to 

11 states and counties in which they conduct power operations or in which TVA has acquired 

12 power-producing properties previously subject to state and local taxation. One-half of the 

13 payments to states is determined by the percentage of total TVA gross proceeds of power sales 

14 within each state, and the other half is apportioned by the percentage of book value of TVA 

15 power property in each state (TVA 2013n). These payments amount to 5 percent of gross 

16 revenues from the sale of power during the preceding year, excluding sales or deliveries to 

17 other Federal agencies and power sales to utilities not on the TVA grid. There is a provision for 

18 minimum payments under certain circumstances.

19 Except for certain direct payments that TVA is required to make to counties, distribution of 

20 payments in lieu of taxes within a state is determined by individual state legislation. Under 

21 Tennessee Code, Title 67, Chapter 9, 48.5 percent of the total payments received by the State 

22 are distributed to the State’s counties and municipalities. Of this amount, 30 percent is 

23 distributed to counties based on county shares of the total State population, 30 percent to 

24 counties based on county acreage shares of the State total, and 30 percent to incorporated 

25 municipalities based on each municipality’s share of the total population of all incorporated 

26 municipalities in the State. The remaining 10 percent is allocated to counties based on each 

27 county’s share of TVA-owned land in the State. The payments in lieu of taxes received by 

28 Hamilton County, Chattanooga, and Soddy-Daisy are provided in Table 3–33. TVA is exempt 
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1 from sales and use taxes per Section 13 of the TVA Act of 1933, as amended. TVA indicates 

2 that the portion of its total payments in lieu of taxes attributable to SQN is 7 percent 

3 (TVA 2013n).

4 Table 3–33. 2008−2011 Payments in Lieu of Taxes Attributable to SQN ($)

Government 2008 2009 2010 2011

City of Chattanooga 104,097 107,431 122,793 125,552 

City of Soddy-Daisy 7,493 7,740 8,879 9,083 

Hamilton County 187,439 196,120 225,500 230,552 

ROI 299,029 311,290 357,172 365,187 

Source: Based on TVA 2013n

5 3.10.6 Local Transportation 

6 The area surrounding SQN is largely rural. Highway access to Hamilton County and SQN from 

7 population centers is via US-27, a principal arterial originating in Chattanooga and paralleling 

8 the Chickamauga Reservoir and the Tennessee River through Hamilton and Rhea Counties. 

9 The Sequoyah Access Road from Soddy-Daisy provides primary access to the site for SQN 

10 employees. The Chattanooga area is connected by interstate freeways to the larger 

11 metropolitan areas of Atlanta, Georgia, Birmingham, Alabama, Nashville, Tennessee, and 

12 Knoxville, Tennessee.

13 The ROI is served by CSX and Norfolk Southern freight rail services, and a Norfolk Southern 

14 spur line provides rail access to the SQN site (TVA 2013n). Freight also is transported by 

15 navigable waterway on the Tennessee River between Knoxville, Tennessee, and the confluence 

16 of the Tennessee and Ohio rivers, via a system of locks and dams (TVA 2013n). The SQN site 

17 is served by a barge slip on the Chickamauga Reservoir.

18 Table 3–34 lists commuting routes to the SQN site and average annual daily traffic (AADT) 

19 volume values. The AADT values represent traffic volumes for a 24-hour period factored by 

20 both the day of the week and the month of the year.

21 Table 3–34. Major Commuting Routes in the Vicinity of SQN: 2012 AADT

Roadway and Location Average Annual Daily Traffic (AADT)(a)

Sequoyah Access Rd. W of Hixson Pike 2,765

Iguo Ferry Rd. @ TVA Access Rd. 917

SR 319 Hixson Pike N of Sequoyah Access Rd. 940

SR 319 Hixson Pike S of Sequoyah Access Rd. 3,034

Hamby Rd. N of Lakesite 704

SR 319 Hixson Pike @ Trail Ridge Rd. 4,261

Sequoyah Access Rd. E of Trail Ridge Rd. 6,714

Sequoyah Access Rd. S of US 27 Exit 11,553

(a) All AADT values represent traffic volume during the average 24-hour day during 2012.

Source: TDOT 2013
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1 3.11 Human Health

2 3.11.1 Radiological Exposure and Risk

3 As required by NRC regulation 10 CFR 20.1101, SQN has a radiation protection program 

4 designed to protect onsite personnel, including TVA employees, contractor employees, visitors, 

5 and offsite members of the public from radiation and radioactive material generated at SQN. 

6 The radiation protection program is extensive and includes, but is not limited to, the following:

7 • organization and administration (i.e., Radiation Protection Manager who has 

8 overall control of 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., measuring of radiation dose to plant workers),

12 • radiological controls (i.e., protective clothing, shielding, filters, respiratory 

13 equipment, and individual work permits with specific radiological 

14 requirements),

15 • radiation area entry and exit controls (i.e., locked or barricaded doors, 

16 interlocks, local and remote alarms, personnel contamination monitoring 

17 stations), 

18 • posting of radiation hazards (i.e., signs and notices alerting plant personnel of 

19 potential hazards),

20 • record keeping and reporting (i.e., documentation of worker dose and 

21 radiation survey data),

22 • radiation safety training (i.e., classroom training and use of mockups to 

23 simulate complex work assignments),

24 • radioactive effluent monitoring management (i.e., control and monitoring of 

25 radioactive liquid and gaseous effluents released into the environment),

26 • radioactive environmental monitoring (i.e., sampling and analysis of 

27 environmental media such as air, water, vegetation, food crops, direct 

28 radiation, and milk, to measure the levels of radioactive material in the 

29 environment that may affect human health), and

30 • radiological waste management (i.e., control, monitoring, processing, and 

31 disposal of radioactive solid waste).

32 Regarding the radiation exposure to SQN personnel, the NRC staff reviewed the data contained 

33 in NUREG-0713, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and 

34 Other Facilities 2011: Forty-Fourth Annual Report (NUREG-0713, Volume 33) (NRC 2013f). 

35 This report, which was the most recent available at the time of this review, summarizes the 

36 occupational exposure data through 2011 that are maintained in the NRC’s Radiation Exposure 

37 Information and Reporting System (REIRS) database. Nuclear power plants are required by 

38 10 CFR 20.2206 to report their occupational exposure data to the NRC annually.
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1 NUREG-0713 calculates a 3-year average collective dose per reactor for all nuclear power 

2 reactors licensed by the NRC. The 3-year average collective dose is one of the metrics that the 

3 NRC uses in the Reactor Oversight Program to evaluate the effectiveness of the licensee’s

4 ALARA program. Collective dose is the sum of the individual doses received by workers at a 

5 facility licensed to use radioactive material over a one year time period. Based on the data for 

6 operating pressurized-water reactors (PWRs) like those at SQN, the average annual collective 

7 dose per reactor was 59.71 person-rem. In comparison, SQN had a reported annual collective 

8 dose per reactor of 55.52 person-rem.

9 In addition, as reported in NUREG-0713, for 2011, no worker at SQN received an annual dose

10 greater than 0.5 rem (0.005 Sv), which is well below the NRC occupational dose limit of 5.0 rem

11 (0.05 Sv) in 10 CFR 20.1201. 

12 3.11.2 Chemical Hazards

13 The use, storage, and discharge of chemicals, biocides, and sanitary wastes, as well as minor 

14 chemical spills are regulated by State and Federal environmental agencies. Chemical hazards 

15 to plant workers resulting from continued operations and refurbishment associated with license 

16 renewal are expected to be minimized by the applicant’s implementing good industrial hygiene 

17 practices as required by permits and Federal and State regulations. Plant discharges of these 

18 chemical and sanitary wastes are monitored and controlled as part of the plant’s NPDES permit 

19 process to minimize impacts to the public and the environment. In addition, proposed changes 

20 in the use of cooling water treatment chemicals would require review by the plant’s NPDES 

21 permit-issuing authority and possible modification of the existing NPDES permit, including 

22 examination of the human health effects of the change. The GEIS concluded that the impacts 

23 from these chemical and sanitary wastes, when released within the limits specified in the 

24 NPDES permit, would be SMALL and classified the issue as Category 1 (NRC 2013c).

25 The use, storage, and discharge of chemicals and sanitary wastes at SQN are controlled in 

26 accordance with site and fleet chemical control procedures and site-specific chemical spill 

27 prevention plans. SQN’s Spill Prevention, Control, and Countermeasures (SPCC) Plan serves 

28 as the site’s hazardous waste contingency plan. Chemical wastes are controlled and managed 

29 in accordance with SQN’s waste management procedure. These plant procedures and plans 

30 are designed to prevent and minimize the potential for a chemical or hazardous waste release 

31 that could affect workers, members of the public, and the environment (TVA 2013n).

32 3.11.3 Microbiological Hazards

33 Microbiological hazards associated with nuclear plant cooling operations and thermal discharge

34 include thermophilic microorganisms such as enteric pathogens (Salmonella spp., Shigella spp., 

35 and Pseudomonas aeruginosa), thermophilic fungi, bacteria (Legionella spp.), and the 

36 free-living amoeba (Naegleria fowleri). The presence of these microorganisms could result in 

37 adverse effects to the health of nuclear power plant workers in plants that use cooling towers 

38 and to the health of the public where thermal effluents discharge into cooling ponds, lakes, 

39 canals, or rivers. 

40 3.11.3.1 Background Information on Microorganisms of Concern

41 Salmonella typhimurium and S. enteritidis are two species of enteric bacteria that cause 

42 salmonellosis, which is more common in summer than in winter. Salmonellosis is transmitted 

43 through contact with contaminated human or animal feces and may be spread through water 

44 transmission or contact with food or infected animals (CDC 2013d). The bacteria grow at 

45 temperatures ranging from 77 to 113 °F (25 to 45 °C), have an optimal growth temperature 
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1 around human body temperature (98.6°F (37 °C)), and can survive extreme temperatures as 

2 low as 41 °F (5 °C) and as high as 122 °F (50 °C) (Oscar 2009). Research studies examining 

3 the persistence of Salmonella spp. outside of a host found that the bacteria can survive for

4 several months in water and in aquatic sediments (Moore et al. 2003).

5 Shigellosis infections are caused by the transmission of Shigella spp. from person to person 

6 through contaminated feces and unhygienic handling of food. Like salmonellosis, infections are 

7 more common in summer than in winter (CDC 2013d). The bacteria grow at temperatures 

8 between 77 and 99 °F (25 and 37 °C) and can survive temperatures as low as 41 °F (5 °C) 

9 (PHAC 2010).

10 Pseudomonas aeruginosa can be found in soil, hospital respirators, water, sewage, and on the 

11 skin of healthy individuals. It is most commonly linked to infections transmitted in healthcare 

12 settings. It is a waterborne pathogen, and infections from exposure to P. aeruginosa in water 

13 can lead to development of mild respiratory illness (CDC 2013c). These bacteria have an 

14 optimal growth temperature of 98.6 °F (37 °C) and can survive in temperatures as high as 

15 107.6 °F (42 °C) (Todar 2004).

16 Legionella spp. infections result in legionellosis (e.g., Legionnaires’ disease), which manifests 

17 as a dangerous form of pneumonia or an influenza-like illness. Legionellosis occurrences vary 

18 by season and geographic location; mid-Atlantic states report the highest numbers of cases 

19 during summer and early fall (CDC 2011). Legionella spp. thrive in aquatic environments as 

20 intracellular parasites of protozoa and are only infectious in humans through inhalation contact 

21 from an environmental source (CDC 2013a). Conditions that favor Legionella spp. growth are 

22 stagnant water between 95 and 115 °F (35 and 46 °C), although the bacteria can grow at 

23 temperatures as low as 68 °F (20 °C) and as high as 122 °F (50 °C) (OSHA 1999).

24 The free-living amoeba Naegleria fowleri prefers warm freshwater habitats and is the causative 

25 agent of human primary amoebic meningoencephalitis. Infections occur when N. fowleri

26 penetrate the nasal tissue through direct contact with water in warm lakes, rivers, or hot springs 

27 and migrate to the brain tissues (CDC 2013b). This free-swimming amoeba is rarely found in 

28 water temperatures below 95 °F (35 °C), and infections rarely occur at those temperatures 

29 (Tyndall et al. 1989). 

30 3.11.3.2 Studies of Microorganisms in Cooling Towers

31 A 1981 study (Tyndall 1982) found pathogenic Naegleria fowleri in heated cooling water at 2 of 

32 11 nuclear power plant sites and infectious Legionella spp. at 7 of the 11 sites. The 

33 concentrations of these organisms at these sites increased less than 10-fold in heated waters 

34 relative to source water. Tyndall’s (1982) recommendations for disease prevention include the 

35 use of protective devices for plant personnel in close contact with cooling water sources known 

36 to contain infectious microorganisms. 

37 In another study, Tyndall (1983) examined the distribution and abundance of Legionella spp.

38 and N. fowleri near large industrial cooling towers. Legionella spp. were detected at low 

39 abundances in air discharged from cooling towers and in some upwind and downwind air 

40 samples during high-wind events. N. fowleri were detected but were not pathogenic. Tyndall 

41 (1983) concludes that industrial hygiene measures to limit plant worker exposure during 

42 maintenance of cooling water systems may be appropriate.

43 A more recent study (Berk et al. 2006) examined 40 natural aquatic environments and 

44 40 cooling towers to determine the relative abundance of amoebae that may harbor infectious 

45 bacteria due to cooling tower operations from industries, hospitals, and public buildings. Those 

46 authors find that infected amoebae are 16 times more likely to occur in cooling towers than in 
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1 natural environments and that cooling towers may be possible “hot spots” for emerging 

2 pathogenic bacteria.

3 3.11.3.3 Microbiological Hazards to Plant Workers

4 Plant workers are most likely to be exposed to pathogenic microorganisms from power plant 

5 operations when cleaning or providing other maintenance services that involve the cooling water 

6 system, including cooling towers and condensers. Diseases (e.g., legionellosis and primary 

7 amoebic meningoencephalitis) that involve respiratory or nasal infectivity routes are of primary 

8 concern, and workers should wear appropriate respiratory protection. Workers performing 

9 underwater activities should wear protective gear to prevent oral or nasal exposure to amoebae 

10 or other pathogenic bacteria. Plant operators should continue using proven industrial hygiene 

11 principles to minimize workforce exposures to microbiological organisms that may occur in the 

12 cooling water system (NRC 2013c).

13 3.11.3.4 Microbiological Hazards to the Public

14 Thermal effluents produced during nuclear power plant operations are discharged to lakes, 

15 ponds, canals, or rivers and, therefore, may enhance the growth of naturally occurring 

16 thermophilic microorganisms. The public may come into contact with these water bodies 

17 through swimming and boating activities. NPDES permits limit the maximum daily temperature 

18 for the discharge. Although public access to these freshwater sources is often limited, at some 

19 locations, depending on the NPDES limits, the temperatures could support survival of the 

20 thermophilic microorganisms during summer conditions. The Tennessee Department of Health 

21 (TDH) (Cooper et al. 2009) found no reported cases of Naegleria fowleri infection and 386 

22 reported cases of legionellosis between 2000 and 2009.

23 3.11.4 Electromagnetic Fields

24 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

25 energized conductors or from induced charges in metallic structures has not been found to be a 

26 problem at most operating plants and generally is not expected to be a problem during the 

27 license renewal term. However, a site-specific review is required to determine the significance 

28 of the electric shock potential along the portions of the transmission lines that are within the 

29 scope of this SEIS.

30 In the GEIS, the NRC found that without a review of the conformance of each nuclear plant 

31 transmission line with National Electrical Safety Code (NESC) criteria, it was not possible to 

32 determine the significance of the electric shock potential (IEEE 2002). Evaluation of individual 

33 plant transmission lines is necessary because the issue of electric shock safety was not 

34 addressed in the licensing process for some plants. For other plants, land use in the vicinity of 

35 transmission lines may have changed, or power distribution companies may have chosen to 

36 upgrade line voltage. To comply with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an 

37 assessment of the impact of the proposed action on the potential shock hazard from the 

38 transmission lines if the transmission lines that were constructed for the specific purpose of 

39 connecting the plant to the transmission system do not meet the recommendations of the NESC 

40 for preventing electric shock from induced currents. The NRC uses the NESC criteria and the 

41 applicant’s adherence to it during the current operating license as its baseline to assess the 

42 potential human health impact of the induced current from an applicant’s transmission lines. As 

43 discussed in the GEIS, the issue of electric shock is of small significance for transmission lines 

44 that are operated in adherence with the NESC criteria.

45 TVA completed a detailed analysis of the current state of compliance with NESC criteria in 

46 2012. In addition, TVA did an aerial light detection and ranging (LIDAR) survey on all of its 
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1 500-kV transmission lines that connect SQN to the electric grid. TVA used the data from the 

2 survey to calculate the potential for induced shock effects for four reference vehicles, including 

3 utility trailers, sport utility vehicles, and large farm machinery. TVA used the Power Line 

4 Systems Software (PLS-CADD) program to analyze the three-dimensional models created from 

5 the LIDAR data. All electromagnetic field calculations in PLS-CADD are based on Electric 

6 Power Research Institute (EPRI) methodology. Of the 500-kV transmission lines studied, TVA 

7 reported that there are nine transmission line spans that have insufficient clearance to limit the 

8 steady-state current caused by the electrostatic effects to the NESC standard of 5 milliamperes 

9 (mA). These line spans are as follows: Widows Creek (three spans), Franklin (two spans), 

10 Watts Bar, Unit 1 (two spans), and Watts Bar, Unit 2 (two spans).

11 In accordance with 10 CFR 51.53(c)(3)(iii), TVA has provided information on actions it is 

12 considering to reduce the potential impacts from those transmission lines that exceed the NESC 

13 standard. Using a 500-kV transmission line uprate program with defined projects, TVA plans to 

14 correct the deficiencies with improvements in various stages of planning or design. These 

15 projects are all scheduled for construction and completion by June 2017, before the end of 

16 SQN’s current operating license.

17 In addition, the following physical adjustments are being considered that could lower the 

18 calculated short-circuit loads to below 5 mA:

19 • Add tower extensions to elevate the 500-kV conductors in the problem spans.

20 • Replace existing towers with taller towers.

21 • Supply shield wires below the 500-kv phase wires in the problem spans.

22 For all but the nine spans listed above, the vertical clearances of the transmission lines built to 

23 connect SQN to TVA’s transmission system are sufficient to limit the steady-state current 

24 caused by electrostatic effects to 5 mA, should the largest anticipated truck, vehicle, or 

25 equipment under the line be short-circuited to ground.

26 In its ER, TVA stated that the location of these nine spans are in areas where the potential for 

27 induced shock would be of a low risk, and a more aggressive remediation schedule is not 

28 warranted. However, as previously stated, TVA plans to correct the deficiencies, which are 

29 scheduled for completion before the end of SQN’s current operating license.

30 3.11.5 Other Hazards

31 Two additional human health issues are addressed in this section: physical occupational 

32 hazards and electric shock hazards.

33 Nuclear power plants are industrial facilities that have many of the typical occupational hazards 

34 found at any other electric power generation utility. Workers at or around nuclear power plants 

35 would be involved in some electrical work, electric power line maintenance, repair work, and 

36 maintenance activities, and thus exposed to some potentially hazardous physical conditions 

37 (e.g., falls, excessive heat, cold, noise, electric shock, and pressure). The issue of physical 

38 occupational hazards is generic to all nuclear power plants (NRC 2013c).

39 The Occupational Safety and Health Administration (OSHA) is responsible for developing and 

40 enforcing workplace safety regulations. OSHA was created by the Occupational Safety and 

41 Health Act of 1970 (29 U.S.C. § 651 et seq.), which was enacted to safeguard the health of 

42 workers. With specific regard to nuclear power plants, plant conditions that result in an 

43 occupational risk, but do not affect the safety of licensed radioactive materials, are under the 

44 statutory authority of OSHA rather than the NRC as set forth in a Memorandum of 

45 Understanding (53 FR 47279, November 22, 1988) between the NRC and OSHA. Occupational 
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1 hazards can be minimized when workers adhere to safety standards and use appropriate 

2 protective equipment; however, fatalities and injuries from accidents can still occur.

3 Physical occupational safety and health hazards are generic to all types of electrical generating 

4 stations, including nuclear power plants (NRC 2013c). As discussed above, worker safety is 

5 regulated by OSHA. As a Federal agency, TVA is not directly subject to regulation from OSHA; 

6 however, TVA and its contractors use health and safety practices that comply with OSHA’s 

7 substantive requirements.

8 3.12 Environmental Justice

9 Under Executive Order (E.O.) 12898 (59 FR 7629), Federal agencies are responsible for 

10 identifying and addressing, as appropriate, disproportionately high and adverse human health 

11 and environmental impacts on minority and low-income populations. In 2004, the Commission 

12 issued a Policy Statement on the Treatment of Environmental Justice Matters in NRC 

13 Regulatory and Licensing Actions (69 FR 52040), which states, “The Commission is committed 

14 to the general goals set forth in E.O. 12898, and strives to meet those goals as part of its 

15 [National Environmental Policy Act] NEPA review process.”

16 The Council on Environmental Quality (CEQ) provides the following information in 

17 Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 1997):

18 Disproportionately High and Adverse Human Health Effects.

19 Adverse health effects are measured in risks and rates that could result in latent 

20 cancer fatalities, as well as other fatal or nonfatal adverse impacts on human 

21 health. Adverse health effects may include bodily impairment, infirmity, illness, or 

22 death. Disproportionately high and adverse human health effects occur when the 

23 risk or rate of exposure to an environmental hazard for a minority or low-income 

24 population is significant (as employed by NEPA) and appreciably exceeds the 

25 risk or exposure rate for the general population or for another appropriate 

26 comparison group (CEQ 1997).

27 Disproportionately High and Adverse Environmental Effects.

28 A disproportionately high environmental impact that is significant (as employed 

29 by NEPA) refers to an impact or risk of an impact on the natural or physical 

30 environment in a low-income or minority community that appreciably exceeds the 

31 environmental impact on the larger community. Such effects may include 

32 ecological, cultural, human health, economic, or social impacts. An adverse 

33 environmental impact is an impact that is determined to be both harmful and 

34 significant (as employed by NEPA). In assessing cultural and aesthetic

35 environmental impacts, impacts that uniquely affect geographically dislocated or 

36 dispersed minority or low-income populations or American Indian tribes are 

37 considered (CEQ 1997).

38 The environmental justice analysis assesses the potential for disproportionately high and 

39 adverse human health or environmental effects on minority and low-income populations that 

40 could result from the operation of SQN during the renewal term. In assessing the impacts, the 

41 following definitions of minority individuals and populations and low-income population were 

42 used (CEQ 1997):

43 Minority Individuals

44 Individuals who identify themselves as members of the following population 

45 groups: Hispanic or Latino, American Indian or Alaska Native, Asian, Black or 

46 African-American, Native Hawaiian or Other Pacific Islander, or two or more 
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1 races, meaning individuals who identified themselves on a Census form as being 

2 a member of two or more races; for example, Hispanic and Asian.

3 Minority Populations

4 Minority populations are identified when (1) the minority population of an affected 

5 area exceeds 50 percent or (2) the minority population percentage of the affected 

6 area is meaningfully greater than the minority population percentage in the 

7 general population or other appropriate unit of geographic analysis.

8 Low-Income Population

9 Low-income populations in an affected area are identified with the annual 

10 statistical poverty thresholds from the Census Bureau’s Current Population 

11 Reports, Series P60, on Income and Poverty.

12 3.12.1 Minority Population

13 According to 2010 Census data, 17.5 percent of the population residing within a 50-mi (80-km) 

14 radius of SQN identified themselves as minority individuals. The largest minority group was 

15 Black or African-American (8.1 percent), followed by Hispanic or Latino (of any race) 

16 (6.7 percent) (CAPS 2012).

17 According to 2010 Census data, minority populations in the socioeconomic ROI (Hamilton and 

18 Rhea Counties) composed 26.3 percent of the total two-county population (see Table 3–27). 

19 Figure 3–9 shows predominantly minority population block groups, using 2010 Census data for 

20 race and ethnicity, within a 50-mi (80-km) radius of SQN.

21 Census block groups were considered minority population block groups if the percentage of the 

22 minority population within the block group exceeded 17.5 percent (the percent of the minority 

23 population within the 50-mi radius of SQN). A minority population exists if the minority 

24 percentage of the population within the block group is meaningfully greater than the minority 

25 population percentage in the 50-mi (80-km) radius. Approximately 237 of the 779 census block 

26 groups located within the 50-mi (80-km) radius of SQN have meaningfully greater minority 

27 populations.

28 As shown in Figure 3–9, minority population block groups are mostly clustered near 

29 Chattanooga and Cleveland, Tennessee, and Dalton, Georgia. None of the block groups near 

30 Soddy-Daisy and SQN have meaningfully greater minority populations.
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1 Figure 3–9. 2010 Census Minority Block Groups Within a 50-mi Radius of SQN

2 Source: USCB 2013d

DeKalb 

0 Cities - Aggregate Minority Populations * SON Site 0 County Boundaries 

r___ State Boundaries 

SOMite Buffer 

Bartow 

W+E 

s 

0 3 6 12 18 24 

.::i.::::i.-liC:=::::Ji--Miles 
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1 3.12.2 Low-Income Population

2 According to 2011 ACS data, an average of 14.5 percent of families and 18.7 percent of 

3 individuals residing in the 29 counties within a 50-mi (80-km) radius of SQN were identified as 

4 living below the Federal poverty threshold in 2011 (USCB 2013d). The 2011 Federal poverty 

5 threshold was $22,350 for a family of four.

6 Based on ACS data, 12.7 percent of families and 16.9 percent of individuals in Tennessee were 

7 living below the Federal poverty threshold in 2011, and the median household income for 

8 Tennessee was $43,989 (USCB 2013d). Hamilton County had higher median household 

9 incomes and lower percentages of families and individuals living in poverty compared to State 

10 averages. In Rhea County, just the opposite occurs; the county has lower household incomes 

11 and higher poverty levels than the State average. Hamilton County had a median household 

12 income average of $45,826 and 15.9 percent of individuals and 12.0 percent of families living 

13 below the poverty level. Rhea County had a median household income average of $36,934 and 

14 20.3 percent of individuals and 14.4 percent of families living below the poverty level 

15 (USCB 2013).

16 Figure 3–10 shows the location of predominantly low-income population block groups within a 

17 50-mi (80 km) radius of SQN. Census block groups were considered low-income population 

18 block groups if the percentage of individuals living below the Federal poverty threshold within 

19 any block group exceeded the percent of the individuals living below the Federal poverty 

20 threshold within the 50-mi radius of SQN. Approximately 310 of the 779 census block groups 

21 located within the 50-mi (80-km) radius of SQN have meaningfully greater low-income 

22 populations.

23 As shown in Figure 3–10, low-income block groups are evenly distributed with no particular 

24 concentrations. Wide areas of rural land and urban centers show pockets of block groups that 

25 meet the low-income criteria. None of the block groups near Soddy-Daisy and SQN have 

26 meaningfully greater low-income populations.
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1 Figure 3–10. 2010 Census Low-Income Block Groups Within a 50-mi (80 km) Radius of 

2 SQN

3 Source: USCB 2013d 

DeKalb 

Bartow 

p; ~ 

N 

0 Cities - Low Income Population * SON Site c:J County Boundaries 

1_ ___ , State Boundaries 

~50 Mile Buffer 

W+E 

s 

0 3 6 12 18 24 

Miles 
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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, SQN 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 before 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 before release are converted to 

9 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. The applicants are required to consider pollution prevention measures as 

13 dictated by the Pollution Prevention Act of 1990 (42 U.S.C. 13101 et seq.) and Resource 

14 Conservation and Recovery Act of 1976 (42 U.S.C. 6901 et seq., herein referred to as RCRA).

15 As described in Section 3.1.5, SQN has a nonradioactive waste management program to 

16 handle this nonradioactive waste. In addition to managing its nonradioactive waste, TVA has 

17 programs in place to minimize the generation of this waste. As stated by TVA in its ER, SQN is 

18 committed to the requirements of the Tennessee Hazardous Waste Reduction Act of 1990, 

19 which requires that, wherever feasible, the generation of hazardous waste is to be reduced or 

20 eliminated as expeditiously as possible. Waste generated should, in order of priority, be 

21 reduced at its source, recovered and reused, recycled, treated, or disposed of to minimize the 

22 present and future threat to human health and the environment.

23 SQN implements a hazardous waste minimization plan to reduce, to the extent feasible, waste 

24 generated, treated, accumulated, or disposed. This plan documents waste streams that have 

25 been eliminated and lists current waste streams generated at the facility. The plan is updated 

26 annually and used in conjunction with plant waste management procedures on solid, special, 

27 hazardous, and mixed waste, and chemicals to control and minimize waste generation to the 

28 maximum extent practicable.

29 3.14 References

30 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

31 Protection Regulations for Domestic Licensing and Related Regulatory Functions.”

32 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

33 “Requirements for preparation, adoption, and submittal of implementation plans.”

34 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

35 “Designation of areas for air quality planning purposes.”

36 50 CFR Part 10.12. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 10, 

37 “General Provisions,” Subpart B– Definitions.

38 50 CFR Part 22.3. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 22, “Eagle 

39 Permits,” Subpart A–Definitions.
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1 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

2 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

3 32 FR 4001. U.S. Fish and Wildlife Service. Native fish and wildlife; endangered species. 

4 Federal Register 32(48):4001. March 11, 1967.

5 40 FR 47505. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

6 amendment listing the snail darter as an endangered species. Federal 

7 Register 40(197):47505–47506. October 9, 1975.

8 41 FR 17736. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

9 determination that two species of butterflies are threatened species and two species of 

10 mammals are endangered species. Federal Register 41(83):17736–17740. April 28, 1976. 

11 Available at <http://ecos.fws.gov/speciesProfile/profile/speciesProfile.action?spcode=A04J> 

12 (accessed 28 May 2014).

13 41 FR 24062. U.S. Fish and Wildlife Service. Endangered status for 159 taxa of animals. 

14 Federal Register 41(115):24062–24067. June 14, 1976.

15 41 FR 41914. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants, 

16 determination of critical habitat for American crocodile, California condor, Indiana bat, and 

17 Florida manatee. Federal Register 41(187):41914–41916. September 24, 1976.

18 47 FR 39827. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

19 determination of Isotria medeoloides (small whorled pogonia) to be an endangered species. 

20 Federal Register 47(178):39827–39831. September 10, 1982.

21 51 FR 22521. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

22 determination of endangered status for Scutellaria montana (large-flowered skullcap). Federal 

23 Register 51(119):22521–22524. June 20, 1986.

24 53 FR 47279. U.S. Nuclear Regulatory Commission. “Memorandum of Understanding (MOU) 

25 between the NRC and the Illinois Department of Nuclear Safety.” Federal Register 53:47279. 

26 November 22, 1988.

27 55 FR 24241. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

28 threatened status determination for Spiraea virginiana (Virginia spiraea). Federal Register

29 55(116):24241–24247. June 15, 1990.

30 59 FR 50852. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

31 final rule to reclassify the plant Isotria medeoloides (small whorled pogonia) from endangered to 

32 threatened.” Federal Register 59(193):50852–50857. October 6, 1994.

33 59 FR 7629. Executive Order No. 12898. “Federal actions to address environmental justice in 

34 minority populations and low-income populations.” Federal Register 59(32):7629–7634. 

35 February 16, 1994.

36 64 FR 46542. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

37 final rule to remove the American peregrine falcon from the Federal List of Endangered and 

38 Threatened Wildlife, and to remove the similarity of appearance provision for free-flying 

39 peregrines in the conterminous United States.” Federal Register 64(164):46542–46558. 

40 August 25, 1999.

41 67 FR 1662. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

42 reclassification of Scutellaria montana (large-flowered skullcap) from endangered to threatened. 

43 Federal Register 67(9):1662–1668. January 14, 2002.
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1 69 FR 52040. U.S. Nuclear Regulatory Commission. “Policy statement on the treatment of 

2 environmental justice matters in NRC regulatory and licensing actions.” Federal 

3 Register 69(163):52040–52048. August 24, 2004.

4 73 FR 17897. Environmental Protection Agency. “Final 8-hour ozone National Ambient Air 

5 Quality Standards designations for the Early Action Compact areas.” Federal 

6 Register 73(64):17897–17906. April 2, 2008.

7 77 FR 6467. Environmental Protection Agency. “Approval and promulgation of implementation 

8 plans; Alabama, Georgia, and Tennessee: Chattanooga; particulate matter 2002 base year 

9 emissions inventory.” Federal Register 77(26):6467–6471. February 8, 2012.

10 77 FR 24392. Environmental Protection Agency. “Approval and promulgation of implementation 

11 plans; Tennessee; regional haze State Implementation Plan.” Federal 

12 Register 77(79):24392–24397. April 24, 2012.

13 78 FR 61046. U.S. Fish and Wildlife Service. Endangered and threatened wildlife and plants; 

14 12-month finding on a petition to list the eastern small-footed bat and the northern long-eared 

15 bat as endangered or threatened species; listing the northern long-eared bat as an endangered 

16 species. Federal Register 78(231):61046-61080. October 2, 2013. Available at 

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38 Bald and Golden Eagle Protection Act of 1940, as amended, 16 U.S.C. §668-668c.

39 Baxter DS. 2000. Chickamauga Reservoir Fisheries Monitoring 1999 Cove rotenone results. 

40 Chattanooga, TN: Tennessee Valley Authority, Resource Group, Water Management, 

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15 towers compared with natural aquatic environments: implications for emerging pathogens. 

16 Environmental Science and Technology 40(23):7440–7444. Available at 

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34 Area Unemployment Statistics.” Available at <http://www.bls.gov/data/> (accessed June 2013).

35 Bohac, CE, Bowen AK. 2012. Water Use in the Tennessee Valley for 2010 and Projected Use in 

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22 County, Tennessee. Oakton, VA: FEMA Map Service Center. Map Number 47065C0255F. 

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2 First Revision. Fort Snelling, MN: FWS Region 3. 258 p. Available at 

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9 Summary and Evaluation. Bloomington, IN: FWS Region 3. September 2009. 45 p. Available at 

10 <http://www.fws.gov/midwest/Endangered/recovery/5yr_rev/pdf/INBA5Yr30Sept2009.pdf> 

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13 Agencies, and Tribes in Managing White-Nose Syndrome in Bats. Hadley, MA: FWS. May 2011. 

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17 Park News Release.” May 1, 2012. Available at 

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23 M.C. Wong, Branch Chief, NRC. Subject: Tennessee Valley Authority. Request for Concurrence 

24 with list of federally listed species and habitats for the proposed Sequoyah Nuclear Plant, 

25 Units 1 and 2, License Renewal. July 3, 2013. ADAMS No. ML13184A228.

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27 to B. Grange, Biologist, NRC. Subject: Question regarding FWS’s 7/3/13 letter on species 

28 affected by Sequoyah Nuclear Plant license renewal. July 15, 2013. ADAMS 

29 No. ML13197A395.

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31 Indiana Bat (Myotis sodalist) by USFWS Region.” Revised August 26, 2013. 6 p. Available at 

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43 (Plethobasus cooperianus).” Available at 

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1 [FWS] U.S. Fish and Wildlife Service. 2013h. “Species Profile: Small whorled pogonia (Isotria 

2 medeoloides).” Available at 

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6 virginiana).” Available at 

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10 Hamilton County, Tennessee. Available at 

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16 abrupta.” Available at <http://ecos.fws.gov/docs/life_histories/F00G.html> (accessed 

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27 timing of appearance. Transactions of the American Fisheries Society 127:1021–1039. 

28 Available at <http://opensiuc.lib.siu.edu/fiaq_pubs/5/> (accessed 20 December 2013).

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10 <http://www.hixsonutility.com/HUDDownloadableDocs/ConsumerConfidenceReport.pdf> 

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13 Mixing Zone Studies for Sequoyah Nuclear Plant as Required by NPDES Permit 

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15 WR2009-1-45-151. January 2009. 126 p. ADAMS No. ML13289A134.

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17 Control.” Washington, DC: HUD. Available at 

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33 Illinois, Indiana, Kentucky, Ohio, Tennessee. Available at 

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

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41 Mettee MF, O’Neil PE, Pierson JM. 1996. Fishes of Alabama and the Mobile Basin. Geological 

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2 Tennessee Valley Authority. Washington, DC: The World Bank. WTP416. November 1998. 

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10 (Myotis grisescens). ERDC TN-EMRRP-SI-25. May 2002. 11 p. Available at 

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23 NatureServe. 2013b. “Comprehensive Report Species—Scutellaria montana.” July 2013. 

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27 NatureServe. 2013c. “Comprehensive Report Species—Lampsilis abrupta.” July 2013. Available 

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30 NatureServe. 2013d. “Comprehensive Report Species—Pleurobema plenum.” July 2013. 

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34 NatureServe. 2013e. “Comprehensive Report Species—Spiraea virginiana.” July 2013. 

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38 NatureServe. 2013f. “NatureServe Explorer: An online encyclopedia of life.” Version 7.1. 

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26 the Operation of Watts Bar Nuclear Plant, Unit 2, Supplement 2. Washington, DC: NRC. 

27 NUREG-0498, Volumes 1 and 2. May 29, 2013. 974 p. ADAMS No. ML13144A202.

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29 the Operation of Watts Bar Nuclear Plant, Unit 2, Supplement 2. Washington, DC: NRC. 

30 NUREG-0498, Volume 1. May 2013. 435 p. ADAMS No. ML13144A092.

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

36 Volumes 1, 2, and 3. June 30, 2013. 1,535 p. ADAMS Nos. ML13106A241, ML13106A242, and 

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39 Tennessee Historical Commission. April 11, 2013. ADAMS No. ML13114A201.

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41 Commercial Nuclear Power Reactors and Other Facilities 2011: Forty-Fourth Annual Report. 

42 Washington, DC: NRC. NUREG-0713, Volume 33. April 2013. 191 p. ADAMS 

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35 75 p. ADAMS No. ML13126A172.

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4 Renewal Application – Env 2.B (TAC Nos. MF0057 and MF0058). September 20, 2013. ADAMS 

5 No. ML13289A108.

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7 Licensing, to Document Control Desk, U.S. Nuclear Regulatory Commission. Subject: 

8 Documents for the environmental review of the Sequoyah Nuclear Plant, Units 1 and 2, License 

9 Renewal Application—Env 2.B (TAC Nos. MF0057 and MF0058). September 20, 2013. ADAMS 

10 Nos. ML13289A109, including ML13289A217 through ML13289A220.

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13 Documents for the environmental review of the Sequoyah Nuclear Plant, Units 1 and 2, License 

14 Renewal Application—Env 2.B (TAC Nos. MF0057 and MF0058). September 20, 2013. ADAMS 

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39 Annual Air Inspection Reports. June 30, 2013. 4 p. ADAMS No. ML13298A032.

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45 September 23, 2013. ADAMS No. ML13296A167.
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37 Tyndall RL. 1983. Presence of Pathogenic Microorganisms in Power Plant Cooling Waters: 

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15 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed July 2013). 

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17 Population: April 1, 2010 to July 1, 2012, 2012 Population Estimates.” Available at 

18 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed June 2013).

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20 (Silphium pinnatifidum Elliott). USDA Forest Service, Eastern Region. Technical Report 2005(3). 

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22 inhscwpev02005i00003_opt.pdf?sequence=2> (accessed 12 November 2013).

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24 Pink Lady’s Slipper.” Last updated 17 August 2011. Retrieved from 

25 <http://www.fs.fed.us/wildflowers/plant-of-the-week/cypripedium_acaule.shtml> (accessed 

26 12 November 2013).

27 [USDA] United States Department of Agriculture. 2012. “2007 Census of Agriculture,” Volume 1, 

28 Chapter 2, Table 1 and Table 7. 2007 Census of Agriculture, Volume 1 Chapter 2, County Level 

29 Data for Alabama, Georgia, North Carolina, and Tennessee. Last modified: 3/29/2012. Table 1: 

30 “County Summary Highlights: 2007” and Table 7: “Hired Farm Labor—Workers and Payroll: 

31 2007.” Available at 

32 <http://www.agcensus.usda.gov/Publications/2007/Full_Report/Census_by_State/> (accessed 

33 November 2013).

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35 County, Tennessee Sequoia. Natural Resources Conservation Service. Available at 

36 <http://websoilsurvey.nrcs.usda.gov/app/WebSoilSurvey.aspx> (accessed 26 February 2013).

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38 (CDL) Program.” Available at <http://nassgeodata.gmu.edu/CropScape/> (accessed May 2013).

39 [USFWS] U.S. Fish and Wildlife Service. 2013. National Wetland Inventory. Available at

40 <http://www.fws.gov/wetlands/> (accessed 9 September 2013).

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2 29 April 2003—Magnitude 4.6.” October 30, 2012. Available at 

3 <http://earthquake.usgs.gov/earthquakes/eqarchives/poster/2003/20030429.php> (accessed 

4 Sept 13, 2013).

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9 13 May 2013).

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11 2020, 2030, and 2040.” Available at <http://tndata.utk.edu/sdcdemographics.htm> (accessed 

12 June 2013).

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14 Lizard (Ophisaurus attenuatus longicaudus). Available at 

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20 19 December 2013).

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24 Part II. Proceedings of the First Freshwater Mussel Conservation Society Symposium 

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26 Whitaker JO, Jr., Brack V, Jr. Distribution and summer ecology in Indiana. p 48–54. In: Kurta A, 

27 Kennedy J, editors. 2002. The Indiana Bat: Biology and Management of an Endangered 

28 Species. Austin, TX: Bat Conservation International.

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30 editors. Rivers of North America. New York, NY: Elsevier Academic Press. p 384–390.

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32 Rotenone Results. Chattanooga, TN: Tennessee Valley Authority, River Basin Operations, 

33 Water Resources. March 1994. 63 p. ADAMS No. ML073510311.

34 Wood N, Ratliff J. 2011. Population and Business Exposure to Twenty Scenario Earthquakes in 

35 the State of Washington. Reston, VA: U.S. Geological Survey. Open-File Report 2011-1016.

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37 15 April 2013).

4-1 

1 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS

2 4.1 Introduction

3 In this chapter, the U.S. Nuclear Regulatory Commission (NRC) evaluates the environmental 

4 consequences of the proposed action (i.e., license renewal of Sequoyah Nuclear Plant, 

5 Units 1 and 2 (SQN)), including the (1) impacts associated with continued operations similar to 

6 those that have occurred during the current license terms; (2) impacts of various alternatives to 

7 the proposed action; (3) impacts from the termination of nuclear power plant operations and 

8 decommissioning after the license renewal term (with emphasis on the incremental effect 

9 caused by an additional 20 years of operation); (4) impacts associated with the uranium fuel 

10 cycle; (5) impacts of postulated accidents (design-basis accidents (DBAs) and severe 

11 accidents); (6) cumulative impacts of the proposed action; and (7) resource commitments 

12 associated with the proposed action, including unavoidable adverse impacts, the relationship 

13 between short-term use and long-term productivity, and irreversible and irretrievable 

14 commitment of resources. The NRC also considers new and potentially significant information 

15 on environmental issues related to operation during the renewal term.

16 The Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS) 

17 (NRC 2013e) identifies 78 issues to be evaluated in the license renewal environmental review 

18 process. Generic issues (Category 1) rely on the analysis presented in the GEIS, unless 

19 otherwise noted. Applicable site-specific issues (Category 2) have been analyzed for SQN and 

20 assigned a significance level of SMALL, MODERATE, or LARGE. Section 1.4 of this SEIS 

21 provides an explanation of the criteria for Category 1 and Category 2 issues, as well as the 

22 definitions of SMALL, MODERATE, and LARGE. Resource-specific impact significance level 

23 definitions are provided where applicable. 

24 4.2 Land Use and Visual Resources

25 This section describes the potential impacts of the proposed action (license renewal) and 

26 alternatives to the proposed action on land use and visual resources. 

27 4.2.1 Proposed Action

28 The land use and visual resource issues applicable to SQN during the license renewal term are 

29 listed in Table 4–1. Section 3.2 describes the land use and visual resources associated with 

30 SQN. There are no Category 2 issues for land use and visual resources.

31 The NRC staff did not identify any new and significant information related to the generic 

32 (Category 1) issues listed above during the review of TVA’s Environmental Report (ER), the site 

33 audit, or the scoping process. Therefore, no impacts are associated with these issues beyond 

34 those discussed in the GEIS. The GEIS concludes that the impact levels for these issues are 

35 SMALL.
Environmental Consequences and Mitigating Actions

4-2 

1 Table 4–1. Land Use and Visual Resources

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) 4.2.1.1 1 

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.

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

2 4.2.2 No-Action Alternative – Land Use and Visual Resources

3 4.2.2.1 Land Use

4 Plant shutdown would not affect onsite land use prior to decommissioning. Plant structures and 

5 other facilities would remain in place until decommissioning, and no additional land would be 

6 required. The staff expects no impacts associated with this issue beyond those discussed in the 

7 GEIS, which concludes that the impact level for this issue would be SMALL.

8 4.2.2.2 Visual Resources

9 The overall appearance of the major plant structures is not expected to change prior to 

10 decommissioning. Once the cooling towers stop operating, the condensate plumes from the 

11 onsite cooling towers would no occur and therefore, would no longer be part of the viewshed.

12 The NRC staff expects no impacts associated with this issue beyond those discussed in the 

13 GEIS. The GEIS concludes that the impact level for this issue would be SMALL. 

14 4.2.3 NGCC Alternative – Land Use and Visual Resources

15 4.2.3.1 Land Use

16 The analysis of land use impacts focuses on the amount of land area that would be affected by 

17 the construction and operation of a natural gas combined-cycle (NGCC) plant at an existing 

18 power plant or brownfield site other than SQN. Locating the new NGCC power plant at or near 

19 an existing power plant site would maximize the availability of support infrastructure and reduce 

20 the need for additional land.

21 Construction of an NGCC plant would require approximately 48 acres (ac) (19 ha) of land for the 

22 plant and associated infrastructure. This estimate is based on NETL’s (2010b) scaling factor of 

23 0.02 ac/MW. Depending on the site location and availability of existing natural gas pipelines, a 

24 100-ft-wide (30.5-m-wide) ROW would be needed for a new pipeline. Collocating a new 

25 pipeline within an existing ROW would minimize land use impacts. Assuming the NGCC 

26 alternative is built within the footprint of an existing power plant site, land use impacts from 

27 NGCC construction would be SMALL.
Environmental Consequences and Mitigating Actions

4-3 

1 In addition to onsite land requirements, land would be required off site for natural gas wells and 

2 collection stations during operations. The 1996 GEIS indicates that 3,600 ac (1,457 ha) would 

3 be necessary for wells, collection stations, and associated pipelines for a 1,000-MW gas-fired 

4 power plant. Using scaled 1996 GEIS figures, the NGCC alternative may require up to 8,640 ac 

5 (3,497 ha) of land for gas extraction and collection. The elimination of uranium fuel for SQN 

6 could partially offset some, but not all, of the land requirements for the NGCC. Scaling from 

7 GEIS (NRC 1996) estimates, approximately 240 ac (97 ha) per year, or 4,800 ac (1,900 ha) 

8 over 20 years, of land would be used for uranium mining to supply fuel to SQN (based on 

9 100 ac (40 ha) of temporarily disturbed land per 1,000-MW nuclear plant). Therefore, land use 

10 impacts from operation of the NGCC alternative would be SMALL.

11 4.2.3.2 Visual Resources

12 The analysis of aesthetic impacts focuses on the visibility of the NGCC alternative and its 

13 degree of contrast to the surrounding landscape. During construction, all clearing and 

14 excavation would occur on the existing power plant or brownfield site and be visible off site. 

15 Since the existing power plant site would already appear industrial, construction of the NGCC 

16 power plant would appear similar to other ongoing onsite activities. The tallest structures at the 

17 new plant would include two exhaust stacks up to 150 ft (46 m) tall and two mechanical draft 

18 cooling towers over 100 ft (30 m) high (NRC 2013d). The facility would be visible off site during 

19 daylight hours, and some structures may require aircraft warning lights. The addition of 

20 mechanical draft cooling towers and associated condensate plumes could add to the visual 

21 impact. The power block of the NGCC alternative could look similar to the existing power plant.

22 In general, given the industrial appearance of the existing power plant site, the new NGCC 

23 power plant would blend in with the surroundings and the NGCC power plant could be similar in 

24 appearance to the existing power plant. Aesthetic changes would be limited to the immediate 

25 vicinity of the existing power plant site, and any impacts would be SMALL assuming the NGCC 

26 alternative is built at an existing power plant site that has infrastructure of a similar appearance 

27 and height to that of the NGCC alternative.

28 4.2.4 SCPC Alternative – Land Use and Visual Resources

29 4.2.4.1 Land Use

30 The analysis of land use impacts focuses on the amount of land area that would be affected by 

31 the construction and operation of a supercritical pulverized coal (SCPC) power plant at an 

32 existing power plant site or a brownfield site with available infrastructure. Locating the new 

33 SCPC power plant at or near an existing power plant site, or a brownfield site with available 

34 infrastructure, would maximize the availability of support infrastructure and reduce the need for 

35 additional land.

36 The NRC staff assumed that the SCPC alternative would require approximately 131 ac (53 ha), 

37 based on a scaling factor of 0.05 ac/MW (NETL 2010a, 2010b). Depending on existing power 

38 plant infrastructure, additional land may be needed to build sufficient infrastructure for frequent 

39 coal and limestone deliveries by rail or barge. This land may not have been previously 

40 industrial, particularly if the SCPC alternative is sited at a smaller previous plant site or 

41 brownfield site. For example, an NGCC plant is typically one-half to one-third the size of an 

42 SCPC plant. If an SCPC plant is built on an existing NGCC site, the footprint of the SCPC plant 

43 would likely exceed the existing footprint of the NGCC site. Impacts could range from minimal, 

44 if the newly disturbed land surrounding the NGCC site was previously used for industrial 

45 purposes, to noticeable, if newly disturbed land that exceeded the original footprint of the NGCC 

46 site was previously used for nonindustrial land uses. Therefore, the land use impacts from 

47 construction would range from SMALL to MODERATE depending on the amount of new 
Environmental Consequences and Mitigating Actions

4-4 

1 infrastructure required for operation (e.g., new railroads) and the extent that land adjacent to the 

2 site is converted to an industrial land use.

3 Offsite land use impacts would occur from coal mining, in addition to land use impacts from the 

4 construction and operation of the new power plant. The 1996 GEIS indicates that 22,000 ac 

5 (8,900 ha) would be necessary for coal mining and processing for a 1000-MW coal-fired power 

6 plant, or 22 ac/MW. A NETL study from 2010, however, found that 1,709 ac (692 ha) would be 

7 needed for coal mining for a 550-MW facility, or 3.1 ac/MW (NETL 2010c). Based on the 1996 

8 GEIS and the NETL study, the NRC assumed a range of 7,440 ac (3,011 ha) (NETL 2010c) to 

9 52,800 ac (21,400 ha) (NRC 1996) of land for coal mining and processing for the SCPC 

10 alternative.

11 The elimination of uranium fuel for SQN could partially offset some, but not all, of the land 

12 requirements for the SCPC alternative. Scaling from GEIS estimates, approximately 240 ac 

13 (97 ha) per year, or 4,800 ac (1,900 ha) over 20 years, of land used for uranium mining to 

14 supply fuel to SQN (based on 100 ac (40 ha) of temporarily disturbed land per 1,000-MW 

15 nuclear plant) no longer would be needed for mining and processing uranium during the 

16 operating life of the SCPC plant. Based on the 7,440 ac (3,011 ha) to 52,800 ac (21,400 ha) of 

17 land that would be required for coal mining and processing, land use impacts during operations 

18 could range from SMALL to MODERATE.

19 4.2.4.2 Visual Resources

20 The analysis of aesthetic impacts focuses on the visibility of the SCPC alternative and its 

21 degree of contrast to the surrounding landscape. During construction, all of the clearing and 

22 excavation would occur on the existing power plant site and would be visible off site. The 

23 coal-fired power plant could be approximately 100 ft (30 m) tall, with two to four exhaust stacks 

24 several hundred feet tall with natural-draft cooling towers approximately 500 ft (152 m) in height 

25 (NRC 2013d). The facility would be visible off site during daylight hours, and some structures 

26 may require aircraft warning lights. The condensate plumes from the cooling towers could also 

27 add to the visual impact.

28 In general, given the industrial appearance of the existing power plant site on which it would be 

29 built, the new SCPC power plant would blend in with the surroundings. The power block of the 

30 SCPC alternative could look very similar to the existing power plant and construction would 

31 appear similar to other ongoing onsite activities. However, if natural draft cooling towers did not 

32 previously exist at the site, the impact could be noticeable. Aesthetic impacts would therefore 

33 range from SMALL to MODERATE, depending on if aesthetic changes are limited to the 

34 immediate vicinity of the existing power plant site, or if the construction of new natural draft 

35 cooling towers results in a noticeable change within the viewshed of the plant.

36 4.2.5 New Nuclear Alternative – Land Use and Visual Resources

37 4.2.5.1 Land Use

38 The analysis of land use impacts focuses on the amount of land area that would be affected by 

39 the construction and operation of a new two-unit nuclear power plant at or adjacent to an 

40 existing nuclear power plant site. Locating the new nuclear power plant at or near an existing 

41 power plant site would maximize the availability of support infrastructure and reduce the need 

42 for additional land.

43 TVA (2013a) estimated 1,000 ac (405 ha) (excluding transmission lines) for construction of the 

44 two new units, based on the sizes of TVA’s existing nuclear plant sites (e.g., Bellefonte, 

45 Sequoyah, and Watts Bar, which range from 600 to 1,500 ac (243 to 607 ha)). Based on the 

46 2013 GEIS, a new reactor at an alternate site would require approximately 500 to 1,000 ac 
Environmental Consequences and Mitigating Actions

4-5 

1 (202 to 405 ha). Land would be required for the construction of spent nuclear fuel and low-level 

2 radioactive waste storage facilities. The NRC staff determined that TVA’s estimate of 

3 1,000 ac (405 ha) is consistent with a scaling factor of approximately 0.49 ac/MW for a new 

4 nuclear plant used in recent SEISs, and is therefore used in this analysis. Locating the new 

5 units at or adjacent to an existing nuclear power plant would mean that the majority of the 

6 affected land area would already be zoned for industrial use. Making use of the existing 

7 infrastructure would reduce the amount of land needed to support the new units. Assuming the 

8 new nuclear alternative is built within the footprint of an existing nuclear power plant site, land 

9 use impacts from constructing two new units at an existing nuclear power plant site would be 

10 SMALL.

11 The amount of land required to mine uranium and fabricate nuclear fuel during reactor

12 operations would be similar to the amount of land required to support SQN. Impacts associated 

13 with uranium mining and fuel fabrication to support the new nuclear alternative would generally 

14 be no different from those occurring in support of the existing SQN reactors. Overall, land use 

15 impacts from nuclear power plant operations would be SMALL because the NRC staff assumed 

16 that the new nuclear plant would be sited entirely within an existing nuclear power plant site.

17 4.2.5.2 Visual Resources

18 The analysis of aesthetic impacts focuses on the visibility of the new nuclear alternative and its 

19 degree of contrast to the surrounding landscape. During construction, all of the clearing and 

20 excavation would occur on site and may be visible off site. Since the existing power plant site 

21 already appears industrial, construction of the new nuclear power plant would appear similar to 

22 other ongoing onsite activities. The tallest power plant structures would be the natural draft 

23 cooling towers, with a height of approximately 400 to 500 ft (122 to 152 m) (NRC 2013d). The 

24 towers would be visible off site during daylight hours, and they may require aircraft warning 

25 lights. Associated condensate plumes could add to the visual impact. The power block of the 

26 two new units would look very similar to the power block(s) at the existing nuclear power plant. 

27 In general, given the industrial appearance of an existing nuclear power plant site, the new 

28 nuclear power plant would blend in with its surroundings. Aesthetic changes would therefore be 

29 limited to the immediate vicinity of the existing power plant site. However, if natural draft cooling 

30 towers did not previously exist at the site, the impact could be noticeable. Aesthetic impacts 

31 would therefore range from SMALL to MODERATE, depending on if aesthetic changes are 

32 limited to the immediate vicinity of the existing power plant site, or if the construction of new 

33 natural draft cooling towers results in a noticeable change within the viewshed of the plant.

34 4.2.6 Combination Alternative – Land Use and Visual Resources

35 4.2.6.1 Land Use

36 The analysis of land-use impacts focuses on the amount of land area that would be affected by 

37 the construction and operation of a combination of wind turbines and PV solar installations.

38 Wind turbines would be located at multiple sites throughout the TVA region, or, if TVA used 

39 purchased power agreements, could include wind farm sites in other parts of the country. Wind 

40 energy facilities would require approximately 0.3 ac (0.12 ha)/MW (NRC 2013d), for a total land 

41 requirement 1,410 to 1,890 ac (570 to 765 ha) to build and operate 2,350 to 3,150 land-based 

42 wind turbines for this alternative. Although a relatively large area of land would be required for 

43 the wind portion of this alternative, only about 5 to 10 percent of the land area would be used by 

44 turbines, power collection and conditioning systems, and other support facilities. During 

45 operations, land areas between the turbines can be put to other beneficial (nonintrusive) use or 

46 may be able to remain as the same land use prior to construction. For example, most of the 
Environmental Consequences and Mitigating Actions

4-6 

1 wind farms would likely be located on open agricultural cropland or grazing pasture, which 

2 would remain largely unaffected by the wind turbines during operations.

3 The solar PV capacity would mostly be installed at already-developed sites, including on 

4 existing buildings. Based on calculations using NREL (2008) estimates, 12,400 to 17,980 ac 

5 (5,018 to 7,276 ha) could be necessary for a solar PV alternative at stand-alone sites. 

6 However, this likely overstates the potential impacts as it is anticipated that the solar PV 

7 capacity would mostly be installed at already-developed sites, including on existing buildings.

8 The elimination of uranium fuel for the SQN would partially offset some, but not all, new land 

9 requirements. Scaling from GEIS estimates, approximately 240 ac (97 ha) per year, or 4,800 ac 

10 (1,900 ha) over 20 years of land used for uranium mining to supply fuel to Sequoyah (based on

11 100 ac (40 ha) of temporarily disturbed land per 1,000-MW nuclear plant), would no longer be 

12 needed for mining and processing uranium. Based on the substantial amount of land required 

13 to construct and operate the wind and solar alternative, overall land use impacts from the 

14 combination alternative would range from SMALL to MODERATE, depending on the number of 

15 existing buildings that would be used during construction of the solar alternative and whether 

16 most of the area required for wind farms would revert back to the original land use.

17 4.2.6.2 Visual Resources

18 The analysis of aesthetic impacts focuses on the degree of contrast between the wind and solar 

19 installations and surrounding landscapes and the visibility of new wind turbines at existing wind 

20 farms and PV solar technologies on existing buildings. In general, aesthetic changes would be 

21 limited to the immediate vicinity of PV solar installations, but could expand for wind installations 

22 depending on the location, topography, and other structures and trees near the chosen sites.

23 Wind turbines would have the greatest potential visual impact. Modern wind turbines have rotor 

24 diameters greater than 300 ft (100 m) on towers that are hundreds of feet tall (NRC 2013d). 

25 Spread across multiple sites, wind turbines often dominate the viewshed and become a major 

26 focus of attention. However, adding additional wind turbines to existing wind farms is not likely 

27 to increase the visual impact of the wind farm unless the number of wind turbines is 

28 considerably increased. Any PV solar technologies located on building rooftops or within 

29 preexisting solar farms, may or may not be seen off site, but would be less noticeable in urban 

30 settings.

31 Based on this information, aesthetic changes caused by this combination alternative would 

32 range from SMALL to MODERATE, depending on visibility of new wind installation and whether 

33 wind turbines are added to existing wind farms or whether entirely new wind farms are required 

34 to support the combination alternative.

35 4.3 Air Quality and Noise

36 This section describes the potential impacts of the proposed action (license renewal) and 

37 alternatives to the proposed action on air quality and noise conditions. 

38 4.3.1 Proposed Action

39 4.3.1.1 Air Quality

40 The air quality issues applicable to SQN during the license renewal term are listed in Table 4–2. 

41 Section 3.3 describes the meteorological, air quality, and noise conditions in the vicinity of SQN. 

42 There are no Category 2 issues for air quality.
Environmental Consequences and Mitigating Actions

4-7 

1 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

2 The Category 1 issue “air quality impacts (all plants)” considers the air quality impacts from 

3 continued operation associated with license renewal. Section 3.3.2 discusses the air quality 

4 conditions in the vicinity of SQN as well as air emissions resulting from operation of SQN. Air 

5 emissions from SQN operations are regulated by the synthetic minor operating permit 

6 conditions (Clean Air Act (CAA) Source ID: 4706504150) and these would continue in effect 

7 during the license renewal period. There are no planned refurbishment activities associated 

8 with license renewal and, therefore, no associated additional air emissions with refurbishment 

9 activities. The only expected equipment change that could increase air emissions will be from a 

10 blackout diesel generator and up to three emergency diesel generators (EDGs) being installed 

11 at each unit in 2016 in response to NRC’s order (Order Number: EA-12-049) titled “Order 

12 Modifying Licenses with Regard to Requirements for Mitigation Strategies for 

13 Beyond-Design-Basis External Events” (TVA 2013d, 2013m). The diesel generators are 

14 expected to be operated only in the event of loss of alternating current (AC) power to the site 

15 and during periodic routine testing. In periodic tests of the diesel generators they are estimated 

16 to emit 0.11, 0.11, 4.1, 1.0, 0.002 MT/year of PM10, PM2.5, nitrogen oxides, carbon monoxide, 

17 sulfur dioxide, respectively (TVA 2013k). Installation and operation of the new generators will 

18 result in limited emissions and are not associated with license renewal (TVA 2013e, 2013i).

19 The Category 1 issue “air quality effects of transmission lines” considers the production of 

20 ozone and oxides of nitrogen; the GEIS found that minute and insignificant amounts of ozone 

21 and nitrogen oxides are generated during transmission. Results of field testing in the vicinity of 

22 SQN’s transmission lines are consistent with GEIS conclusions, in that ozone levels were not 

23 measurable above ambient amounts at ground level (TVA 2013a).

24 The NRC staff did not identify any new and significant information during the review of TVA’s 

25 ER (TVA 2013a), the site audit, or during the scoping process. As a result, no information or 

26 impacts related to these issues were identified that would change the conclusions presented in 

27 the GEIS. Therefore, there are no impacts related to these issues beyond those discussed in 

28 the GEIS. For these two Category 1 issues, the GEIS concluded that the impacts are SMALL.

29 4.3.1.2 Noise

30 One Category 1 noise issue is applicable to SQN, “noise impacts” (see Table 4–2). 

31 Section 3.3.3 discusses the noise conditions in the vicinity of SQN as well as noise resulting 

32 from operation of SQN. There is no planned refurbishment associated with license renewal 

33 and, therefore, no associated noise emissions with refurbishment activities. The NRC staff did 

34 not identify any new and significant information during the review of TVA’s ER (TVA 2013a), the 

35 site audit, or during the scoping process. No major facility construction or refurbishments are 

36 planned to occur during the license renewal period. Therefore, there are no impacts related to 

37 this issue beyond those discussed in the GEIS. For this Category 1 issue, the GEIS concluded 

38 that the impacts are SMALL.
Environmental Consequences and Mitigating Actions

4-8 

1 4.3.2 No-Action Alternative – Air Quality and Noise

2 4.3.2.1 Air Quality

3 When the plant stops operating, there will be a reduction in emissions from activities related to 

4 plant operation, such as use of diesel generators and employee vehicles. In Section 4.3.1, the 

5 NRC staff determined that these emissions would have a SMALL impact on air quality during 

6 the renewal term. Therefore, if emissions decrease, the impact on air quality would also 

7 decrease and would be SMALL.

8 4.3.2.2 Noise

9 When the plant stops operating, there will be a reduction in noise that is generated from sources 

10 associated with plant operations, such as fans, turbine generators, transformers, cooling towers, 

11 compressors, emergency generators, main steam-safety relief valves, and emergency sirens. 

12 In Section 4.3.1, the NRC staff determined that these noise sources have a SMALL impact on 

13 ambient noise levels during the renewal term. Therefore, if these noise sources are reduced, 

14 the impact on ambient noise levels would also be reduced and would be SMALL.

15 4.3.3 NGCC Alternative – Air Quality and Noise

16 4.3.3.1 Air Quality

17 This alternative includes the construction and operation of six 400-MWe NGCC generation units 

18 with a total output of 2,400 MWe. Because of land restrictions at the SQN site, the NGCC 

19 generating plant would likely be located near an existing power plant or brownfield site with 

20 available infrastructure within the TVA region (including parts of Tennessee, North Carolina, 

21 Virginia, Kentucky, Georgia, Alabama, and Mississippi).

22 Construction of the NGCC plant would result in temporary impacts on local air quality. Activities 

23 including earthmoving and vehicular traffic generate fugitive dust. In addition, emissions from 

24 these activities would contain various air pollutants, including carbon monoxide, oxides of 

25 nitrogen, oxides of sulfur, particulate matter (PM), volatile organic compounds (VOCs), as well 

26 as various greenhouse gases (GHGs). Air emissions would be intermittent and vary based on 

27 the level and duration of a specific activity throughout the construction phase. Gas-fired power 

28 plants are constructed relatively quickly; construction lead times for NGCC plants are 

29 approximately 2 to 3 years (Dujardin 2005; EIA 2011). Various mitigation techniques could be 

30 utilized to minimize air emissions and reduce fugitive dust. Since air emissions from 

31 construction activities would be limited, local, and temporary, the NRC staff concludes that the 

32 associated air quality impacts from construction would be SMALL.

33 Operation of the NGCC plant would result in significant emissions of certain criteria pollutants, 

34 including carbon monoxide, nitrogen oxides, sulfur oxides, and PM. Consequently, a new 

35 NGCC plant would qualify as a major-emitting industrial facility and would be subject to a New 

36 Source Review (NSR) under requirements of the CAA to ensure air emissions are minimized 

37 and the local air quality is not substantially degraded (EPA 2013c). The NGCC plant would 

38 need to comply with the standards of performance for stationary combustion turbines set forth in 

39 Title 40, Part 60, of the Code of Federal Regulations (40 CFR Part 60) Subpart KKKK. Subpart 

40 P of 40 CFR Part 51.307 contains the visibility protection regulatory requirements, including 

41 review of the new sources that may affect visibility in any Federal Class I area. If the NGCC 

42 alternative were located near a mandatory Class I area, additional air pollution control 

43 requirements would be required.

44 A new NGCC plant would also have to comply with Title IV of the CAA (42 U.S.C. 7651) 

45 reduction requirements for SOx and NOx, which are the main precursors of acid rain and the 
Environmental Consequences and Mitigating Actions

4-9 

1 major causes of reduced visibility. Title IV establishes maximum SOx and NOx emission rates 

2 from the existing plants and a system of SOx emission allowances that can be used, sold, or 

3 saved for future use by new plants.

4 More recently, the U.S. Environmental Protection Agency (EPA) has promulgated additional 

5 rules and requirements that apply to certain fossil-fuel-based power plants, such as NGCC 

generation. The Clean Air Interstate Rule4 6 (CAIR) and the Title V Greenhouse Gas (GHG) 

7 Tailoring Rule impose several additional standards to limit ozone, particulate, and GHG 

8 emissions from fossil-fuel-based power plants (EPA 2013d). A new NGCC plant would be 

9 subject to these additional rules and regulations.

10 The EPA has developed standard emission factors that relate the quantity of released air 

11 pollutants to a variety of regulated activities. Emission for a NGCC plant can be estimated once 

12 the plant capacity and gas heat content are known (EPA 2000). Assuming a plant gross 

13 capacity of 2,400 MWe, a capacity factor of 0.85, and a gas heat content of 1,021 British 

14 thermal units per cubic foot, the NRC staff estimates the following air emissions for an NGCC 

15 alternative plant:

16  sulfur oxides (SOx) – 330 tons (300 MT) per year,

17  nitrogen oxides (NOx) – 960 tons (870 MT) per year,

18  carbon monoxide (CO) – 1,450 tons (1,320 MT) per year,

19  particulate matter (PM10) – 640 tons (580 MT) per year,

20  carbon dioxide (CO2) – 10,643,500 tons (9,655,621 MT) per year, and

21  methane (CH4) – 830 tons (760 MT) per year.

22 Carbon capture and storage (CCS) could be used as a method to reduce carbon dioxide by up 

23 to 90 percent; however, it would also decrease the power production capacity of an NGCC plant 

24 by up to 15 percent (NETL 2013).

25 As noted above, a new NGCC plant would be subject to several EPA regulations designed to 

26 minimize air quality impacts from operations. Nevertheless, a new NGCC plant would be a 

27 major source of criteria pollutants and GHGs and the overall air quality impacts from the 

28 operation of a new NGCC plant located within the TVA region would be SMALL to MODERATE.

29 4.3.3.2 Noise

30 Construction vehicles and equipment associated with the construction of the NGCC plant would 

31 generate noise; these impacts would be intermittent and last only through the duration of plant 

32 construction. Noise emissions from common construction equipment would be in the 85 to 

33 95 decibels adjusted (dBA) range (FHWA 2012). However, noise abatement and controls can 

34 be incorporated to reduce noise impacts.

35 Noise impacts from operations would include cooling towers (water pumps, cascading water, or 

36 fans), transformers, turbines, pumps, compressors, exhaust stack, the combustion inlet filter 

37 house, condenser fans, high-pressure steam piping, and vehicles (Saussus 2012). The NRC 

38 staff does not expect noise impacts for operation of an NGCC plant to be any greater than those 

 

4 The Clean Air Interstate Rule (CAIR) was first issued by EPA in 2005; however, the Federal rule was vacated by the D.C. Circuit 

Court on February 8, 2008. In December 2008, the U.S. Court of Appeals for the D.C. Circuit reinstated the rule, allowing it to 

remain in effect but also requiring EPA to revise the rule and its implementation plan. On July 6, 2010, EPA proposed replacing 

CAIR with the Cross-State Air Pollution Rule (CSAPR) for control of sulfur dioxide and nitrogen oxide emissions that cross state 

lines, the regulations of which would be implemented in 2011 and finalized in 2012. However, CSAPR was vacated by the 

D.C. Circuit Court on August 21, 2012. On April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit opinion vacating 

CSAPR. EPA is reviewing the opinion and CAIR remains in effect.
Environmental Consequences and Mitigating Actions

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1 associated with the existing SQN site. Therefore, the noise impacts of a new NGCC plant 

2 located within the TVA region would be SMALL.

3 4.3.4 SCPC Alternative – Air Quality and Noise

4 4.3.4.1 Air Quality

5 This alternative includes the construction and operation of two to four SCPC units with a total 

6 output of 2,400 MWe. Because of land restrictions at the SQN site, the SCPC generating plant 

7 would likely be located near an existing power plant or brownfield site with available 

8 infrastructure within the TVA region (including parts of Tennessee, North Carolina, Virginia, 

9 Kentucky, Georgia, Alabama, and Mississippi).

10 Construction of the SCPC plant would result in temporary impacts on local air quality. Activities 

11 including earthmoving and vehicular traffic generate fugitive dust. In addition, emissions from 

12 these activities would contain various air pollutants, including carbon monoxide, oxides of 

13 nitrogen, oxides of sulfur, particulate matter (PM), volatile organic compounds (VOCs), as well 

14 as various GHGs. Air emissions would be intermittent and vary based on the level and duration 

15 of a specific activity throughout the construction phase. Construction lead times for coal plants 

16 are around 5 years (NETL 2013). Various mitigation techniques could be utilized to minimize air 

17 emissions and reduce fugitive dust. Since air emissions from construction activities would be 

18 limited, local, and temporary, the NRC staff concludes that the associated air quality impacts 

19 from construction would be SMALL.

20 Operation of the SCPC plant would result in significant emissions of certain criteria pollutants, 

21 including carbon monoxide, nitrogen oxides, sulfur oxides, and PM. Consequently, a new 

22 SCPC plant would qualify as a major-emitting industrial facility and would be subject to a New 

23 Source Review (NSR) under requirements of the CAA to ensure air emissions are minimized 

24 and the local air quality is not substantially degraded (EPA 2013c). The SCPC plant would 

25 need to comply with the standards of performance for electric utility steam generating units set 

26 forth in 40 CFR Part 60 Subpart Da. Subpart P of 40 CFR Part 51.307 contains the visibility 

27 protection regulatory requirements, including review of the new sources that may affect visibility 

28 in any Federal Class I area. If the SCPC alternative were located near a mandatory Class I 

29 area, additional air pollution control requirements would be required.

30 A new SCPC plant would also have to comply with CAA (42 U.S.C. 7651) Title IV reduction 

31 requirements for sulfur oxides and nitrogen oxides, which are the main precursors of acid rain 

32 and the major causes of reduced visibility. Title IV establishes maximum sulfur oxide and 

33 nitrogen oxide emission rates from existing plants and a system of sulfur oxide emission 

34 allowances that can be used, sold, or saved for future use by new plants.

35 More recently, EPA has promulgated additional rules and requirements that apply to certain 

36 fossil-fuel-based power plants, such as SCPC generation. The CAIR, the Mercury and Air 

37 Toxics Standards (MATS), and the Title V Greenhouse Gas (GHG) Tailoring Rule impose 

38 several additional standards to limit ozone, particulate, mercury, sulfur oxides and GHG 

39 emissions from fossil-fuel-based power plants (EPA 2013d). A new SCPC plant would be 

40 subject to these additional rules and regulations.

41 EPA has developed standard emission factors that relate the quantity of released air pollutants 

42 to a variety of regulated activities. Emission for an SCPC plant can be estimated once the plant 

43 capacity, type and method of coal burning, and pollution control devices are known 

44 (EPA 1998a). Assuming a dry-bottom, tangentially fired, bituminous coal plant with a capacity 

45 of 2,400 MWe, the NRC staff estimates the following air emissions for an SCPC alternative 

46 plant:
Environmental Consequences and Mitigating Actions

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1 ● sulfur oxides (SOx) – 10,660 tons (9,670 MT) per year,

2 ● nitrogen oxides (NOx) – 2,110 tons (1,910 MT) per year,

3 ● carbon monoxide (CO) – 2,110 tons (1,910 MT) per year,

4 ● particulate matter (PM10) – 670 tons (610 MT) per year,

5 ● particulate matter (PM2.5) – 330 tons (300 MT) per year,

6 ● carbon dioxide (CO2) – 19,158,400 tons (17,380,500 MT) per year, and

7 ● mercury (Hg) – 0.35 tons (0.32 MT) per year

8 The above emission estimates assume a limestone wet scrubber is used to reduce sulfur oxide 

9 emissions by 95 percent, a low NOx burner (LNB) is used to reduce nitrogen oxide emissions by 

10 95 percent, and a fabric-filter baghouse with a 98-percent efficiency is used to control particulate 

11 emissions. Carbon capture and storage (CCS) could be used as a method to reduce carbon 

12 dioxide by up to 90 percent; however, it would also decrease the power production capacity of 

13 an SCPC plant by up to 28 percent (NETL 2013).

14 As previously noted, a new SCPC plant would be subject to several EPA regulations designed 

15 to minimize air quality impacts from operations. Nevertheless, a new SCPC plant would be a 

16 major source of criteria pollutants and GHGs and the overall air quality impacts from the 

17 operation of a new SCPC plant located within the TVA region would be MODERATE.

18 4.3.4.2 Noise

19 Construction vehicles and equipment associated with the construction of an SCPC plant would 

20 generate noise; these impacts would be intermittent and last only through the duration of plant 

21 construction. Noise emissions from common construction equipment are estimated to be in the 

22 85 to 95 dBA range (FHWA 2012). However, noise abatement and controls can be 

23 incorporated to reduce noise impacts.

24 Noise impacts from operations would include cooling towers (water pumps, cascading water, or 

25 fans), transformers, turbines, pumps, boiler, compressors, and other auxiliary equipment, such 

26 as standby generators, and vehicles (Fahda et al. 2012). The NRC staff does not expect noise 

27 impacts for an SCPC plant to be any greater than those associated with the existing SQN site. 

28 Therefore, the noise impacts of a new SCPC plant located within the TVA region would be 

29 SMALL.

30 4.3.5 New Nuclear Alternative – Air Quality and Noise

31 4.3.5.1 Air Quality

32 This alternative includes the construction and operation of two new nuclear units with a total 

33 output of 2,400 MWe. Because of land restrictions at the SQN site, the new nuclear plants 

34 would likely be located near an existing power plant within the TVA region (including parts of 

35 Tennessee, North Carolina, Virginia, Kentucky, Georgia, Alabama, and Mississippi).

36 Construction of the new nuclear plant would result in temporary impacts on local air quality. 

37 Activities including earthmoving and vehicular traffic generate fugitive dust. In addition, 

38 emissions from these activities would contain various air pollutants, including carbon monoxide, 

39 oxides of nitrogen, oxides of sulfur, particulate matter (PM), volatile organic compounds (VOCs), 

40 as well as various GHGs. Air emissions would be intermittent and vary based on the level and 

41 duration of a specific activity throughout the construction phase. Construction lead times for 

42 nuclear plants are anticipated to be 7 years (NRC 2013a). Various mitigation techniques could 

43 be utilized to minimize air emissions and reduce fugitive dust. Since air emissions from 
Environmental Consequences and Mitigating Actions

4-12

1 construction activities would be limited, local, and temporary, the NRC staff concludes that the 

2 associated air quality impacts from construction would be SMALL.

3 Operation of a new nuclear generating plant would result in similar air emissions to those of the 

4 existing SQN site; air emissions would be primarily from backup diesel generators and boilers 

5 as well as particulates from the cooling towers. As noted in Section 3.3, TVA maintains a 

6 synthetic minor operating permit for sources of air pollution at the SQN site (TVA 2013a). A 

7 synthetic minor source has the potential to emit air pollutants in quantities at or above the major 

8 source threshold levels but has accepted federally enforceable limitations to keep the emissions 

9 below such levels. Because air emissions from a new nuclear plant would be similar to those 

10 from SQN, the NRC staff expects similar air permitting conditions and regulatory requirements. 

11 Subpart P of 40 CFR Part 51.307 contains the visibility protection regulatory requirements, 

12 including the review of the new sources that may affect visibility in any Federal Class I area. If a 

13 new nuclear plant were located near a mandatory Class I area, additional air pollution control 

14 requirements may be required.

15 The NRC staff estimates the following air emissions from a new nuclear plant:

16 ● sulfur oxides (SOx) – 0.22 tons (0.19 MT) per year,

17 ● nitrogen oxides (NOx) – 13 tons (12 MT) per year,

18 ● carbon monoxide (CO) – 4 tons (3 MT) per year,

19 ● total suspended particles (TSP) – 5.8 tons (5.2 MT) per year,

20 ● particulate matter (PM10) – 0.2 tons (0.18 MT) per year, and

21 ● carbon dioxide equivalent (CO2e) – 700 tons (635 MT) per year.

22 As previously noted, a new nuclear plant would be considered a minor source of criteria 

23 pollutants and GHGs and the overall air quality impacts from the operation of a new nuclear 

24 plant located within the TVA region would be SMALL.

25 4.3.5.2 Noise

26 Construction vehicles and equipment associated with the construction of the new nuclear plant 

27 would generate noise; these impacts would be intermittent and last only through the duration of 

28 plant construction. Noise emissions from construction equipment are estimated to be in the 85 

29 to 95 dBA range (FHWA 2012). However, noise abatement and controls can be incorporated to 

30 reduce noise impacts.

31 Noise impacts from operations would include cooling towers (water pumps, cascading water, or 

32 fans), transformers, turbines, pumps, compressors, and other auxiliary equipment, such as 

33 standby generators, and vehicles. The NRC staff does not expect noise impacts for a new 

34 nuclear plant to be any greater than that analyzed for the existing SQN site. Therefore, the 

35 noise impacts of a new nuclear plant located within the TVA region would be SMALL.

36 4.3.6 Combination Alternative – Air Quality and Noise

37 4.3.6.1 Air Quality

38 The combination alternative relies on wind and solar generating capacity to replace SQN. This 

39 alternative includes an installed wind capacity of 4,700 to 6,300 MW (based on a 30 to 

40 40 percent capacity factor range) and an installed solar photovoltaic (PV) capacity of 2,000 to 

41 2,900 MW (based on a 17 to 24 percent capacity factor range) to provide replacement power. 

42 Wind generation would occur at multiple wind farm sites scattered across the TVA region, or, if 

43 TVA used purchased power agreements, could include wind farm sites in other parts of the 
Environmental Consequences and Mitigating Actions

4-13

1 country. Solar PV generation would mostly be located on existing buildings at 

2 already-developed sites throughout the TVA region.

3 Construction of the combination alternative would result in temporary impacts on local air 

4 quality. Activities including earthmoving and vehicular traffic generate fugitive dust. In addition, 

5 emissions from these activities would contain various air pollutants, including carbon monoxide, 

6 oxides of nitrogen, oxides of sulfur, particulate matter (PM), volatile organic compounds (VOCs), 

7 as well as various GHGs. Air emissions would be intermittent and vary based on the level and 

8 duration of a specific activity throughout the construction phase. The construction of wind farms 

9 and solar PV can be completed in about 1 year (First Solar 2013; Tegen 2006). Various 

10 mitigation techniques could be utilized to minimize air emissions and reduce fugitive dust. Since 

11 air emissions from construction activities would be limited, local, and temporary, the NRC staff 

12 concludes that the associated air quality impacts from construction would be SMALL.

13 Operation of the combination alternative would result in no routine direct air emissions. 

14 However, there would be intermittent air emissions associated with maintenance equipment and 

15 vehicles servicing the wind turbines and solar PV systems. These emissions would be similar to 

16 air pollutants from construction, and include carbon monoxide, nitrogen oxides, sulfur oxides, 

17 PM, and VOCs, as well as various GHGs, but would be minimal compared to those from 

18 construction activities. Emissions from operations would be limited, local, and intermittent; 

19 therefore, the NRC staff concludes that the associated air quality impacts from operation would 

20 be SMALL.

21 4.3.6.2 Noise

22 Construction vehicles and equipment associated with the construction of the combination 

23 alternative would generate noise; these impacts would be intermittent and last only through the 

24 duration of construction. Noise impacts from wind generation operations would include 

25 aerodynamic noise from the turbine rotors and mechanical noise from the turbine drivetrain 

26 components; noise levels are dependent on the wind and atmospheric conditions, which vary 

27 with time. Studies show that at approximately 1,000 ft (300 m) from a wind turbine, noise levels 

28 can reach 48 dBA (GE 2010; Hessler 2011). Except for intermittent noise associated with 

29 servicing and maintenance, there would be no routine operational noise impacts associated with 

30 the solar PV systems. The NRC staff does not expect noise impacts for the combined 

31 alternative to be any greater than those associated with the existing SQN site. Therefore, the 

32 noise impacts of wind and solar PV facilities located within the TVA region would be SMALL.

33 4.3.7 Air Quality and Noise Summary

34 Table 4–3 compares estimated air emissions resulting from the proposed action, NGCC 

35 alternative, SCPC alternative, new nuclear alternative, and the combination alternative. This 

36 table presents only direct emissions from operations of the electricity generating technologies 

37 and does not include emissions from construction or workforce vehicle emissions. The NGCC 

38 and SCPC alternatives will produce significantly greater air pollutant emissions than those 

39 associated with the proposed action (license renewal of SQN), new nuclear alternative, or the 

40 combination alternative.

41 As discussed in the sections above, noise levels and impacts from operation of the NGCC, 

42 SCPC, new nuclear, and combination alternatives would not be greater than those associated 

43 with operation of the SQN site.
Environmental Consequences and Mitigating Actions

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1 Table 4–3. Estimated Direct Air Emissions from Operation of SQN, NGCC, SCPC, New 

2 Nuclear, and Combination Alternative

Proposed Action(a) NGCC SCPC New Nuclear(b) Combination(c)

NOx 13.3 1,000 2,110 13 0

SOx 0.220 330 10,660 0.22 0

PM10 0.24 640 670 0.2 0

CO 3.5 1,450 2,110 4 0 

CO2e 697 9,743,500 17,538,400 700 0

(a) SQN emissions presented are from the 2009 annual compliance report of combustion sources.

(b) Values presented are rounded values from the 2009 SQN estimated air emissions.

(c) Operation of the combined alternative would result in no routine direct air emissions.

Source: TVA 2013d

3 4.4 Geologic Environment

4 This section describes the potential impacts of the proposed action (license renewal) and 

5 alternatives to the proposed action on geologic and soil resources.

6 4.4.1 Proposed Action

7 The geology and soils issue applicable to SQN during the license renewal term is listed in 

8 Table 4–4. Section 3.4 discusses the geologic environment of the SQN site and vicinity. There 

9 are no Category 2 issues for geology and soils.

10 Table 4–4. Geology and Soils

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

11 The NRC staff did not identify any new and significant information associated with the 

12 Category 1 geology and soils issue identified in Table 4–4 during the review of the applicant’s 

13 ER, the site audit, the scoping process, or the evaluation of other available information. As a 

14 result, no information or impacts related to this issue was identified that would change the 

15 conclusions presented in the GEIS (NRC 2013). For this geology and soil issue, the GEIS 

16 concludes that the impacts are SMALL. It is expected that there would be no incremental 

17 impacts related to this Category 1 issue during the renewal term beyond those discussed in the 

18 GEIS and therefore the impacts associated with this issue by the proposed action would be 

19 SMALL.
Environmental Consequences and Mitigating Actions

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1 4.4.2 No-Action Alternative – Geology and Soils

2 There would not be any impacts to the geology and soils at the SQN site with shut down of the 

3 facility. With the shutdown of the facility, no additional land would be disturbed. Therefore, 

4 impacts would be SMALL.

5 4.4.3 Alternatives to the Proposed Action – Geology and Soils

6 For all alternatives, impacts to geology and soil resources would occur during construction and 

7 no additional land would be disturbed during operations. During construction, for all the 

8 alternatives to the proposed action discussed in this section, sources of aggregate material, 

9 such as crushed stone and sand and gravel, would be required to construct buildings, 

10 foundations, roads, and parking lots. The NRC staff presumes that these resources would likely 

11 be obtained from commercial suppliers using local or regional sources. Land clearing during 

12 construction and the installation of power plant structures and impervious surfaces would 

13 expose soils to erosion and alter surface drainage. The NRC staff also presumes that best 

14 management practice (BMP) would be implemented in accordance with applicable permitting 

15 requirements so as to reduce soil erosion. These practices would include the use of sediment 

16 fencing, staked hay bales, check dams, sediment ponds, riprap aprons at construction and 

17 laydown yard entrances, mulching and geotextile matting of disturbed areas, and rapid 

18 reseeding of temporarily disturbed areas. Removed soils and any excavated materials would 

19 be stored onsite for redistribution such as for backfill at the end of construction. Construction 

20 activities would be temporary and localized. Therefore, for all the alternatives to the proposed 

21 action, construction impacts would be SMALL. 

22 4.4.4 NGCC Alternative – Geology and Soils

23 The impact significance level on geology and soil resources is the same for all alternatives as 

24 discussed in Section 4.4.3 above. Therefore, impacts of the NGCC alternative on geology and 

25 soils resources would be SMALL. 

26 4.4.5 SCPC Alternative – Geology and Soils

27 The impact significance level on geology and soil resources is the same for all alternatives as 

28 discussed in Section 4.4.3 above. Therefore, impacts of the SCPC alternative on geology and 

29 soils resources would be SMALL.

30 4.4.6 New Nuclear Alternative – Geology and Soils 

31 The impact significance level on geology and soil resources is the same for all alternatives as 

32 discussed in Section 4.4.3 above. Therefore, impacts of the new nuclear alternative on geology 

33 and soils resources would be SMALL.

34 4.4.7 Combination Alternative – Geology and Soils

35 The impact significance level on geology and soil resources is the same for all alternatives as 

36 discussed in Section 4.4.3 above. Therefore, impacts of the combination alternative on geology 

37 and soils resources would be SMALL.
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1 4.5 Water Resources

2 This section describes the potential impacts of the proposed action (license renewal) and 

3 alternatives to the proposed action on surface water and groundwater (GW) resources.

4 4.5.1 Proposed Action

5 4.5.1.1 Proposed Action Surface Water Resources

6 The surface water use and quality issues applicable to SQN during the license renewal term are 

7 listed in Table 4–5. Surface water resources relevant to the SQN site are described in 

8 Section 3.5.1.

9 Table 4–5. Surface Water Resources

Issues GEIS Section Category

Surface water use and quality (noncooling system impacts) 4.5.1.1 1

Altered current patterns at intake and discharge structures 4.5.1.1 1

Altered salinity gradients 4.5.1.1 1 

Altered thermal stratification of lakes 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 once-through cooling systems) 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

Sources: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51 (78 FR 37282); NRC 2013

10 Generic Surface Water Resources

11 The NRC staff did not identify any new and significant information with regard to Category 1 

12 (generic) surface water issues based on review of the SQN ER (TVA 2013a), the public scoping

13 process, or as a result of the environmental site audit. As a result, no information or impacts 

14 related to these issues were identified that would change the conclusions presented in the 

15 GEIS. Therefore, it is expected that there would be no incremental impacts related to these 

16 Category 1 issues during the renewal term beyond those discussed in the GEIS. For these 

17 surface water issues, the GEIS concludes that the impacts are SMALL. 

18 Surface Water Use Conflicts

19 This section presents the NRC staff’s review of the plant-specific (Category 2) surface water use 

20 conflict issue listed in Table 4–5.
Environmental Consequences and Mitigating Actions

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1 Plants with Cooling Ponds or Cooling Towers Using Makeup Water From a River

2 For nuclear power plants like SQN that use cooling towers or cooling ponds supplied with 

3 makeup water from a river, the potential impact on the flow of the river and its availability to 

4 meet the demands of other users is a Category 2 issue. This designation requires a 

5 plant-specific assessment. 

6 In evaluating the potential impacts resulting from surface water use conflicts associated with 

7 license renewal, the NRC staff uses as its baseline the surface water resource conditions as 

8 described in Sections 3.1.3 and 3.5.1 of this SEIS. Terrestrial and aquatic resources are 

9 described in Sections 3.6 and 3.7, respectively. These baseline conditions encompass the 

10 defined hydrologic (flow) regime of the surface water(s) potentially affected by continued 

11 operations as well as the magnitude of surface water withdrawals for cooling and other 

12 purposes (as compared to relevant appropriation and permitting standards). The baseline also 

13 considers other downstream uses and users of surface water.

14 As described in Section 3.5.1.1 of this SEIS, TVA operates and regulates the Tennessee River 

15 system and its many impoundments, including the Chickamauga Reservoir, to provide for 

16 multiple, year-round uses for navigation, flood control, power generation, water-quality 

17 improvement and aquatic resources, water supply, recreation, and economic growth. The SQN 

18 site is located on a peninsula on the western shore of Chickamauga Reservoir. As such, SQN 

19 operations are included in system-wide planning and management. 

20 Peak water demand by the condenser circulating water (CCW) system and the essential raw 

21 cooling water (ERCW) system require SQN withdrawals from Chickamauga Reservoir at a rate 

of 2,600 cubic feet per second (cfs) (73.5 m3 22 /s, or 1,680 mgd) (TVA 2011b) (see Section 3.1.3). 

23 During the 5-year period from 2008 to 2012, withdrawals from Chickamauga Reservoir to 

support the operations of SQN have averaged 2,445 cfs (69.1 m3 24 /s, or 1,580 mgd) (see 

25 Section 3.5.1.2). Limitations on withdrawals are closely related to thermal compliance for plant 

26 diffuser discharges through NPDES permitted outfall 101 to the Tennessee River. As detailed 

27 below, SQN uses once-through cooling both with and without the assistance of cooling towers 

28 (termed helper and open modes, respectively). SQN operates in a once-through CCW system 

29 during most of the year. In the open mode, the water bypasses the cooling tower lift pumps and 

30 is returned to the Chickamauga Reservoir through the diffuser pond and the discharge diffusers 

31 (TVA 2013a). 

32 Annual average flow of the Tennessee River at Chickamauga Dam is approximately 32,500 cfs 

(920 m3 33 /s, or 21,000 mgd). Under the reservoir operations study of 2004, TVA must provide a 

daily average release of at least 3,000 cfs (84.7 m3 34 /s, or about 1,940 mgd) from 

35 Chickamauga Dam from October through April. From May through September, there are no 

36 minimum daily release requirements; only weekly requirements (TVA 2013i) (see Table 4–6). 

37 Thus, during periods of minimum daily average flow, SQN could in theory withdraw (at its peak 

withdraw rate of 2,600 cfs (73.5 m3 38 /s)) more than 80 percent of the Tennessee River flow. 

39 However, NPDES permit (No. TN0026450) requirements for SQN thermal discharges have the 

40 added effect of capping SQN water withdrawals. In consideration of SQN operations and 

41 thermal discharge limits, TVA currently avoids scheduling daily average releases from the 

Chickamauga Dam at rates below 6,000 cfs (169 m3 42 /s, or 3,880 mgd) when both SQN units are 

in operation, and 3,000 cfs (84.7 m3 43 /s, or 1,940 mgd) when one SQN unit is in operation. Since 

January 2007, no daily release from Chickamauga Dam has been less than 6,200 cfs (175 m3 44 /s, 

45 or 4,000 mgd), including during the recent drought years of 2007 and 2008 (TVA 2013i).
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1 Table 4–6. Reservoir Operating System, Minimum Flows for Chickamauga Dam

Month Flow

January 3,000 cfs daily average

February 3,000 cfs daily average

March 3,000 cfs daily average

April 3,000 cfs daily average

May 7,000 cfs biweekly average

June – July 13,000–25,000 cfs weekly average, depending on week and amount of water in tributary 

reservoir storage

August 25,000–29,000 cfs weekly average, depending on amount of water in tributary reservoir 

storage (through Labor Day)

September 7,000 cfs biweekly average (after Labor Day)

October 3,000 cfs daily average

November 3,000 cfs daily average

Note: To convert cfs to m3/s, divide by 35.4. To convert cfs to mgd, divide by 1.547.

Source: TVA 2013i

2 Within this operating environment, once-through cooling operations at SQN essentially return all 

3 the water withdrawn to the Chickamauga Reservoir. However, surface water is consumed 

4 through evaporation and drift when the plant operates in helper mode. In this mode, the cooling 

5 towers are used to ensure that Chickamauga Reservoir temperatures remain within the limits 

6 specified in SQN’s NPDES permit, as described in Section 3.1.3.1, and also discussed below. 

7 SQN’s NPDES permit limits the daily maximum 24-hour average river temperature at the 

8 downstream end of the diffuser mixing zone to 86.9 °F (30.5 °C). This limit may be exceeded 

9 when the 24-hour average ambient temperature exceeds 84.9 °F (29.4 °C) and the plant is 

10 operated in helper mode. In that case, the 1-hour average river temperature downstream of the 

11 mixing zone cannot exceed 93.0 °F (33.9 °C) without the consent of the Tennessee Department 

12 of Environment and Conservation (TDEC).

13 To date, no thermal discharge limit has been exceeded under the current NPDES permit 

14 (TVA 2013i). The temperature of the SQN thermal discharge is primarily a function of the intake 

15 water temperature, heat added by the plant condensers, and heat removed by the cooling 

16 towers. Other sources and sinks of heat along the flow path of the condenser cooling water are 

17 small compared to the contributions by the condensers and the cooling towers. For a given 

18 level of power generation and helper mode cooling, higher intake water temperature will result in 

19 higher temperature of the thermal discharge from SQN. Under low flow conditions, heated 

20 effluent from outfall 101 can propagate 1.1 mi (1.8 km) upstream to the plant intake. When this 

21 recirculation of heat occurs, helper mode is often employed to prevent the progressive increase 

22 in the intake water temperature, even when there is no immediate risk of exceeding an NPDES 

23 temperature limit. Specifically, in the springtime, TVA may implement helper mode operation if 

the daily average river flow past the plant drops below about 8,000 cfs (226 m3 24 /s, or about 

25 5,170 mgd) (TVA 2013i). 

26 Helper mode operation averaged 113 days per year for 2006 to 2009 (TVA 2011b). For the 

27 period 2007 to 2011, helper mode use averaged about 120 days per year. Helper mode usage 
Environmental Consequences and Mitigating Actions

4-19

1 increased to 125 days per year for the period 2007 to 2013. Based on a long-term forecasting 

2 model using projected temperature increases for the license renewal term, TVA has projected 

3 that helper mode operation may increase in certain years by as much as 70 percent compared 

4 to the average recent operational experience. However, this conservative projection does not 

5 account for TVA’s ability to implement options (e.g., increasing river flow) to address extreme 

6 hydrothermal conditions that would otherwise require unit derates (reduction of power 

7 generation rates) and shutdowns (TVA 2013i).

8 When operated in full helper mode under design conditions, water losses to the atmosphere 

9 from evaporation and drift resulting from cooling tower operation could consume up to 70 cfs 

(1.98 m3 10 /s, or 45 mgd). TVA identifies this as a conservative, upper-bounding scenario 

11 (TVA 2013a). It reflects a condition in which both cooling towers and all seven cooling tower lift 

12 pumps (CTLPs) are operating. This peak consumptive loss of water is approximately 

2.7 percent of the peak amount (2,600 cfs (73.5 m3 13 /s, or 1,680 mgd)) that is withdrawn from the 

14 reservoir for two-unit operation, circulated through the plant, and then returned to the reservoir. 

15 Further, the net consumptive loss on an average daily basis because of helper cooling tower 

16 operation is not likely to exceed 1.2 percent of the typical minimum daily river flow (6,000 cfs), 

17 and 0.2 percent of the annual average daily river flow (32,500 cfs) past the SQN site 

18 (TVA 2013a). 

19 In reality and as noted above, SQN has historically operated in helper mode only about 

20 one-third of the year. The number of recorded “days” of helper mode operation is based on at 

21 least one of SQN’s seven CTLPs being placed into operation for some number of hours. For 

22 the majority of the days where cooling tower helper mode is necessary, SQN averages no more 

23 than about four CTLPs in operation (TVA 2013i). As a result, on an annualized basis, the 

average net consumptive use of water is approximately 9 cfs (0.25 m3 24 /s, or 6 mgd) 

25 (TVA 2013a), which is about 0.15 percent of the typical minimum flow. Relative to the cited 

26 magnitude of the variability of flows in the Tennessee River and through Chickamauga 

27 Reservoir (as managed by TVA) (see Table 4–6), the hydrologic impacts of surface water

28 withdrawals associated with SQN operations are minor.

29 In conclusion, operation of SQN during the license renewal term is not expected to result in a 

30 water use conflict on the Chickamauga Reservoir. The operation of the Tennessee River 

31 system and its many impoundments, including the Chickamauga Reservoir, is and will likely 

32 continue to be managed to safeguard resources for a wide range of uses. As discussed in 

33 Section 3.5.1.1 of this SEIS, water levels within the system are regulated to ensure adequate 

34 instream and downstream flows, which minimizes the impacts on aquatic and riparian 

35 resources. To maintain adequate water depth for navigation, water levels in the 

36 Chickamauga Reservoir are maintained within an operating range of 6.5 ft (1.98 m) above MSL 

37 between winter and summer (TVA 2013a). The NRC staff believes that consumptive water use 

38 from continued SQN operations will continue to be a very small percentage of the overall flow of 

39 the Tennessee River through the Chickamauga Reservoir. Thermal criteria imposed by TDEC, 

40 through SQN’s NPDES permit, effectively limit SQN’s water withdrawals and consumptive water 

41 use to ensure that cooling tower discharges support the designated uses of the reservoir for 

42 water supply and aquatic resources. Therefore, the NRC staff concludes that the impact on 

43 surface water resources and downstream water availability from SQN consumptive water use 

44 during the license renewal term would be SMALL.

45 4.5.1.2 Proposed Action Groundwater Resources 

46 The GW issues applicable to SQN during the license renewal term are listed in Table 4–7. 

47 Section 3.5.2 describes GW resources at SQN.
Environmental Consequences and Mitigating Actions

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1 Table 4–7. Groundwater

Issue GEIS Section Category

GW contamination and use (noncooling system impacts) 4.5.1.2 1

GW use conflicts (plants that withdraw <100 gpm) 4.5.1.2 1

Radionuclides released to GW 4.5.1.2 2 

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

2 The NRC staff did not identify any new and significant information associated with the 

3 Category 1 GW issues identified in Table 4–7 during the review of the applicant’s ER, the site 

4 audit, the scoping process, or the evaluation of other available information. As a result, no 

5 information or impacts related to these issues were identified that would change the conclusions 

6 presented in the GEIS (NRC 2013). For these issues, the GEIS concludes that the impacts are 

7 SMALL. Therefore, it is expected that there would be no incremental impacts related to these 

8 Category 1 issues during the renewal term beyond those discussed in the GEIS, and therefore 

9 the impacts associated with these issues by the proposed action would be SMALL.

10 The Category 2 issue (see Table 4–7) related to GW during the renewal term is discussed in the 

11 following text.

12 Radionuclides Released to Groundwater

13 This issue considers potential contamination of GW from the release of radioactive liquids from 

14 plant systems into the environment. Section 3.5.2.3 of this document contains a description of 

15 tritium contamination in GW detected close to some plant structures. In evaluating the potential 

16 impacts on GW quality associated with license renewal, the NRC staff uses as its baseline the 

17 existing GW conditions as described in Section 3.5.2.3 of this SEIS. These baseline conditions 

18 encompass the existing quality of GW potentially affected by continued operations (as 

19 compared to relevant State or EPA primary drinking water standards) as well as the current and 

20 potential onsite and offsite uses and users of GW for drinking and other purposes. The baseline 

21 also considers other downgradient or in aquifer uses and users of GW. 

22 Groundwater contaminated with tritium is not close to the site boundary and has not been 

23 detected off site. At SQN, neither the soils, structural fill, nor the underlying Conasauga Group 

24 is considered to be an aquifer or a source of water.

25 Tritium concentrations in GW from 2006 to the present show some variation but do not exhibit a 

26 discernible trend, either higher or lower (Julian and Williams 2007; TVA 2010, 2011b, 2012, 

27 2013a, 2013b). The water levels, permeability measurements, and lack of changes in tritium

28 concentrations indicate a lack of significant GW movement. In effect, a small volume of GW is 

29 contaminated with tritium and is moving very slowly. Past liquid spills that caused the tritium 

30 contamination in GW have been corrected. In the future, the tritium in the GW is projected to 

31 move very slowly with the GW and eventually reach Chickamauga Reservoir. Therefore, 

32 because of the very slow rate of GW discharge into the much larger volume of water contained 

33 in the reservoir, tritium concentrations would be highly diluted to very low concentrations.

34 Remediation of the contaminated GW at the site is not planned by TVA because of the limited 

35 areal extent of tritium concentrations in GW, low exposure and dose risks, and negligible 

36 potential for offsite GW migration (TVA 2013c). The NRC will continue to monitor any 

37 unanticipated radionuclide releases and take appropriate regulatory action. Final cleanup of the 

38 site, including contaminated geologic materials, would be addressed by TVA with NRC 

39 oversight during decommissioning of the facility.
Environmental Consequences and Mitigating Actions

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1 There does not appear to be any immediate threat to GW resources. Present and future 

2 operations are not expected to impact the quality of GW in any aquifers that are a current or 

3 potential future source of water for offsite users. Water use in the area should not be affected. 

4 Based on the information presented and the NRC staff’s review, the NRC staff concludes that 

5 inadvertent releases of tritium have not substantially impaired site GW quality or affected GW

6 use. The NRC staff further concludes that GW quality impacts are SMALL and would remain 

7 SMALL during the license renewal term.

8 4.5.2 No-Action Alternative - Water Resources 

9 4.5.2.1 No-Action Alternative Surface Water Resources 

10 The rate of consumptive use of surface water would decrease as SQN is shut down and the 

11 reactor cooling system continues to remove the decay heat from the reactor fuel. The thermal 

12 component of plant discharges would be greatly reduced upon shutdown. Wastewater 

13 discharges would be reduced considerably. Shutdown would reduce the impacts on surface 

14 water use and quality. These impacts would remain SMALL.

15 4.5.2.2 No-Action Alternative Groundwater Resources

16 There are no aquifers beneath the SQN site. Groundwater is not presently used from SQN and 

17 would not be used when the facility ceases operation. Therefore, the impact on GW is SMALL.

18 4.5.3 NGCC Alternative - Water Resources

19 4.5.3.1 NGCC Alternative Surface Water Resources 

20 The NGCC alternative would be located at an existing power plant site or brownfield site with 

21 available resources. Construction activities associated with the NGCC alternative would be 

22 similar to construction activities for most large industrial facilities. A new NGCC plant would 

23 occupy a much smaller footprint (i.e., about 48 ac (19 ha)) than the current SQN or the 

24 proposed SCPC or new nuclear alternatives. This would also result in less extensive 

25 excavation and earthwork than under either of the other conventional replacement-power facility 

26 alternatives. The staff assumes that there would be no direct use of surface water during 

27 construction, because it is assumed GW would be used, or water could be supplied by a local 

28 water utility. In addition, the dewatering of excavations is unlikely to consume enough water to 

29 affect surface water bodies.

30 For the NGCC alternative, the NRC staff also assumes that any existing intake and discharge

31 infrastructure at an alternative site location would be refurbished to maximize use of existing 

32 facilities. This would reduce construction-related impacts on surface water quality. 

33 Dredge-and-fill operations would be conducted under a permit from the United States Army 

34 Corps of Engineers (USACE) and State-equivalent permits requiring the implementation of 

35 BMPs to minimize impacts. Construction activities associated with these alternatives will alter 

36 onsite surface water drainage features. Some temporary impacts to surface water quality may 

37 result from increased sediment loading and from any pollutants in stormwater runoff from 

38 disturbed areas, from excavation, and dredge-and-fill activities. Stormwater runoff from 

39 construction areas and spills and leaks from construction equipment could potentially affect 

40 downstream surface water quality. Nevertheless, for this alternative, it is anticipated that 

41 appropriate soil erosion and sediment control measures would be observed. Application of 

42 BMPs in accordance with a State-issued NPDES general permit, including appropriate waste 

43 management, water discharge, stormwater pollution prevention plan, and spill prevention 

44 practices, would prevent or minimize surface water quality impacts during construction.
Environmental Consequences and Mitigating Actions

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1 Depending on the path of any required new gas pipelines and transmission lines to service the 

2 NGCC plant, some stream crossings could be necessary. However, because of the short-term 

3 nature of any required dredging and filling and stream-crossing activities, the hydrologic 

4 alterations and sedimentation would be localized and water-quality impacts would be temporary. 

5 In addition, modern pipeline construction techniques, such as horizontal directional drilling, 

6 would further minimize the potential for water-quality impacts in the affected streams. Such 

7 activities, including any dredge-and-fill operations, would be conducted under a permit from the 

8 USACE or State-equivalent permits for dredge-and-fill and stream encroachment, requiring the 

9 implementation of BMPs to minimize impacts.

10 For onsite facility operations, the NGCC alternative would require much less cooling water than 

11 SQN, and total consumptive water use would also be much less on an annualized basis. The 

12 staff assumes that a new NGCC plant at an alternative TVA site would utilize a closed-cycle 

13 cooling system employing mechanical draft cooling towers. It is projected that an NGCC plant 

would require approximately 23 cfs (0.65 m3 14 /s, or 14.9 mgd) of water for cooling and related 

15 processes, with consumptive use totaling approximately 77 percent of the total withdrawn (or 

about 17.6 cfs (0.5 m3 16 /s, or 11.4 mgd)). While the significance of cooling water withdrawals on 

17 a particular water body would vary based on the site selected within TVA’s service area, peak 

18 consumptive water use from operation of a new NGCC plant at an alternative site would be 

19 about 25 percent of that associated with existing SQN operations. However, on an annualized 

20 basis, an NGCC plant’s consumptive use would actually be twice that of current SQN operations 

(i.e., 9 cfs (0.25 m3 21 /s, or 6 mgd)), as detailed in Section 4.5.1.1. Surface water withdrawals 

22 would be subject to applicable State water appropriation or registration requirements to manage 

23 surface water use conflicts. Cooling water treatment additives would essentially be the same as 

24 SQN. While the discharge water quality would be chemically similar, the discharge volume from 

25 a new NGCC plant would be a small fraction of the cooling water discharge, blowdown, and 

26 related effluents discharged from SQN during either once-through cooling or helper mode. All 

27 effluent discharges would be subject to State-issued NPDES individual permits for the discharge 

28 of wastewater and industrial stormwater to waters of the United States. Therefore, based on the 

29 above assessment, the impacts on surface water use and quality under the NGCC alternative 

30 would be SMALL.

31 4.5.3.2 NGCC Alternative Groundwater Resources

32 For the NGCC alternative, the staff assumed that construction water would be obtained from 

33 GW or from a local water utility. Construction water would be required for such uses as potable 

34 and sanitary use by the construction workforce and for concrete production, equipment 

35 washdown, dust suppression, and soil compaction. The dewatering of excavations is unlikely to 

36 consume enough water to affect GW supplies. During construction and throughout the life of 

37 this alternative, GW withdrawals would be subject to applicable State water appropriation and 

38 registration requirements. The application of BMPs in accordance with a State-issued NPDES

39 general permit, including appropriate waste management, water discharge, stormwater pollution 

40 prevention plan, and spill prevention practices, would prevent or minimize GW quality impacts 

41 during construction. For this alternative, after the facility is constructed and operational, GW

42 from onsite wells would be used as a source of potable water and for fire protection. During 

43 operations, the consumptive use of potable water and water for fire protection would be similar 

44 to the proposed action. Therefore, the impact of this alternative on GW resources would be 

45 SMALL.
Environmental Consequences and Mitigating Actions

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1 4.5.4 SCPC Alternative - Water Resources

2 4.5.4.1 SCPC Alternative Surface Water Resources 

3 Impacts from construction activities associated with the SCPC alternative on surface water

4 resources would be expected to be similar to but somewhat greater than those under the NGCC 

5 alternative (see Section 4.5.3.1). This is attributable to the additional land required (i.e., 131 ac 

6 (53.0 ha)) for construction of the power block and for excavation and construction of other onsite 

7 facilities for coal handling and storage, and for coal ash and scrubber waste management. The 

8 staff assumes that there would be no direct use of surface water during construction because it 

9 is conservatively assumed that GW would be used, or water could be supplied by a local water 

10 utility. 

11 Some temporary impacts to surface water quality may result from increased sediment loading 

12 and from pollutants in stormwater runoff from disturbed areas and from excavation and 

13 dredge-and-fill activities. There also would be the potential for water-quality effects to occur 

14 from the extension or refurbishment of rail spurs to transport coal to the site location. 

15 Nevertheless, as described in Section 4.5.3.1 for the NGCC alternative, water-quality impacts 

16 would be minimized by the application of BMPs and compliance with State-issued NPDES

17 permits for construction. Any dredge-and-fill operations would be conducted under a permit 

18 from USACE and State-equivalent permits requiring the implementation of BMPs to minimize 

19 impacts.

20 Cooling water treatment additives would essentially be the same so that the discharge water 

21 quality would be chemically similar to SQN. During peak cooling operations, the SCPC 

22 alternative would consumptively use less water than SQN does operating in helper cooling 

23 mode, because of the greater generation efficiency of the SCPC technology. The staff assumes 

24 that a new SCPC plant at an alternative TVA site would utilize natural draft cooling towers. It is 

projected that an SCPC plant would require approximately 53 cfs (1.5 m3 25 /s, or 34 mgd) of water 

26 for cooling makeup and related processes, with consumptive use totaling approximately 

80 percent of the total withdrawn (about 42 cfs (1.2 m3 27 /s, or 27 mgd)). Nevertheless, on an 

28 annualized basis, an SCPC plant’s consumptive use would actually be substantially greater than 

that of current SQN operations (i.e., 9 cfs (0.25 m3 29 /s, or 6 mgd)), as detailed in Section 4.5.1.1. 

30 Surface water withdrawals and effluent discharges would be subject to applicable regulatory 

31 requirements under this alternative. As a result, the overall impacts on surface water use and 

32 quality from construction and operations under the SCPC alternative would be SMALL.

33 4.5.4.2 SCPC Alternative Groundwater Resources

34 Facts considered, assumptions made, and conclusion reached in determining the impact 

35 significance level on GW resources from the SCPC alternative are the same as for the NGCC 

36 alternative described in Section 4.5.3.2. Therefore, impacts of the SCPC alternative on GW

37 resources would be SMALL.

38 4.5.5 New Nuclear Alternative - Water Resources

39 4.5.5.1 New Nuclear Alternative Surface Water Resources 

40 Impacts from construction activities on surface water resources associated with the new nuclear 

41 alternative would be greater in scale than those described for the SCPC alternative (see 

42 Section 4.5.4.1) by virtue of the larger land area required (i.e., up to 1,000 ac (405 ha)). While 

43 coal storage or ash and scrubber waste management facilities would not be required as under 

44 the SCPC alternative, deep excavation work for the nuclear island as well as more extensive 
Environmental Consequences and Mitigating Actions

4-24

1 site clearing and larger laydown area for facility construction would have potentially greater 

2 impacts on water resources caused by stream alteration, water use, and stormwater runoff. 

3 The NRC staff assumes that there would be no direct use of surface water during construction, 

4 because it is conservatively assumed that GW would be used, or water would be supplied by a 

5 local water utility. During construction, the dewatering of excavations is unlikely to affect offsite 

6 surface water bodies. In support of new nuclear unit construction, temporary impacts to surface 

7 water quality may result from increased sediment loading and from pollutants in stormwater

8 runoff from disturbed areas, deep excavations, and from any required dredge-and-fill activities. 

9 Nevertheless, as described in Section 4.5.3.1 water-quality impacts would be minimized by the 

10 application of BMPs and compliance with State-issued NPDES permits for construction. Any 

11 dredge-and-fill operations would be conducted under a permit from the USACE and State12 equivalent permits requiring the implementation of BMPs to minimize impacts. 

13 To support operations of a new nuclear power plant, the staff expects that the new facility would 

14 utilize natural draft cooling towers operating in a closed-cycle configuration. Consequently, it is 

estimated that the operation of two new nuclear units would require up to 96 cfs (2.7 m3 15 /s, or 

16 62 mgd) of water for cooling makeup and related processes, with consumptive use totaling 

approximately 80 percent of the total withdrawn (about 74 cfs (2.1 m3 17 /s, or 48 mgd)). While 

18 cooling water makeup requirements would be considerably less under this alternative (less than 

19 5 percent) as compared to current SQN operations, consumptive water use would be 

20 considerably greater than SQN, and consumptive use would be continuous throughout the year, 

21 subject to seasonal variation. While the relative significance of cooling water withdrawals on a 

22 particular water body would vary based on the site selected within TVA’s service area for the 

23 new nuclear units, SQN’s peak daily consumptive use is similar to the projected average 

24 consumptive loss under this alternative. 

25 The NRC assumes that water treatment additives for new nuclear plant operations and effluent 

26 discharges would be relatively similar in quality and volume to SQN. As summarized in 

27 Section 4.5.3.1, surface water withdrawals and effluent discharges would be subject to 

28 applicable regulatory requirements under this alternative. As a result, the overall impacts on 

29 surface water use and quality from construction and operations under the new nuclear 

30 alternative would be SMALL.

31 4.5.5.2 New Nuclear Alternative Groundwater Resources

32 Facts considered, assumptions made, and conclusion reached in determining the impact 

33 significance level on GW resources from the new nuclear alternative are the same as for the 

34 NGCC alternative described in Section 4.5.3.2. Therefore, impacts of the new nuclear 

35 alternative on GW resources would be SMALL.

36 4.5.6 Combination Alternative - Water Resources

37 4.5.6.1 Combination Alternative Surface Water Resources 

38 Impacts on surface water resources from constructing up to 3,150 land-based wind turbines 

39 would primarily be limited to the relatively small amounts of water needed at each installation 

40 site for dust suppression and soil compaction during site clearing and for concrete production. 

41 Construction of utility-scale solar PV farms would require relatively larger volumes of water per 

42 site due to the much larger land area required per megawatt of replacement power produced.

43 The NRC assumes that required water would be procured from offsite sources and trucked to 

44 the point of use on an as-needed basis. Water could also be supplied by a local water utility. 

45 The likely use of ready-mix concrete would also reduce the need for onsite use of nearby water 

46 sources for construction. 
Environmental Consequences and Mitigating Actions

4-25

1 In addition, the installation of land-based wind turbines and utility-scale solar PV farms would 

2 require installation of access roads and possibly transmission lines (especially for sites not 

3 already proximal to transmission line corridors). Access road construction would also require 

4 some water for dust suppression and roadbed compaction and would have the potential to 

5 result in soil erosion and stormwater runoff from cleared areas. For construction, water would 

6 likely be trucked to the point of use from offsite locations along with road construction materials. 

7 In all cases, it is expected that construction activities would be conducted in accordance with 

8 State-issued NPDES or equivalent permits for stormwater discharges associated with 

9 construction activity, which would require the implementation of appropriate BMPs to prevent or 

10 mitigate water-quality impacts. In contrast to land-based wind turbine sites and utility-scale 

11 solar PV farms, installation of small solar PV units on rooftops and at already-developed sites 

12 within the TVA service area would have little or no impact on surface water resources.

13 To support the operation of wind turbine and PV installations, no direct use of surface water

14 would be expected. Water would likely be obtained from GW or purchased from a water utility. 

15 Regardless, only very small amounts of water would be needed to periodically clean turbine 

16 blades and motors and could be trucked to the point of use as part of routine servicing. Water 

17 also would be required to clean panels at solar PV farms. Adherence to appropriate waste 

18 management and minimization plans, spill prevention practices, and pollution prevention plans 

19 during servicing of wind turbine and solar PV installations and operation of vehicles connected 

20 with site operations would minimize the risks to soils and surface water resources from spills of 

21 petroleum, oil, and lubricant products and stormwater runoff. In consideration of the information 

22 above, the impacts on surface water use and quality from construction and operations under the 

23 combination alternative would be SMALL.

24 4.5.6.2 Combination Alternative Groundwater Resources

25 Construction dewatering would be minimal because of the small footprint of foundation 

26 structures, pad sites, and piling emplacements. Little or no impacts on GW use or water quality 

27 would be expected from routine operations. Consequently, the impacts on GW use and quality 

28 under this alternative would be SMALL.

29 4.6 Terrestrial Resources

30 This section describes the potential impacts of the proposed action (license renewal) and 

31 alternatives to the proposed action on terrestrial resources.

32 4.6.1 Proposed Action

33 Terrestrial resources issues applicable to SQN during the license renewal term are listed in 

34 Table 4–8. Terrestrial resources at SQN are described in Section 3.6. 
Environmental Consequences and Mitigating Actions

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1 Table 4–8. Terrestrial Resources

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 oncethrough cooling systems or cooling ponds)4.6.1.1 1 

Cooling tower impacts on vegetation (plants with cooling towers) 4.6.1.1 1

Bird collisions with plant structures and transmission lines(a) 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 ROW management impacts on terrestrial resources(a) 4.6.1.1 1 

Electromagnetic fields on flora and fauna (plants, agricultural crops, 

honeybees, wildlife, livestock) 

4.6.1.1 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.

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

2 4.6.1.2 Generic Terrestrial Resource Issues

3 For the Category 1 terrestrial resources issues listed in Table 4–8, the NRC staff did not identify 

4 any new and significant information during the review of the ER (TVA 2013a), the NRC staff’s 

5 site audit, the scoping process, or the evaluation of other available information. Therefore, there 

6 are no impacts related to these issues beyond those discussed in the GEIS. For these issues, 

7 the GEIS concludes that the impacts are SMALL.

8 4.6.1.3 Effects on Terrestrial Resources (Non-Cooling System Impacts)

9 The geographic scope for the assessment of this issue is the SQN site and area near the site. 

10 Section 3.6 describes the terrestrial resources on and in the vicinity of the SQN site, including 

11 State-protected plants, birds, mammals, reptiles, and amphibians as well as birds protected 

12 under the Migratory Bird Treaty Act and Bald and Golden Eagle Protection Act. Construction of 

13 the SQN plant converted approximately 525 ac (212 ha) of terrestrial habitat, such as mixed 

14 hardwood forest, pine forest, pasture, and old fields, into buildings, parking lots, landscaped 

15 areas, and other industrial uses. The remaining terrestrial and associated wetland habitats 

16 have not changed significantly since construction (TVA 2013a). As discussed in Chapter 3 and 

17 according to the applicant’s ER (TVA 2013a), TVA has no plans to conduct refurbishment or 

18 replacement actions associated with license renewal to support the continued operation of SQN. 

19 Further, TVA (2013a) anticipates no new construction in previously undisturbed habitats. Nor 

20 does TVA (2013a) expect changes in operations or changes in existing land use conditions 

21 because of license renewal.

22 TVA would continue to conduct ongoing plant operational and maintenance activities during the 

23 license renewal period. However, these activities are expected to have minimal impacts on 

24 terrestrial resources because activities would not occur within previously undisturbed habitats 

25 and because regulations, permits, and policies are in place to protect terrestrial resources at 
Environmental Consequences and Mitigating Actions

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1 SQN (TVA 2013a). For example, TVA manages the SQN site in accordance with the U.S. Army 

2 Corps of Engineers’ Section 404 permitting process, TVA’s NPDES Permit TN0026450, TVA’s 

3 Multi-Sector General Stormwater Permit TNR 050015 issued by the Tennessee Department of 

4 Environment and Conservation (TDEC), and TVA’s Spill Prevention, Control, and 

5 Countermeasures (SPCC) Plan, as appropriate (TVA 2013a). Under TVA’s Multi-Sector 

6 General Stormwater Permit, TVA is required to develop, maintain, and implement a Stormwater 

7 Pollution Prevention Plan (SWPPP) that identifies potential sources of pollution that could affect 

8 the quality of stormwater and identifies how TVA will prevent or reduce pollutants from 

9 stormwater discharges (TVA 2013a). Similarly, TVA has an SPCC plan that identifies and 

10 describes the procedures, materials, equipment, and facilities used at the station to minimize 

11 the frequency and severity of oil spills (TVA 2013a). In accordance with the Federal Insecticide, 

12 Fungicide, and Rodenticide Act, only certified personnel conduct pesticide and herbicide 

13 applications at SQN (TVA 2013a).

14 When new activities that could impact the environment occur at SQN, TVA implements various 

15 procedural controls and BMPs to protect terrestrial habitats and wildlife, State-listed and 

16 important species, wetland areas, and water quality (TVA 2013a). For example, as a Federal 

17 agency, TVA is required to conduct environmental reviews for such activities, which include an 

18 analysis of the potential environmental impacts. TVA uses such analyses to inform its decisions 

19 and determine what action, if any, is to be taken to protect, restore, and enhance the 

20 environment. In its ER for the proposed SQN license renewal, TVA (2013a) determined that 

21 these control measures ensure that activities at SQN comply with the National Environmental 

22 Policy Act (NEPA), TVA’s implementing regulations, the Council on Environmental Quality

23 (CEQ) regulations, and other environmental laws, regulations, and executive orders.

24 Based on the NRC staff’s independent review, the staff concludes that operation and 

25 maintenance activities that TVA might undertake during the renewal term, such as maintenance 

26 and repair of plant infrastructure (e.g., roadways, piping installations, onsite transmission lines, 

27 fencing and other security infrastructure), would likely be confined to previously disturbed areas 

28 of the site. Furthermore, TVA has established and implements several policies, procedures, 

29 and control measures to ensure that activities at SQN comply with NEPA, TVA’s implementing 

30 regulations, the CEQ’s regulations, and other environmental laws, regulations, and executive 

31 orders. Therefore, the NRC staff expects non-cooling system impacts on terrestrial resources 

32 during the license renewal term to be SMALL.

33 4.6.1.4 Water Use Conflicts with Terrestrial Resources (Plants with Cooling Ponds or Cooling 

34 Towers Using Makeup Water from a River)

35 For nuclear power plants using cooling towers or cooling ponds supplied with makeup water 

36 from a river, the potential impact on the flow of the river and its availability to meet the demands 

37 of other users is a Category 2 issue. This designation requires a plant-specific assessment of 

38 the potential impacts resulting from surface water use conflicts, which is discussed in detail in 

39 Section 4.5.1. This section addresses the effects of water use conflicts on terrestrial resources 

40 in riparian communities, and the potential impacts on aquatic (instream) communities are 

41 discussed in Section 4.7.1. Water use conflicts with terrestrial resources in riparian 

42 communities could occur when water that supports these resources is diminished either 

43 because of decreased availability due to droughts; increased water demand for agricultural, 

44 municipal, or industrial usage; or a combination of such factors (NRC 2013d).

45 The NRC staff concluded in Section 4.5.1 of this SEIS that the operation of SQN during the 

46 license renewal term is not expected to result in a surface water use conflict on the 

47 Chickamauga Reservoir. This conclusion was reached because TVA regulates water levels in 

48 the Chickamauga Reservoir and the Tennessee River system to ensure adequate instream and 
Environmental Consequences and Mitigating Actions

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1 downstream flows for aquatic and riparian resources. The NRC staff concluded that 

2 consumptive water use from continued SQN operations has been and will continue to be a very 

3 small percentage of the overall flow of the Tennessee River through the Chickamauga 

4 Reservoir. Therefore, the NRC staff concludes that the impact of water use conflicts with 

5 riparian communities during the license renewal term would be SMALL.

6 4.6.2 No-Action Alternative – Terrestrial Resources

7 If the plant were to cease operating, the terrestrial ecology impacts would be SMALL, assuming 

8 that no additional land disturbances on or off site would occur prior to decommissioning 

9 activities.

10 4.6.3 NGCC Alternative – Terrestrial Resources

11 Construction of an NGCC plant would occur at the site of an existing power plant other than 

12 SQN or a brownfield site with available resources and would require about 48 ac (19 ha) of land 

13 for the plant itself and up to 8,640 ac (3,497 ha) of additional land off site for wells, collection 

14 stations, and pipelines to bring the gas to the plant (see Section 4.2.3.1). Because the onsite 

15 land requirement is relatively small, the plant operator would likely be able to site most of the 

16 construction footprint in previously disturbed, degraded habitat, which would minimize impacts 

17 to terrestrial habitats and species. Offsite construction would occur mostly on land where gas 

18 extraction is occurring already. Siting any new gas pipelines or transmission lines along existing 

19 utility corridors would minimize impacts. Erosion and sedimentation, fugitive dust, and 

20 construction debris impacts would be minor with implementation of appropriate BMPs. Impacts 

21 to terrestrial habitats and species from transmission line operation and corridor vegetation 

22 maintenance, and operation of the mechanical-draft cooling towers would be similar in 

23 magnitude and intensity as those resulting from operating nuclear reactors and would, therefore, 

24 be SMALL (NRC 2013d). Overall, the impacts of construction and operation of an NGCC plant 

25 to terrestrial habitats and species would be SMALL.

26 4.6.4 SCPC Alternative – Terrestrial Resources

27 Construction of an SCPC plant would require approximately 131 ac (53 ha), as described in 

28 Section 4.2.4.1. Because of the relatively large land requirement for the SCPC alternative, a 

29 portion of the site may be land that had not been previously disturbed, especially if the SCPC 

30 alternative is sited at an existing NGCC plant site. Construction within undisturbed land would 

31 directly affect terrestrial habitat by removing existing vegetative communities and displacing 

32 wildlife. The level of direct impacts would vary substantially based on the amount and 

33 ecological importance of directly affected habitats. Construction of a railroad spur may be 

34 necessary, depending on the existing infrastructure at the site. Siting the spur along an existing, 

35 previously disturbed railroad corridor would minimize impacts to terrestrial habitat. Otherwise, 

36 the rail spur could create new edge habitat and reduce the availability of continuous tracts of 

37 habitat. Erosion and sedimentation, fugitive dust, and construction debris impacts would likely 

38 be minor with the implementation of appropriate BMPs. Impacts to terrestrial habitats and 

39 species from transmission line operation and corridor vegetation maintenance, and operation of 

40 the cooling system would be similar in magnitude and intensity as those resulting from operating 

41 nuclear reactors and would, therefore, be SMALL (NRC 2013d). The SCPC alternative may 

42 require 7,440 ac (3,011 ha) to 52,800 ac (21,400 ha) of additional land for coal mining and 

43 processing, as described in Section 4.2.4.1. Offsite activities would occur mostly on land where 

44 coal extraction is ongoing. Because of the potentially large area of undisturbed habitat that 

45 could be affected from construction of an SCPC plant, the impacts of construction on terrestrial 
Environmental Consequences and Mitigating Actions

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1 habitats and species could range from SMALL to MODERATE depending on the amount and 

2 ecological importance of directly affected habitats. The impacts of operation would be SMALL.

3 4.6.5 New Nuclear Alternative – Terrestrial Resources

4 The new nuclear alternative, including the new reactor units and auxiliary facilities, would affect 

5 1,000 ac (405 ha) of land at the site of an existing nuclear power plant other than SQN 

6 (TVA 2013a), as described in Section 4.2.5.1. Because of the significant land requirement for 

7 the site, impacts to terrestrial species and habitats would vary depending on the amount of 

8 previously undisturbed land that would be cleared for the new nuclear alternative. By siting the 

9 new nuclear alternative at an existing nuclear site, the majority of land that would be affected by 

10 construction would be developed or previously disturbed. However, as with the SCPC 

11 alternative, the level of direct impacts would vary based on the extent and ecological importance 

12 of habitat disturbed during construction activities. For the purposes of this analysis, the NRC 

13 staff assumed that the new nuclear alternative is built within the footprint of an existing nuclear 

14 power plant site. Erosion and sedimentation, fugitive dust, and construction debris impacts 

15 would be minor with implementation of appropriate BMPs. Impacts to terrestrial habitats and 

16 species from transmission line operation and corridor vegetation maintenance, and operation of 

17 the cooling system would be similar in magnitude and intensity to those resulting from operating 

18 nuclear reactors and would, therefore, be SMALL (NRC 2013a). The offsite land requirement 

19 would be about 2,400 ac (971 ha) (NRC 1996) and impacts associated with uranium mining and 

20 fuel fabrication to support the new nuclear alternative would be no different from those occurring 

21 in support of SQN (see Section 4.2.5.1). Assuming the new nuclear alternative is built within the 

22 footprint of an existing nuclear power plant site, the impacts of construction and operation of a 

23 new nuclear facility on terrestrial species and habitats would be SMALL.

24 4.6.6 Combination Alternative – Terrestrial Resources

25 4.6.6.1 Wind

26 The wind portion of the combination alternative would contain between 2,350 to 

27 3,150 land-based wind turbines requiring approximately 1,410 to 1,890 ac (570 to 765 ha) of 

28 land, although only 5 to 10 percent of this area would be affected during operations, as 

29 discussed below. The remaining area would be relatively unaffected after construction is 

30 complete.

31 During construction of wind farms, the logistics of delivering heavy or oversized components to 

32 ideal locations such as hilltops or ridgelines could require extensive modifications to existing 

33 road infrastructures and construction of access roads that take circuitous routes to their 

34 destination to avoid unacceptable grades. However, once construction was completed, many 

35 access roads could be reclaimed and replaced with more-direct access to the wind farm for 

36 maintenance purposes. Likewise, land used for equipment laydown and turbine component 

37 assembly and erection could be returned to its original state. Following construction, BMPs that 

38 include plans to restore disturbed land would also reduce the impact of construction on 

39 terrestrial habitats. Overall, construction impacts on terrestrial species and habitats could range 

40 from SMALL to MODERATE depending upon the degree of undisturbed and forested habitat 

41 that is directly affected by the wind portion of the combination alternative.

42 Because wind turbines require ample spacing between one another to avoid air turbulence 

43 between them, the footprint of utility-scale wind farms would range from 410 to 1,890 ac (570 to 

44 765 ha). During operations, however, only 5 to 10 percent of the total acreage within the 

45 footprint of wind installations would actually be occupied by turbines, access roads, support 

46 buildings, and associated infrastructure while the remaining land areas could be put to other 
Environmental Consequences and Mitigating Actions

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1 compatible uses, including agriculture. Habitat loss and some habitat fragmentation may occur 

2 as a result, especially for wind turbines installed in forested areas. Operation of wind turbines 

3 could uniquely affect terrestrial species from noise, collision with turbines and meteorological 

4 towers, site maintenance activities, disturbance associated with activities of the project 

5 workforce, and interference with migratory behavior. Bat and bird mortality from turbine 

6 collisions is a concern for operating wind farms; however, recent developments in turbine design 

7 have reduced the potential for bird and bat strikes. Additionally, impacts to those bird and bat 

8 species protected by the Migratory Bird Treaty Act or the Bald and Golden Eagle Protection Act 

9 could be mitigated through licensee and NRC interactions with the appropriate agencies. 

10 Impacts to terrestrial habitats and species from transmission line operation and corridor 

11 vegetation maintenance would be similar in magnitude and intensity to those resulting from 

12 operating nuclear reactors and would, therefore, be SMALL (NRC 2013d). Overall, operational 

13 impacts to terrestrial species and habitats could range from SMALL to MODERATE depending 

14 on the likelihood of bird strikes and interference with migratory behaviors.

15 4.6.6.2 Solar

16 Up to 12,400 to 17,980 ac (5,018 to 7,276 ha) could be necessary for a solar PV alternative at 

17 standalone sites (see Section 4.2.6.1). However, the amount of land would likely be less 

18 because some of the solar installation would include many relatively small installations on 

19 building roofs or existing residential, commercial, or industrial sites. Constructing solar 

20 installations on existing structures would have minimal impacts to terrestrial resources given 

21 that these sites provide negligible, if any, terrestrial habitat. Construction at standalone solar 

22 sites could have greater impacts given the large amount of land required. Siting standalone 

23 installations in previously disturbed areas would minimize impacts. Because many of the 

24 installations would likely be installed in developed areas that are already connected to the 

25 regional electric grid, construction of additional transmission lines or access roads to solar PV 

26 installation sites would likely be unnecessary. During operations, impacts would be minimal 

27 because of relatively flat and low design of most installations. Therefore, the NRC staff 

28 determined that the impact from construction on terrestrial habitats and species could range 

29 from SMALL to MODERATE, depending on the number of installations built within previously 

30 undisturbed habitats, and the impacts of operation to terrestrial habitats and species would be 

31 SMALL.

32 4.6.6.3 Conclusion

33 Overall, construction of the combination alternative would have a SMALL to MODERATE impact 

34 on terrestrial habitats and species, and operation would also have a SMALL to MODERATE 

35 impact.

36 4.7 Aquatic Resources

37 This section describes the potential impacts of the proposed action (license renewal) and 

38 alternatives to the proposed action on aquatic resources. 

39 4.7.1 Proposed Action

40 The aquatic resource issues applicable to SQN during the license renewal term are listed in 

41 Table 4–9. Section 3.1.3 describes the SQN cooling water system. Section 3.7 describes the 

42 aquatic resources. The impacts of managing the transmission line right-of-way do not apply 

43 because the proposed license renewal will use the existing onsite switchyard and transmission 

44 facilities (TVA 2013g). The NRC staff did not consider impacts along existing transmission 

45 system right-of-ways off site as a part of this SEIS. 
Environmental Consequences and Mitigating Actions

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1 Table 4–9. Aquatic Resources 

Issues

GEIS

Section Category

Impingement and entrainment of aquatic organisms (plants with once-through

cooling systems or cooling ponds)

4.6.1.2 2

Impingement and entrainment of aquatic organisms (plants with cooling 

towers)

4.6.1.2 1

Entrainment of phytoplankton and zooplankton (all plants) 4.6.1.2 1 

Thermal impacts on aquatic organisms (plants with once-through cooling 

systems or cooling ponds)

4.6.1.2 2 

Thermal impacts on aquatic organisms (plants with cooling towers) 4.6.1.2 1

Infrequently reported thermal impacts (all plants) 4.6.1.2 1

Effects of cooling water discharge on dissolved oxygen, gas supersaturation, 

and eutrophication

4.6.1.2 1

Effects of nonradiological contaminants on aquatic ecosystems 4.6.1.2 1 

Exposure of aquatic organisms to radionuclides 4.6.1.2 1 

Effects of dredging on aquatic organisms 4.6.4.2 1

Water use conflicts with aquatic resources (plants with cooling ponds or 

cooling towers using makeup water from a river)

4.6.1.2 2

Effects on aquatic resources (noncooling system impacts) 4.6.1.2 1

Losses from predation, parasitism, and disease among organisms exposed to 

sublethal stresses

4.6.1.2 1

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

2 4.7.1.1 Aquatic Ecology Issues

3 The NRC staff did not identify any new and significant information related to the generic 

4 (Category 1) issues listed above during the review of TVA’s ER, the site audit, or the scoping

5 process. Therefore, no impacts are associated with these issues beyond those discussed in the 

6 GEIS. The GEIS concludes that the impact levels for these issues are SMALL. 

7 For the site-specific (Category 2) issues, the NRC staff examined the present and past impacts 

8 resulting from plant operation to infer future impacts over the license renewal term, i.e., the 

9 remainder of the present term plus an additional 20 years. Two related concepts bound the 

10 analysis of direct and indirect impacts in time and space: the timeframe and geographic extent. 

11 The timeframe defines how far back and how far forward the analysis will extend, and the 

12 timeframe for the direct and indirect impacts is less extensive than the timeframe for cumulative 

13 impacts (discussed in section 4.16.5 of this SEIS). The timeframe of analyses for ecological 

14 resources centers on the present and extends far enough into the past to understand trends and 

15 to determine whether the resource is stable, which the NRC definitions of impact levels require. 

16 For assessing direct and indirect impacts, the geographic extent depends on the biology of the 

17 species under consideration. 
Environmental Consequences and Mitigating Actions

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1 In assessing the level of impact, the NRC staff looks at the projected effects in comparison to a 

2 baseline condition. Consistent with NEPA guidance (CEQ 1997), the baseline of the 

3 assessment is the condition of the resource without the action, i.e., under the no-action 

4 alternative. Under the no-action alternative, the plant would shut down and the resource would 

5 conceptually be in its present condition without the plant, which is not necessarily the condition 

6 of the resource before the plant was constructed.

7 4.7.1.2 Impingement and Entrainment of Aquatic Organisms

8 Impingement and entrainment of aquatic organisms are site-specific (Category 2) issues for 

9 assessing impacts of license renewal at plants with once-through cooling systems. 

10 Impingement, according to EPA (66 FR 65256),

11 ...takes place when organisms are trapped against intake screens by the force of 

12 the water passing through the cooling water intake structure. Impingement can 

13 result in starvation and exhaustion (organisms are trapped against an intake 

14 screen or other barrier at the entrance to the cooling water intake structure), 

15 asphyxiation (organisms are pressed against an intake screen or other barrier at 

16 the entrance to the cooling water intake structure by velocity forces that prevent 

17 proper gill movement, or organisms are removed from the water for prolonged 

18 periods of time), and descaling (fish lose scales when removed from an intake 

19 screen by a wash system) and other physical harms.

20 The impingement rate is influenced by factors including flow, intake velocity, and swimming 

21 speed. Death from impingement (impingement mortality) can occur immediately or 

22 subsequently as an individual succumbs to physical damage upon its return to the water body. 

23 The NRC staff assumes a 100 percent mortality rate for impinged organisms in the absence of a 

24 fish-return system. The SQN intakes do not have a fish-return system. 

25 Entrainment, as defined by the EPA (66 FR 65256) occurs when

26 ...organisms are drawn through the cooling water intake structure into the cooling 

27 system. Organisms that become entrained are normally relatively small benthic, 

28 planktonic, and nektonic organisms, including early life stages of fish and 

29 shellfish. Many of these small organisms serve as prey for larger organisms that 

30 are found higher on the food chain. As entrained organisms pass through a 

31 plant’s cooling system they are subject to mechanical, thermal, and/or toxic 

32 stress. Sources of such stress include physical impacts in the pumps and 

33 condenser tubing, pressure changes caused by diversion of the cooling water 

34 into the plant or by the hydraulic effects of the condensers, sheer stress, thermal 

35 shock in the condenser and discharge tunnel, and chemical toxemia induced by 

36 antifouling agents such as chlorine. The mortality rate of entrained organisms 

37 varies by species and can be high under normal operating conditions. [footnotes 

38 omitted]

39 EPA indicated that “entrainment is related to flow” and that “[l]arger withdrawals of water may 

40 result in commensurately greater levels of entrainment” (69 FR 41576). For entrainment 

41 assessment, the NRC staff assumes 100 percent mortality of entrained organisms. 

42 The GEIS (NRC2013e) lists species commonly impinged or entrained at power plants. The list 

43 includes species found in the Chickamauga Reservoir, including alewife (Alosa 

44 pseudoharengus), gizzard shad (Dorosoma cepedianum), common carp (Cyprinus carpio), 

45 white bass (Morone chrysops), sunfish (Lepomis spp.), crappie (Pomoxis annularis and 

46 P. nigromaculatus), yellow perch (Perca flavescens), and freshwater drum (Aplodinotus 

47 grunniens). Further, the GEIS reports that impingement at some plants is often seasonal with 

48 order-of-magnitude greater numbers of fish impinged in the colder months. For some southern 
Environmental Consequences and Mitigating Actions

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1 plants (e.g., McGuire Nuclear Plant in North Carolina or V.C. Summer Nuclear Generating 

2 Station in South Carolina), most of the fish that were impinged (gizzard shad or threadfin shad) 

3 were already dead or moribund at the time they were impinged, and the GEIS concludes that 

4 they would have been lost even if they had not been impinged.

5 Because of the various linkages between entrainment and impingement at different life stages 

6 for the species present in the Chickamauga Reservoir, the NRC staff used a weight-of-evidence 

7 approach to evaluate the effects of impingement and entrainment on the aquatic resources in 

8 the Chickamauga Reservoir. The term “weight-of-evidence” has many meanings. Menzie et al. 

9 (1996) provides an overview of the weight-of-evidence approach as “...the process by which 

10 multiple measurement endpoints are related to an assessment endpoint to evaluate whether 

11 significant risk of harm is posed to the environment.” The NRC’s final SEIS regarding Cooper 

12 Nuclear Station (NRC 2010) defined weight-of-evidence as “an organized process for evaluating 

13 information or data from multiple sources to determine whether there is evidence to suggest that 

14 an existing or future environmental action has the potential to result in an adverse impact.” The 

15 EPA (1998b) recommends a weight-of-evidence approach for ecological risk assessments. The 

16 NRC (2010, 2013c, 2013f) has used this approach in the SEISs for other license renewal 

17 applications. 

18 The NRC staff examined multiple lines of evidence to determine if the operation of the SQN 

19 cooling system has the potential to cause adverse impacts to aquatic organisms in the vicinity of 

20 the SQN site. The first line of evidence is based on impingement data obtained by TVA during 

21 studies conducted from 1981 to 1985 (Dycus 1986), a short winter study in 2001–2002 (Kay and 

22 Baxter 2002), and studies from 2005 to 2007 (TVA2007c) in response to EPA’s 2004 

23 then-proposed 316(b) Rule. The second line of evidence is based on entrainment data provided 

24 by TVA during studies that occurred from 1981 through 1985 (Dycus 1986) and in 2004 (Baxter 

25 and Buchanan 2010). The third line of evidence utilizes TVA’s (2012c) monitoring of fish 

26 populations prior to and during operations at the two sampling sites above and below the SQN 

27 site. 

28 The lines of evidence directly relate to NRC’s definitions of SMALL, MODERATE, and LARGE, 

29 as described in Section 1.4 are as follows:

30 • The NRC staff categorized the impingement and entrainment impacts as 

31 SMALL and concluded that impingement and entrainment will not 

32 destabilize or noticeably alter the aquatic resources if

33 ­ monitoring data show the same species were consistently entrained 

34 or impinged without resulting in an observable decrease over time in 

35 the abundance of the species most affected by entrainment and 

36 impingement and

37 ­ the number of equivalent adults and the amount of production 

38 foregone from impingement were small in comparison to the adult 

39 population of the same species in the reservoir.

40 • The NRC staff categorized the impingement and entrainment impacts as 

41 MODERATE and concluded that impingement and entrainment noticeably 

42 alters but does not destabilize the aquatic resources near the SQN site if

43 ­ the monitoring data show a sustained decrease over time in the 

44 abundance of entrained or impinged species at sampling locations 
Environmental Consequences and Mitigating Actions

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1 above and below the site but no change in the abundance of species 

2 that feed on the entrained or impinged species and

3 ­ the number of equivalent adults and the amount of production 

4 foregone from impingement were high enough to noticeably change 

5 but not cause a decreasing trend in the population of one or more of 

6 the species in the reservoir over a period of more than one or two 

7 years.

8 • The NRC staff categorized the impingement and entrainment impacts as 

9 LARGE and concluded that impingement and entrainment effects are 

10 clearly noticeable and destabilize the aquatic resources near the SQN 

11 site if

12 ­ monitoring data indicate a sustained decrease over time in the 

13 abundance of an entrained or impinged species at sampling locations 

14 above and below the site and a similar decrease over time in the 

15 abundance of species that feed on the entrained or impinged species 

16 and

17 ­ the number of equivalent adults and the amount of production 

18 foregone for impinged species were high enough to noticeably change 

19 and decrease the population of any species. 

20 Impingement 

21 TVA conducted three impingement studies at the SQN intake. The first study occurred between 

22 1981 and July 1985 (Dycus 1986), starting the same year as the commercial operation of SQN 

23 Unit 1 began. TVA discontinued impingement sampling prior to the end of the fifth consecutive 

24 year of impingement sampling because of low impingement rates. During the 4.5 years of 

25 sampling, threadfin shad was the dominant species impinged (Dycus 1986). Threadfin shad 

26 made up between 30 percent and 80 percent of the fish impinged in any given year (based on 

27 data presented in Dycus 1986). Other species with high impingement rates included gizzard 

28 shad (0.6 percent to 24 percent), freshwater drum (4 percent to 19 percent), and bluegill 

29 (6 percent to 17 percent).

30 TVA researchers (Kay and Baxter 2002) conducted the second impingement study in the winter, 

31 from December 19, 2001, through February 25, 2002. During this study, TVA collected 

32 10 impingement samples based of about 24 hours of operation per sample (48 hours for one 

33 sample in January) and identified 13,570 individuals from 15 fish species representing 8 families 

34 and weighing a total of 50,532 g (111 lb). Because one sample was of 48 hours duration, this is 

35 equivalent to 11 sampling days collected over a period of 69 days. Assuming that these 

36 sampling days are representative and extrapolating to the 69-day sampling period, the total 

37 number of fish caught would be (13,570 fish/11 days) x 69 days = 85,121 fish and the total 

38 biomass would be 311,973 g (699 lb). The fish were generally small, with an overall average 

39 weight of 3.7 g (0.13 oz) per fish, calculated as 50,532 g collected divided by 13,570 individuals 

40 collected. Threadfin shad was again the numerically dominant species, with 13,160 individuals 

41 comprising 97 percent of the total number of individuals collected (74 percent of the total 

42 weight). The next most common species was bluegill (0.80 percent of the total number of 

43 individuals, 0.64 percent of the weight), freshwater drum (0.77 percent of the total number of 

44 individuals, 15 percent of the weight), and gizzard shad (0.43 percent of the total number of 

45 individuals, 1.3 percent of the weight). All other species contributed less than 1 percent of the 

46 total number and weight.
Environmental Consequences and Mitigating Actions

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1 TVA researchers conducted weekly impingement studies from January 25, 2005, through 

2 January 15, 2007 (TVA2007c), again collecting fish after 24 hours of operation. TVA reported 

3 22 species from 9 families during this impingement study. The estimated annual impingement 

4 (extrapolated from weekly impingement rates) was 20,233 fish during the first year and 

5 40,362 fish during the second year, as shown in Table 4–10. Threadfin shad comprised 

6 91 percent of the total individuals during the entire impingement study, followed by bluegill 

7 (3 percent), freshwater drum (2 percent), and channel and blue catfish (1 percent each). All 

8 other species contributed less than 1 percent of the total. The largest contributors to biomass 

9 were the blue catfish (22 percent), threadfin shad (21 percent), channel catfish (17 percent), and 

10 freshwater drum (15 percent).

11 Table 4–10. List of Fish Species by Family, Scientific, and Common Name and Numbers 

12 Collected in Impingement Samples From 2005 Through 2007 at the SQN Intake

Family Scientific Name Common Name

Total Number of 

Fish in 

Impingement 

Samples(a)

Calculated 

Annual 

Impingement(b)

Year 1 Year 2 Year 1 Year 2

Atherinidae Labidesthes sicculus unidentified sunfish 0 1 0 7

Centrarchidae Lepomis spp. unidentified sunfish 0 1 0 7

Lepomis auritus redbreast sunfish 2 1 14 7

Lepomis macrochirus bluegill 122 120 854 840

Lepomis microlophus redear sunfish 1 0 7 0 

Micropterus 

punctulatus 

spotted bass 1 13 7 91

Micropterus salmoides largemouth bass 5 5 35 35

Pomoxis annularis white crappie 3 3 21 21

Pomoxis 

nigromaculatus 

black crappie 0 47 0 329

Clupeidae Alosa chrysochloris skipjack herring 10 10 70 70

Alosa pseudoharengus Alewife 10 4 70 28

Dorosoma cepedianum gizzard shad 17 25 119 175

Dorosoma petenense threadfin shad 2,529 5,373 17,703 37,611

Cyprinidae Moxostoma spp. unidentified 

redhorse

0 1 0 7

Notropis atherinoides emerald shiner 1 0 7 0

Pimephales notatus bluntnose minnow 0 2 0 14

Pimephales vigilax bullhead minnow 1 3 7 21

Ictaluridae Ameiurus natalis yellow bullhead 1 0 7 0 

Ictalurus furcatus blue catfish 25 40 175 280

Ictalurus punctatus channel catfish 50 32 350 224

Pylodictis ofivaris flathead catfish 3 11 21 77
Environmental Consequences and Mitigating Actions

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Family Scientific Name Common Name

Total Number of 

Fish in 

Impingement 

Samples(a)

Calculated 

Annual 

Impingement(b)

Year 1 Year 2 Year 1 Year 2

Moronidae Morone chrysops white bass 2 4 14 28

Morone 

mississippiensis 

yellow bass 24 10 168 70

Morone saxatilis striped bass 4 0 28 0

Percidae Sander canadensis Sauger 1 0 7 0

Poeciliidae Gambusia affinis western 

mosquitofish

1 0 7 0

Sciaenidae Aplodinotus grunniens freshwater drum 76 60 532 420

Total fish 2,889 5,766 20,223 40,362

(a) Total collected from once a week, 24-hr impingement samples.

(b) Calculated as the total number of fish in weekly impingement samples multiplied by 7 days per week.

Source: TVA 2007c

1 Entrainment 

2 TVA conducted entrainment studies of ichthyoplankton (fish eggs and larvae) from 1981 through 

3 1985 (Dycus 1986) and in 2004 (Baxter and Buchanan 2010). Entrainment rates of 

4 ichthyoplankton are influenced by the timing of the study, which usually occurs during the spring 

5 spawning season, by the fraction of the water withdrawn (which in turn is influenced by the river 

6 flow), and by the life history of the species being entrained. Table 4–11 provides the hydraulic, 

7 egg, and larval entrainment rates for the 6 years of entrainment studies. 

8 Hydraulic entrainment (the fraction of the water flowing past the SQN site that is withdrawn for 

9 cooling) varies depending on the plant operations and the flow past the site. Mean hydraulic 

10 entrainment ranged from 5.7 percent in 1983 and 1984 (Dycus 1986) to 24.2 percent in 2004 

11 (TVA2013g), although in 1985 both units were shut down for the last 4 months of the year. The 

12 average hydraulic entrainment between 1981 and 1985 was 8.6 percent. According to TVA

13 (2013g), the higher hydraulic entrainment in 2004 may have been the result of lower reservoir 

14 flow rates. The peak hydraulic entrainment of 111.1 percent occurred as a result of zero 

15 release at Chickamauga Dam and an average release from Watts Bar Dam (Baxter and 

16 Buchanan 2010). Entrainment rates of over 100 percent occur during periods when the flow of 

17 water past the plant is smaller than the withdrawal from the reservoir (TVA2013a). This is most 

18 likely due to upstream flow. For reference, Hopping et al. (2009) discuss the various 

19 mechanisms that influence upstream flow, including flow advection as a result of reservoir 

20 sloshing from peaking operations, the entrainment of ambient flow by the high velocity diffuser 

21 jets, and velocity gradients created by boundary resistance, shoreline irregularities, and bends 

22 in the river. 
Environmental Consequences and Mitigating Actions

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1 Eggs

2 Dycus (1986) reports that freshwater drum comprised 99.5 percent of all fish eggs collected 

3 during entrainment sampling conducted in 1985. Freshwater drum spawn large numbers of 

4 eggs (40,000 to 60,000 per female), broadcasting them into the open water to float until 

5 hatching occurs, typically in one or two days (Etnier and Starnes 1993). Results from studies 

6 conducted in 1981 and 1982 estimated the percentage of freshwater drum eggs entrained as 

7 6.7 percent and 41.4 percent, respectively (Baxter and Buchanan 2010). Results from the 2004 

8 sampling study show freshwater drum eggs comprised 98.8 percent of the fish eggs collected 

9 (Baxter and Buchanan 2010). The percent entrained was estimated to be 11.2 percent of the 

10 5.4 billion eggs transported past SQN or about 600 million fish eggs per year lost to 

11 entrainment.

12 Larvae

13 Table 4–11 shows the estimated percentages of all larvae passing SQN that were entrained 

14 during studies conducted from 1981 through 1985 and in 2004. For the total number of larvae 

15 entrained in 2004, 15.6 percent of those passing were entrained, compared to 2.2 to 4.7 percent 

16 for previous sampling years. Clupeid (shad) larvae comprised 87.9 percent of the total fish 

17 larvae entrained. Morone larvae (white, yellow, and striped bass) comprised 5.5 percent, 

18 freshwater drum comprised 3.2 percent, and centrarchids (sunfish, such as bluegill) accounted 

19 for 3.1 percent (Baxter and Buchanan 2010).

20 The large number of entrained clupeids (shad) greatly influenced the overall estimated 

21 entrainment rate for larvae in 2004. Clupeids were found in the intake samples at average 

22 densities lower than in the reservoir and were entrained at a rate of 15.6 percent (the fraction of 

23 the clupeids passing the plant that were entrained). Clupeid entrainment rates were lower for 

24 1981 through 1985 (ranging from 1.1 to 2.7 percent), as would be expected from the lower 

25 hydraulic entrainment during that time period (Baxter and Buchanan 2010). 

26 Although centrarchids (sunfish) represented only 3.1 percent of the entrained larvae, they were 

27 entrained at a higher rate than clupeids. TVA’s entrainment analysis from the 2004 study 

28 indicated that 24.2 percent of the centrarchid larvae that passed the plant were entrained. 

29 Lower entrainment rates, ranging from 0.6 to 1.8 percent, were seen in the entrainment studies 

30 between 1981 and 1985 (Baxter and Buchanan 2010).

31 Morone larvae comprised 5.5 percent of the entrained larvae during the 2004 study and were 

32 entrained at a rate of 5 percent of the larvae passing by the plant (Baxter and Buchanan 2010). 

33 Entrainment rate estimates from the studies in the 1980s range from 1.7 to 4.8 percent (Baxter 

34 and Buchanan 2010). 

35 Although cyprinids (carp) made up 0.2 percent of the larvae sampled, the entrainment rate was 

36 over 72 percent. This is based on very low densities of carp larvae in either the intake samples 

(7 per 1000 m3 of water) or in the reservoir samples (2 per 1000 m3 37 of water). The estimated 

38 percentage of carp entrained in the studies that were done in the 1980s ranged from 2.3 to 

39 5.9 percent (Baxter and Buchanan 2010). As discussed in Section 3.7, carp are nonnative, 

40 introduced species and a female carp may produce over two million eggs in a given season 

41 (Etnier and Starnes 1993).

42 Freshwater drum comprised only 3.2 percent of the larvae collected during the 2004 study 

43 period, and the entrainment rate was 45.4 percent, which is within the range of the entrainment 

44 rates observed from the studies conducted in the 1980s (5.5 to 57.8 percent).
Environmental Consequences and Mitigating Actions

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1 Table 4–11. Entrainment Percentages for Fish Eggs and Larvae at Sequoyah Nuclear 

2 Plant 1981–1985 and 2004

1981 1982 1983 1984 1985 2004

Mean percent hydraulic entrainment 13.4 12.6 5.7 5.7 12.2 24.2

Sampling period

Beginning 4/6/81 3/18/82 3/9/83 3/7/84 3/11/85 5/20/04

End 8/27/81 8/17/82 8/22/83 8/21/84 8/27/85 7/12/04

Eggs

freshwater drum 6.7 41.4 22.6 9.7 16.6 11.2

Larvae

Clupeidae (shad) 2.1 1.5 2.7 1.8 1.1 15.4

Cyprinidae (carp) 4.3 4.2 5.9 2.3 3.1 72.6

Catostomidae (suckers) 0.0 0.0 6.1 2.6 0.0 0.0

Ictaluridae (catfish) 8.4 7.7 9.1 45.9 27.8 0.0

Moronidae (white/yellow bass) 1.7 2.7 4.8 2.2 2.46 5.0

Centrarchidae (sunfish) 1.0 1.8 1.1 0.6 0.7 24.2

Percidae (perch) 3.6 1.6 10.7 1.6 3.5 0.0

Sciaenidae (drums) 5.5 25.6 57.8 22.7 30.2 45.4

Total 2.3 2.2 4.7 2.3 2.6 15.6

Sources: Baxter and Buchanan 2010; Dycus 1986

3 Discussion of Impingement and Entrainment 

4 Of the planktonic fish eggs and larvae that pass SQN and are not entrained, most probably pass 

5 through the Chicamauga Dam and are lost to the Chicamauga Reservoir ecosystem. Their 

6 contribution to the ecosystem below the dam is unclear. Although the NRC staff considers the 

7 entrainment mortality rate to be 100 percent, the entrained organisms appear to be mostly 

8 destined to go through the dam not to contribute to the Chicamauga Reservoir ecosystem in any 

9 event. Because some fish eggs and larvae may survive passage through the dam, the total 

10 mortality due to the dam and SQN together will be greater than that due to the dam alone. The 

11 NRC staff found insufficient information to quantify these mortality rates, however. 

12 Impingement studies conducted within a 26-year time span indicate the highest rates of 

13 impingement were for four species: threadfin shad, bluegill, freshwater drum, and gizzard shad. 

14 In electrofishing and gillnet data from sampling sites upstream (Tennessee RM 490.5) and 

15 downstream (Tennessee RM 482) of the SQN site, collected during studies between 1999 and 

16 2011, TVA (2012c) did not observe trends in either the abundance or the distribution of these 

17 four species. The NRC staff notes that the high variation inherent in such sampling makes any 

18 pattern recognition difficult. Further, impingement of threadfin shad in large numbers occurs 

19 frequently in the southeastern United States. A study of 32 southeastern United States power 

20 plants found threadfin shad accounted for more than 90 percent of all fish impinged (Loar 

21 et al. 1978). EPA (2001) reported similar findings in its compilation of impingement data. The 

22 study was not limited to facilities in the southeast and the percentage of threadfin shad impinged 
Environmental Consequences and Mitigating Actions

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1 was not as high, although threadfin shad was the most frequently impinged species. EPA found 

2 the typical annual impingement rate per facility for all reservoirs and lakes (excluding the Great 

3 Lakes) to be 678,000 fish per year, ranging from 203,000 to 1,370,000 depending on the facility. 

4 Shad are intolerant of cold water temperatures, which often results in high winter mortality, such 

5 as that observed at SQN and discussed in Section 3.7. Shad are less susceptible to 

6 impingement at higher temperatures when they are able to swim away from the intake. 

7 At SQN, the same species are being impinged across years at approximately the same rates, 

8 with the largest number being threadfin shad, followed by gizzard shad, bluegill, and freshwater 

9 drum. The consistency in impingement of these species over the years suggests that 

10 impingement is having little effect on fish populations in the Chickamauga Reservoir. Further, 

11 sampling studies conducted between 1999 and 2011 upstream and downstream of SQN have 

12 not shown obvious and sustained declines in fish populations that can be attributed specifically 

13 to entrainment or impingement during the operation of SQN (see Section 3.7). In past SEISs, 

14 NRC has investigated sustained declines in fish populations as an indication of instability for 

15 assessing level of impact (e.g., NRC2013f). 

16 TVA (2007c) used two types of models, an equivalent adult (EA) model and a production 

17 foregone model with information from 2006 and 2007, to express the impact of fish impingement

18 at SQN. Equivalent adult losses, which TVA applied for harvestable fish species, are modeled 

19 estimates of the number of fish impinged that would have survived to harvestable (adult) age. 

20 Production foregone, which TVA applied to non-harvestable species assumed to be prey for 

21 harvestable species, is the modeled reduction in prey biomass available to predators due to the 

22 loss of prey, including the expected future growth of the prey prior to consumption by the 

23 predators. Many fish impinged at SQN are immature or small, and these models assume a 

24 natural mortality rate such that not all would have survived to become adults, and so the 

25 modeled number of equivalent (adult) fish affected is much lower than the actual number of 

26 immature fish actually affected. TVA (2007c) considers the modeled numbers that would have 

27 survived to be the “biological liability,” which is a representation of the effect the plant’s 

28 operation has on the aquatic organisms. The total modeled numbers of fish that would have 

29 survived had they not been impinged are 1,868 and 821 fish for studies conducted in 

30 2005–2006 and 2006–2007, respectively. Table 4–12 shows the estimated total numbers of 

31 impinged fish per year for each full year of impingement sampling at the SQN site and TVA’s 

32 modeled numbers after application of the EA and production foregone models. Modeled 

33 equivalent impingement numbers range from 821 fish in 2006–2007 to 5,843 fish in 1981–1982. 

34 Because of the many uncertainties in assumptions incorporated into these models, much 

35 uncertainty is associated with the results.

36 Entrainment and impingement studies show that the species most affected by operation of SQN 

37 (freshwater drum, threadfin and gizzard shad, and bluegill) are some of the most common 

38 species in the reservoir and that the operation of the SQN site has not destabilized or noticeably 

39 altered the populations of these species. Assuming that the past effects predict future effects, 

40 the impact of entrainment and impingement on these aquatic resources from the proposed 

41 license renewal for the SQN plant would be SMALL.
Environmental Consequences and Mitigating Actions

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1 Table 4–12. Total Estimated Numbers of Fish Impinged by Year at SQN and TVA’s 

2 Modeled Numbers Using Equivalent Adult (EA) and Production Foregone (PF) Models

1980–81 1981–82 1982–83 1983–84 1984–85 2005–06 2006–07

Extrapolated annual 

number for all species 

impinged

94,528 81,158 20,685 41,076 27,195 20,223 40,362

Modeled annual 

number after EA and 

PF reduction

4,851 5,843 2,256 4,162 2,761 1,868 821

Percent of shad 

(threadfin and gizzard) 

by number

87% 81% 71% 72% 73% 88% 93%

Percent of shad after 

EA and PF modeling 66% 52% 36% 45% 47% 59% 77%

Source: TVA 2007c

3 4.7.1.3 Thermal Impacts on Aquatic Organisms 

4 Thermal discharges can increase the ambient water temperature in sections of the 

5 Chickamauga Reservoir. Section 3.1.3 discusses the operation of the SQN cooling system and 

6 the design of the diffuser used for discharges. SQN uses once-through cooling during most of 

7 the year. When the river temperature approaches the NPDES limit, TVA uses the helper 

8 cooling towers to help prevent the plant from exceeding the NPDES limits. Use of the helper 

9 towers can reduce not only potential thermal impacts, but also entrainment and impingement

10 impacts because of reduced water withdrawal. The number of helper tower operation hours, 

11 reported as equivalent days, varies from year to year, but has averaged 125 equivalent days per 

12 year between 2007 and 2013. In 2009, helper towers operated less than 34 equivalent days, 

13 and, in 2008, they operated 197 equivalent days (TVA2013g). TVA calculates equivalent days 

14 of cooling tower operation based on a summation of the number of hours that at least one CTLP 

15 is in service (TVA 2013g).

16 As discussed in Section 3.1.3, the NPDES permit specifies a mixing zone that is 750 ft (230 m) 

17 wide and extends 275 ft (84 m) upstream of the diffusers and 1,500 ft (460 m) downstream of 

18 the diffusers. The diffusers are placed such that they span almost the entire width of the main 

19 channel (TVA2011b). TVA (2013g) indicates that the main channel is approximately 900 ft 

20 (270 m) wide adjacent to the plant, and that the entire reservoir width (including the main 

21 channel and the overbank areas) is approximately 2,000 ft (610 m) wide in the vicinity of the 

22 diffuser, thus allowing room for fish to avoid the plume in the mixing zone. 

23 Temperature limits set by the permit include a 24-hour downstream temperature of 30.5 °C 

24 (86.9 °F), and, if the ambient temperature of the reservoir water exceeds 29.4 °C (84.9 °F), the 

25 24-hour downstream temperature cannot exceed 33.9 °C (93 °F). The NPDES permit also 

26 specifies a maximum 24-hour average temperature increase of no more than 5.0 °C (9.0 °F) for 

27 November through March (when the reservoir is coldest), and 3.0 °C (5.4 °F) for April through 

28 October. The maximum hourly average temperature rate-of-change is limited to 2.0 °C (3.6 °F) 

29 per hour (TVA2013a). Temperature criteria are based on 24-hour averaging. TVA (2012) 

30 measured temperature profiles in the summer (August 25, 2011) and autumn 
Environmental Consequences and Mitigating Actions

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1 (September 14, 2011). The thermal plume was the longest in the summer measurement period 

2 and extended approximately 4.1 mi (6.6 km) downstream of the discharge point to Tennessee 

3 RM 479.5. The ambient surface temperature (measured at Tennessee RM 486.7) was 81.9 °F 

4 (27.7 °C) and the highest temperature measured downstream of the discharge was 86.85 °F 

5 (30.5 °C) (at Tennessee RM 481.1). 

6 Water temperatures of 97 °F (36 °C) are considered the upper thermal limit for mortality of 

7 warm-water fish species such as gizzard shad, common carp, largemouth bass, and sunfish 

8 (NRC 2013d). The upper lethal temperatures for cool water species such as freshwater drum, 

9 yellow perch, smallmouth bass, walleye, and sauger are similar or slightly lower than those for 

10 the warm-water species, although cool-water species need cooler average temperatures for 

11 growing and reproducing (NRC 2013). The thermal limits specified by the NPDES permit do not 

12 exceed the upper temperature limit for mortality of warm- or cool-water fish species. 

13 TVA conducted studies on certain species to determine if plant operations, including thermal 

14 discharges, affected the fish, including sauger (Hickman and Buchanan 1995), white crappie 

15 (Buchanan and McDonough 1990), white bass (Buchanan 1994), and channel catfish (Peck and 

16 Buchanan 1991). The studies report no instances of attraction or avoidance of the thermal 

17 plume for fish species within the Chickamauga Reservoir. 

18 Between November 1993 and March 1994, TVA (Kay and Buchanan 1995) conducted field 

19 investigations including gillnetting, creel census, and estimates of the number of persons fishing 

20 and number of fishing boats in the vicinity of the diffuser to determine whether fish were 

21 attracted to or unable to avoid the thermal plume. TVA conducted gillnetting at two sites: 

22 Tennessee RM 483.4, in the thermal plume, and Tennessee RM 483.8, upstream from the 

23 underwater dam. Catfish, bass, and centrarchids were collected in similar numbers at both 

24 sampling sites, and the studies report no indication that fish were avoiding the thermal plume or 

25 were attracted to the plume. Sauger, a cool-water species, was collected in comparable 

26 numbers at both sampling stations, indicating to the investigators that the thermal effluent did 

27 not preclude them from moving past the site. 

28 The diffuser discharge plume is buoyant relative to the ambient water in the river. In general, 

29 however, the buoyancy is less at lower ambient water temperatures and, thus, the mixing and 

30 dilution of the thermal plume is less during months when the river is coolest. In addition, 

31 stratification of the river occurs in the warmer months (April through September) at which time 

32 the water at a depth of 5 ft (1.5 m) (the basis for the NPDES permit criteria) is warmer than the 

33 water at the bottom of the river. According to TVA (2013b), the diffuser jets cause an upwelling 

34 that can cool the surface water around the diffuser mixing zone. The river flow over the 

35 underwater dam also contributes to the upwelling, which in extreme cases of stratification 

36 produces neutral buoyancy in the effluent, causing it to remain submerged. 

37 Ecological monitoring studies did not find a measurable or discernible effect on aquatic 

38 organisms in the vicinity of the SQN discharge. Further, TVA has a valid NPDES permit from 

39 the State of Tennessee that limits the discharge temperatures. The NRC staff relies on the 

40 State’s permitting process to ensure the health of the aquatic organisms in the reservoir. In 

41 view of all these observations, the NRC staff concludes that the thermal impact on aquatic 

42 organisms as a result of the proposed license renewal would be SMALL. 

43 4.7.1.4 Water Use Conflicts with Aquatic Resources

44 Water use conflicts occur when the amount of water needed to support aquatic resources is 

45 diminished as a result of demand for agricultural, municipal, or industrial use or decreased water 

46 availability due to droughts, or a combination of these factors.
Environmental Consequences and Mitigating Actions

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1 As discussed in Sections 3.1.3 and 4.5.1.1, the total SQN peak water demand is 1,680 mgd 

(2,600 cfs, or 73.5 m3 2 /sec). This is approximately 8 percent of the annual average flow of the 

Tennessee River at the Chickamauga Dam (21,000 mgd (32,500 cfs or 920 m3 3 /s)). As 

4 mentioned in Section 3.5.1, for once-through cooling system operation at SQN, the condenser 

5 flow rate is nearly equal to the surface water withdrawal rate, giving a negligible consumptive 

6 use rate.

7 Between 2008 and 2012, the SQN plant withdrew an average of 1,580 mgd (2,445 cfs, or 

69.1 m3 8 /s) of water, which is also about 8 percent of the Tennessee River’s average flow past 

the SQN site (31,100 cfs (881 m3 9 /s)). When it occurs, the majority of the consumptive loss 

10 occurs on days when the plant operates the cooling towers in helper mode. The amount of 

11 water consumed from the river (during the cooling tower operations) on a daily average basis 

can approach about 45 mgd (70 cfs, or 2 m3 12 /s)) (see Section 4.5.1.1). On a daily average basis, 

13 the net consumptive loss is likely to be roughly 1.2 percent of the river flow past the SQN site. 

14 During 2011, the cooling towers were operated fewer than 90 equivalent days (TVA 2013g). 

15 Additional information on water use conflicts can be found in Section 4.5.1.1. 

16 The amount of water consumed by the operation of SQNs is minor in comparison to the flow 

17 past the plant and even smaller in comparison to the volume of water in the Chickamauga 

18 Reservoir. Changes in surface water elevation and aquatic habitat due to water consumption by 

19 SQN are very small in comparison to those due to TVA’s use of dams to regulate the river. The 

20 fish species described in Section 3.7 as present in the Chickamauga Reservoir in the vicinity of 

21 the SQN site do not appear to be affected by the consumption of water from the reservoir. The 

22 NRC staff concludes that the impact of water use conflicts on aquatic species from the proposed 

23 license renewal would be SMALL. 

24 4.7.2 No-Action Alternative – Aquatic Resources

25 This section describes environmental effects to aquatic organisms if the NRC takes no action. 

26 No action, in this case, means that the NRC would not renew the operating licenses for SQN, 

27 the SQN units would shut down, and TVA would initiate decommissioning in accordance with 

28 10 CFR Part 50.82. The environmental impacts from decommissioning and related activities 

29 are discussed in the Final Generic Environmental Impact Statement on Decommissioning of 

30 Nuclear Facilities (NRC 2002) and in Section 2.1.3 of this SEIS.

31 If SQN were to shut down, any existing impacts to aquatic ecology would decrease. Some 

32 withdrawal of water from the Chickamauga Reservoir would continue during the shutdown 

33 period as the fuel is cooled, although the amount of water withdrawn would decrease over time. 

34 The aquatic organisms would be subject to lower rates of impingement, entrainment, and heat 

35 shock. Impacts on aquatic resources from the no-action alternative would be SMALL. 

36 4.7.3 NGCC Alternative – Aquatic Resources

37 The NRC staff assumes that construction activities for the NGCC alternative would occur at an 

38 existing power plant site (other than SQN) or a brownfield site with available infrastructure and 

39 could affect drainage areas or other onsite aquatic features. Also, the NRC staff assumes TVA

40 will implement BMPs to minimize erosion and sedimentation in nearby streams, ponds, or rivers. 

41 Stormwater control measures would be required to comply with the State’s NPDES permitting. 

42 Any dredging or in-water work at sites other than on the Tennessee River or its tributaries, 

43 which are controlled by TVA, could require permits from the U.S. Army Corps of Engineers 

44 (USACE) pursuant to Section 404 of the Federal Water Pollution Control Act (FWPCA) (Clean 

45 Water Act (CWA)) as amended (33 U.S.C. 1251 et seq.). Other USACE permits could be 

46 required, depending on the location of the site. Dredging activities would also require BMPs for 
Environmental Consequences and Mitigating Actions

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1 in-water work to minimize sedimentation and erosion. Due to the short-term nature of the 

2 dredging activities, the effect on the aquatic habitats would likely be relatively localized and 

3 temporary (recovery time for aquatic communities typically takes several years).

4 The NGCC plant would typically require less cooling water be withdrawn from the environment 

5 than SQN. The lower withdrawal rates would reduce the numbers of fish and other aquatic 

6 resources affected by the operation of the intake and decrease the heat released from the 

7 discharge as compared to the SQN units. Chemical discharges from operation of the NGCC 

8 alternative cooling system would be similar to SQN. Air emissions from the NGCC alternative 

9 would emit particulates (as discussed in Section 4.3.3.1) that could be introduced into the water 

10 from erosion of soil or from settling on the surface of the water. The particulates would result in 

11 minimal exposure to aquatic organisms. Overall aquatic impacts from operation of an NGCC 

12 plant would likely be less than for the continued operation of SQN. Impacts on aquatic 

13 organisms from construction and operation of an NGCC alternative would be SMALL. 

14 4.7.4 SCPC Alternative – Aquatic Resources

15 The NRC staff assumes that construction activities for the SCPC alternative would occur at an 

16 existing power plant site (other than SQN) or a brownfield site with available infrastructure, and 

17 could affect drainage areas or other onsite aquatic features. Also, the NRC staff assumes TVA

18 will implement BMPs to minimize erosion and sedimentation in nearby streams, ponds, or rivers. 

19 Stormwater control measures would be required to comply with the State’s NPDES permitting. 

20 Any dredging or in-water work at sites other than on the Tennessee River or its tributaries, 

21 which are controlled by TVA, could require permits from USACE pursuant to Section 404 of the 

22 CWA as amended (33 U.S.C. 1251 et seq.). Other USACE permits could be required 

23 depending on the location of the site. Dredging activities would also require BMPs for in-water 

24 work to minimize sedimentation and erosion. Due to the short-term nature of the dredging 

25 activities, the effect on the aquatic habitats would likely be relatively localized and temporary 

26 (recovery time for aquatic communities typically takes several years).

27 The SCPC plant would typically require slightly less cooling water be withdrawn from the 

28 environment than SQN. The lower withdrawal rates would reduce the numbers of fish and other 

29 aquatic resources affected by the operation of the intake and the heat released from the 

30 discharge would be less than that for the SQN units. The actual impact to the aquatic 

31 organisms would depend on the ecosystem and biological interactions among the organisms. 

32 The SCPC plant would have similar chemical discharges to those from the SQN units as a 

33 result of operation of the cooling system. Air emissions from the SCPC units would include 

34 small amounts of ash (as discussed in Section 4.3.4.1) that would settle on water bodies or be 

35 introduced into the water from soil erosion. Overall, the aquatic impacts from operation of an 

36 SCPC plant would be less than for the continued operation of the SQN units if the SCPC plant 

37 were located on Chickamauga Reservoir in the vicinity of the SQN site. Without knowing the 

38 location of the SCPC unit and the aquatic species and their interactions within the ecosystem, 

39 the NRC staff cannot assume that overall impacts of operation of an SCPC plant would be less 

40 than those for the license renewal term at the SQN site. Impacts on aquatic organisms from 

41 construction and operation of an SCPC alternative would likely be SMALL to MODERATE. 

42 4.7.5 New Nuclear Alternative – Aquatic Resources

43 The NRC staff assumes that construction activities for the new nuclear alternative would occur 

44 at a site other than the SQN site and could affect drainage areas or other onsite aquatic 

45 features. Also, the NRC staff assumes TVA will implement BMPs to minimize erosion and 

46 sedimentation in nearby streams, ponds, or rivers. Stormwater control measures would be 
Environmental Consequences and Mitigating Actions

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1 required to comply with the State’s NPDES permitting. If the site selected is a greenfield site, a 

2 new intake and discharge system would be required. If it is located at an existing nuclear site, 

3 such as the Bellefonte site in Alabama, the available infrastructure could be used in its current 

4 configuration or be modified or expanded. Any dredging or in-water work at sites other than on 

5 the Tennessee River or its tributaries, which are controlled by TVA, could require permits from 

6 USACE pursuant to Section 404 of the CWA as amended (33 U.S.C. 1251 et seq.). Other 

7 USACE permits could be required, depending on the location of the site. Dredging activities 

8 would also require BMPs for in-water work to minimize sedimentation and erosion. Due to the 

9 short-term nature of the dredging activities, the effect on the aquatic habitats would likely be 

10 relatively localized and temporary (recovery time for aquatic communities typically takes several 

11 years).

12 The new nuclear units would use a closed-cycle cooling system so that water consumption 

13 would be less than for the SQN units, which operate in open-cycle and helper modes. As a 

14 result, the withdrawal of water and the thermal input from the discharge would be less than for 

15 the SQN units. This in turn would reduce entrainment, impingement, and thermal impacts to 

16 aquatic organisms. Without knowing the location of the new nuclear units and the aquatic 

17 species and their ecosystem interactions, NRC staff cannot assume that the overall impacts of 

18 operation of a new nuclear unit would be less than those for the license renewal term at the 

19 SQN site. Impacts on aquatic organisms from construction and operation of a new nuclear 

20 facility would be SMALL to MODERATE. 

21 4.7.6 Combination Alternative - Aquatic Resources 

22 The staff assumes that construction activities for the combination alternative would occur at 

23 another site, other than the SQN site, and could affect drainage areas or other onsite aquatic 

24 features. The NRC staff assumes TVA will implement BMPs to minimize erosion and 

25 sedimentation in nearby streams, ponds, or rivers. The State’s NPDES permitting would require 

26 stormwater control measures. During operations, the land-based wind and solar alternative 

27 would not require withdrawal of water or consumptive water use. Thus, the impacts on aquatic 

28 ecology from the land-based wind and solar combination alternative would be SMALL.

29 4.8 Special Status Species and Habitats

30 This section describes the potential impacts of the proposed action (license renewal) and 

31 alternatives to the proposed action on special status species and habitats.

32 4.8.1 Proposed Action

33 The special status species and habitats issue applicable to SQN during the license renewal 

34 term is listed in Table 4–13. Section 3.8 of this SEIS describes the special status species and 

35 habitats that have the potential to be affected by the proposed action. The discussion of 

36 species and habitats protected under the Endangered Species Act of 1973, as amended (ESA), 

37 includes a description of the action area as defined by the ESA section 7 regulations at 

38 50 CFR Part 402.02. The action area encompasses all areas that would be directly or indirectly 

39 affected by the proposed SQN license renewal.

40 Appendix C.1 contains information on the NRC staff’s section 7 consultation with the U.S. Fish 

41 and Wildlife Service (FWS) for the proposed action. The NRC did not consult with the National 

42 Marine Fisheries Service (NMFS) as part of the SQN license renewal review because (as 

43 described in Section 3.8 and 4.8.1.1) no species or habitats under NMFS’s jurisdiction occur 

44 within the action area.
Environmental Consequences and Mitigating Actions

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1 Table 4–13. Special Status Species and Habitats

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

2 4.8.1.1 Species and Habitats Protected under the Endangered Species Act 

3 Species and Habitats under FWS Jurisdiction

4 Section 3.8 considers whether the 11 Federally listed and proposed species identified in 

5 Table 4–14 occur in the action area based on each species’ habitat requirements, life history, 

6 scientific surveys and studies, and other available information. In that section, the NRC staff 

7 concludes that none of these species are likely to occur in the action area. The NRC staff also 

8 concludes that no candidate species (CS) or proposed or designated critical habitat occur in the 

9 action area. Thus, the NRC staff concludes that the proposed action would have no effect on 

10 Federally listed species or habitats under FWS’s jurisdiction.

11 Table 4–14. Effect Determinations for Federally Listed Species

Species Common Name Federal 

Status(a)

Effect 

Determination

Mammals

Myotis grisescens gray bat E no effect

Myotis septentrionalis northern long-eared bat P no effect

Myotis sodalis Indiana bat E no effect

Fish

Percuba tanasi snail darter T no effect

Freshwater Mussels

Dromus dromas dromedary pearlymussel E no effect

Lampsilis abrupta pink mucket E no effect

Plethobasus cooperianus orangefoot pimpleback E no effect

Pleurobema plenum rough pigtoe E no effect

Plants

Isotria medeoloides small whorled pogonia T no effect

Scutellaria montana large-flowered skullcap T no effect

Spiraea virginiana Virginia spiraea T no effect

(a) E = endangered; T = threatened; P = proposed
Environmental Consequences and Mitigating Actions

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1 If in the future a Federally listed species is observed on the SQN site, the NRC has measures in 

2 place to ensure that NRC staff would be appropriately notified. SQN’s operating licenses, 

3 Appendix B, “Environmental Protection Plan,” Section 4.1.1 (NRC 1980, 1981) require TVA to 

4 report to the NRC within 24 hours any occurrence of a species protected by the ESA on the 

5 SQN site. Additionally, the NRC’s regulations containing notification requirements require that 

6 operating nuclear power reactors report to the NRC within 4 hours “any event or situation, 

7 related to...protection of the environment, for which a news release is planned or notification to 

8 other government agencies has been or will be made” (10 CFR Part 50.72(b)(2)(xi)). Such 

9 notifications include reports regarding Federally listed species, as described in Section 3.2.12 of 

10 NUREG-1022 (NRC 2013b). Further, as a Federal agency, TVA has the responsibility to 

11 comply with section 7 of the ESA if listed species or effects of the action are identified that were 

12 not previously considered.

13 Species and Habitats under NMFS’s Jurisdiction

14 As discussed in Section 3.8, no species or habitats under NMFS’s jurisdiction occur within the 

15 action area. Thus, the NRC staff concludes that the proposed action would have no effect on 

16 Federally listed species or habitats under NMFS’s jurisdiction.

17 Cumulative Effects

18 The ESA regulations at 50 CFR Part 402.12(f)(4) direct Federal agencies to consider cumulative 

19 effects as part of the proposed action effects analysis. Under the ESA, cumulative effects are 

20 defined as “those effects of future State or private activities, not involving Federal activities, that 

21 are reasonably certain to occur within the action area of the Federal action subject to 

22 consultation” (50 CFR Part 402.02). Unlike the NEPA definition of cumulative impacts (see 

23 Section 4.16), cumulative effects under the ESA do not include past actions or other Federal 

24 actions requiring separate ESA section 7 consultation. When formulating biological opinions 

25 under formal section 7 consultation, the FWS and NMFS (1998) consider cumulative effects 

26 when determining the likelihood of jeopardy or adverse modification. Therefore, consideration 

27 of cumulative effects under the ESA is necessary only if listed species will be adversely affected 

28 by the proposed action (FWS 2014).

29 In the case of SQN, because the NRC staff concluded earlier in this section that the proposed 

30 license renewal would have no effect on listed, proposed, or CS or on designated or proposed 

31 critical habitat, consideration of cumulative effects is not necessary.

32 4.8.1.2 Species and Habitats Protected under the Magnuson–Stevens Act

33 As discussed in Section 3.8, NMFS has not designated essential fish habitat (EFH) pursuant to 

34 the Magnuson–Stevens Fishery Conservation and Management Act, as amended 

35 (Magnuson–Stevens Act) in the Chickamauga Reservoir. Thus, the NRC staff concludes that 

36 the proposed action would have no effect on EFH.

37 4.8.2 No-Action Alternative – Special Status Species and Habitats

38 Under the no-action alternative, SQN would shut down. Federally listed species and designated 

39 critical habitat can be affected not only by operation of nuclear power plants but also by 

40 activities during shutdown. The ESA action area for the no-action alternative would most likely 

41 be the same or similar to the action area described in Section 3.8. Because the plant would 

42 require substantially less cooling water, potential impacts to aquatic species and habitats would 

43 be reduced, although the plant would still require some cooling water for some time. Changes 

44 in land use and other shutdown activities might affect terrestrial species differently than under 

45 continued operation. 
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1 Because no Federally listed species or habitats occur in the action area, the no-action 

2 alternative would likely have no effect on any such species or habitats. However, NRC would 

3 assess the need for ESA consultation upon plant shutdown. The ESA forbids the taking of a 

4 listed species, where to “take” means “harass, harm, pursue, hunt, shoot, wound, kill, trap, 

5 capture, or collect, or attempt to engage in any such conduct.” In the case of a take, ESA 

6 section 7 requires that NRC initiate consultation with the FWS or NMFS. The implementing 

7 regulations at 50 CFR Part 402.16 also direct Federal agencies to reinitiate consultation in 

8 circumstances where (a) the incidental take limit in a biological opinion is exceeded, (b) new 

9 information reveals effects to Federally listed species or designated critical habitats that were 

10 not previously considered, (c) the action is modified in a manner that causes effects not 

11 previously considered, or (d) new species are listed or new critical habitat is designated that 

12 may be affected by the action. An ESA Section 7 consultation could identify impacts on 

13 Federally listed species or critical habitat, require monitoring and mitigation to minimize such 

14 impacts, and provide a level of exempted takes. Regulations and guidance regarding the ESA 

15 Section 7 consultation process are provided in 50 CFR Part 402 and in the Endangered Species 

16 Consultation Handbook (FWS and NMFS 1998). Upon shutdown, if the NRC determined that 

17 the no-action alternative would result in take of listed species or that one or more of the 

18 reinitiation criteria at 50 CFR Part 402.16 would be met, the NRC would reinitiate consultation, 

19 as appropriate, with FWS at that time. TVA, as a Federal agency, would also have 

20 responsibilities under section 7 of the ESA upon SQN shutdown.

21 The effects on ESA-listed aquatic species would likely be smaller than the effects under 

22 continued operation but would depend on the listed species and habitats present when the 

23 alternative is implemented. The types and magnitudes of adverse impacts to terrestrial 

24 ESA-listed species would depend on the shutdown activities and the listed species and habitats 

25 present when the alternative is implemented, and thus, the NRC cannot forecast a particular 

26 level of impact for this alternative.

27 The no-action alternative would not affect EFH because NMFS has not designated EFH in the 

28 Chickamauga Reservoir.

29 4.8.3 NGCC Alternative – Special Status Species and Habitats

30 This alternative entails shutdown and decommissioning of SQN and construction of a new 

31 NGCC alternative at an existing power plant site other than the SQN site or at a brownfield site

32 with available infrastructure in the TVA region. Section 4.8.2 discusses ESA considerations for 

33 the shutdown of SQN.

34 Unlike the proposed action, no-action alternative, and new nuclear alternative, the NRC does 

35 not license NGCC facilities, and the NRC would not be responsible for initiating section 7 

36 consultation if listed species or habitats might be adversely affected under this alternative. The 

37 facilities themselves would be responsible for protecting listed species because the ESA forbids 

38 the taking of a listed species. If TVA were to implement the NGCC alternative, as a Federal 

39 agency, TVA would be required to consult with FWS or NMFS under section 7. Similarly, TVA, 

40 and not NRC, would be responsible for engaging in EFH consultation with NMFS under the 

41 Magnuson–Stevens Act if EFH could be affected by construction or operation of the NGCC 

42 alternative.

43 Because the NGCC alternative would be built on an existing power plant site other than the 

44 SQN site, the special status species and habitats affected by the action would be different than 

45 those considered under the proposed action. The types and magnitudes of adverse impacts to 

46 ESA-listed species and EFH would depend on the proposed site, plant design, operation, and 
Environmental Consequences and Mitigating Actions

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1 listed species and habitats present when the alternative is implemented. Therefore, the NRC 

2 cannot forecast a particular level of impact for this alternative.

3 4.8.4 SCPC Alternative – Special Status Species and Habitats

4 This alternative entails shutdown and decommissioning of SQN and construction of a new 

5 SCPC alternative at an existing power plant site other than the SQN site or at a brownfield site 

6 with available infrastructure in the TVA region. Section 4.8.2 discusses ESA considerations for 

7 the shutdown of SQN.

8 Unlike the proposed action, no-action alternative, and new nuclear alternative, the NRC does 

9 not license SCPC facilities, and the NRC would not be responsible for initiating section 7 

10 consultation if listed species or habitats might be adversely affected under this alternative. The 

11 facilities themselves would be responsible for protecting listed species because the ESA forbids 

12 the taking of a listed species. If TVA were to implement the NGCC alternative, as a Federal 

13 agency, TVA would be required to consult with FWS or NMFS under section 7. Similarly, TVA, 

14 and not NRC, would be responsible for engaging in EFH consultation with NMFS under the 

15 Magnuson–Stevens Act if EFH could be affected by construction or operation of the NGCC 

16 alternative. 

17 Because the SCPC alternative would be built on an existing power plant site other than the SQN 

18 site, the special status species and habitats affected by the action would be different than those 

19 considered under the proposed action. The types and magnitudes of adverse impacts to ESA20 listed species and EFH would depend on the proposed site, plant design, operation, and listed 

21 species and habitats present when the alternative is implemented. Therefore, the NRC cannot 

22 forecast a particular level of impact for this alternative.

23 4.8.5 New Nuclear Alternative – Special Status Species and Habitats

24 This alternative entails shutdown and decommissioning of SQN and construction of a new 

25 nuclear alternative at an existing power plant site other than the SQN site in the TVA region. 

26 Section 4.8.2 discusses ESA considerations for the shutdown of SQN.

27 The NRC would remain the licensing agency under this alternative, and thus, the ESA would 

28 require NRC to initiate consultation with the FWS and NMFS, as applicable, prior to construction 

29 to ensure that the construction and operation of the new nuclear plant would not adversely 

30 affect any Federally listed species or adversely modify or destroy designated critical habitat. If 

31 the new nuclear plant is sited in an area that could affect water bodies with designated EFH, the 

32 Magnuson–Stevens Act would require the NRC to consult with NMFS to evaluate potential 

33 impacts to that habitat. TVA, as a Federal agency, would have consultation responsibilities 

34 under the ESA and Magnuson–Stevens Act.

35 Because the new nuclear alternative would be built on an existing power plant site other than 

36 the SQN site, the special status species and habitats affected by the action would be different 

37 than those considered under the proposed action. The types and magnitudes of adverse 

38 impacts to ESA-listed species and EFH would depend on the proposed site, plant design, 

39 operation, and listed species and habitats present when the alternative is implemented. 

40 Therefore, the NRC cannot forecast a particular level of impact for this alternative.

41 4.8.6 Combination Alternative – Special Status Species and Habitats

42 This alternative entails shutdown and decommissioning of SQN and construction and operation 

43 of wind turbines, possibly outside of the TVA region through purchased power agreements, and 
Environmental Consequences and Mitigating Actions

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1 solar photovoltaic systems throughout the TVA region. Section 4.8.2 discusses ESA

2 considerations for the shutdown of SQN.

3 Unlike the proposed action, no-action alternative, and new nuclear alternative, the NRC does 

4 not license wind turbines or solar photovoltaic systems, and the NRC would not be responsible 

5 for initiating section 7 consultation if listed species or habitats might be adversely affected under 

6 this alternative. The facilities themselves would be responsible for protecting listed species 

7 because the ESA forbids the taking of a listed species. If TVA were to implement this 

8 alternative, as a Federal agency, TVA would be required to consult with FWS or NMFS under 

9 section 7. Similarly, TVA, and not NRC, would be responsible for engaging in EFH consultation 

10 with NMFS under the Magnuson–Stevens Act if EFH could be affected by any component of 

11 this alternative.

12 Because this alternative would involve several sites throughout the TVA region, the special 

13 status species and habitats affected by the action would be different than those considered 

14 under the proposed action. The types and magnitudes of adverse impacts to ESA-listed 

15 species and EFH would depend on the proposed sites, alternative design, operation, and listed 

16 species and habitats present when the alternative is implemented. Therefore, the NRC cannot 

17 forecast a particular level of impact for this alternative.

18 4.9 Historic and Cultural Resources

19 This section describes the potential impacts of the proposed action (license renewal) and 

20 alternatives to the proposed action on historic and cultural resources. 

21 4.9.1 Proposed Action

22 The historic and cultural resource issue applicable to SQN during the license renewal term is 

23 listed in Table 4–15. Section 3.9 of this SEIS describes the historic and cultural resources that 

24 have the potential to be affected by the proposed action. 

25 Table 4–15. Historic and Cultural Resources 

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

26 The National Historic Preservation Act of 1966, as amended (NHPA) requires Federal agencies 

27 to consider the effects of their undertakings on historic properties, and renewing the operating 

28 license of a nuclear power plant is an undertaking that could potentially affect historic properties. 

29 Historic properties are defined as resources eligible for listing in the National Register of Historic 

30 Places (NRHP). The criteria for eligibility are listed in 36 CFR Part 60.4, “Criteria for 

31 evaluation,” and include (1) association with significant events in history, (2) association with the 

32 lives of persons significant in the past, (3) embodiment of distinctive characteristics of type, 

33 period, or construction, and (4) sites or places that have yielded, or are likely to yield, important 

34 information.

35 The historic preservation review process (Section 106 of the NHPA) is outlined in regulations 

36 issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800, “Protection 

37 of historic properties.”
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1 In accordance with the provisions of the NHPA, the NRC is required to make a reasonable effort 

2 to identify historic properties included in or eligible for inclusion in the NRHP in the area of 

3 potential effect (APE). The APE for a license renewal action the nuclear power plant site, its 

4 immediate environs including viewshed, and inscope transmission lines that may be affected by 

5 the license renewal decision, and land-disturbing activities associated with continued reactor

6 operations.

7 If historic properties are present within the APE, the NRC is required to contact the State 

8 Historic Preservation Office, assess the potential impact, and resolve any possible adverse 

9 effects of the undertaking (license renewal) on historic properties. In addition, the NRC is 

10 required to notify the State Historic Preservation Office if historic properties would not be 

11 affected by license renewal or if no historic properties are present. The State Historic 

12 Preservation Office is part of the Tennessee Historical Commission in the State of Tennessee.

13 4.9.1.1 Consultation

14 In accordance with 36 CFR Part 800.8(c), on March 14, 2013, the NRC initiated consultations 

15 on the proposed action by writing to the ACHP and Tennessee Historical Commission 

16 (NRC 2013e, 2013g). Also on March 14, 2013, the NRC initiated consultations with the 

17 following 14 Federally recognized tribes (NRC 2013e) (see Appendix C for a discussion of these 

18 letters):

19 • Cherokee Nation,

20 • Chickasaw Nation,

21 • Alabama Quassarte Tribal Town,

22 • Muscogee (Creek) Nation,

23 • Alabama-Coushatta Tribe of Texas,

24 • Thlopthlocco Tribal Town,

25 • Eastern Shawnee Tribe of Oklahoma,

26 • Kialegee Tribal Town,

27 • Eastern Band of the Cherokee Indians,

28 • Absentee Shawnee Tribe of Oklahoma,

29 • United Keetoowah Band of Cherokee Indians in Oklahoma,

30 • Seminole Tribe of Florida,

31 • Seminole Nation of Oklahoma, and

32 • Shawnee Tribe.

33 In its letters, the NRC provided information about the proposed action, defined the APE, and 

34 indicated that the NHPA review would be integrated with the NEPA process, in accordance with 

35 36 CFR Part 800.8. Also in its letters, the NRC invited participation in the identification and 

36 possible decisions concerning historic properties and also invited participation in the scoping

37 process.

38 In February 2013, the NRC contacted the Tennessee Historical Commission concerning the 

39 license renewal of SQN and scheduled a meeting to discuss the potential impacts to cultural 

40 resources at SQN. The NRC met with the staff of the Tennessee Historical Commission in 

41 April 2013. During this meeting, the Tennessee Historical Commission representative did not 
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1 express any concerns about the proposed license renewal (NRC 2013j). The Tennessee 

2 Historical Commission representative also suggested that the NRC consult with the Eastern 

3 Tennessee Historical Society and the Tennessee Historical Society as interested parties. In 

4 May 2013, the NRC sent letters to these historical societies offering them an opportunity to 

5 consult in the environmental review (NRC 2013f, 2013h). The NRC did not receive a response 

6 before the publication of this draft SEIS.

7 The NRC received scoping comments from one tribe, the United Keetoowah Band of Cherokee 

8 Indians in Oklahoma, in March 2013 (UKB 2013) (see Appendix C). The United Keetoowah 

9 Band of Cherokee Indians in Oklahoma did not raise any concerns and indicated there are no 

10 religious or culturally significant sites in the project area but said it would like to be contacted if 

11 any inadvertent discoveries of human remains are made as a result of the proposed Federal 

12 action (license renewal). 

13 Currently, TVA has no planned physical changes or ground-disturbing activities related to 

14 license renewal at the SQN site (TVA 2013g). As described in Section 3.9, there are no known 

15 historic properties or NRHP-eligible cultural resources located within the SQN site. However, 

16 Site 40HA22 is located near the SQN boundary, but not within the SQN site, and was previously 

17 impacted by the construction of SQN. Since Site 40HA22 is located on TVA controlled lands, 

18 TVA has the responsibility, under Section 110 of the NHPA, to address site preservation and 

19 possible effects to the site from TVA actions such as reservoir operations (TVA 2013c). In 

20 addition, as a Federal agency, TVA will also have to comply with Section 106 of the NHPA for 

21 any future undertakings in the vicinity of Site 40HA22. TVA has reopened Section 106 

22 consultation with the Tennessee State Historic Preservation Office and submitted revisions to its 

23 previous 2010 cultural resource survey of TVA lands, and updated information about this site 

24 with the Tennessee Division of Archaeology (TVA 2013a, 2013e). In addition, TVA reinitiated 

25 consultation with tribes, including the United Keetoowah Band of Cherokee Indians in Oklahoma 

26 (TVA 2013h). There has been no formal eligibility determination of the site for the NRHP at the 

27 time of publishing of this draft SEIS, although TVA believes the site is eligible and will treat it as 

28 such (TVA 2013a).

29 The Igou Cemetery is located in the southern area of the SQN site and is protected by several 

30 State statutes. The Tennessee Code Annotated (T.C.A.) 39-17-311 is the primary statute 

31 providing protection for the historic cemetery, which is maintained by TVA. NRC staff contacted 

32 the Tennessee Historical Commission to discuss the historic cemeteries associated with SQN 

33 (Igou and McGill). The Tennessee Historical Commission did not express any concerns 

34 regarding the management or protection of these historic cemeteries (NRC 2013k).

35 TVA has established procedures to ensure cultural resources are considered in project planning 

36 at SQN. These are the same procedures used throughout TVA properties. In addition, TVA 

37 has established procedures for consulting with the State Historic Preservation Office, Federally 

38 recognized Indian tribes, and any other interested parties. These procedures describe how TVA 

39 will comply with Section 106 of the NHPA for identifying, evaluating, and resolving any adverse 

40 effects to historic properties. In addition, TVA has procedures in place for the inadvertent 

41 discovery of cultural resources during project activities which include a description of the 

42 process for consulting with the Tennessee Historical Commission and Indian tribes 

43 (TVA 2013c). Also, TVA provides NEPA Overview and Categorical Exclusion training; 

44 100 percent of the TVA environmental personnel working at SQN have completed this training 

45 (TVA 2013c).

46 Based on the following factors and considerations, the NRC staff concludes that license renewal 

47 would cause no adverse effect on historic properties (36 CFR Part 800.4(d)(1)) for the following 

48 reasons:
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1 • there are currently no NRHP-eligible historic properties on the SQN site, 

2 • TVA will continue to protect the Igou Cemetery and Site 40HA22, 

3 • input has been received from tribes,

4 • TVA has continued to adhere to its cultural resources protection procedures,

5 • the NRC has received assurance that no license renewal-related physical 

6 changes or ground-disturbing activities will occur,

7 • the Tennessee Historical Commission has offered its input, and 

8 • the NRC has received findings from the cultural resource assessment and 

9 consultations.

10 4.9.2 No-Action Alternative – Historic and Cultural Resources

11 Not renewing the operating licenses and terminating reactor operations would have no effect on 

12 historic properties and cultural resources on or in the immediate vicinity of SQN. A separate 

13 environmental review would be conducted to determine the impacts of decommissioning 

14 activities on historic properties and cultural resources. Therefore, the impacts on historic and 

15 cultural resources from plant shutdown would be SMALL.

16 4.9.3 NGCC Alternative – Historic and Cultural Resources

17 Land areas affected by the construction and operation of an NGCC alternative would be 

18 surveyed to identify and record historic and cultural resources, including land required for a new 

19 gas pipeline, roads, transmission corridors, and other ROWs. Former industrial (brownfield)

20 sites would need to be surveyed to verify the level of previous disturbance and to evaluate the 

21 potential for cultural resources to be present. Any cultural resources found during these surveys 

22 would need to be recorded and evaluated for eligibility for listing on the National Register of 

23 Historic Properties (NRHP). Mitigation of adverse effects would be considered if eligible 

24 properties were encountered. Areas with the most significant cultural resources should be 

25 avoided. Visual impacts, such as historic property viewsheds near the proposed power plant 

26 site, should also be evaluated.

27 The potential impacts to historic properties and cultural resources would vary depending on the 

28 site selected for the proposed NGCC alternative. Assuming the NGCC alternative is located at 

29 an existing power plant site (other than SQN) or brownfield site in the region, TVA could further 

30 reduce the potential impacts to historic and cultural resources if effectively managed under 

31 current laws and regulations. However, historic and cultural resources could be affected by the 

32 construction of a new or upgraded gas pipeline. Therefore, the impacts to historic and cultural 

33 resources from the construction and operation of a NGCC alternative at an existing or 

34 brownfield site could range from SMALL to MODERATE assuming that existing gas pipelines 

35 are used or that existing gas pipelines are upgraded.

36 4.9.4 SCPC Alternative – Historic and Cultural Resources

37 Land areas affected by the construction of the SCPC alternative would need to be surveyed to 

38 identify and record historic and cultural resources—all potentially affected land areas, including 

39 land required for new roads, railroads, transmission corridors, and other right-of-ways (ROWs). 

40 Former industrial (brownfield) sites would need to be surveyed to verify the level of previous 

41 disturbance and to evaluate the potential for cultural resources to be present. Power plant 

42 developers would need to survey cultural resources. Any resources found would need to be 
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1 recorded and evaluated for eligibility for listing on the NRHP. Mitigation of adverse effects 

2 would need to be considered if eligible properties were encountered. Areas with the most 

3 significant cultural resources should be avoided. Visual impacts, such as historic property 

4 viewsheds near the proposed power plant site, should also be evaluated. 

5 The potential impacts to historic properties and cultural resources would vary depending on the 

6 site selected for the proposed SCPC alternative. The 500-ft (150-m) cooling towers could 

7 impact the viewshed of historic properties. However, selecting a previously disturbed former 

8 power plant or brownfield site in the TVA region could reduce the potential impacts to historic 

9 and cultural resources if effectively managed under current laws and regulations. Therefore, the 

10 impacts to historic and cultural resources from the construction and operation of a SCPC power 

11 plant would be SMALL.

12 4.9.5 New Nuclear Alternative – Historic and Cultural Resources

13 Land areas affected by the construction of the new nuclear alternative would need to be 

14 surveyed to identify and record historic and cultural resources—all potentially affected land 

15 areas, including land required for new roads, transmission corridors, other ROWs. Former plant 

16 sites would need to be surveyed to verify the level of previous disturbance and to evaluate the 

17 potential for cultural resources to be present. Any cultural resources found during these surveys 

18 would need to be recorded and evaluated for eligibility for listing on the NRHP. Mitigation of 

19 adverse effects would need to be considered if eligible properties were encountered. Areas with 

20 the most significant cultural resources should be avoided. Visual impacts, such as historic 

21 property viewsheds near the proposed power plant site, should also be evaluated.

22 The potential impacts to historic properties and cultural resources would vary depending on the 

23 site selected for the proposed new nuclear alternative. The 500-ft (150-m) cooling towers could 

24 impact the viewshed of historic properties. However, selecting an existing nuclear plant site 

25 (other than SQN) in the TVA Region could further reduce the potential impacts to historic and 

26 cultural resources if effectively managed under current laws and regulations. Therefore, the 

27 impacts to historic and cultural resources from the construction and operation of a new nuclear 

28 power plant would be SMALL.

29 4.9.6 Combination Alternative – Historic and Cultural Resources

30 Land areas would also need to be surveyed that could be potentially affected by the 

31 construction and operation of new wind or solar power generation to identify and record historic 

32 and cultural resources, including land required for new roads, transmission corridors, or other 

33 ROWs. Any historic properties found during these surveys would need to be recorded and 

34 evaluated for eligibility for listing on the NRHP. Mitigation of adverse effects would need to be 

35 considered if eligible properties were encountered. Areas with the most significant cultural 

36 resources should be avoided. Visual impacts, such as historic property viewsheds near the 

37 power generating sites, also should be evaluated.

38 The potential impacts on historic properties and cultural resources would vary, depending on the 

39 sites selected for the proposed power generating components of this combination alternative. 

40 Construction of wind farms and their support infrastructure could impact historic and cultural 

41 resources because of ground-disturbing activities (e.g., grading and digging). Land-based solar 

42 PV installations would require more land than rooftop installations and would have a greater 

43 potential impact on historic and cultural resources because of ground-disturbing activities. New 

44 solar PV installations on rooftops would minimize any land disturbances, thereby reducing 

45 impacts to historic and cultural resources. Aesthetic changes caused by the installation of new 

46 wind turbines and solar PV systems would have a noticeable effect on historic property 
Environmental Consequences and Mitigating Actions

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1 viewsheds. However, construction of additional wind turbines and solar PV systems within 

2 existing developed solar installations and wind farms could lessen visual impacts to historic 

3 properties. Therefore, the impacts to historic and cultural resources from the construction and 

4 operation of the wind and solar power generation components of this combination alternative 

5 could range from SMALL to LARGE.

6 4.10 Socioeconomics

7 This section describes the potential impacts of the proposed action (license renewal) and 

8 alternatives to the proposed action on socioeconomic resources.

9 4.10.1 Proposed Action

10 The socioeconomic issues applicable to SQN during the license renewal term are listed in 

11 Table 4–16. Section 3.10 describes the socioeconomic resources.

12 Table 4–16. Socioeconomic Issues 

Issues

GEIS

Section 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, to 10 CFR Part 51

13 Socioeconomic effects of ongoing reactor operations at SQN have become well-established as 

14 regional socioeconomic conditions have adjusted to the presence of the nuclear power plant. These 

15 conditions are described in Section 3.10. Any changes in employment and tax payments caused by 

16 license renewal and any associated refurbishment activities could have a direct and indirect impact on 

17 community services and housing demand, as well as traffic volumes in the communities around a 

18 nuclear power plant.

19 The supplemental site-specific socioeconomic impact analysis for the SQN license renewal, 

20 included a review of the TVA ER, scoping comments, other information records, and a data 

21 gathering site visit to SQN. The NRC staff did not identify any new and significant information 

22 during the review that would result in impacts that would exceed the predicted socioeconomic 

23 impacts evaluated in the GEIS, and no additional socioeconomic issues were identified beyond 

24 those listed in Table B–1 of Appendix B, Subpart A, to 10 CFR Part 51.

25 In addition, TVA indicated in their ER that they have no planned refurbishment activities, and do 

26 not plan to add non-outage workers during the license renewal term and that increased 

27 maintenance and inspection activities could be managed using the current workforce. 

28 Consequently, people living in the vicinity of SQN are not likely to experience any changes in 

29 socioeconomic conditions during the license renewal term beyond what is currently being 
Environmental Consequences and Mitigating Actions

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1 experienced. Therefore, the impact of continued reactor operations during the license renewal 

2 term would not exceed the socioeconomic impacts predicted in the GEIS. For these issues, the 

3 GEIS predicted that the impacts would be SMALL for all nuclear plants.

4 4.10.2 No-Action Alternative – Socioeconomics

5 4.10.2.1 Socioeconomic Issues Other than Transportation 

6 Not renewing the operating licenses and terminating reactor operations would have a noticeable 

7 impact on socioeconomic conditions in the communities located near SQN. The loss of jobs 

8 and income would have an immediate socioeconomic impact. Some, but not all, of the 

9 1,141 SQN employees would begin to leave after reactor operations are terminated; and overall 

10 tax revenue and purchasing activity generated by plant operations would be reduced. As 

11 explained in Chapter 3, TVA payments in lieu of taxes each year are based upon the gross 

12 revenues TVA receives from electricity sales from within the service area, regardless of where 

13 the power is generated (TVA 2013a). However, terminating reactor operations at SQN would 

14 reduce the percentage of power sales and book value of TVA property in Tennessee and, in 

15 turn, the amount of money allocated to the State’s counties and municipalities. Therefore, tax16 equivalent payments to the State of Tennessee would continue, but at a reduced amount. TVA 

17 will still be responsible for producing and distributing electricity (and tax-equivalent payments), 

18 even if the operating licenses for SQN are not renewed (TVA 2013a). The loss of tax revenue 

19 could reduce or eliminate some public and educational services. Indirect employment and 

20 income generated by plant operations would also be reduced.

21 Former SQN workers and their families could leave in search of employment elsewhere. The 

22 increase in available housing along with decreased demand could cause housing prices to fall. 

23 Since the majority of SQN employees reside in Hamilton and Rhea counties, socioeconomic 

24 impacts from the termination of reactor operations would be concentrated in these counties, with 

25 a corresponding reduction in purchasing activity and tax revenue in the regional economy. 

26 Income and revenue losses from the termination of reactor operations at SQN would directly 

27 affect Hamilton County and nearby communities most reliant on income from power plant 

28 operations. However, the reduction in jobs at SQN would most likely occur gradually as TVA

29 transitions from reactor operations to decommissioning. Socioeconomic impacts may not be 

30 noticeable in local communities, because this transition may occur over a long period of time. 

31 The socioeconomic impacts from the termination of nuclear plant operations (which may not 

32 entirely cease until after decommissioning) would, depending on the jurisdiction, range from 

33 SMALL to LARGE.

34 4.10.2.2 Transportation 

35 Traffic congestion caused by commuting workers and truck deliveries on roads in the vicinity of 

36 SQN would be reduced after power plant shutdown. Most of the reduction in traffic volume 

37 would be associated with the loss of jobs. The number of truck deliveries to SQN would be 

38 reduced until decommissioning. Traffic-related transportation impacts would be SMALL as a 

39 result of the shutdown of the nuclear power plant.

40 4.10.3 NGCC Alternative – Socioeconomics

41 4.10.3.1 Socioeconomic Issues Other than Transportation 

42 Socioeconomic impacts are defined in terms of changes to the demographic and economic 

43 characteristics and social conditions of a region. For example, the number of jobs created by 

44 the construction and operation of a power plant could affect regional employment, income, and 

45 expenditures.
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1 Two types of jobs would be created by this alternative: (1) construction jobs, which are 

2 transient, short in duration, and less likely to have a long-term socioeconomic impact and 

3 (2) power plant operations jobs, which have the greater potential for permanent, long-term 

4 socioeconomic impacts. Workforce requirements for the construction and operation of the 

5 NGCC alternative were evaluated to measure their possible effects on current socioeconomic 

6 conditions.

7 Scaling from GEIS estimates, the construction workforce would peak at 2,880 workers 

8 (TVA 2013a). The relative economic effect of this many workers on the local economy and tax 

9 base would vary with the greatest impacts occurring in the communities where the majority of 

10 construction workers would reside and spend their income. As a result, local communities could 

11 experience a short term economic “boom” from increased tax revenue and income generated by 

12 construction expenditures and the increased demand for temporary (rental) housing and public 

13 services as well as commercial services.

14 After construction, local communities could experience a return to pre-construction economic 

15 conditions. Based on this information and given the number of workers required for this 

16 alternative, socioeconomic impacts during construction in communities near the SQN site could 

17 range from MODERATE to LARGE.

18 The workforce during power plant operations likely would be 120 to 180 operations workers. 

19 Local communities would experience the economic benefits from increased tax revenue and 

20 income generated by operational expenditures and demand for housing and public services as 

21 well as commercial services. The amount of property tax payments under the NGCC alternative 

22 may also increase if additional land is required to support this alternative.

23 This alternative would also result in the loss of jobs at SQN and a corresponding reduction in 

24 purchasing activity and revenue contributions to the regional economy. However, the reduction 

25 in jobs at SQN would most likely occur gradually as TVA transitions from reactor operations to 

26 decommissioning. Socioeconomic impacts may not be noticeable in local communities, because 

27 this transition may occur over a long period of time. The socioeconomic impacts of terminating 

28 reactor operations are described in Section 4.10.2.1. Based on this information and given the 

29 number of operations workers required for this alternative, socioeconomic impacts during NGCC 

30 power plant operations on local communities could range from SMALL to MODERATE.

31 4.10.3.2 Transportation 

32 Transportation impacts associated with construction and operation of a six-unit, NGCC power 

33 plant would consist of commuting workers and truck deliveries of construction materials to the 

34 power plant site. During periods of peak construction activity, up to 2,880 workers could be 

35 commuting daily to the construction site. Workers commuting to the construction site would 

36 arrive via site access roads and the volume of traffic on nearby roads could increase 

37 substantially during shift changes. In addition to commuting workers, trucks would be 

38 transporting construction materials and equipment to the work site, thus increasing the amount 

39 of traffic on local roads. The increase in vehicular traffic would peak during shift changes, 

40 resulting in temporary levels of service impacts and delays at intersections. Pipeline 

41 construction and modification of existing natural gas pipeline systems could also have a 

42 temporary impact. Materials also could be delivered by barge or rail, depending on location of 

43 the NGCC alternative. Traffic-related transportation impacts during construction would likely 

44 range from MODERATE to LARGE.

45 Traffic-related transportation impacts would be greatly reduced after construction of the NGCC 

46 alternative. Transportation impacts would include daily commuting by the operating workforce, 

47 equipment and materials deliveries, and the removal of commercial waste material to offsite 
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1 disposal or recycling facilities by truck. The operations workforce of 120 to 180 likely would not 

2 be noticeable relative to total traffic volumes on local roadways. Since fuel is transported by 

3 pipeline, the transportation infrastructure would experience little to no increased traffic from 

4 plant operations. Overall, given the relatively small operations workforce of 120 to 180 workers, 

5 transportation impacts would be SMALL during power plant operations.

6 4.10.4 SCPC Alternative – Socioeconomics

7 4.10.4.1 Socioeconomic Issues Other than Transportation

8 As explained in Section 4.10.2.2, two types of jobs would be created by this alternative: 

9 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

10 socioeconomic impact and (2) power plant operations jobs, which have the greater potential for 

11 permanent, long-term socioeconomic impacts. Workforce requirements for the construction and 

12 operation of the SCPC alternative were evaluated to measure their possible effects on current 

13 socioeconomic conditions.

14 Scaling from GEIS estimates, the construction workforce would peak at 2,880 to 6,000 workers 

15 (TVA 2013a). The relative economic effect of this many workers on the local economy and tax 

16 base would vary with the greatest impacts occurring in the communities where the majority of 

17 construction workers would reside and spend their income. As a result, local communities could 

18 experience a short term economic “boom” from increased tax revenue and income generated by 

19 construction expenditures and the increased demand for temporary (rental) housing and public 

20 services as well as commercial services.

21 After construction, local communities could experience a return to pre-construction economic 

22 conditions. Based on this information and given the number of workers required for this 

23 alternative, socioeconomic impacts during construction in communities near the site could range 

24 from MODERATE to LARGE.

25 The workforce during power plant operations likely would range between 360 and 

26 480 operations workers. Local communities would experience the economic benefits from 

27 increased tax revenue and income generated by operational expenditures and demand for 

28 housing and public as well as commercial services. The amount of property tax payments 

29 under the SCPC alternative may also increase if additional land is required to support this 

30 alternative.

31 This alternative would also result in the loss of jobs at SQN and a corresponding reduction in 

32 purchasing activity and revenue contributions to the regional economy. However, the reduction 

33 in jobs at SQN would most likely occur gradually as TVA transitions from reactor operations to 

34 decommissioning. Socioeconomic impacts may not be noticeable in local communities, because 

35 this transition may occur over a long period of time. The socioeconomic impacts of terminating 

36 reactor operations are described in Section 4.10.2.1. Based on this information and given the 

37 number of operations workers, socioeconomic impacts during SCPC power plant operations on 

38 local communities could range from SMALL to MODERATE.

39 4.10.4.2 Transportation

40 Transportation impacts associated with construction and operation of an SCPC power plant 

41 would consist of commuting workers and truck deliveries of construction materials to the power 

42 plant site. During periods of peak construction activity, up to 2,880 to 6,000 workers could be 

43 commuting daily to the construction site. Workers commuting to the construction site would 

44 arrive via site access roads and the volume of traffic on nearby roads could increase 

45 substantially during shift changes. In addition to commuting workers, trucks would be 

46 transporting construction materials and equipment to the work site, thereby increasing the 
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1 amount of traffic on local roads. The increase in vehicular traffic would peak during shift 

2 changes, resulting in temporary levels of service impacts and delays at intersections. Materials 

3 could also be delivered by rail or barge, depending on location of the SCPC alternative. 

4 Traffic-related transportation impacts during construction would likely range from MODERATE 

5 to LARGE.

6 Traffic-related transportation impacts on local roads would be greatly reduced after the 

7 completion of the power plant. The estimated maximum number of operations workers 

8 commuting daily to the power plant site could be 480. Frequent coal and limestone deliveries 

9 and ash removal by rail would add to the overall transportation impact. The increase in traffic 

10 on roadways would peak during shift changes, resulting in temporary levels of service impacts 

11 and delays at intersections. Onsite coal storage would make it possible to receive several trains 

12 per day at a site with rail access. If the SCPC power plant is located on navigable waters, coal 

13 and other materials could be delivered by barge. Coal and limestone delivery and ash removal 

14 via rail would cause levels of service impacts because of delays at railroad crossings. Overall, 

15 transportation impacts would be SMALL to MODERATE during SCPC power plant operations.

16 4.10.5 New Nuclear Alternative – Socioeconomics

17 4.10.5.1 Socioeconomic Issues Other than Transportation

18 As explained in Section 4.10.2.2, two types of jobs would be created by this alternative: 

19 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

20 socioeconomic impact and (2) power plant operations jobs, which have the greater potential for 

21 permanent, long-term socioeconomic impacts. Workforce requirements for the construction and 

22 operation of a new nuclear power plant were evaluated to measure their possible effects on 

23 current socioeconomic conditions.

24 TVA estimated the construction workforce would peak at 5,000 workers (TVA 2013a). The 

25 relative economic effect of this many workers on the local economy and tax base would vary 

26 with the greatest impacts occurring in the communities where the majority of construction 

27 workers would reside and spend their income. As a result, local communities could experience 

28 a short term economic “boom” from increased tax revenue and income generated by 

29 construction expenditures and the increased demand for temporary (rental) housing and public 

30 as well as commercial services.

31 After construction, local communities could experience a return to pre-construction economic 

32 conditions. Based on this information and given the number of workers required for this 

33 alternative, socioeconomic impacts during construction in communities near the site could range 

34 from MODERATE to LARGE.

35 The workforce during power plant operations likely would range between 540 and 

36 720 operations workers. Some SQN operations workers likely would transfer to the new nuclear 

37 power plant. Local communities would experience the economic benefits from increased tax 

38 revenue and income generated by operational expenditures and demand for housing and public 

39 as well as commercial services. The amount of property tax payments under the new nuclear 

40 alternative may also increase if additional land is required to support this alternative.

41 This alternative would also result in the loss of jobs at SQN and a corresponding reduction in 

42 purchasing activity and revenue contributions to the regional economy. However, the reduction 

43 in jobs at SQN would most likely occur gradually as TVA transitions from reactor operations to 

44 decommissioning. Socioeconomic impacts may not be noticeable in local communities, because 

45 this transition may occur over a long period of time. The socioeconomic impacts of terminating 

46 reactor operations are described in Section 4.10.2.1. Based on this information and given the 
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1 number of operations workers required for this alternative, socioeconomic impacts during 

2 nuclear power plant operations on local communities could range from SMALL to MODERATE.

3 4.10.5.2 Transportation

4 Transportation impacts associated with construction and operation of a new nuclear power plant 

5 would consist of commuting workers and truck deliveries of construction materials to the power 

6 plant site. During periods of peak construction activity, up to 5,000 workers could be commuting 

7 daily to the construction site (TVA 2013a). Workers commuting to the construction site would 

8 arrive via site access roads and the volume of traffic on nearby roads could increase 

9 substantially during shift changes. In addition to commuting workers, trucks would be 

10 transporting construction materials and equipment to the work site, thereby increasing the 

11 amount of traffic on local roads. The increase in vehicular traffic would peak during shift 

12 changes, resulting in temporary levels of service impacts and delays at intersections. Materials 

13 could also be delivered by rail or barge, depending on the location. Traffic-related 

14 transportation impacts during construction would likely range from MODERATE to LARGE.

15 Traffic-related transportation impacts on local roads would be greatly reduced after the 

16 completion of the power plant. Transportation impacts would include daily commuting by the 

17 operating workforce, equipment and materials deliveries, and the removal of commercial waste 

18 material to offsite disposal or recycling facilities by truck. Traffic on roadways would peak during 

19 shift changes, resulting in temporary levels of service impacts and delays at intersections. 

20 Overall, at the new nuclear power plant site, transportation impacts would be SMALL to 

21 MODERATE during operations.

22 4.10.6 Combination Alternative – Socioeconomics

23 4.10.6.1 Socioeconomic Issues Other than Transportation 

24 As explained in Section 4.10.2.2, two types of jobs would be created by this alternative: 

25 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

26 socioeconomic impact and (2) operations jobs, which have the greater potential for permanent, 

27 long-term socioeconomic impacts. Workforce requirements for the construction and operation 

28 of wind and solar generation components of this combination alternative were evaluated to 

29 estimate their possible effects on current socioeconomic conditions.

30 Installation of 2,350-3,150 wind turbines would likely be done in stages and could employ up to 

31 200 construction workers. Additional workers would be required to install solar photovoltaic 

32 systems on existing buildings or structures at already-developed residential, commercial, or 

33 industrial sites. Similar to the wind farms, installation would likely be done in stages and could 

34 also employ up to 200 construction workers.

35 Conversely, a relatively small number of operations workers (about 50) would be needed to 

36 maintain the wind farm while a similar amount of operations workers (about 50) would be 

37 needed to maintain the photovoltaic systems. Local communities would experience the 

38 economic benefits from increased tax revenue and income generated by operational 

39 expenditures and demand for housing and public as well as commercial services. The amount 

40 of property tax payments under the wind and solar photovoltaic components may also increase 

41 if additional land is required to support this combination alternative. 

42 This combination alternative would also result in the loss of jobs at SQN and a corresponding 

43 reduction in purchasing activity, tax payments, and revenue contributions would occur in the 

44 surrounding regional economy. However, the reduction in jobs at SQN would most likely occur 

45 gradually as TVA transitions from reactor operations to decommissioning. Socioeconomic 

46 impacts may not be noticeable in local communities, because this transition may occur over a 
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1 long period of time. The socioeconomic impacts of terminating reactor operations are described 

2 in Section 4.10.2.1. Based on this information and given the small numbers of construction and 

3 operations workers required for this alternative, socioeconomic impacts during construction and 

4 operations on local communities would be SMALL.

5 4.10.6.2 Transportation 

6 Transportation impacts during the construction and operation of the wind and solar components 

7 of this combination alternative would be less than the impacts for any of the previous 

8 alternatives discussed. This is because the construction workforce for each component and the 

9 volume of materials and equipment needing to be transported to the respective construction site 

10 would be smaller than for the individual alternative. In other words, the transportation impacts 

11 would not be concentrated as in the other alternatives, but spread out over a wider area.

12 Workers commuting to the construction site would arrive via site access roads and the volume 

13 of traffic on nearby roads could increase during shift changes. In addition to commuting 

14 workers, trucks would be transporting construction materials and equipment to the work site, 

15 thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would 

16 peak during shift changes, resulting in temporary levels of service impacts and delays at 

17 intersections. Transporting heavy and oversized components on local roads could have a 

18 noticeable impact over a large area. Some components and materials could also be delivered 

19 by rail or barge, depending on location. Traffic-related transportation impacts during 

20 construction could range from SMALL to MODERATE at the wind farms and solar installations; 

21 depending on current road capacities and average daily traffic volumes.

22 During operations, transportation impacts would be less noticeable during shift changes and 

23 maintenance activities. Given the small numbers of operations workers, the levels of service 

24 traffic impacts on local roads from wind farm and solar photovoltaic operations would be 

25 SMALL.

26 4.11 Human Health

27 This section describes the potential impacts of the proposed action (license renewal) and 

28 alternatives to the proposed action on human health resources. 

29 4.11.1 Proposed Action 

30 The human health resource issues applicable to SQN during the license renewal term are listed 

31 in Table 4–17. Section 3.11 describes the human health resources.
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1 Table 4–17. Human Health Issues

Issues 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 4.9.1.1.3 2

Microbiological hazards to plant workers 4.9.1.1.3 1 

Chronic effects of electromagnetic fields (EMFs) 4.9.1.1.4 (a) N/A

Physical occupational hazards 4.9.1.1.5 1 

Electric shock hazards 4.9.1.1.5 2

(a) 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

2 4.11.1.1 Normal Operating Conditions

3 Generic Human Health Issues (Category 1)

4 The NRC staff did not identify any new and significant information during its review of TVA’s ER,

5 the site audit, or the scoping process for the Category 1 issues listed in Table 4–17. Therefore, 

6 there are no impacts related to these issues beyond those discussed in the GEIS. For these 

7 Category 1 issues, the GEIS concluded that the impacts are SMALL.

8 Chronic Effects of Electromagnetic Fields

9 In the GEIS, the chronic effects of 60-Hz electromagnetic fields (EMFs) from power lines were 

10 not designated as Category 1 or 2, and will not be until a scientific consensus is reached on the 

11 health implications of these fields.

12 The potential for chronic effects from these fields continues to be studied and is not known at 

13 this time. The National Institute of Environmental Health Sciences (NIEHS) directs related 

14 research through the U.S. Department of Energy (DOE).

15 The report by NIEHS (NIEHS 1999) contains the following conclusion:

16 The NIEHS concludes that ELF-EMF (extremely low frequency-electromagnetic 

17 field) exposure cannot be recognized as entirely safe because of weak scientific 

18 evidence that exposure may pose a leukemia hazard. In our opinion, this finding 

19 is insufficient to warrant aggressive regulatory concern. However, because 

20 virtually everyone in the United States uses electricity and therefore is routinely 

21 exposed to ELF-EMF, passive regulatory action is warranted such as continued 

22 emphasis on educating both the public and the regulated community on means 

23 aimed at reducing exposures. The NIEHS does not believe that other cancers or 

24 non-cancer health outcomes provide sufficient evidence of a risk to currently 

25 warrant concern.

26 This statement is not sufficient to cause the NRC staff to change its position with respect to the 

27 chronic effects of EMFs. The NRC staff considers the GEIS finding of “UNCERTAIN” still 

28 appropriate and will continue to follow developments on this issue.
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1 Site-Specific Human Health Issues (Category 2)

2 Microbiological Hazards to the Public 

3 The 2013 GEIS (NRC 2013e) categorizes microbiological hazard to the public as a site-specific 

4 (Category 2) issue that requires an assessment of potential health effects to the public from 

5 microorganisms associated with nuclear power plants with cooling ponds, lakes, canals, or 

6 discharge into rivers. During the license renewal term, members of the public might be exposed 

7 to microbiological hazards just as they might be during operation during the original license 

term. 8 

9 Microbiological hazards to the public are discussed in Section 3.11.3. Potential public exposure 

10 to thermophilic microorganisms from cooling tower or thermal discharge to Chickamauga 

11 Reservoir is limited at SQN. SQN maintains an NPDES permit administered by the State of 

12 Tennessee that limits thermal discharge to a 24-hour downstream temperature of no greater 

13 than 86.9 °F (30.5 °C) during summer months. When the ambient temperature is greater than 

14 84.9 °F (29.4 °C), this restriction can be exceeded, but the permit states that SQN may not have 

15 an hourly average downstream temperature greater than 93.0 °F (33.9 °C) (TVA 2013g). These 

16 temperatures are below the stated optimal growing temperature of approximately 95 °F (35 °C) 

17 for Legionella spp. and 98.6 °F (37 °C) for Pseudomonas aeruginosa. Naegleria fowleri is rarely 

18 found in water temperatures below 95 °F (35 °C). In addition, thermal effluent from SQN is 

19 discharged to Chickamauga Reservoir through two diffuser pipes and mixed with ambient water, 

20 preventing the stagnant water habitat needed for optimal growth of these microorganisms 

21 (TVA 2013g). Further, public boating access to Chickamauga Reservoir is located downstream 

22 and opposite of SQN, and public swimming access occurs more than 3 mi (5 km) downstream 

23 from SQN (NRC 2013e; TVA 2013g).

24 The NRC staff concludes that Chickamauga Reservoir water conditions and SQN operation are 

25 not likely to encourage the growth of the microbiological organisms of concern and present an 

26 exposure hazard to the public. The NRC staff concludes that impacts on public health from 

27 thermophilic microbiological organisms from continued operation of SQN in the license renewal 

28 period would be SMALL.

29 Electric Shock Hazards

30 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

31 energized conductors or from induced charges in metallic structures has not been found to be a 

32 problem at most operating plants and generally is not expected to be a problem during the 

33 license renewal term. However, a site-specific review is required to determine the significance 

34 of the electric shock potential along the portions of the transmission lines that are within the 

35 scope of this SEIS.

36 As discussed in Section 3.11.4, TVA performed an evaluation of its transmission lines to 

37 determine whether the lines conform to the National Electrical Safety Code (NESC) criteria for 

38 induced electric shock. The TVA evaluation concluded that nine spans of its transmission lines 

39 exceeded the NESC criteria.

40 In accordance with 10 CFR Part 51.53(c)(3)(iii), TVA has provided information on actions it is 

41 considering to reduce the potential impacts from those transmission lines that exceed the NESC 

42 standard. TVA has a 500-kV transmission line uprate program with defined projects in the 

43 planning and design stage which will correct the deficiencies. These projects are all scheduled 

44 for completion by June 2017, before the end of SQN’s current operating license (TVA 2013g).

45 Based on TVA’s stated plans to correct the deficiencies with the affected transmission line 

46 spans to achieve conformance with the NESC criteria during its current license term and its 
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1 expected conformance with the standard during the license renewal term, the NRC staff 

2 concludes that the potential impacts from acute electric shock during the license renewal term 

3 would be SMALL.

4 4.11.1.2 Environmental Impacts of Postulated Accidents

5 This section describes environmental impacts from postulated accidents that might occur during 

6 the period of extended operation at SQN. The term “accident” refers to any unintentional event 

7 outside the normal plant operational envelope that results in a release or the potential for 

8 release of radioactive materials into the environment. Two classes of postulated accidents are 

9 evaluated in the GEIS. These are DBAs and severe accidents. 

10 Design-Basis Accidents

11 To receive U.S. Nuclear Regulatory Commission (NRC) approval to operate a nuclear power 

12 facility, an applicant for an initial operating license must submit a safety analysis report (SAR) as 

13 part of its application. The SAR presents the design criteria and design information for the 

14 proposed reactor and comprehensive data on the proposed site. The SAR also discusses 

15 various hypothetical accident situations and the safety features that are provided to prevent and 

16 mitigate accidents. The NRC staff reviews the application to determine whether the plant 

17 design meets the Commission’s regulations and requirements and includes, in part, the nuclear 

18 plant design and its anticipated response to an accident.

19 Design-basis accidents are those accidents that both the licensee and NRC staff evaluate to 

20 ensure that the plant can withstand normal and abnormal transients, and a broad spectrum of 

21 postulated accidents, without undue hazard to the health and safety of the public. A number of 

22 these postulated accidents are not expected to occur during the life of the plant, but are 

23 evaluated to establish the design basis for the preventive and mitigative safety systems of the 

24 facility. The acceptance criteria for DBAs are described in 10 CFR Part 50 and 10 CFR 

25 Part 100. 

26 The environmental impacts of DBAs are evaluated during the initial licensing process, and the 

27 ability of the plant to withstand these accidents is demonstrated to be acceptable before 

28 issuance of the operating license. The results of these evaluations are found in licensee 

29 documentation such as the applicant’s final safety analysis report, the safety evaluation report, 

30 the final environmental statement (FES), and this section of the supplemental environmental 

31 impact statement (SEIS). A licensee is required to maintain the acceptable design and 

32 performance criteria throughout the life of the plant, including any extended-life operation. The 

33 consequences for these events are evaluated for the hypothetical maximum exposed individual; 

34 as such, changes in the plant environment will not affect these evaluations. Because licensees 

35 are required to assess operational consequences and maintain aging management programs 

36 for the period of extended operation, the environmental impacts as calculated for DBAs should 

37 not differ significantly from initial licensing assessments over the life of the plant, including the 

38 period of extended operation. Accordingly, the design of the plant relative to DBAs during the 

39 period of extended operation is considered to remain acceptable and the environmental impacts 

40 of those accidents were not examined further in the GEIS. 

41 Based on information in the GEIS, the Commission found that: 

42 The environmental impacts of design-basis accidents are SMALL for all nuclear 

43 plants. Due to the requirements for nuclear plants to maintain their licensing 

44 basis and implement aging management programs during the license renewal 

45 term, the environmental impacts during a license renewal term should not differ 

46 significantly from those calculated for the design-basis accident assessments 

47 conducted as part of the initial plant licensing process.
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1 For the purposes of license renewal, DBAs are designated as a Category 1 issue (Table 4–18). 

2 The early resolution of the DBAs makes them a part of the current licensing basis (CLB) of the 

3 plant; the CLB of the plant is to be maintained by the licensee under its current license and, 

4 therefore, under the provisions of 10 CFR Part 54.30, is not subject to review under license 

5 renewal. 

6 Table 4–18. Issues Related to Postulated Accident

Issue GEIS

Section Category

Design-basis accidents 4.8.1.2 1

Severe accidents 4.8.1.2 2

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

7 Severe Accidents

8 Severe nuclear accidents are those that are more severe than DBAs because they could result

9 in substantial damage to the reactor core, whether or not there are serious offsite 

10 consequences. In the GEIS, the staff assessed the impacts of severe accidents during the 

11 license renewal period, using the results of existing analyses and site-specific information to 

12 conservatively predict the environmental impacts of severe accidents for each plant during the 

13 renewal period.

14 Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, 

15 fires, and sabotage have not traditionally been discussed in quantitative terms in FESs and 

16 were not specifically considered for SQN in the GEIS (NRC 2013e). In Section 1.7.6 of the 

17 GEIS (NRC 2013), NRC states that neither decisions nor recommendations will be made in the 

18 GEIS regarding earthquakes (seismicity) or flooding at nuclear power plants. Described in 

19 Section 1.7.4 of the GEIS, the risk from intruders (which includes terrorist-related activities) 

20 against nuclear power plants is not unique to facilities requesting license renewal. As discussed 

21 in the Statements of Consideration for the 10 CFR Part 54 rulemaking, the Commission has 

22 determined that there is no need for a special review of security issues in the context of an 

23 environmental review for license renewal. The NRC routinely assesses threats and other 

24 information provided by other Federal agencies and sources. The NRC also ensures that 

25 licensees meet their security requirements through its ongoing regulatory process (routine 

26 inspections) as a current and generic regulatory issue that affects all nuclear power plants. 

27 Based on information in the GEIS, the Commission found that: 

28 The probability-weighted consequences of atmospheric releases, fallout onto 

29 open bodies of water, releases to groundwater, and societal and economic 

30 impacts from severe accidents are small for all plants. However, alternatives to 

31 mitigate severe accidents must be considered for all plants that have not 

32 considered such alternatives.

33 As described in the Design Basis Events section, information related to external flooding does 

34 not affect the impacts discussed in the GEIS. The NRC’s assessment of flood hazards for 

35 existing nuclear power plants is a separate and distinct process from license renewal reviews. 

36 As indicated in the GEIS (NRC 2013e), seismic and flood hazard issues are addressed by the 

37 NRC on an ongoing basis at all licensed nuclear facilities. However, in accordance with 

38 10 CFR Part 51.53(c)(3)(ii)(L), the NRC staff has reviewed severe accident mitigation 
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1 alternatives (SAMAs) analysis provided by TVA for SQN. The results of the review are 

2 discussed in the Severe Accident Mitigation Alternatives section below.

3 Severe Accident Mitigation Alternatives

4 If the NRC staff has not previously evaluated SAMAs for the applicant’s plant in an 

5 environmental impact statement (EIS) or related supplement or in an environmental 

6 assessment, 10 CFR Part 51.53(c)(3)(ii)(L) requires a consideration of alternatives to mitigate 

7 severe accidents. SAMAs have not been previously considered for SQN; therefore, the 

8 remainder of Section 4.11.1.2 addresses SAMAs. The purpose of this consideration of SAMAs 

9 is to ensure that plant changes (i.e., hardware, procedures, and training) with the potential for 

10 improving severe accident safety performance are identified and evaluated. Pursuant to 

11 10 CFR Part 54, the only changes that must be implemented by the applicant as part of the

12 license renewal process are those that are identified as being cost beneficial, that provide a 

13 significant reduction in total risk, and that are related to adequately managing the effects of aging

14 during the period of extended operation.

15 Overview of SAMA Process

16 This section presents a summary of the SAMA evaluation for SQN as described in the 

17 TVA’s ER (TVA 2013a), additional requested information (TVA 2013c), and the review of those 

18 evaluations. The entire evaluation is presented in Appendix F. The NRC staff performed its 

19 review with contract assistance from the Center for Nuclear Waste Regulatory Analyses. The 

20 NRC staff review is available in full in Appendix F; the complete SAMA evaluation is available in 

21 Attachment E of TVA’s ER.

22 The SAMA evaluation for SQN was conducted with a four-step approach. In the first step, TVA

23 quantified the level of risk associated with potential reactor accidents using the plant-specific 

24 probabilistic risk assessment (PRA) and other risk models. In the second step, TVA examined 

25 the major risk contributors and identified possible ways (SAMAs) of reducing that risk. Common 

26 ways of reducing risk are changes to components, systems, procedures, and training. In the 

27 third step, TVA estimated the benefits and the costs associated with each of the candidate 

28 SAMAs. Estimates were made of how much each SAMA could reduce risk. Those estimates 

29 were developed in terms of dollars in accordance with NRC guidance for performing regulatory 

30 analyses. The costs of implementing the candidate SAMAs were also estimated. In the fourth 

31 step, TVA compared the cost and benefit of each of the remaining SAMAs to determine whether 

32 each SAMA was cost beneficial, meaning the benefits of the SAMA exceeded its cost.

33 Estimate of Risk

34 TVA submitted an assessment of SAMAs for SQN as part of the ER (TVA 2013d). The 

35 assessment was based on the most recent revision to the PRA for each unit, including an 

36 internal events model and a plant-specific offsite consequence analysis performed using the 

37 WinMACCS Version 3.6.0 computer code, and insights from the SQN individual plant 

38 examination (IPE) submittals (TVA 1992, 1998) and individual plant examination of external 

39 events (IPEEE) submittals (TVA 1995, 1999).

40 TVA’s determination of offsite risk at SQN is based on the following three major analysis 

41 elements: (1) essentially new Level 1 and 2 risk models that replace the original 1992 and 

42 revised 1998 IPE submittals (TVA 1992, 1998), (2) analyses of the 1995 and 1999 IPEEE 

43 submittals (TVA 1995, 1999), and (3) the combination of offsite consequence measures from 

44 WinMACCS analyses with release frequencies and radionuclide source terms from the Level 2 

45 PRA model.
Environmental Consequences and Mitigating Actions

4-66

The SQN Unit 1 core damage frequency (CDF) is approximately 3.0×10−5 1 per reactor-year while 

the Unit 2 CDF is approximately 3.5×10−5 2 per reactor-year. These values were used as the 

3 baseline CDF in the SAMA evaluations (TVA 2013d). The CDF is based on the risk 

4 assessment for internally initiated events, which includes internal flooding. TVA did not explicitly 

5 include the contribution from external events within the SQN risk estimates; however, it did 

6 account for the potential risk reduction benefits for individual SAMAs associated with external 

7 events by multiplying the estimated benefits for internal events by a factor of 2.9 for Unit 1 and 

8 2.6 for Unit 2. This is discussed further in Appendix F, Sections F.2.2 and F.6.2. Using the 

9 calculated risk reduction as a quantitative measure of the potential benefit from SAMA 

10 implementation, TVA performed a cost-benefit comparison, as described in the Cost-Benefit 

11 Comparison section.

12 The breakdown of CDF by initiating event is provided in Table 4–19. As shown in this table, 

13 Internal Flooding, Loss of All Component Cooling Water and Stuck Open Safety/Relief Valve 

14 are the dominant contributors to the CDF in both units. Station blackout (SBO) and anticipated 

15 transients without scram (ATWS) are not listed in Table 4–19 because multiple initiators 

16 contribute to their occurrence. Station blackout contributes about 13 percent and 10 percent to 

the occurrence of severe accidents for Units 1 and 2, respectively (3.9×10−6 17 per reactor-year 

and 3.6×10−6 18 per reactor-year) of the total CDF while ATWS contribute about 14 percent and 

12 percent for Units 1 and 2, respectively, (4.1×10−6 19 per reactor-year for each unit) to the total 

20 CDF. In a subsequent correction to the ATWS model, TVA indicated that ATWS contributes 

21 about 2 percent and 2.3 percent to the total CDF for Units 1 and 2, respectively (TVA 2013c).

22 The Level 2 SQN PRA model that forms the basis for the SAMA evaluation is essentially a new 

23 model for SQN. The Level 2 model was developed with a focus on the quantification of Large 

24 Early Release Frequency (LERF) but does include the development of other end states. The 

25 Level 2 model utilizes containment event trees (CETs) containing both phenomenological and 

26 systemic events. The core damage sequences from the Level 1 PRA are binned into plant 

27 damage states based on similar characteristics that influence the accident progression following 

28 core damage. These bins provide the interface between the Level 1 and Level 2 CET analyses. 

29 The CETs are linked directly to the Level 1 event trees and CET nodes based on the plant 

30 damage states.

31 The CET considers the influence of physical and chemical processes on the integrity of the 

32 containment and on the release of fission products once core damage has occurred. Each CET 

33 sequence was assigned to one of seven end state categories. Four of these categories 

34 represent LERF with the remaining representing late and small early releases and an intact 

35 containment. These end states were subsequently grouped into 12 release categories (or 

36 release modes) that provide the input to the Level 3 consequence analysis. The frequency of 

37 each release category was obtained by summing the frequency of the individual accident

38 progression CET endpoints binned into the release category. The determination of the 

39 characteristics for each release category was based on representative accident scenarios that 

40 reflect the core damage and containment behavior for the dominant sequence or sequences 

41 within a plant damage state and the dominant Level 2 sequence within the release category. 

42 The source terms for the representative scenarios were based on a SEQSOR emulation 

43 spreadsheet methodology. The results of this analysis for SQN are provided in Table E.1-15 of 

44 ER Attachment E (TVA 2013d).
Environmental Consequences and Mitigating Actions

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1 Table 4–19. SQN Units 1 and 2 CDF for Internal Events

Initiating Event

Unit 1 CDF

(per year)

Unit 1

Percent CDF

Contribution1

Unit 2 CDF

(per year)

Unit 2

Percent CDF

Contribution1

Internal Flooding 1.7×10−5 56 2.3×10−5 66

Loss of All Component Cooling Water 3.6×10−6 12 3.2×10−6 9

Stuck Open Safety/Relief Valve 2.3×10−6 8 2.5×10−6 7

Secondary Side Break Outside of Containment 1.3×10−6 4 1.4×10−6 4

Losses of Main Feedwater 9.3×10−7 3 6.9×10−7 2

Reactor Trip 9.2×10−7 3 9.1×10−7 3

Loss of Train A Component Cooling Water 2 9.0×10−7 3 7.6×10−7 2

Loss of Instrument Boards 7.4×10−7 2 5.7×10−7 2

Other Initiating Events 3 6.8×10−7 2 5.6×10−7 2

Loss of Offsite Power 6.5×10−7 2 3.9×10−7 1

Turbine Trip 5.1×10−7 2 5.1×10−7 1

Small Loss of Coolant Accident 3.9×10−7 1 4.5×10−7 1

Total CDF (Internal Events) 3.0×10−5 100 3.5×10−5 100

1 Percentages were rounded to the nearest whole percent for reporting and may not sum to 100 percent because of round off error. 2 Train A is listed as Train 1A for Unit 1 and Train 2A for Unit 2. 3 Multiple initiating events with each contributing less than 1 percent.
Environmental Consequences and Mitigating Actions

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1 TVA computed offsite consequences for potential releases of radiological material using the 

2 WinMACCS Version 3.6.0 code and analyzed exposure and economic impacts from its 

3 determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 

4 site-specific input values for core radionuclide inventory, source term and release 

5 characteristics, site meteorological data, projected population distribution and growth within a 

6 50-mile radius, emergency response evacuation modeling, and economic data. Because of the 

7 similarity of the reactor cores at Watts Bar Unit 1, SQN Unit 1, and SQN Unit 2, the radionuclide 

8 inventory for the SQN SAMA analysis is based on the core inventory for Watts Bar Unit 1 

9 multiplied by the power ratio of the SQN Unit 1 power of 1,148 MWe to the Watts Bar Unit 1 

10 power of 1,123 MWe (TVA 2013d, Attachment E). Although the SQN Unit 2 power was slightly 

11 lower at 1,126 MWe, the same core inventory for SQN Unit 1 was conservatively used for the 

12 SQN Unit 2 consequence analysis. The estimation of onsite impacts (in terms of cleanup and 

13 decontamination costs and occupational dose) is based on guidance in NUREG/BR–0184 

14 (NRC 1997).

15 In the ER, the applicant estimated the dose risk to the population within 80 km (50 mi) of the 

16 SQN site to be 0.450 person-sievert (Sv) per year (45.0 person-rem per year) for Unit 1 and 

17 0.439 person-Sv per year (43.9 person-rem per year) for Unit 2 (TVA 2013a, Tables E.1-20 and 

18 E.1-21). The breakdown of the population dose risk by containment release mode is 

19 summarized in Table 4–20. Late containment failure releases and large early releases caused 

20 by containment isolation failures accounted for approximately 79 and 75 percent of the 

21 population dose risk at Units 1 and 2, respectively. Late containment failure releases alone 

22 contributed approximately 47 and 45 percent of the population dose risk at Units 1 and 2. Late 

23 containment failure releases and large early releases caused by containment isolation failures 

24 accounted for approximately 85 and 83 percent of the offsite economic cost risk at Units 1 and 

25 2, respectively. Late containment failure releases alone contributed approximately 58 and 56 

26 percent of the offsite economic cost risk at Units 1 and 2.

27 The NRC staff has reviewed TVA’s data and evaluation methods and concludes that the quality 

28 of the risk analyses is adequate to support an assessment of the risk reduction potential for 

29 candidate SAMAs. Accordingly, the staff based its assessment of offsite risk on the CDFs and 

30 offsite doses reported by TVA.
4-69

Environmental Consequences and Mitigating Actions

1 Table 4–20. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk for Internal Events

Release Mode Population Dose Risk 1 Offsite Economic Cost Risk

ID 2 Frequency (per year) Person-rem/yr Percent 

Contribution3 $/yr Percent Contribution3

Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2

Ia 4.1×10−8 4.6×10−8 1.2×10−1 1.3×10−1 <1 <1 2.3×10+2 2.6×10+2 <1 <1

Ib 9.7×10−7 9.5×10−7 2.5×10+0 2.5×10+0 6 6 5.2×10+3 5.1×10+3 5 5

Ic 2.7×10−7 3.9×10−7 7.0×10−1 1.0×10+0 2 2 1.4×10+3 2.1×10+3 1 2

IIa 3.3×10−6 3.3×10−6 1.2×10+1 1.2×10+1 26 27 2.2×10+4 2.2×10+4 23 24

IIb 6.3×10−7 3.3×10−7 2.2×10+0 1.1×10+0 5 3 4.2×10+3 2.2×10+3 4 2

IIc 6.5×10−8 6.3×10−8 1.3×10−1 1.2×10−1 <1 <1 2.9×10+2 2.8×10+2 <1 <1

IId 4.8×10−8 6.8×10−8 1.1×10−1 1.5×10−1 <1 <1 2.4×10+2 3.4×10+2 <1 <1

III 6.4×10−7 7.4×10−7 5.9×10+0 6.7×10+0 13 15 7.0×10+3 8.1×10+3 7 9

IVa 1.8×10−5 1.7×10−5 1.9×10+1 1.9×10+1 42 43 5.0×10+4 4.9×10+4 52 53

IVb 2.2×10−6 1.2×10−6 2.2×10+0 1.2×10+0 5 3 5.7×10+3 3.2×10+3 6 3

Va 2.1×10−6 2.0×10−6 2.8×10−1 2.7×10−1 1 1 2.6×10+2 2.5×10+2 <1 <1

Vb 1.1×10−6 1.9×10−6 1.5×10−1 2.5×10−1 <1 1 1.3×10+2 2.3×10+2 <1 <1

Totals 4.5×10+1 4.4×10+1 100 100 9.7×10+4 9.3×10+4 100 100

1 Unit Conversion Factor: 1 Sv = 100 rem 2 Release Category Descriptions

I – Large early releases with containment failures

II – Large early releases with containment isolation failures

III – Large early releases with containment bypass

IV – Late containment failure release

V – Small early release with some mitigation 3 Percentages are rounded to the nearest whole percent for reporting and may not sum to 100 percent because of roundoff error.
Environmental Consequences and Mitigating Actions

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1 Potential Plant Improvements

2 The TVA’s process for identifying potential plant improvements (SAMAs) consisted of the 

3 following elements: 

4  review of industry documents including NEI 05-01 (NEI 2005) and 12 other 

5 plant SAMA analyses for potential cost-beneficial SAMA candidates,

6  review of potential plant improvements identified in the SQN IPE and IPEEE, 

7 and

8  review of the risk significant events in the current SQN PRA Levels 1 and 2 

9 models for modifications to include in the comprehensive list of SAMA

10 candidates.

11 Based on this process, an initial set of 309 candidate SAMAs, referred to as Phase I SAMAs, 

12 were identified. In Phase I of the evaluation, TVA performed a qualitative screening of the initial 

13 list of SAMAs and eliminated SAMAs from further consideration using the following criteria:

14  The SAMA is not applicable to SQN.

15  The SAMA has already been implemented at SQN.

16  The SAMA is similar in nature and could be combined with another SAMA 

17 candidate.

18  The SAMA has an estimated implementation cost in excess of the Modified 

19 Maximum Averted Cost Risk (MMACR).

20  The SAMA is related to non-risk significant systems.

21  A plant improvement that addresses the intent of the SAMA is already in 

22 progress.

23 Based on this screening, a total of 262 SAMAs were eliminated leaving 47 for further evaluation. 

24 The remaining SAMAs, referred to as Phase II SAMAs, are listed in Tables E.2-1 and E.2-2 of 

25 Attachment E to the ER (TVA 2013a). In Phase II, a detailed evaluation was performed for each 

26 of the 47 remaining SAMA candidates.

27 The NRC staff concludes that TVA used a systematic and comprehensive process for 

28 identifying potential plant improvements for SQN, and that the set of SAMAs evaluated in the 

29 ER, together with those evaluated in response to NRC staff inquiries, is reasonably 

30 comprehensive and, therefore, acceptable. The NRC staff evaluation included reviewing 

31 insights from the SQN plant-specific risk studies that included internal initiating events as well as 

32 fire, seismic, and other external initiated events, and reviewing plant improvements considered 

33 in previous SAMA analyses.

34 Evaluation of Risk Reduction and Costs of Improvements

35 In the ER, the applicant evaluated the risk-reduction potential of the 47 SAMAs that were not 

36 screened out in the Phase I analysis and retained for the Phase II evaluation. The SAMA

37 evaluations were performed using generally conservative assumptions.

38 Except for one SAMA associated with internal fires, TVA used model requantification to 

39 determine the potential benefits for each SAMA. The CDF, population dose, and offsite 

40 economic cost reductions were estimated using the SQN SAMA PRA model for the SAMAs not 

41 associated with fire events. The changes made to the model to quantify the impact of SAMAs 

42 are detailed in Section E.2.3 of Attachment E to the ER (TVA 2013a). Bounding evaluations 

43 were performed to address specific SAMA candidates or groups of similar SAMA candidates. 
Environmental Consequences and Mitigating Actions

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1 For the fire related SAMA 287, the benefit was determined by assuming the conditional core 

2 damage probability and the associated CDF for the four fire compartments involved was 

3 reduced by a factor of 10. The evaluation assumed that all release category frequencies were 

4 reduced by the same percentage as CDF. The reduced CDF and release category frequencies 

5 were then used to determine the reduction in population dose and offsite economic cost in a 

6 manner similar to all other SAMAs (TVA 2013c). The NRC staff notes that the above, as 

7 applied by TVA, included increasing the benefit by the external event multiplier which is a 

8 significant conservatism because the SAMAs would only impact the fire CDF.

9 For the SAMAs determined to be potentially cost beneficial, Table 4–22 lists the assumptions 

10 made to estimate the risk reduction for each of the evaluated SAMAs, the estimated risk 

11 reduction in terms of percent reduction in CDF, population dose risk and offsite economic cost 

12 risk, and the estimated total benefit (present value) of the averted risk. The estimated benefits 

13 reported in Table 4–22 reflect the combined benefit in both internal and external events. The 

14 determination of the benefits for the various SAMAs is further discussed in Appendix F, 

15 Section F.6.

16 TVA estimated the costs of implementing the 47 Phase II SAMAs through the use of other 

17 licensees’ estimates for similar improvements and the development of site-specific cost 

18 estimates where appropriate.

19 In Table 4–21 below, TVA indicated the following cost ranges were utilized based on the review 

20 of previous SAMA applications and an evaluation of expected implementation costs at SQN.

21 Table 4–21. Estimated Cost Ranges of SAMA Implementation Costs at SQN

Type of Change Estimated Cost Range

Procedural only $50K

Procedural change with engineering or training required $50K to $200K

Procedural change with engineering and testing or 

training required

$200K to $300K

Hardware modification $100K to >$1,000K

22 TVA stated that the SQN site-specific cost estimates were based on the engineering judgment 

23 of project engineers experienced in performing design changes at the facility and were 

24 compared, where possible, to estimates developed and used at plants of similar design and 

25 vintage.

26 In response to an NRC staff RAI to provide further information as to what was included in the 

27 SQN cost estimates, TVA indicated that the cost estimates were done in 2012 dollars and 

28 included contingency costs and capital overhead. Cost estimates from past projects were used 

29 when applicable. For cost estimates that were not based directly on past projects, itemized cost 

30 estimates were developed where applicable and appropriate. Specific hardware costs from 

31 recent projects such as piping, valves, electrical cable, and switchgear were used when 

32 applicable. Engineering estimates were based on typical man-hours costs for design changes. 

33 Training costs were developed based on the man-hours needed to prepare operator training 

34 materials. Cost input was received from the electrical, mechanical, and civil disciplines as 

35 required. The cost estimates were reviewed by the project manager and/or the discipline 

36 engineering managers when warranted. Replacement power, lifetime maintenance, escalation 

37 and inflation were not considered in the estimate (TVA 2013c).
Environmental Consequences and Mitigating Actions

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1 Table 4–22. Potentially Cost-Beneficial SAMAs for Units 1 and 2 of the SQN

2 Percentage Risk Reductions Are Presented for CDF, Population Dose Risk (PDR), and Offsite Economic Cost Risk (OECR)

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent Risk 

Reduction

Unit 1 

Internal and 

External 

Benefit

Unit 2 Percent Risk 

Reduction

Unit 2 

Internal and 

External 

CDF PDR OECR CDF PDR OECR Benefit

8—Increase training on response to 

loss of two 120V AC buses

$50,000 <0.1% 0.0% 0.0% >$50,000║

$573 

($1,430) #

<0.1% 0.0% 0.0% >$50,000║

$226

($566)#

Assumption: To assess the benefit of increased training on loss of two 120V AC buses causing inadvertent actuation signals, the inadvertent 

actuation of safety injection was removed from the model. In response to an RAI, determined by TVA to be potentially cost beneficial.

32—Automatically align emergency 

core cooling system to recirculation†

$2,100,000 13.4% 4.2% 2.9% $458,00 

($1,144,000)#

31.8% 8.9% 6.8% $1,026,000 

($2,564,000)#

Assumption: A bounding analysis was performed by eliminating the failure of the manual action required to align high-pressure recirculation 

(HARR1) by setting the event to false.

45—Enhance procedural guidance 

for use of cross-tied component 

cooling pumps

$50,000 0.8% 1.1% 1.2% $83,700 

($209,000)#

0.6% 1.1% 1.2% $71,500 

($179,000)#

Assumption: The fault trees for the component cooling water system were modified to reflect that failure of multiple pumps was required to cease 

flow to the respective heat exchanger train.

70—Install accumulators for turbine 

driven auxiliary feedwater pump flow 

control valves

$256,000 6.1% 4.9% 3.2% $348,000 

($870,000)#

5.12% 5.01% 3.33% $311,000 

($779,000)#

Assumption: A bounding analysis was performed by eliminating the failure of the existing flow control valves.

87—Replace service and instrument 

air compressors with more reliable 

compressors

$886,000* 6.5% 4.2% 2.8% $326,000 

($815,000)#

5.6% 4.3% 2.9% $293,000 

($732,000)#

Assumption: A bounding analysis was performed by eliminating the failure of cooling to the compressors. This includes compressors for the 

auxiliary compressed air system and the compressed air system. In response to an RAI, determined by TVA to be potentially cost beneficial.
Environmental Consequences and Mitigating Actions

4-73

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent Risk 

Reduction

Unit 1 

Internal and 

External 

Benefit

Unit 2 Percent Risk 

Reduction

Unit 2 

Internal and 

External 

CDF PDR OECR CDF PDR OECR Benefit

88—Install nitrogen bottles as 

backup gas supply for safety relief 

valves†

$100,000 3.5% 0.2% 0.2% $78,100 

($195,000)#

3.1% 0.5% 0.2% $79,000 

($198,000)#

Assumption: A bounding analysis was performed by modifying the atmospheric relief valve fault tree logic for all four valves to remove their 

dependence on compressed air.

105—Delay containment spray 

actuation after a large loss of coolant 

accident

$100,000 6.8% 2.7% 1.8% $257,000

($641,000)#

16.0% 5.0% 3.8% $539,000 

($1,348,000)#

106—Install automatic containment 

spray pump header throttle valves

$100,000 6.8% 2.7% 1.8% $257,000 

($641,000)#

16.0% 5.0% 3.8% $539,000 

($1,348,000)#

249—High volume makeup to the 

refueling water storage tank†

$565,000 6.8% 2.7% 1.8% $257,000 

($641,000)#

16.0% 5.0% 3.8% $539,000 

($1,348,000)#

Assumption: A bounding analysis was performed by changing the model so that the refueling water storage tank was always available. This 

included removing refueling water storage tank rupture, as well as failure to deliver flow from the refueling water storage tank to containment

spray pumps A and B. In addition, the failure probability of the human action to align high-pressure recirculation (HARR1) was decreased by half 

to account for the increased time that the operator would have to perform this action.

160—Implement procedures for 

temporary heating, ventilation, and 

air conditioning‡

$300,000 9.1% 7.8% 9.1% $665,000 

($1,661,000)#

5.0% 2.3% 2.5% $220,000 

($550,000)#

Assumption: The analysis was performed by adding a human action to provide temporary cooling (failure frequency of 10−1) for the following 

areas given cooler/ventilation failure: turbine-driven auxiliary feedwater pump room; residual heat removal pump rooms A and B; safety injection 

pump rooms A and B, containment spray room; centrifugal charging pump cooler rooms A and B; and space coolers A and B for boric acid 

transfer pump and auxiliary feedwater (AFW) pumps.
Environmental Consequences and Mitigating Actions

4-74

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent Risk 

Reduction Unit 1 

Internal and 

External 

Benefit

Unit 2 Percent Risk 

Reduction Unit 2 

Internal and 

External 

CDF PDR OECR CDF PDR OECR Benefit

215—Provide a means to ensure 

reactor coolant pump seal cooling so 

that reactor coolant pump seal loss 

of coolant accidents are precluded 

for station blackout events

$1,500,000 47.5% 46.2% 54.1% $3,832,000 

($9,580,000)#

38.5% 44.2% 53.2% $3,234,000 

($8,085,000)#

Assumption: This analysis was used to evaluate the change in plant risk from providing a means to ensure reactor coolant pump seal cooling so 

that reactor coolant pump seal loss of coolant accidents are precluded for station backout events. The analysis was performed by adding an 

additional seal cooling system to the logic “anded” with the existing reactor coolant pump thermal barrier cooling logic. The new seal cooling 

system with independent power source was given an unavailability of 0.05, which is representative of a single pump train system.

268—Perform an evaluation of the 

component cooling water 

system/AFW area cooling 

requirements

$313,000 29.5% 26.9% 31.7% $2,269,000 

($5,673,000)#

21.3% 26.0% 31.5% $1,881,000 

($4,704,000)#

Assumption: The analysis was performed by eliminating the failure of the component cooling water system and AFW space coolers.

275—Install spray protection on 

motor-driven auxiliary feedwater 

pumps and pump space coolers†

$800,000 8.0% 6.9% 8.0% $587,000 

($1,467,000)#

17.8% 8.4% 8.9% $792,000 

($1,979,000)#

Assumption: A bounding analysis was performed by eliminating spray initiators from the motor-driven auxiliary feedwater pumps, and space 

coolers used to cool motor-driven auxiliary feedwater pumps.

279—Improve internal flooding 

response procedures and training to 

improve the response to internal 

flooding events

$400,000 5.3% 7.3% 7.1% $520,000 

($1,301,000)#

14.9% 10.0% 9.8% $796,000 

($1,990,000)#

Assumption: The analysis was performed by reducing the overall failure probability of important flooding human actions, with the flood multiplier 

for important human actions reduced by a factor of two.
Environmental Consequences and Mitigating Actions

4-75

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent Risk 

Reduction Unit 1 

Internal and 

External 

Benefit

Unit 2 Percent Risk 

Reduction Unit 2 

Internal and 

External 

CDF PDR OECR CDF PDR OECR Benefit

283—Provide frequent awareness 

training to plant staff on important 

human actions

$345,000 5.3% 4.4% 4.9% $372,000 

($930,000)#

6.6% 5.0% 5.5% $397,000 

($993,000)#

Assumption: A bounding analysis was performed by reducing the failure probability of important human actions by 10 percent. The human error 

probability dependency factors for important human actions were also improved by 10 percent.

285—Protect important equipment in 

the turbine building from internal 

flooding†

$955,000* 8.8% 5.8% 5.0% $478,000 

($1,196,000)#

7.6% 6.2% 5.3% $439,000 

($1,099,000)#

Assumption: The analysis was performed by adding a factor to the flooding initiators that resulted in reduced spray damage to the turbine 

building distribution boards and the raw cooling water pumps to simulate addition of spray shields. The spray shield was given a failure 

probability of 10−3.

286—Install flood doors to prevent 

water propagation in the electric 

board room†,§

$4,695,000* 10.8% 26.0% 22.4% $1,611,000 

($4,028,000)#

9.1% 26.9% 23.5% $1,454,000 

($3,634,000)#

Assumption: The analysis was performed by removing the failure of important equipment from certain floods to simulate watertight doors.

288—Install spray protection on 

component cooling water system 

pumps and component cooling water 

system/AFW space coolers†,§

$1,809,000* 8.9% 9.8% 11.6% $793,000 

($1,982,000)#

6.9% 9.6% 11.4% $669,000 

($1,674,000)#

Assumption: A bounding analysis was performed by eliminating spray initiator events from the component cooling water system pumps and 

component cooling water system/AFW space coolers fault tree logic.
Environmental Consequences and Mitigating Actions

4-76

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent Risk 

Reduction Unit 1 

Internal and 

External 

Benefit

Unit 2 Percent Risk 

Reduction Unit 2 

Internal and 

External 

CDF PDR OECR CDF PDR OECR Benefit

289—Install backup cooling system

for component cooling water 

system/AFW space coolers†

$2,219,000* 21.7% 19.1% 22.6% $1,629,000 

($4,072,000)#

13.7% 16.0% 19.2% $1,164,000 

($2,909,000)#

Assumption: The analysis was performed by adding a backup space cooler to the fault tree logic, such that failure of the existing and backup 

coolers is required for failure of the component cooling water system and AFW space coolers.

# Value in parentheses represents the larger benefit calculated in the sensitivity analysis (TVA 2013d, Attachment E, Tables E.2-3 and E.2-4). 

* TVA identified that implementation costs could be shared between Units 1 and 2 for this SAMA and considered the combined total averted cost risk from both 

Units 1 and 2 in the cost-benefit evaluation.

† By assessing the sensitivity analysis and the resulting increases in estimated benefits (shown in parentheses), TVA considered the following additional SAMAs 

to be potentially cost beneficial for either one or both of the units: SAMA 32 (Unit 2), SAMA 88 (Units 1 and 2), SAMA 160 (Unit 2), SAMA 249 (Units 1 and 2), 

SAMA 275 (Units 1 and 2), SAMA 285 (Units 1 and 2), SAMA 286 (Units 1 and 2), SAMA 288 (Units 1 and 2), and SAMA 289 (Units 1 and 2).

‡ For the baseline results presented in this table, SAMA 160 was considered potentially cost beneficial for Unit 1 only. However, TVA considered SAMA 160 to 

be potentially cost beneficial for Unit 2 based on the sensitivity results (shown in parentheses).

§ SAMAs 286 and 288 were considered to be potentially cost beneficial, because implementation costs could be shared between Units 1 and 2 and the 

sensitivity analysis results for the combined total averted cost risk from both units (shown in parentheses) exceeded the SAMA implementation cost.

║ Additional analyses performed by TVA for the loss of two busses indicated that averted cost risk could exceed $50,000 (TVA 2013c).
Environmental Consequences and Mitigating Actions

4-77

1 The NRC staff reviewed the applicant’s cost estimates, presented in Tables E.2-1 and E.2-2 of 

2 Attachment E to the ER (TVA 2013a). For certain improvements, the NRC staff also compared 

3 the cost estimates to estimates developed elsewhere for similar improvements, including 

4 estimates developed as part of other licensees’ analyses of SAMAs for operating reactors. With 

5 requested clarifications for a few SAMAs (TVA 2013c), NRC staff concludes that the cost 

6 estimates provided by TVA are sufficient and appropriate for use in the SAMA evaluation.

7 Cost-Benefit Comparison

8 If the implementation costs for a candidate SAMA exceeded the calculated benefit, the SAMA 

9 was determined to be not cost beneficial. If the benefit exceeded the estimated cost, the SAMA 

10 candidate was considered to be cost beneficial. Sensitivity analyses performed by the applicant 

11 can lead to increases in the calculated benefits. Two sensitivity cases were developed by TVA: 

12 one used a discount rate of 3 percent and the other used an alternative value for failure 

13 probability to explicitly account for uncertainty and include margin into cost-benefit evaluation. 

14 Additional details on the sensitivity analysis are presented in Appendix F, Section F.6.2.

15 The TVA’s baseline cost-benefit analysis identified nine and eight candidate SAMAs as 

16 potentially cost beneficial for Units 1 and 2, respectively. From a sensitivity analysis, TVA 

17 identified an additional seven and nine candidate SAMAs as potentially cost beneficial for 

18 Units 1 and 2, respectively. Results of the cost-benefit evaluation are presented in Table 4–22 

19 for these potentially cost-beneficial SAMAs. 

20 In response to NRC RAI, TVA identified 4 additional SAMA candidates as potentially cost 

21 beneficial for both units. These additional cost-beneficial SAMAs arose from the NRC 

22 evaluation of the baseline SAMA analysis and questioning on potentially lower cost alternatives. 

23 In response to NRC staff RAI on the SAMA analyses, TVA indicated that SAMA 8—to increase 

24 training on response to loss of two 120V AC busses—and SAMA 87—to replace service and 

25 instrument air compressors with more reliable compressors—will be retained as potentially cost 

26 beneficial for both units (TVA 2013c).

27 In its response to questions on potentially lower cost alternatives, TVA identified two additional 

28 SAMA candidates as potentially cost beneficial for (1) human actions to automatically trip the 

29 RCP on loss of CCW and (2) manufacturing a gagging device for a steam generator safety 

30 valve and developing a procedure or work order for closing a stuck-open valve (TVA 2013c). 

31 These two potentially cost-beneficial SAMAs are not listed in Table 4–22. 

32 TVA indicated that the potentially cost-beneficial SAMAs will be considered in the 

33 design process. 

34 Conclusions

35 TVA considered 309 candidate SAMAs based on risk-significant contributors at SQN from 

36 updated probabilistic safety assessment models, SAMA-related industry documentation, 

37 plant-specific enhancements not in published industry documentations, and its review of SAMA 

38 candidates from potential improvements at twelve other plants. Phase I screening reduced the 

39 list to 47 unique SAMA candidates by eliminating SAMAs that were not applicable to SQN, had 

40 already been implemented at SQN, were combined into a more comprehensive or plant-specific 

41 SAMA, had excessive implementation cost, had a very low benefit, or relate to in-progress 

42 implementation of plant improvements that address the intent of the SAMA.

43 For the remaining SAMA candidates, TVA performed a cost-benefit analysis. The baseline 

44 cost-benefit analysis identified nine and eight candidate SAMAs as potentially cost-beneficial for 

45 Units 1 and 2, respectively. From a sensitivity analysis, TVA identified an additional seven and 

46 nine candidate SAMAs as potentially cost beneficial for Units 1 and 2, respectively. In response 
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1 to NRC staff RAI, TVA identified 4 additional SAMA candidates as potentially cost beneficial for 

2 both units. These additional cost-beneficial SAMAs arose from the NRC evaluation of the 

3 baseline SAMA analysis and questioning on potentially lower cost alternatives. In response to 

4 NRC staff RAI on the SAMA analyses, TVA indicated that SAMA 8—to increase training on 

5 response to loss of two 120V AC busses—and SAMA 87—to replace service and instrument air 

6 compressors with more reliable compressors—will be retained as potentially cost beneficial for 

7 both units. In its response to questions on potentially lower cost alternatives, TVA identified 

8 two additional SAMA candidates as potentially cost beneficial for (1) human actions to 

9 automatically trip the RCP on loss of CCW and (2) manufacturing a gagging device for a steam 

10 generator safety valve and developing a procedure or work order for closing a stuck-open valve.

11 The NRC staff reviewed TVA’s SAMA analysis and concludes that, subject to the discussion in 

12 this section and Appendix F, the methods used and implementation of the methods were sound. 

13 As mentioned in Section F.3.2, the new improved flood mitigation systems to be installed at 

14 SQN Units 1 and 2 would be expected to reduce the risk from all external events and possibly 

15 some internal events. These new systems are additional plant improvements to which TVA has 

16 committed. On the basis of the applicant’s treatment of SAMA benefits and costs, NRC staff 

17 finds that the SAMA evaluations performed by TVA are reasonable and sufficient for the license 

18 renewal submittal.

19 The staff concurs with TVA’s conclusion that 20 candidate SAMAs are potentially cost beneficial 

20 for SQN Unit 1 and 21 candidate SAMAs are potentially cost beneficial for SQN Unit 2, which 

21 was based on generally conservative treatment of costs, benefits, and uncertainties. This 

22 conclusion of a moderate number of potentially cost-beneficial SAMAs is consistent with a 

23 moderately large population within 50 mi (80 km) of SQN and moderate level of residual risk 

24 indicated in the SQN PRA. 

25 Additionally, the NRC staff evaluated the identified potentially cost-beneficial SAMAs to 

26 determine if they are in the scope of license renewal, i.e., they are subject to aging 

27 management. This evaluation considers whether the systems, structures, and components 

28 (SSCs) associated with these SAMAs: (1) perform their intended function without moving parts 

29 or without a change in configuration or properties and (2) that these SSCs are not subject to 

30 replacement based on qualified life or specified time period. The NRC staff determined that 

31 these SAMAs do not relate to adequately managing the effects of aging during the period of 

32 extended operation. Therefore, they need not be implemented as part of license renewal in 

33 accordance with 10 CFR Part 54, “Requirements for renewal of operating licenses for nuclear 

34 power plants.”

35 4.11.2 No-Action Alternative

36 Human health risks would be smaller following plant shutdown. The two reactor units, which are 

37 currently operating within regulatory limits, would emit less radioactive gaseous, liquid, and solid 

38 material to the environment. In addition, following shutdown, the variety of potential accidents at 

39 the plant (radiological or industrial) would be reduced to a limited set associated with shutdown 

40 events and fuel handling and storage. In Section 4.11.1.1, the NRC staff concluded that the 

41 impacts of continued plant operation on human health would be SMALL, except for “[c]hronic 

42 effects of electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. In 

43 Section 4.11.1.2, the NRC staff concluded that the impacts of accidents during operation were 

44 SMALL. Therefore, as radioactive emissions to the environment decrease, and as likelihood 

45 and variety of accidents decrease following shutdown, the NRC staff concludes that the risk to 

46 human health following plant shutdown would be SMALL.
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1 4.11.3 NGCC Alternative – Human Health

2 4.11.3.1 Construction

3 Impacts on human health from construction of the natural gas-fired alternative, including the 

4 possible construction of a new pipeline, would be similar to effects associated with the 

5 construction of any major industrial facility. Compliance with worker protection rules would 

6 control those impacts on workers at acceptable levels. Impacts from construction on the 

7 general public would be minimal since crews would limit active construction area access to 

8 authorized individuals. Based on the above, the NRC staff concludes that the impacts on 

9 human health from the construction of the natural gas-fired alternative would be SMALL.

10 4.11.3.2 Operation

11 Impacts from the operation of a natural gas-fired facility introduces public risk from inhalation of 

12 gaseous emissions. The risk may be attributable to nitrogen oxide emissions that contribute to 

13 ozone formation, which in turn contribute to health risk. Regulatory agencies, including the EPA

14 and State agencies, base air emission standards and requirements on human health impacts. 

15 These agencies also impose site-specific emission limits as needed to protect human health. 

16 Given the regulatory oversight exercised by the EPA and State agencies, the NRC staff 

17 concludes that the human health impacts from natural gas-fired power generation would be 

18 SMALL.

19 4.11.4 SCPC Alternative – Human Health

20 4.11.4.1 Construction

21 Impacts on workers are expected to be similar to those experienced during construction of any 

22 major industrial facility. Impacts from construction of combustion-based energy facilities are 

23 expected to be the same as those for construction of fossil-fuel facilities. Construction would 

24 increase traffic on local roads, which could affect the health of the general public. Human health 

25 impacts would be the same for all facilities whether located on greenfield sites, brownfield sites, 

26 or at an existing nuclear plant. Personal protective equipment, training, and engineered barriers 

27 would protect the workforce (NRC 2013e). Based on the above, the NRC staff concludes that 

28 the impacts on human health from the construction of the supercritical pulverized coal 

29 alternative would be SMALL.

30 4.11.4.2 Operation

31 Coal-fired power generation introduces worker risks from coal and limestone mining, worker and 

32 public risk from coal, lime, and limestone transportation, worker and public risk from disposal of 

33 coal-combustion waste, and public risk from inhalation of stack emissions. In addition, human 

34 health risks are associated with the management and disposal of coal combustion waste. Coal 

35 combustion generates waste in the form of ash, and equipment for controlling air pollution 

36 generates additional ash and scrubber sludge. Human health risks may extend beyond the 

37 facility workforce to the public depending on their proximity to the coal combustion waste 

38 disposal facility. The character and the constituents of coal-combustion waste depend on both 

39 the chemical composition of the source coal and the technology used to combust it. Generally, 

40 the primary sources of adverse consequences from coal-combustion waste are from exposure 

41 to sulfur oxide and nitrogen oxide in air emissions and radioactive elements such as uranium

42 and thorium, as well as the heavy metals and hydrocarbon compounds contained in fly ash and 

43 bottom ash, and scrubber sludge (NRC 2013e).

44 Regulatory agencies, including the EPA and state agencies, base air emission standards and 

45 requirements on human health impacts. These agencies also impose site-specific emission 
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1 limits as needed to protect human health. Given the regulatory oversight exercised by the EPA 

2 and State agencies, the NRC staff concludes that the human health impacts from radiological 

3 doses and inhaled toxins and particulates generated from coal-fired generation would be 

4 SMALL (NRC 2013e).

5 4.11.5 New Nuclear Alternative – Human Health

6 4.11.5.1 Construction

7 Impacts on human health from construction of two new nuclear units would be similar to impacts 

8 associated with the construction of any major industrial facility. Compliance with worker 

9 protection rules would control those impacts on workers at acceptable levels. Impacts from 

10 construction on the general public would be minimal since limiting active construction area 

11 access to authorized individuals is expected. Impacts on human health from the construction of 

12 two new nuclear units would be SMALL.

13 4.11.5.2 Operation

14 The human health effects from the operation of two new nuclear power plants would be similar 

15 to those of the existing SQN. As presented in Section 4.11.1.1, impacts on human health from 

16 the operation of SQN would be SMALL. Therefore, the impacts on human health from the 

17 operation of two new nuclear plants would be SMALL.

18 4.11.6 Combination Alternative – Human Health

19 4.11.6.1 Construction

20 Impacts on human health from construction of a combination wind and solar photovoltaic 

21 alternative would be similar to effects associated with the construction of any major industrial 

22 facility. Compliance with worker protection rules would control those impacts on workers at 

23 acceptable levels. Impacts from construction on the general public would be minimal since 

24 crews would limit active construction area access to authorized individuals. Based on the 

25 above, the NRC staff concludes that the impacts on human health from the construction of a 

26 wind and solar alternative would be SMALL.

27 4.11.6.2 Operation

28 Operational hazards at a wind facility for the workforce include working at heights, working near 

29 rotating mechanical or electrically energized equipment, and working in extreme weather. 

30 Potential impacts to workers and the public include ice thrown from rotor blades and broken 

31 blades thrown because of mechanical failure. Potential impacts also include EMF exposure, 

32 aviation safety, and exposure to noise and vibration from the rotating blades.

33 Operational hazards at a solar photovoltaic facility may involve exposure to airborne toxic 

34 metals (e.g., cadmium) and silicon if a photovoltaic cell were to lose its integrity from a fire. 

35 Workers could also inhale silicon dust if the photovoltaic cells were smashed by an object or 

36 from a fall to the ground.

37 However, given the expected compliance with worker protection rules and remediation efforts to 

38 contain the toxic material, the potential impacts to workers at the facility and offsite exposure to 

39 the public, the impacts would be 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 and special pathway receptors.

5 4.12.1 Proposed Action

6 The environmental justice issue applicable to SQN during the license renewal term is listed in 

7 Table 4–23. Section 3.12 of this SEIS describes the environmental justice matters with respect 

8 to SQN.

9 Table 4–23. Environmental Justice

Issue GEIS Section Category

Minority and low-income populations 4.10.1 2 

Source: Table B–1 in Appendix B, Subpart A, to 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 3–9 and 3–10 in this SEIS show the location of predominantly minority and low-income 

24 population block groups residing within a 50-mi (80-km) radius of SQN. This area of impact is 

25 consistent with the impact analysis for public and occupational health and safety, which also 

26 focuses on populations within a 50-mi (80-km) radius of the plant. Chapter 4 presents the 

27 assessment of environmental and human health impacts for each resource area. The analyses 

28 of impacts for all environmental resource areas indicated that the impact from license renewal 

29 would be SMALL.

30 Potential impacts on minority and low-income populations (including migrant workers or 

31 Native Americans) would mostly consist of socioeconomic and radiological effects; however, 

32 radiation doses from continued operations during the license renewal term are expected to 

33 continue at current levels, and they would remain within regulatory limits. Section 4.11.1.2 of 

34 this SEIS discusses the environmental impacts from postulated accidents that might occur 

35 during the license renewal term, which include both design basis and severe accidents. In both 

36 cases, the Commission has generically determined that impacts associated with DBAs are small 

37 because nuclear plants are designed and operated to successfully withstand such accidents, 

38 and the probability weighted consequences of severe accidents are small.
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1 Therefore, based on this information and the analysis of human health and environmental 

2 impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 

3 adverse human health and environmental effects on minority and low-income populations from 

4 the continued operation of SQN during the license renewal term.

5 As part of addressing environmental justice concerns associated with license renewal, the NRC 

6 also assessed the potential radiological risk to special population groups (such as migrant

7 workers or Native Americans) from exposure to radioactive material received through their 

8 unique consumption practices and interaction with the environment, including subsistence 

9 consumption of fish, native vegetation, surface waters, sediments, and local produce; 

10 absorption of contaminants in sediments through the skin; and inhalation of airborne radioactive 

11 material released from the plant during routine operation. This analysis is presented below.

12 4.12.1.1 Subsistence Consumption of Fish and Wildlife

13 The special pathway receptors analysis is an important part of the environmental justice

14 analysis because consumption patterns may reflect the traditional or cultural practices of 

15 minority and low-income populations in the area, such as migrant workers or Native Americans. 

16 Section 4-4 of Executive Order (E.O.) 12898 (59 FR 7629) directs Federal agencies, whenever 

17 practical and appropriate, to collect and analyze information about the consumption patterns of 

18 populations that rely principally on fish and/or wildlife for subsistence and to communicate the 

19 risks of these consumption patterns to the public. In this SEIS, the NRC considered whether 

20 there were any means for minority or low-income populations to be disproportionately affected 

21 by examining impacts on American Indian, Hispanics, migrant workers, and other traditional 

22 lifestyle special pathway receptors. The assessment of special pathways considered the levels 

23 of radiological and nonradiological contaminants in native vegetation, crops, soils and 

24 sediments, GW, surface water, fish, and game animals on or near SQN.

25 The following is a summary discussion of TVA’s radiological environmental monitoring programs 

26 that assess the potential impacts from the subsistence consumption of fish and wildlife near the 

27 SQN site.

28 TVA has an ongoing comprehensive Radiological Environmental Monitoring Program (REMP) to 

29 assess the impact of SQN operations on the environment. To assess the impact of nuclear 

30 power plant operations, samples are collected annually from the environment and analyzed for 

31 radioactivity. A plant effect would be indicated if the radioactive material detected in a sample 

32 was significantly larger than background levels. Two types of samples are collected. The first 

33 type, a control sample, is collected from areas that are beyond the measurable influence of the 

34 nuclear power plant or any other nuclear facility. These samples are used as reference data to 

35 determine normal background levels of radiation in the environment. These samples are then 

36 compared with the second type of samples, indicator samples, collected near the nuclear power 

37 plant. Indicator samples are collected from areas where any contribution from the nuclear 

38 power plant will be at its highest concentration. These samples are then used to evaluate the 

39 contribution of nuclear power plant operations to radiation or radioactivity levels in the 

40 environment. An effect would be indicated if the radioactivity levels detected in an indicator 

41 sample was significantly larger than the control sample or background levels.

42 Samples of environmental media are collected from the aquatic and terrestrial pathways in the 

43 vicinity of SQN. The aquatic pathways include GW, surface water, drinking water, fish, and 

44 shoreline sediment. The terrestrial pathways include airborne particulates and food products 

45 (i.e., broad leaf vegetation). During 2011, analyses performed on samples of environmental 

46 media at SQN showed no significant or measurable radiological impact above background 

47 levels from site operations (TVA 2012b).
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1 4.12.1.2 Conclusion

2 Based on the radiological environmental monitoring data from SQN, the NRC staff concludes 

3 that no disproportionately high and adverse human health impacts would be expected in special 

4 pathway receptor populations in the region as a result of subsistence consumption of water, 

5 local food, fish, and wildlife. Continued operation of SQN would not have disproportionately 

6 high and adverse human health and environmental effects on these populations.

7 4.12.2 No-Action Alternative – Environmental Justice

8 This section evaluates the potential for disproportionately high and adverse human health and 

9 environmental effects on minority and low-income populations that could result from the no 

10 action alternative. Impacts on minority and low-income populations would depend on the 

11 number of jobs and the amount of tax revenues lost by communities in the immediate vicinity of 

12 the power plant after SQN ceases operations. Not renewing the operating licenses and 

13 terminating reactor operations would have a noticeable impact on socioeconomic conditions in 

14 the communities located near SQN. The loss of jobs and income would have an immediate 

15 socioeconomic impact. Some, but not all, of the 1,141 SQN employees would begin to leave 

16 after reactor operations are terminated; and overall tax revenue generated by plant operations 

17 would be reduced. The reduction in tax revenue would decrease the availability of public 

18 services in Hamilton County. This could disproportionately affect minority and low-income 

19 populations that may have become dependent on these services. See also Appendix J of 

20 NUREG-0586, Supplement 1 (NRC 2002), for additional discussion of these impacts.

21 4.12.3 NGCC Alternative – Environmental Justice

22 This section evaluates the potential for disproportionately high and adverse human health, 

23 environmental, and socioeconomic effects on minority and low-income populations that could 

24 result from the construction and operation of a new NGCC plant. Some of these potential 

25 effects have been identified in resource areas discussed in this SEIS. For example, increased 

26 demand for rental housing during replacement power plant construction could disproportionately 

27 affect low-income populations. 

28 Potential impacts to minority and low-income populations from the construction and operation of 

29 a new NGCC plant at an existing power plant site would mostly consist of environmental and 

30 socioeconomic effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise and 

31 dust impacts from construction would be short-term and primarily limited to onsite activities. 

32 Minority and low-income populations residing along site access roads would be affected by 

33 increased commuter vehicle traffic during shift changes and truck traffic. However, these effects 

34 would be temporary during certain hours of the day and would not likely be high and adverse. 

35 Increased demand for rental housing during construction could affect low-income populations in 

36 the vicinity of the existing power plant site. However, given that power plant sites are generally 

37 located near metropolitan areas, construction workers could commute to the site, thereby 

38 reducing the potential demand for rental housing.

39 Emissions from the operation of an NGCC plant could affect minority and low income 

40 populations living in the vicinity of the new power plant. However, permitted air emissions are 

41 expected to remain within regulatory standards.

42 Based on this information and the analysis of human health and environmental impacts 

43 presented in this SEIS, the construction and operation of a new NGCC plant would not likely 

44 have disproportionately high and adverse human health and environmental effects on minority 

45 and low-income populations in the vicinity of the existing power plant site. However, a definitive 
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1 determination of the potential for disproportionately high and adverse human health and 

2 environmental effects on minority and low-income populations would depend on the alternative’s 

3 location, plant design, and expected operational characteristics. Therefore, the NRC cannot 

4 definitively forecast the effects on minority and low-income populations for this alternative.

5 4.12.4 SCPC Alternative – Environmental Justice 

6 This section evaluates the potential for disproportionately high and adverse human health and 

7 environmental effects on minority and low-income populations that could result from the 

8 construction and operation of a new SCPC power plant. Some of these potential effects have 

9 been identified in resource areas discussed in this SEIS. For example, increased demand for 

10 rental housing during replacement power plant construction could disproportionately affect 

11 low-income populations. 

12 Potential impacts to minority and low-income populations from the construction and operation of 

13 a new SCPC plant at the existing power plant site would consist of environmental and 

14 socioeconomic effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise and 

15 dust impacts from construction would be short-term and primarily limited to onsite activities. 

16 Minority and low-income populations residing along site access roads would be affected by 

17 increased commuter vehicle traffic during shift changes and truck traffic. However, these effects 

18 would be temporary during certain hours of the day and would not likely be high and adverse. 

19 Increased demand for rental housing during construction could affect low-income populations. 

20 However, given the proximity of some existing power plant sites to metropolitan areas, many 

21 construction workers could commute to the site, thereby reducing the potential demand for 

22 rental housing.

23 Emissions from the operation of a SCPC plant could affect minority and low income populations 

24 living in the vicinity of the new power plant. However, permitted air emissions are expected to 

25 remain within regulatory standards.

26 Based on this information and the analysis of human health and environmental impacts 

27 presented in this SEIS, the construction and operation of a new SCPC plant would not likely 

28 have disproportionately high and adverse human health and environmental effects on minority 

29 and low-income populations. However, a definitive determination of the potential for 

30 disproportionately high and adverse human health and environmental effects on minority and 

31 low-income populations would depend on the alternative’s location, plant design, and expected 

32 operational characteristics. Therefore, the NRC cannot definitively forecast the effects on 

33 minority and low-income populations for this alternative.

34 4.12.5 New Nuclear Alternative – Environmental Justice 

35 This section evaluates the potential for disproportionately high and adverse human health and 

36 environmental effects on minority and low-income populations that could result from the 

37 construction and operation of a new nuclear power plant. Some of these potential effects have 

38 been identified in resource areas discussed in this SEIS. For example, increased demand for 

39 rental housing during replacement power plant construction could disproportionately affect 

40 low-income populations.

41 Potential impacts to minority and low-income populations from the construction and operation of 

42 a new nuclear power plant would mostly consist of environmental and socioeconomic effects 

43 (e.g., noise, dust, traffic, employment, and housing impacts). Noise and dust impacts from 

44 construction would be short-term and primarily limited to onsite activities. Minority and low45 income populations residing along site access roads would be affected by increased commuter 
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1 vehicle traffic during shift changes and truck traffic. However, these effects would be temporary 

2 during certain hours of the day and would not likely be high and adverse. Increased demand for 

3 rental housing during construction could affect low-income populations. However, given the 

4 proximity of some existing nuclear power plant sites to metropolitan areas, many construction 

5 workers could commute to the site, thereby reducing the potential demand for rental housing.

6 Potential impacts to minority and low income populations from new nuclear power plant 

7 operations would mostly consist of radiological effects; however, radiation doses are expected 

8 to be well below regulatory limits andpermitted air emissions are expected to remain within 

9 regulatory standards.

10 Based on this information and the analysis of human health and environmental impacts 

11 presented in this SEIS, the construction and operation of a new nuclear power plant would not 

12 likely have disproportionately high and adverse human health and environmental effects on 

13 minority and low-income populations. However, a definitive determination of the potential for 

14 disproportionately high and adverse human health and environmental effects on minority and 

15 low-income populations would depend on the alternative’s location, plant design, and expected 

16 operational characteristics. Therefore, the NRC cannot definitively forecast the effects on 

17 minority and low-income populations for this alternative.

18 4.12.6 Combination Alternative – Environmental Justice 

19 This section evaluates the potential for disproportionately high and adverse human health and 

20 environmental effects on minority and low-income populations that could result from the 

21 construction and operation of a combination of wind and solar photovoltaic electrical power 

22 generating activities. Some of these potential effects have been identified in resource areas 

23 discussed in this SEIS. For example, increased demand for rental housing during construction 

24 could disproportionately affect low-income populations. 

25 Potential impacts to minority and low-income populations from the construction and operation of 

26 new wind turbines and solar photovoltaic installations would mostly consist of environmental 

27 and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise 

28 and dust impacts from construction would be short-term and primarily limited to onsite activities. 

29 Minority and low-income populations residing along site access roads would be affected by 

30 increased commuter vehicle traffic during shift changes and truck traffic. However, these effects 

31 would be temporary during certain hours of the day and would not likely be high and adverse. 

32 Increased demand for rental housing during construction could affect low-income populations. 

33 However, given the small number of construction workers and the possibility that many workers 

34 could commute to these construction sites, the potential need for rental housing would not be 

35 significant.

36 Minority and low income populations living in close proximity to wind farm and solar photovoltaic 

37 power generating installations could be disproportionately affected by maintenance and 

38 operations activities. However,operational impacts from the wind turbines and solar 

39 photovoltaic installations would mostly be limited to noise and aesthetic effects. 

40 Based on this information and the analysis of human health and environmental impacts 

41 presented in this SEIS, the construction and operation of new wind farm and solar photovoltaic 

42 installations would not likely have disproportionately high and adverse human health and 

43 environmental effects on minority and low-income populations. However, a definitive 

44 determination of the potential for disproportionately high and adverse human health and 

45 environmental effects on minority and low-income populations would depend on the alternative’s 

46 location, plant design, and expected operational characteristics. Therefore, the NRC cannot 

47 definitively forecast the effects on minority and low-income populations for this alternative.
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1 4.13 Waste Management

2 This section describes the potential impacts of the proposed action (license renewal) and 

3 alternatives to the proposed action on waste management and pollution prevention.

4 4.13.1 Proposed Action

5 The waste management issues applicable to SQN during the license renewal term are listed in 

6 Table 4–24. Section 3.13 of this SEIS describes SQN waste management.

7 Table 4–24. Waste Management

Issues 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) N/A

Mixed-waste storage and disposal 4.11.1.4 1 

Nonradioactive waste storage 4.11.1.4 1 

(a) The impacts of this issue only apply for the license renewal term.

(b) N/A (not applicable)—The categorization and impact finding definition do not apply to this issue.

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

8 The NRC staff’s evaluation of the environmental impacts associated with spent nuclear fuel is 

9 addressed in two issues in Table 4–24, “Offsite radiological impacts (spent fuel and high-level 

10 waste disposal)” and “Onsite spent fuel.” The issue, “Offsite radiological impacts (spent fuel and 

11 high-level waste disposal),” is not evaluated in this SEIS. In addition, the issue, “Onsite spent 

12 fuel” only evaluates the environmental impacts during the licensed life for operation of the 

13 reactor, i.e. the license renewal term. As discussed below, the Waste Confidence Continued 

14 Storage of Spent Nuclear Fuel Rule and supporting generic EIS are expected to provide the 

15 necessary NEPA analyses of the environmental impacts at an onsite or offsite spent nuclear 

16 fuel storage facility. 

17 For the term of license renewal, the staff did not find any new and significant information related 

18 to “Onsite spent fuel” and the remaining waste management issues listed in Table 4–24 during 

19 its review of the TVA’s ER (TVA 2013g), the site visit, and the scoping process. Therefore, 

20 there are no impacts related to these issues beyond those discussed in the GEIS. For these 

21 Category 1 issues, the GEIS concludes that the impacts are SMALL.

22 Historically, the NRC’s Waste Confidence Decision and Rule represented the Commission’s 

23 generic determination that spent fuel can continue to be stored safely and without significant 

24 environmental impacts for a period of time after the end of a reactor’s licensed life for operation. 

25 This generic determination meant that the NRC did not need to consider the storage of spent 

26 fuel after the end of a reactor’s licensed life for operation in NEPA documents that supported its 

27 reactor and spent fuel storage application reviews. The NRC first adopted the Waste 

28 Confidence Decision and Rule in 1984. The NRC amended the Decision and Rule in 1990, 

29 reviewed it in 1999, and amended it again in 2010 (49 FR 34658 and 34694; 55 FR 38474; 
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1 64 FR 68005; and 75 FR 81032 and 81037). The Waste Confidence Decision provided a 

2 regulatory basis and NEPA analysis to support the Waste Confidence Rule (10 CFR 51.23). 

3 On December 23, 2010, the Commission published in the Federal Register a revision of the 

4 Waste Confidence Rule, supported again by a Waste Confidence Decision, to reflect 

5 information gained from experience in the storage of spent fuel and the increased uncertainty in 

6 the siting and construction of a permanent geologic repository for the disposal of spent nuclear 

7 fuel and high-level waste (75 FR 81032 and 81037). In response to the 2010 Waste Confidence 

8 Rule, the States of New York, New Jersey, Connecticut, and Vermont—along with several other 

9 parties—challenged the Commission’s NEPA analysis in the decision, which provided the 

10 regulatory basis for the rule. On June 8, 2012, the United States Court of Appeals, District of 

11 Columbia Circuit in New York v. NRC, 681 F. 3d 471 (D.C. Cir., 2012) vacated the NRC’s Waste 

12 Confidence Rule, after finding that it did not comply with NEPA.

13 In response to the court’s ruling, the Commission, in CLI-12-16 (NRC 2012a), determined that it

14 would not make final decisions for licensing actions that depend upon the Waste Confidence 

15 Rule until the court’s remand is appropriately addressed. The Commission also noted that all 

16 licensing reviews and proceedings should continue to move forward. In addition, the 

17 Commission directed in SRM-COMSECY-12-0016 (NRC 2012b) that the NRC staff proceed 

18 with a rulemaking that includes the development of a generic EIS. 

19 The generic EIS, which provides a regulatory basis for the revised rule, would provide NEPA

20 analyses of the environmental impacts of spent fuel storage at a reactor site or at an 

21 away-from-reactor storage facility after the end of a reactor’s licensed life for operation 

22 (“continued storage”). As directed by the Commission, the NRC will not make final decisions 

23 regarding renewed license applications until the court’s remand is appropriately addressed. 

24 This will ensure that there would be no irretrievable or irreversible resource commitments or 

25 potential harm to the environment before the impacts of continued storage have been 

26 appropriately considered.

27 On September 13, 2013, the NRC published a proposed revision of 10 CFR Part 51.23 (i.e., the 

28 Waste Confidence Rule), which, if adopted as a final rule, would generically address the 

29 environmental impacts of continued storage (78 FR 56776). The NRC also prepared a draft 

30 generic EIS to support this proposed rule (NRC 2013c) (78 FR 56621). The final rule is 

31 scheduled to be published by October 2014. Upon issuance of the final rule and generic EIS for 

32 waste confidence, the NRC staff will consider whether additional NEPA analysis of continued 

33 storage is warranted before taking any action on the SQN license renewal application. 

34 4.13.2 No-Action Alternative – Waste Management

35 If the no-action alternative were implemented, SQN would cease operation at the end of its 

36 initial operating licenses, or sooner, and enter decommissioning. The generation of spent 

37 nuclear fuel high-level waste would stop and generation of low-level, mixed waste and 

38 nonradioactive waste would decrease. The impacts of decommissioning are discussed in 

39 Section 4.15.2. Impacts from implementation of the no-action alternative are expected to be 

40 SMALL.

41 4.13.3 NGCC Alternative – Waste Management

42 4.13.3.1 Construction

43 Construction-related debris would be generated during plant construction activities, and would 

44 be recycled or disposed of in approved landfills.
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1 4.13.3.2 Operation

2 Waste generation from natural gas-fired technology would be minimal. The only significant 

3 waste generated at a natural gas-fired power plant would be spent selective catalytic reduction 

4 (SCR) catalyst, which is used to control nitrous oxide emissions.

5 The spent catalyst would be regenerated or disposed of offsite. Other than spent SCR catalyst, 

6 waste generation at an operating natural gas-fired plant would be limited to nonhazardous 

7 waste and trash resulting from operations and maintenance activities. Overall, the NRC staff 

8 concludes that waste impacts from natural gas-fired power generation would be SMALL.

9 4.13.4 SCPC Alternative – Waste Management

10 4.13.4.1 Construction

11 Construction-related debris would be generated during plant construction activities, and would 

12 be recycled or disposed of in approved landfills.

13 4.13.4.2 Operation

14 Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 

15 for controlling air pollution generates additional ash, spent SCR catalyst, and scrubber sludge. 

16 The management and disposal of the large amounts of coal combustion waste is a significant 

17 part of the operation of a coal-fired power generating facility.

18 Although a coal-fired power generating facility is likely to use offsite disposal of coal combustion 

19 waste, some short-term storage of coal combustion waste (either in open piles or in surface 

20 impoundments) is likely to take place on site, thus establishing the potential for leaching of toxic 

21 chemicals into the local environment.

22 Based on the large volume, as well as the toxicity of waste generated by coal combustion, the 

23 NRC staff concludes that the impacts from waste generated at a coal-fired plant would be 

24 MODERATE.

25 4.13.5 New Nuclear Alternative – Waste Management

26 4.13.5.1 Construction

27 Construction-related debris would be generated during construction activities, and would be 

28 recycled or disposed of in approved landfills.

29 4.13.5.2 Operation

30 During normal plant operations, routine plant maintenance, and cleaning activities would 

31 generate radioactive low-level waste, spent nuclear fuel, and high-level waste as well as 

32 nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 

33 management at SQN. Quantities of radioactive and nonradioactive waste generated by SQN 

34 would be comparable to that generated by the two new nuclear plants.

35 According to the GEIS (NRC 1996, 2013c), the generation and management of solid radioactive 

36 and nonradioactive waste during the license renewal term are not expected to result in 

37 significant environmental impacts. Based on this information, the waste impacts would be 

38 SMALL for the new nuclear alternative.
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1 4.13.6 Combination Alternative – Waste Management

2 4.13.6.1 Construction

3 Construction-related debris would be generated during construction activities, and would be 

4 recycled or disposed of in approved landfills.

5 4.13.6.2 Operation

6 Waste generation from a combination wind and solar photovoltaic alternative would be minimal, 

7 consisting of debris from routine maintenance and the disposal of worn or broken parts. Based 

8 on this information, the NRC staff concludes that waste impacts from the construction and 

9 operation of a combination wind and solar photovoltaic alternative would be SMALL.

10 4.14 Evaluation of New and Potentially Significant Information

11 New and significant information must be both new and bear on the proposed action or its 

12 impacts, presenting a seriously different picture of the impacts from those envisioned in the

13 GEIS (i.e., impacts of greater severity than impacts considered in the GEIS, considering their 

14 intensity and context). 

15 In accordance with 10 CFR 51.53(c), the ER that the applicant submits must provide an analysis 

16 of the Category 2 issues in Table B–1 of 10 CFR Part 51, Subpart A, Appendix B. Additionally, 

17 it must discuss actions to mitigate any adverse impacts associated with the proposed action and 

18 environmental impacts of alternatives to the proposed action. In accordance with 

19 10 CFR 51.53(c)(3), the ER does not need to contain an analysis of any Category 1 issue 

20 unless there is new and significant information on a specific issue.

21 The NRC process for identifying new and significant information is described in NUREG–1555, 

22 Supplement 1, Standard Review Plans for Environmental Reviews for Nuclear Power Plants, 

23 Supplement 1: Operating License Renewal (NRC 1999a, 2013i). The search for new 

24 information includes: 

25 • review of an applicant’s ER and the process for discovering and evaluating 

26 the significance of new information, 

27 • review of public comments,

28 • review of environmental quality standards and regulations, 

29 • coordination with Federal, state, and local environmental protection and 

30 resource agencies, and 

31 • review of technical literature. 

32 New information that the staff discovers is evaluated for significance using the criteria set forth 

33 in the GEIS. For Category 1 issues in which new and significant information is identified, 

34 reconsideration of the conclusions for those issues is limited in scope to assessment of the 

35 relevant new and significant information; the scope of the assessment does not include other 

36 facets of an issue that the new information does not affect.

37 The NRC staff reviewed the discussion of environmental impacts associated with operation 

38 during the renewal term in the GElS and has conducted its own independent review, including a 

39 public involvement process (e.g., public meetings) to identify new and significant issues for the 

40 SQN license renewal application environmental review. The NRC staff has not identified new 

41 and significant information on environmental issues related to operation of SQN during the 
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1 renewal term. The NRC staff also determined that information provided during the public 

2 comment period did not identify any new issue that requires site-specific assessment. 

3 4.15 Impacts Common to All Alternatives

4 This section describes the impacts that are considered common to all alternatives discussed in 

5 this SEIS, including the proposed action and replacement power alternatives. The continued 

6 operation of a nuclear power plant and replacement fossil fuel power plants both involve mining, 

7 processing, and the consumption of fuel, which results in comparative impacts (NRC 2013e). 

8 The termination of operations and the decommissioning of both a nuclear power plant and 

9 replacement fossil fueled power plants are also discussed in the following sections, as well as 

10 GHG emissions.

11 4.15.1 Fuel Cycles

12 This section describes the environmental impacts associated with the fuel cycles of the 

13 proposed action and replacement power alternatives. Most replacement power alternatives 

14 employ a set of steps in the utilization of their fuel sources, which can include extraction, 

15 transformation, transportation, and combustion. Emissions generally occur at each stage of the 

16 fuel cycle (NRC 2013e).

17 4.15.1.1 Uranium Fuel Cycle

18 The uranium fuel cycle issues applicable to SQN are discussed below and listed in Table 4–25.

19 Table 4–25. Issues Related to the Uranium Fuel Cycle

Issues 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

20 The uranium fuel cycle includes uranium mining and milling, the production of uranium 

21 hexafluoride, isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation 

22 of radioactive materials, and management of low-level wastes and high-level wastes related to 

23 uranium fuel cycle activities. The generic potential impacts of the radiological and 

24 nonradiological environmental impacts of the uranium fuel cycle and transportation of nuclear 

25 fuel and wastes are described in detail in NUREG–1437, Generic Environmental Impact 

26 Statement for License Renewal of Nuclear Plants (NRC 1996, 1999b, 2013c).

27 The NRC staff did not identify any new and significant information related to the uranium fuel 

28 cycle issues listed in Table 4–25 during its review of the applicant’s ER (TVA 2013g), the site 

29 visit, and the scoping process. Therefore, there are no impacts related to these issues beyond 

30 those discussed in the GEIS. For these Category 1 issues, the GEIS concludes that the 

31 impacts are SMALL, except for the issue, “Offsite radiological impacts (collective effects),” to 

32 which the NRC has not assigned an impact level. This issue assesses the 100-year radiation 
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1 dose to the U.S. population (i.e., collective effects or collective dose) from radioactive effluents 

2 released as part of the uranium fuel cycle for nuclear power plant during the license renewal 

3 term compared to the radiation dose from natural background exposure. There are no 

4 regulatory limits applicable to collective doses to the public from fuel-cycle facilities. The 

5 Commission has determined that the practice of estimating health effects on the basis of 

6 collective doses may not be meaningful. Fuel-cycle facilities are designed and operated to meet 

7 regulatory limits and standards. Therefore, the Commission has concluded that the collective 

8 impacts are acceptable and would not be sufficiently large to require the NEPA conclusion that 

9 the option of extended operation should be eliminated (78 FR 37282).

10 4.15.1.2 Replacement Power Plant Fuel Cycles

11 Fossil Fuel Energy Alternatives

12 Fuel cycle impacts for a fossil-fuel-fired plant result from the initial extraction of fuel, cleaning 

13 and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 

14 solid wastes from fuel combustion. These impacts are discussed in more detail in 

15 section 4.12.1.2 of the GEIS (NRC 2013e) and can generally include: 

16 • significant changes to land use and visual resources; 

17 • impacts to air quality, including release of criteria pollutants, fugitive dust, 

18 VOCs, and coalbed methane in the atmosphere; 

19 • noise impacts; 

20 • geology and soil impacts due to land disturbances and mining; 

21 • water resource impacts, including degradation of surface water and GW

22 quality; 

23 • ecological impacts, including loss of habitat and wildlife disturbances; 

24 • historic and cultural resources impacts within the mine footprint; 

25 • socioeconomic impacts from employment of both the mining workforce and 

26 service and support industries; 

27 • environmental justice impacts; 

28 • health impacts to workers from exposure to airborne dust and methane 

29 gases; and

30 • generation of coal and industrial wastes.

31 New Nuclear Energy Alternatives

32 Fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport of fuel to 

33 the facility, and management and ultimate disposal of spent fuel. The environmental impacts of 

34 the uranium fuel cycle are discussed above in Section 4.15.1.1.

35 Renewable Energy Alternatives

36 The “fuel cycle” for renewable energy facilities is difficult to define for technologies such as wind 

37 and solar because these natural resources exist regardless of any effort to harvest them for 

38 electricity production. Impacts from the presence or absence of these renewable energy 

39 technologies are oftendifficult to determine (NRC 2013e).
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1 4.15.2 Terminating Power Plant Operations and Decommissioning

2 This section describes the environmental impacts associated with the termination of operations 

3 and the decommissioning of a nuclear power plant and replacement power alternatives. All 

4 operating power plants will terminate operations and be decommissioned at some point after the 

5 end of their operating life or after a decision is made to cease operations. For the proposed 

6 action, license renewal would delay this eventuality for an additional 20 years beyond the 

7 current license periods, which ends in 2020 and 2021 for SQN Units 1 and 2, respectively. 

8 4.15.2.1 Existing Nuclear Power Plant

9 Environmental impacts from the activities associated with the decommissioning of any reactor

10 before or at the end of an initial or renewed license are evaluated in Supplement 1 of 

11 NUREG–0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 

12 Facilities Regarding the Decommissioning of Nuclear Power Reactors (NRC 2002a). 

13 Additionally, the incremental environmental impacts associated with decommissioning activities 

14 resulting from continued plant operation during the renewal term are discussed in the GEIS.

15 Table 4–26 lists the Category 1 issues in Table B–1 of 10 CFR Part 51, Subpart A, Appendix B 

16 that are applicable to SQN decommissioning following the license renewal term.

17 Table 4–26. Issues Related to Decommissioning

Issues 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 

18 Decommissioning would occur whether SQN were shut down at the end of its current operating 

19 license or at the end of the period of the license renewal term. TVA stated in its ER 

20 (TVA 2013a) that it is not aware of any new and significant information on the environmental 

21 impacts of SQN during the license renewal term. The staff has not found any new and 

22 significant information during its independent review of TVA’s ER, the site visit, or the scoping

23 process. Therefore, the NRC staff concludes that there are no impacts related to these issues, 

24 beyond those discussed in the GEIS. For all of these issues, the NRC staff concluded in the 

25 GEIS that the impacts are SMALL.

26 4.15.2.2 Replacement Power Plants

27 Fossil Fuel Energy Alternatives

28 The environmental impacts from the termination of power plant operations and 

29 decommissioning of a fossil-fuel-fired plant are dependent on the facility’s decommissioning 

30 plan. General elements and requirements for a fossil fuel plant decommissioning plan are 

31 discussed in section 4.12.2 of the GEIS and can include the removal of structures to at least 3 ft 

32 (1 m) below grade; removal of all coal, combustion waste, and accumulated sludge; removal of 

33 intake and discharge structures; and the cleanup and remediation of incidental spills and leaks 

34 at the facility. The decommissioning plan outlines the actions necessary to restore the site to a 
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1 condition equivalent in character and value to the greenfield or brownfield site on which the 

2 facility was first constructed (NRC 2013e).

3 The environmental consequences of decommissioning are discussed in section 4.12.2 of the 

4 GEIS and can generally include:

5 • short-term impacts on air quality and noise from the deconstruction of facility 

6 structures,

7 • short-term impacts on land use and visual resources,

8 • long-term reestablishment of vegetation and wildlife communities,

9 • socioeconomic impacts due to the decommissioning workforce and the 

10 long-term loss of jobs, and

11 • elimination of health and safety impacts on operating personnel and the 

12 general public.

13 New Nuclear Alternative

14 Termination of operations and decommissioning impacts for a nuclear plant include all activities 

15 related to the safe removal of the facility from service and the reduction of residual radioactivity 

16 to a level that permits release of the property under restricted conditions or unrestricted use and 

17 termination of a license (NRC 2013e). The environmental impacts of the uranium fuel cycle are 

18 discussed above in Section 4.15.1.

19 Renewable Alternative

20 Termination of power plant operation and decommissioning for renewable energy facilities 

21 would be similar to the impacts discussed for fossil-fuel-fired plants above. Decommissioning 

22 would involve the removal of facility components and operational wastes and residues in order 

23 to restore the site to a condition equivalent in character and value to the greenfield or brownfield 

24 site on which the facility was first constructed (NRC 2013e).

25 4.15.3 Greenhouse Gas Emissions and Climate Change

26 The following sections discuss GHG emissions released from operation of SQN and the 

27 environmental impacts that could occur from changes in climate conditions. The cumulative 

28 impacts of GHG emissions on climate are discussed in Section 4.16.12, Global Climate 

29 Change. 

30 4.15.3.1 Greenhouse Gas Emissions From the Proposed Project and Alternatives

31 Gases found in the Earth’s atmosphere that trap heat and play a role in Earth’s climate are 

32 collectively termed GHGs. GHG include, but are not limited to, carbon dioxide (CO2), methane 

33 (CH4), nitrous oxide (N2O), water vapor (H2O), hydrofluorocarbons (HFC), perfluorocarbons 

34 (PFC), and sulfur hexafluoride (SF6). Earth’s climate responds to changes in concentration of 

35 GHG in the atmosphere as GHGs affect the amount of energy absorbed and heat trapped by 

36 the atmosphere. Increasing GHG concentration in the atmosphere generally increases Earth’s 

37 surface temperature. Atmospheric concentrations of CO2, CH4, and N2O have significantly 

38 increased since 1750 (IPCC 2007c). CO2, CH4, N2O, HFCs, PFCs, and SF6 (termed long-lived 

39 GHGs) are well mixed throughout Earth’s atmosphere and their impact on climate is long lasting

40 as a result of their long atmospheric lifetime (EPA 2009b). CO2 is of primary concern for global 

41 climate change because of its long atmospheric lifetime and it is the primary gas emitted as a 

42 result of human activities (USGCRP 2009). Climate change research indicates that the cause 
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1 of the Earth’s warming over the last 50 years is due to the buildup of GHGs in atmosphere 

2 resulting from human activities (USGCRP 2014).

3 Proposed Action

4 Operations at SQN emit GHG directly and indirectly. In accordance with E.O. 13514 (Federal 

5 Leadership in Environmental, Energy, and Economic Performance), the Tennessee Valley 

6 Authority (TVA), a Federal agency and owner of SQN, is required to measure and report GHG 

emissions resulting from SQN’s direct and indirect activities.5 7 SQN’s direct GHG emissions 

8 result from stationary combustion sources (auxiliary boilers and diesel generators), mobile 

9 combustion sources (fleet vehicles), and fugitive fluorinated gases (electrical and refrigerant 

10 equipment). Indirect GHG emissions originate from mobile combustion sources (workforce 

11 commuting and official travel), off-site municipal solid waste disposal, contracted wastewater

12 treatment, purchased electricity, and transmission and distribution losses of the consumed 

13 purchased electricity. 

14 Annual GHG emissions are presented in Table 4–27 for 2008-2012. These quantified GHG 

15 emission estimates include the direct and indirect sources discussed above that emit long-lived 

GHGs, presented as CO2 equivalents (CO2e).6 16 The GHG emission estimates presented do not 

17 include potential emissions as result of leakage, servicing, repair, and disposal of refrigerant 

18 equipment at SQN (CEQ 2012). Ozone depleting substances, such as chlorofluorocarbons and 

19 hydrochlorofluorocarbons (HCFC), are present at SQN and can potentially be emitted 

20 (TVA 2013i). However, estimating GHG emissions from these substances is complicated due 

21 their ability to deplete ozone, which is also a GHG, making their global warming potentials

22 (GWPs) difficult to quantify. These ozone depleting substances are regulated by the CAA under 

23 Title VI. TVA maintains a program to manage stationary refrigeration appliances at SQN to 

24 recycle, recapture, and reduce emissions of ozone depleting substances and is in compliance 

25 with Section 608 of the CAA (TVA 2013a). 

26 In response to the NRC’s order (Order Number: EA-12-049) titled “Order Modifying Licenses 

27 with Regard to Requirements for Mitigation Strategies for Beyond-Design-Basis External 

28 Events,” TVA will install one large blackout diesel generator and up to three EDGs at each unit 

29 in 2016 to mitigate and cope with an extended station blackout event (TVA 2013i). The diesel 

30 generators are expected to be operated only in the event of loss of AC power to the site and 

31 during periodic routine testing. Periodic testing of the diesel generators is estimated to emit 

32 200 MT CO2e/year (TVA 2013i, 2013d). 

33 The additional GHG emissions from routine testing of the diesel generators will be minor. As 

34 there are no plans for refurbishment at SQN for license renewal, GHG emissions are not 

35 expected beyond those direct and indirect sources discussed above. Table 4–27 provides 

36 emissions indicative of those expected during the extended period of operation.

 

5 GHG direct and indirect emission categories are defined in the 2012 Federal Greenhouse Gas Accounting and Reporting 

Guidance Technical Support Document. The direct and indirect emission classification was retained for SQN’s GHG emissions 

inventory and GHG emission discussions in this EIS. http://www.whitehouse.gov/sites/default/files/microsites/ceq/

revised_federal_greenhouse_gas_accounting_and_reporting_guidance_060412.pdf. 

6 Carbon dioxide equivalents (CO2e) is a metric used to compare the emissions of GHG based on their global warming potential 

(GWP). GWP is a measure used to compare how much heat a GHG traps in the atmosphere. GWP is the total energy that a gas 

absorbs over a period of time, compared to carbon dioxide. Carbon dioxide equivalents is obtained by multiplying the amount of 

the GHG by the associated GWP. For example, the GWP of CH4 is estimated to be 21; therefore, 1 ton of CH4 emission is 

equivalent to 21 tons of CO2 emissions.
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Table 4–27. Estimated GHG emissions(a) 1 from Operations at SQN

Year CO2e(b) (MT/year)

2008 23,250

2009 24,640

2010 24,250

2011 28,720

2012 25,000

(a) GHG emission estimates presented include indirect and direct GHG emissions. Direct GHG emission from 

stationary combustion sources at SQN reported to the U.S. Environmental Protection Agency were added to the 

GHG inventory provided by TVA 2013d.

(b) Values rounded to the nearest tens.

Source: TVA 2013i, 2013t

2 No-Action Alternative

3 When the plant stops operating, there will be a reduction in GHG emissions from activities 

4 related to plant operation, such as use of diesel generators and employee vehicles. GHG 

5 emissions are anticipated to be less than that presented in Table 4–27. 

6 NGCC Alternative

7 As discussed in the Section 2.3, the NRC staff evaluated an NGCC alternative that consists of 

six 400 MW units. The 2013 GEIS (NRC 2013e) presents lifecycle7 8 GHG emissions associated 

9 with natural gas power generation. As presented in Table 4.12-5 of the GEIS, lifecycle GHG 

10 emissions from natural gas can range from 120 to 930 g carbon equivalent per kilowatt-hour 

11 (Ceq/kWh). The EPA has developed standard emission factors that relate the quantity of 

12 released pollutants to a variety of regulated activities (EPA 2000). Using these emission 

13 factors, the NRC staff estimates that operation of six 400-MW NGCC units will directly emit 

14 9.7 MMT of CO2e per year.

15 SCPC Alternative

16 As discussed in Section 2.4 of this SEIS, the NRC staff evaluated an SCPC alternative that 

17 consists of two to four SCPC units with a total output of 2,400 MW. The 2013 revised GEIS

18 presents lifecycle GHG emissions associated with coal power generation. As presented in 

19 Table 4.12-4 of the GEIS, lifecycle GHG emissions from coal power generation can range from 

20 264 to 1689 grams of carbon equivalent per kilowatt-hour (g Ceq/kWh). The NRC staff estimates 

21 that operation of two to four SCPC units will directly emit 17.5 MMT of CO2e per year.

22 New Nuclear Alternative

23 As discussed in Section 2.5, the NRC staff evaluated the new nuclear plant alternative that 

24 would consist of two units with approximate generating capacity of 1,200 MW each. The 2013 

25 revised GEIS presents lifecycle GHG emissions associated with nuclear power generation. As 

26 presented in Table 4.12-4 through 4.12-6 of the GEIS, lifecycle GHG emissions from nuclear 

 

7 Lifecycle carbon emissions analyses consider construction, operation, decommissioning and associated processing of fuel (gas, 

coal, etc.).
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1 power generation can range from 1 to 288 g Ceq/kWh. GHG emissions from operation of the 

2 new nuclear power plant alternative would be similar to the GHG emissions from operation of

3 SQN presented in Table 4–27.

4 Combination Alternative

5 As discussed in Section 2.6, the NRC staff evaluated a combination alternative that relies on 

6 wind and solar capacity to replace SQN. The total installed solar photo voltaic (PV) capacity 

7 would be 2,000 to 2,900 MW and total installed wind capacity would be 4,700 to 6,300 MW. 

8 The 2013 revised GEIS presents lifecycle GHG emissions associated with renewable power 

9 generation. As presented in Table 4.12-6 of the GEIS, lifecycle GHG emissions from wind 

10 power range from 2 to 81 g Ceq/kWh and solar PV from 5 to 217 g Ceq/kWh. Beyond 

11 maintenance of the wind turbines and solar PV (e.g. serving equipment or repairs), there would 

12 be no direct emissions associated with operations from wind generation or from solar PV.

13 Summary of GHG emissions from the proposed action and alternatives

14 Table 4–28 presents the direct GHG emissions from operation of the proposed action (license 

15 renewal) and alternatives. As quantified in the table, nuclear power plants emit a substantially 

16 lower amount of GHG emissions than electrical generation based on fossil fuels. The NGCC 

17 and SCPC direct GHG emissions estimates do not consider carbon capture technologies that 

18 could capture and remove CO2. In 2012, the EPA issued a final GHG Tailoring Rule to address 

19 GHG emissions from stationary sources under the CAA permitting requirements; the GHG 

20 Tailoring Rule establishes when an emission source will be subject to permitting requirements 

21 and control technology to reduce GHG emissions. The National Energy Technology Laboratory 

22 (NETL) estimates that carbon capture technologies can remove as much as 90 percent of CO2

23 (NETL 2010a); if carbon capture technologies were to be installed for the NGCC and SCPC 

24 alternatives, GHG emissions would still be substantially greater than the proposed action, the 

25 new nuclear alternative, and the combination alternative.

Table 4–28. Direct(a) 26 GHG Emissions from Operation of the Proposed Action and 

27 Alternatives

Technology CO2e (MT/year)

SQN continued operation(b) 700

NGCC 9,743,500

SCPC 17,538,400

New Nuclear 700

Combination Alternative 0

(a) GHG emissions presented include only direct emissions from operation of the electricity generating technology. 

For the NGCC and SCPC alternatives, GHG emission result from direct combustion of the gas and coal. For the 

proposed action and new nuclear alternative; direct GHG emissions are a result of combustion sources such as 

diesel generators, auxiliary boilers, etc.

(b) Direct emissions from continued operation include emissions from stationary sources (diesel generators and 

auxiliary boilers). Data provided reflect the highest direct GHG emissions from the most recent 5 years of SQN 

operation (Table 3.3.2-1, TVA 2013i, 2013d). 

Source: TVA 2013i, 2013d
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1 4.15.3.2 Climate Change Impacts to Resource Areas

2 Climate change is the decades or longer change in climate measurements (temperature, 

3 precipitation, etc.) that has been observed on a global, national, and regional level (EPA 2012; 

4 IPCC 2007c; USGCRP 2014). Climate change can vary regionally, locally, and seasonally 

5 depending on local, regional, and global factors. Just as the regional climate differs throughout 

6 the world, the impacts of climate change can vary between locations. 

7 On a global level, from 1901 to 2011, average surface temperatures have risen at a rate of 

8 0.14  ̊F per decade (0.08 °C per decade), and total annual precipitation has increased at an 

9 average rate of 2.3 percent per decade (EPA 2012). The observed global change in average 

10 surface temperature and precipitation has been accompanied by an increase in sea surface 

11 temperatures, a decrease in global glacier ice, increase in sea level, and changes in extreme 

12 weather events. Such extreme events include an increase in frequency of heat waves, heavy 

13 precipitation, and minimum and maximum temperatures (EPA 2012; IPCC 2007c;

14 USGCRP 2009).

15 In the United States, the U.S Global Change Research Program (USGCRP) reports that from 

16 1895 to 2012, average surface temperature has increased by 1.3 °F to 1.9 °F (0.72 to 1.06 °C) 

17 and since 1900, average annual precipitation has increased by 5 percent (USGCRP 2014). On 

18 a seasonal basis, warming has been the greatest in winter and spring. Since the 1980s, an 

19 increase in the length of the freeze-free season, the period between the last occurrence of 32  ̊F 

20 (0 °C) in the spring and first occurrence of 32  ̊F (0 °C) in the fall, has been observed for the 

21 contiguous United States; between 1991 and 2011 the average freeze-free season was 10 days 

22 longer than between 1901 and 1960 (USGCRP 2014). Since the 1970s, the United States has 

23 warmed at a faster rate as the average surface temperature rose at an average rate of 0.31 to 

24 0.45  ̊F (0.17 to 0.25 °C) per decade. In addition, the year 2012 was the warmest on record 

25 (USGCRP 2014). Observed climate related changes in the United States include increases in 

26 the frequency and intensity of heavy precipitation, earlier onset of spring snowmelt and runoff, 

27 rise of sea level in coastal areas, increase in occurrence of heat waves, and a decrease in 

28 occurrence of cold waves (EPA 2012; NOAA 2013; USGCRP 2009, 2014).

29 Temperature data indicates that the Southeast region, where SQN is located, did not 

30 experience significant warming overall for the time period from 1900 to 2012 (USGCRP 2014). 

31 The lack of warming in the Southeast has been termed the “warming hole” (NOAA 2013). 

32 However, since 1970, average annual temperatures in the Southeast have risen by 2  ̊F (1.1 °C) 

33 and accompanied by an increase in the number of days with daytime maximum temperatures 

34 above 90 °F (32.2 °C) and nights above 75 °F (23.9 °C) (IPCC 2007c; NOAA 2013; 

35 USGCRP 2009, 2014). This atmospheric warming trend is also evident for the SQN site and 

36 vicinity. Based on data from the SQN meteorological station spanning the period of 1972 

37 through 2012, linear regression analysis indicates that the average daily minimum temperature 

38 has increased about 3.4°F (1.9°C), whereas the average daily maximum temperature has 

39 increased about 2.5°F (1.4°C) (TVA 2013i). Average annual precipitation data for the Southeast 

40 does not exhibit an increasing or decreasing trend for the long term period (1895-2011) or a 

41 trend in the length of the freeze-free season (NOAA 2013). Nevertheless, since the mid-1970s, 

42 the number of freezing days has declined by four to seven days in the region (USGCRP 2009). 

43 On the other hand, average precipitation in the region has increased in the fall and decreased in 

44 the summer (NOAA 2013 and USGCRP 2009). The number of tornadoes in the Southeast 

45 region has increased since the 1950s; however, the observed increasing tornado trend is not 

46 statistically significant and may be a result of better reporting of tornadoes (USGCRP 2014).

47 GHG emission concentration and climate models are commonly used to project possible climate 

48 change. Climate models indicate that over the next few decades, temperature increases will 
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1 continue due to current GHG emissions concentrations in the atmosphere (USGCRP 2014) 

2 Over the longer term, the magnitude of temperature increases and climate change effects will 

3 depend on both past and future GHG emission scenarios (IPCC 2007c; USGCRP 2009, 2014). 

4 Climate models project a continued increase in global surface temperatures, more frequent and 

5 long-lasting heat waves, continued increase in sea level, continued decline in arctic sea ice, an 

6 increase in heavy precipitation events, and an increased frequency of severe droughts.

7 For the license renewal period of SQN, climate model simulations (between 2021-2050 relative 

8 to the reference period (1971-1999)) indicate an increase in annual mean temperature in the 

9 Southeast region from 1.5-3.5  ̊F (0.83-1.9 °C) (NOAA 2013). The predicted increase in 

10 temperature during this time period occurs for all seasons with the largest increase occurring in

11 the summertime (June, July, and August). Climate model simulations (for the time period 

12 2021-2050) suggest spatial differences in annual mean precipitation changes with some areas 

13 experiencing an increase and others a decrease in precipitation (for Tennessee, a 0 to 

14 3 percent increase in annual mean precipitation is predicted); however, these changes in 

15 precipitation were not significant and the models indicate changes that are less than normal 

16 year to year variations (NOAA 2013). While future regional changes in precipitation are difficult 

17 to predict, the USGCRP reports that storm tracks are expected to shift northward, increases in 

18 heavy precipitation events will continue, the number of dry days between rainfalls will increase, 

19 and an increase in drought are expected (USGCRP 2014). Higher temperatures increase 

20 evaporation that contributes to dry conditions and a warmer climate allows more moisture to be 

21 held in the atmosphere because of warmer air’s ability to hold more water vapor 

22 (USGCRP 2009). 

23 Changes in climate have broader implications for public health, water resources, land use and 

24 development, and ecosystems. For instance, changes in precipitation patterns and increase in 

25 air temperature can affect water availability and quality, distribution of plant and animal species, 

26 and land-use patterns and land-cover, which can in turn affect terrestrial and aquatic habitats. 

27 The sections below discuss how future climate change may impact air quality, water resources, 

28 land-use, terrestrial resources, aquatic resources, and human health in the region of interest for 

29 SQN. Although there is uncertainty in the exact future climate change scenario, the discussions 

30 provided below demonstrate the potential implications of climate change on resources. 

31 Air Quality

32 Air pollutant concentrations result from complex interactions between physical and dynamic 

33 properties of the atmosphere, land, and ocean. The formation, transport, dispersion, and 

34 deposition of air pollutants depend in part on weather conditions (IPCC 2007a). Air pollutant 

35 concentrations are sensitive to winds, temperature, humidity, and precipitation (EPA 2009b). 

36 Hence, climate change can impact air quality as a result of the changes in meteorological 

37 conditions. 

38 Ozone has been found to be particularly sensitive to climate change (EPA 2009a; IPCC 2007a; 

39 USGCRP 2014). Ozone is formed as a result of the chemical reaction of nitrogen oxides (NOx) 

40 and volatile organic compounds (VOCs) in the presence of heat and sunlight. Sunshine, high 

41 temperatures, and air stagnation are favorable meteorological conditions to higher levels of 

42 ozone (EPA 2009, IPCC 2007a). The emission of ozone precursors also depends on 

43 temperature, wind, and solar radiation (IPCC 2007a); both NOx and biogenic VOC emissions 

44 are expected to be higher in a warmer climate (EPA 2009a). Warmer climate and weaker air 

45 circulation is conducive to higher ozone levels. Although surface temperatures are expected to 

46 increase in the Southeast region, ozone levels will not necessarily increase since ozone 

47 formation is also dependent on the relative amount of precursors available (NASA 2004). 

48 Regional air quality modeling indicates that the Southern regions of the U.S. can experience an 
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1 increase in ozone concentration by the year 2050 (Tagaris, 2009). However, air quality 

2 projections (particularly ozone and PM2.5) are uncertain and indicate that concentrations are 

3 driven primarily by emissions rather than by physical climate change (IPCC 2013).

4 Land Use

5 Changes or fluctuations in river and lake water levels could result in land use changes along 

6 affected water bodies as well as the possible loss of man-made infrastructure. This could 

7 necessitate infrastructure redesign and replacement, or its relocation. The Southeast region 

8 has experienced an expanding population and regional land-use changes faster than any other 

9 region in the U.S., which has resulted in reduced land available for agriculture and forests 

10 (USGCRP 2014). As noted by the U.S. Global Change Research Program (USGCRP 2009), 

11 the projected rapid rate and large amount of climate change over the next century will challenge 

12 the ability of society and natural systems to adapt. For example, it is difficult and expensive to 

13 alter or replace infrastructure designed to last for decades (such as buildings, bridges, roads, 

14 and reservoirs) in response to continuous and/or abrupt climate change. Energy and 

15 transportation infrastructure and other property could also be adversely affected. Projections in 

16 land-use changes, between 2010 and 2050, indicate that the Southeast region will experience a 

17 continued increase in exurban and suburban development and a decrease in forests and 

18 cropland land cover (USGCRP 2014). However, the limited extent of climate change that may 

19 occur during the 20-year license renewal term would not likely cause land use conditions to 

20 change in the vicinity of SQN.

21 Water Resources

22 Predicted changes in the timing, intensity, and distribution of precipitation would be likely to 

23 result in changes in surface water runoff affecting water availability across the Southeast. 

24 Specifically, while average precipitation during the fall has increased by 30 percent since about 

25 1900, summer and winter precipitation has declined by about 10 percent across the eastern 

26 portion of the region including eastern Tennessee (USGCRP 2009). A continuation of this trend 

27 coupled with predicted higher temperatures during all seasons (particularly the summer 

28 months), would reduce GW recharge during the winter, produce less runoff and lower stream 

29 flows during the spring, and potentially lower GW base flow to rivers during the drier portions of 

30 the year (when stream flows are already lower). As cited by the USGCRP, the loss of moisture 

31 from soils because of higher temperatures along with evapotranspiration from vegetation is 

32 likely to increase the frequency, duration, and intensity of droughts across the region into the 

33 future (USGCRP 2009, USGCRP 2014). Changes in runoff in a watershed along with reduced 

34 stream flows and higher air temperatures all contribute to an increase in the ambient 

35 temperature of receiving waters. Annual runoff and river-flow are projected to decline in the 

36 Southeast region (USGCRP 2014). Land use changes, particularly those involving the 

37 conversion of natural areas to impervious surface, exacerbate these effects. These factors 

38 combine to affect the availability of water throughout a watershed, such as that of the 

39 Tennessee River, for aquatic life, recreation, and industrial uses. Additionally, Tennessee is a 

40 karst rich state and the aquifers are a significant source of domestic water to residents; changes 

41 in precipitation patterns and drought conditions can impact this GW resource (TWRA 2009). 

42 While changes in projected precipitation for the Southeast region are uncertain, the USGCRP 

43 has reasonable expectation that there will be reduced water availability due to the increased 

44 evaporative losses from rising temperatures alone (USGCRP 2014). For the 2010 to 2060 

45 period, net water supply availability in the Southeast region is projected to decrease; specifically 

46 water availability in eastern Tennessee is expected to decrease by 2.5 to 5 percent 

47 (USGCRP 2014). 
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1 Terrestrial Resources

2 As described above, an increase in annual mean temperature combined with less rainfall will 

3 increase the frequency, duration, and intensity of drought in the Southeast. As the climate 

4 changes, terrestrial resources will either be able to tolerate the new physical conditions, such as 

5 less water availability, or shift their population range to new areas with a more suitable climate, 

6 or decline and perhaps be extirpated from the area. Some species may be more susceptible to 

7 changes in climate. For example, migratory birds that travel long distances may not be able to 

8 pick up on environmental clues that a warmer, earlier spring is occurring in the United States 

9 while the birds are still overwintering in the tropics. Fraser et al. (2013) found that songbirds 

10 overwintering in the Amazon did not leave their winter sites earlier, even when spring sites in 

11 the eastern United States experienced a warmer spring. As a result, the song birds missed 

12 periods of “peak food” availability. Special status species and habitats, such as those that are 

13 Federally protected by the ESA, would likely be more sensitive to climate changes because 

14 these species’ populations are already experiencing threats that are endangering their 

15 continued existence throughout all or a significant portion of their ranges. Because of this, 

16 these species populations are already experiencing reduced genetic variability that could 

17 prohibit them from adapting to and surviving amidst habitat and climate changes. Climate 

18 changes could also favor non-native invasive species and promote population increases of 

19 insect pests and plant pathogens, which may be more tolerant to a wider range of climate 

20 conditions or have range limits that are set by extreme cold temperatures or ice cover (Bradley 

21 et al. 2010; Hellman et al. 2008). Physiological stressors associated with climate change may 

22 also exacerbate the effects of other existing stressors in the natural environment, such as those 

23 caused by habitat fragmentation, nitrogen deposition and runoff from agriculture, and air 

24 emissions.

25 Aquatic Resources

26 The potential effects of climate change described above for water resources, whether from 

27 natural cycles or man-made activities, could result in changes that would affect aquatic 

28 resources in the Tennessee River. Raised air temperatures could result in higher water 

29 temperatures in the Tennessee River reservoirs. For instance, TVA found that a 1 °F (0.5 °C) 

30 increase in air temperature resulted in an average water temperature increase between 0.25 °F 

31 and 0.5 °F (0.14 °C and 0.28 °C) in the Chickamauga Reservoir (TVA 2013i). Higher water 

32 temperatures would increase the potential for thermal effects on aquatic biota and, along with 

33 altered river flows, could exacerbate existing environmental stressors, such as excess nutrients 

34 and lowered dissolved oxygen associated with eutrophication (NCADAC 2013). Even slight 

35 changes could alter the structure of the aquatic communities in the reservoir. As discussed 

36 above under “terrestrial resources,” special status species, such as those that are Federally 

37 protected under the ESA, would be more sensitive to climate changes. Invasions of non-native 

38 species that thrive under a wide range of environmental conditions could further disrupt the 

39 current structure and function of aquatic communities (NRC 2013).

40 Historic and Cultural Resources

41 Changes or fluctuations in river and lake water levels because of climate change could result in 

42 the disturbance or loss of historic and cultural resources from flooding, erosion, inundation, or 

43 drying out. Because of water-level changes, some resources could be lost before they could be 

44 documented or otherwise studied. However, the limited extent of climate change that may 

45 occur during the 20-year license renewal term would not likely result in any significant loss of 

46 historic and cultural resources at SQN.
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1 Socioeconomics

2 Rapid changes in climate conditions could have an impact on the availability of jobs in certain 

3 industries. For example, tourism and recreation are major job creators in some regions, 

4 bringing significant revenue to regional economies. Across the nation, fishing, hunting, and 

5 other outdoor activities make important economic contributions to rural economies and are also 

6 a part of the cultural tradition. A changing climate would mean reduced opportunities for some 

7 activities in some locations and expanded opportunities for others. Hunting and fishing 

8 opportunities could also change as animals’ habitats shift and as relationships among species 

9 are disrupted by their different responses to climate change (USGCRP 2014). Water10 dependent recreation could also be affected (USGCRP 2009). The USGCRP reports that 

11 climate change in the Southeast region by the year 2050 could create unfavorable conditions for 

12 summertime outdoor recreation and tourism activity (USGCRP 2014). However, the limited 

13 extent of climate change that may occur during the 20-year license renewal term would not 

14 likely cause any significant changes in socioeconomic conditions in the vicinity of SQN.

15 Human Health

16 Increasing temperatures because of changes in climate conditions could have an impact on 

17 human health. The limited extent of changes in climate conditions that may occur during the 

18 license renewal term would not likely result in any change to the impacts discussed in 

19 Section 4.11 from SQN’s radioactive and non-radioactive effluents. Increased water 

20 temperatures may increase the potential for adverse effects of thermophilic organisms that can 

21 be a threat to human health.

22 Environmental Justice

23 Rapid changes in climate conditions could disproportionately affect minority and low-income 

24 populations. The USGCRP (2009) indicates that “infants and children, pregnant women, the 

25 elderly, people with chronic medical conditions, outdoor workers, and people living in poverty 

26 are especially at risk from a variety of climate-related health effects.” Examples of these effects 

27 include increased heat stress, air pollution, extreme weather events, and diseases carried by 

28 food, water, and insects. The greatest health burdens related to climate change are likely to fall 

29 on the poor, especially those lacking adequate shelter and access to other resources such as 

30 air conditioning. Elderly poor people on fixed incomes are more likely to have debilitating 

31 chronic diseases or limited mobility. In addition, the elderly have a reduced ability to regulate 

32 their own body temperature or sense when they are too hot. According to the USGCRP (2009), 

33 they “are at greater risk of heart failure, which is further exacerbated when cardiac demand 

34 increases in order to cool the body during a heat wave.” The USGCRP study also found that 

35 people taking medications, such as diuretics for high blood pressure, have a higher risk of 

36 dehydration (USGCRP 2009). The USGCRP (2014) study reconfirmed the previous report 

37 findings regarding the risks of climate change on low-income populations, and also warns that 

38 climate change could affect the availability and access to local plant and animal species thus 

39 impacting the people that have historically depended on them for food or medicine 

40 (USGCRP 2014). However, due to the limited amount of expected changes in the environment 

41 during the 20-year license renewal term, minority and low-income populations at SQN are not 

42 likely to experience disproportionately high and adverse impacts from climate change.

43 4.16 Cumulative Impacts of the Proposed Action

44 As described in Section 1.4 of this SEIS, the NRC has approved a revision to its environmental 

45 protection regulation, 10 CFR Part 51, “Environmental protection regulations for domestic 

46 licensing and related regulatory functions.” This revision amends Table B–1 in Appendix B, 
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1 Subpart A, to 10 CFR Part 51 by adding a new Category 2 issue, “Cumulative impacts,” to 

2 evaluate the potential cumulative impacts of license renewal. 

3 The NRC staff considered potential cumulative impacts in the environmental analysis of 

4 continued operation of the SQN during the 20-year license renewal period. Cumulative impacts 

5 may result when the environmental effects associated with the proposed action are overlaid or 

6 added to temporary or permanent effects associated with other past, present, and reasonably 

7 foreseeable actions. Cumulative impacts can result from individually minor, but collectively 

8 significant, actions taking place over a period of time. It is possible that an impact that may be 

9 SMALL by itself could result in a MODERATE or LARGE cumulative impact when considered in 

10 combination with the impacts of other actions on the affected resource. Likewise, if a resource 

11 is regionally declining or imperiled, even a SMALL individual impact could be important if it 

12 contributes to or accelerates the overall resource decline.

13 For the purposes of this cumulative analysis, past actions are those before the receipt of the

14 license renewal application. Present actions are those related to the resources at the time of 

15 current operation of the power plant, and future actions are those that are reasonably 

16 foreseeable through the end of plant operation, including the period of extended operation. 

17 Therefore, the analysis considers potential impacts through the end of the current license terms, 

18 as well as the 20-year renewal license terms. The geographic area over which past, present, 

19 and reasonably foreseeable actions would occur depends on the type of action considered and 

20 is described below for each resource area.

21 To evaluate cumulative impacts, the incremental impacts of the proposed action, as described 

22 in Sections 4.1 to 4.13, are combined with other past, present, and reasonably foreseeable 

23 future actions regardless of which agency (Federal or non-Federal) or person undertakes such 

24 actions. The NRC staff used the information provided in the TVA’s ER; responses to requests 

25 for additional information; information from other Federal, State, and local agencies; scoping

26 comments; and information gathered during the visits to the SQN site to identify other past, 

27 present, and reasonably foreseeable actions. To be considered in the cumulative analysis, the 

28 NRC staff determined if the project would occur within the noted geographic areas of interest 

29 and within the period of extended operation, was reasonably foreseeable, and if there would be 

30 potential overlapping effect with the proposed project. For past actions, consideration within the 

31 cumulative impacts assessment is resource- and project-specific. In general, the effects of past 

32 actions are included in the description of the affected environment in Chapter 3, which serves as 

33 the baseline for the cumulative impacts analysis. However, past actions that continue to have 

34 an overlapping effect on a resource potentially affected by the proposed action are considered 

35 in the cumulative analysis.

36 Other actions and projects identified during this review and considered in the NRC staff’s 

37 analysis of the potential cumulative effects are described in Appendix E. Not all actions or 

38 projects listed in Appendix E are considered in each resource area because of the uniqueness 

39 of the resource and its geographic area of consideration. 

40 4.16.1 Air Quality and Noise

41 This section addresses the direct and indirect effects of license renewal on air quality and noise 

42 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

43 actions. As described in Section 4.3, the incremental impacts on air quality and noise levels 

44 from the proposed license renewal would be SMALL. The geographic area considered in the 

45 cumulative air quality analysis is the county of the proposed action, as air quality designations 

46 for criteria air pollutants are generally made at the county level. Counties are further grouped 

47 together based on a common airshed—known as an air quality control region (AQCR)—to 
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1 provide for the attainment and maintenance of the National Ambient Air Quality Standards 

2 (NAAQS). The SQN site is located in Hamilton County, Tennessee, which is part of the 

3 Chattanooga Interstate AQCR (40 CFR 81.42, “Chattanooga Interstate Air Quality Control 

4 Region”); this AQCR also includes several counties in Georgia.

5 4.16.1.1 Air Quality

6 Section 3.3.2 presents a summary of the air quality designation status for Hamilton County. As 

7 noted in Section 3.3.2, the EPA regulates six criteria pollutants under the NAAQS, including 

8 carbon monoxide, lead, nitrogen dioxide, ozone, sulfur dioxide, and particulate matter (PM). 

9 Hamilton County is designated as unclassified or in attainment with respect to carbon monoxide, 

10 lead, sulfur dioxide, ozone, and PM, ≤ 10 micrometers (μm) (PM10) (40 CFR 81.343). Hamilton 

11 County is a non-attainment area with respect to the 1997 annual PM, ≤ 2.5 μm (PM2.5) standard 

12 (40 CFR Part 81.343, “Tennessee”).

13 Criteria pollutant air emissions from the SQN site are presented in Section 3.3.2. These 

14 emissions are from permitted sources, including two cooling towers, a carpenter shop, as well 

15 as emissions from blasting operations, insulator saws, auxiliary boilers, and several emergency 

16 or blackout diesel generators (TVA 2013a). Section 4.3.1.1 noted that, except for limited 

17 emissions associated with new diesel generators being installed in response to lessons learned 

18 from the Fukushima incident, there would be no additional air emissions associated with the 

19 SQN license renewal because there is no planned site refurbishment. Therefore, cumulative 

20 changes to air quality in Hamilton County would be the result of changes to present-day 

21 emissions, as well as future projects and actions within the county.

22 Appendix E provides a list of present and reasonably foreseeable projects that could contribute 

23 to cumulative impacts to air quality. For example, the listed coal-fired energy projects and 

24 manufacturing facilities are presently operational and are sources of criteria air pollutants. 

25 Continued air emissions from existing projects and actions listed in Appendix E as well as 

26 proposed new source activities would contribute to air emissions in Hamilton County. 

27 Development and construction activities associated with regional growth of housing, business, 

28 and industry, as well as associated vehicular traffic, will also result in additional air emissions. 

29 Project timing and location, which are difficult to predict, affect cumulative impacts to air quality. 

30 However, permitting and licensing requirements, efficiencies in equipment, cleaner fuels, and 

31 various mitigation measures can be used to minimize cumulative air quality impacts.

32 Climate change can affect air quality as a result of changes in meteorological conditions. Air 

33 pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 

34 (EPA 2009b). As discussed in Section 4.14.3.2, ozone levels have been found to be particularly 

35 sensitive to climate change influences (EPA 2009a, IPCC 2007b). Sunshine, high 

36 temperatures, and air stagnation are favorable meteorological conditions leading to higher 

37 levels of ozone (EPA 2009a, IPCC 2007b). Although surface temperatures are expected to 

38 increase in the Southeast region, ozone levels will not necessarily increase since ozone 

39 formation is also dependent on the relative amount of precursors available (NASA 2004). The 

40 combination of higher temperatures, stagnant air masses, sunlight, and emissions of precursors 

41 may make it difficult to meet ozone NAAQS (USGCRP 2009). States, however, must continue 

42 to comply with the CAA and ensure air quality standards are met.

43 4.16.1.2 Noise

44 Section 3.3.3 presents a summary of noise sources at SQN and site vicinity. Noise emission 

45 sources from SQN include fans, turbine generators, transformers, cooling towers, compressors, 

46 emergency generators, main steam-safety relief valves, and emergency sirens. With the 

47 exception of emergency sirens, most of the noise sources are not audible at the site boundary 
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1 or are intermittent and considered a minor nuisance. As a major industrial facility, SQN noise 

2 emissions can reach 65–75 A-weighted decibels (dBA) levels on site, which attenuates with 

3 distance. Within the last 5 years, SQN has not received any noise-related complaints from 

4 operation (TVA 2013i). Additionally, future residents of the recreational vehicle (RV) park near 

5 the SQN site boundary, as identified in Appendix E, are not anticipated to be affected since 

6 most noise sources from SQN are not audible at the SQN site boundary. Occupants of the 

7 RV park will be the nearest residents to SQN. Beyond any local ordinances, there are no 

8 Federal regulations for public exposures to noise. As there are no planned refurbishment 

9 activities associated with license renewal, cumulative impacts to noise levels would be the result 

10 of continued operation sources from SQN and around the site, as well as future projects and 

11 actions in the vicinity of SQN.

12 Appendix E provides a list of present and reasonably foreseeable projects that could contribute 

13 to cumulative noise impacts. Development and construction activities associated with regional 

14 growth of housing, business, and industry, as well as associated vehicular traffic, will result in 

15 additional noise generation. Construction equipment, for instance, can result in noise levels in 

16 the range of 85–95 dBA; however, noise levels attenuate rapidly with distance such that at half 

17 a mile distance from construction equipment noise levels can drop to 51–61 dBA (NRC 2002). 

18 Therefore, contributions to noise levels from future actions are limited by projects in the vicinity 

19 of the SQN site. While the timing of these future activities is difficult to predict, noise emissions 

20 are expected to occur for short periods of time. Additionally, future residents of the RV park 

21 near the SQN property boundary are not anticipated to be affected since noise sources from 

22 SQN are not audible at the SQN site boundary.

23 Conclusion

24 Given that there is no planned site refurbishment associated with the SQN license renewal and, 

25 therefore, no expected changes in air emissions or noise levels beyond those noted for the 

26 operation of new diesel generators, cumulative air quality and noise impacts would be the result 

27 of changes to present-day and reasonably foreseeable projects and actions. As noted above, 

28 the timing and location of new projects, which are difficult to predict, affect cumulative impacts 

29 on air quality and noise levels. However, various strategies and techniques are available to limit 

30 air quality impacts. Also, noise abatement and controls can be incorporated to reduce noise 

31 impacts (HUD 2013, FHWA 2013). Therefore, the NRC staff concludes that the cumulative 

32 impacts from past, present, and reasonably foreseeable future actions on air quality and noise 

33 levels during the license renewal term would be SMALL.

34 4.16.2 Geology and Soils

35 This section addresses the direct and indirect effects of license renewal on geology and soils 

36 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

37 actions. As noted in Section 4.4.1, the TVA has no plans to conduct refurbishment or 

38 replacement actions. Ongoing operation and maintenance activities at the SQN site are 

39 expected to be confined to previously disturbed areas. Any geologic materials, such as 

40 aggregates used to support operation and maintenance activities, would be procured from local 

41 and regional sources. These materials are abundant in the region. Geologic conditions are not 

42 expected to change during the license renewal term. Thus, activities associated with continued 

43 operations are not expected to affect the geologic environment. Considering ongoing activities 

44 and reasonably foreseeable actions, the NRC staff concludes that the cumulative impacts on 

45 geology and soils during the SQN license renewal term would be SMALL.
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1 4.16.3 Water Resources

2 This section addresses the direct and indirect effects of license renewal on water resources 

3 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

4 actions. As described in Sections 4.5.1.1 and 4.5.1.2, the incremental impacts on water 

5 resources from continued operations of SQN, during the license renewal term would be SMALL. 

6 The NRC staff also conducted an assessment of other projects and actions for consideration in 

7 determining their cumulative impacts on water resources (see Appendix E). The geographic 

8 area considered for the surface water resources component of the cumulative impacts analysis 

9 spans the Tennessee River Basin (watershed) but focuses on the catchment area (i.e., the

10 Chickamauga Reservoir Catchment Area) for the reach of the Tennessee River from Watts Bar 

11 Dam to Chickamauga Dam and the potential for impacts to downstream users. As such, this 

12 review focused on those projects and activities that would withdraw water from or discharge

13 effluent to the Tennessee River or its tributaries (e.g., the Hiwassee River). For GW, the 

14 geographic area of interest comprises the local GW basin relative to the SQN site and 

15 Chickamauga Reservoir in which GW flows to discharge points, or is withdrawn through wells 

16 including residential and public water supply wells (e.g., Hixson Utility District). As such, this 

17 review focused on those projects and activities that would (1) withdraw water from or discharge 

18 waste water to the local GW basin relative to the SQN site and Chickamauga Reservoir or 

19 (2) use GW from the Hixson Utility District.

20 4.16.3.1 Surface Water Resources

21 Water resource managers must balance multiple conflicting water management objectives. 

22 Within the Tennessee River Basin, this includes demands for power generation, public water 

23 supply, industrial use, irrigation, recreation, flood protection, and instream flow requirements to 

24 sustain aquatic life (TVA 2011b). Specifically, Section 26a of the TVA Act requires that TVA 

25 approval be obtained before any construction activities can be carried out that affect navigation, 

26 flood control, or public lands along the shoreline of TVA-managed reservoirs or in the 

27 Tennessee River or its tributaries. TVA requires permits for intake structures and withdrawals 

28 from the Tennessee River, which enables system-wide tracking of water usage. As the operator 

29 of Chickamauga Reservoir and upstream and downstream dams, TVA controls the reservoir to 

30 maintain adequate water resources and manage water use conflicts and competing objectives 

31 under variable interannual and intraannual flow conditions (TVA 2013a, 2013q). These 

32 competing issues and their associated regulatory considerations are discussed in Section 3.5 of 

33 this SEIS.

34 The U.S. Geological Survey (USGS) and TVA have extensively studied water use in the 

35 Tennessee Valley (Hutson et al. 2004, TVA 2012g). The study, Water Use in the Tennessee 

36 Valley for 2010 and Projected Use in 2035 (TVA 2012g), considers present and reasonably 

37 foreseeable uses of water in the Tennessee River Basin. Projections are based on increasing 

38 resource demands for a growing population; changes in economics, manufacturing, technology, 

39 environmental regulations; and reservoir operations. Climate change was not included in this 

40 study but climate change implications have been considered by NRC staff as discussed later in 

41 this section.

42 Specifically, the largest use of surface water in the Tennessee River Basin is for thermoelectric 

43 power generation. According to TVA (2012g), tabulated surface water withdrawals for 

44 thermoelectric, industrial, public-supply, and irrigation water use in the basin’s Chickamauga 

45 Reservoir Catchment Area in 2010 were 1,591.37, 66.24, 31.33, and 0.53 mgd, respectively. 

46 Corresponding return flows, which includes pumped GW, were 1,724.21, 64.19, 16.34, and 

47 0.0 mgd, respectively. Return flows include effluent discharges from such sources as power 

48 plants, other industrial facilities, and municipal wastewater treatment plants.
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1 Thermoelectric power generation accounts for more than 90 percent of all withdrawals from the 

2 Chickamauga Reservoir Catchment Area. In 2010, cumulative surface water withdrawals from 

3 the Tennessee River Basin above Chickamauga Dam totaled 4,899 mgd. This volume is about 

4 15 percent of the mean annual flow (i.e., 21,000 mgd) through Chickamauga Dam. 

5 Corresponding consumptive use was 252 mgd, which is 5 percent of total withdrawn and 

6 approximately 1 percent of the mean annual flow through the dam. During the same period, the 

7 combined consumptive water use in the Watts Bar and Chickamauga Reservoir catchment 

8 areas, encompassing Watts Bar Nuclear Power Plant (WBN) Unit 1 and SQN, was estimated to 

9 total 22.93 mgd, which was 9 percent of all upstream consumptive uses (TVA 2012g).

10 By 2035, it is projected that water use will decrease by 21 percent overall from 2010 levels in 

11 the Tennessee River Basin. This is mostly attributable to declines in water demand for power 

12 generation based on the expected shut-down of coal-fired power plants with high withdrawal 

13 rates for once-through cooling systems. However, net (consumptive) water use is projected to 

14 increase by 51 percent due in part to future power plants switching to closed-cycle cooling 

15 systems (TVA 2012g). Although once-through systems return most of their withdrawn water to 

16 the source (minus evaporative losses of less than 3 percent), surface water withdrawals for 

17 closed-cycle cooling systems entail consumptive losses of greater than 50 percent, resulting in 

18 the return of less water (see Section 4.5.1.1). These impacts may be greater during times of 

19 drought, especially when temperatures are high. As there are no other power generation 

20 facilities in the Chickamauga Reservoir Catchment Area of the river basin, NRC staff would 

21 expect no decline in water use over the license renewal period for SQN. In fact, Watts Bar 

22 Unit 2 (WBN 2) is scheduled for completion in December 2015. Once full operations are 

23 achieved, water use for WBN Units 1 and 2 is projected to be 284 mgd, of which 40 mgd will be 

24 consumptive use (NRC 2013c). Combined with SQN’s annualized surface water consumptive 

25 use of 6 mgd (see Section 4.5.1.1), the total combined consumptive use in the Watts Bar and 

26 Chickamauga Reservoir Catchment Area could be as much as 46 mgd. Nevertheless, these 

27 combined, consumptive losses would still be a very small fraction of the mean annual flow of the 

28 Tennessee River as measured near the WBN site, which is equivalent to 17,800 mgd 

29 (NRC 2013c).

30 In contrast to water demand for thermoelectric power generation, demands for other uses are 

31 projected to increase throughout the whole of the river basin by 2035 because of population 

32 growth. Demands for public supply, other industrial, and irrigation water use are projected to 

33 increase by 215, 354, and 12 mgd, respectively. Total consumptive water use in the Tennessee 

34 River watershed is expected to increase by 241 mgd to 712 mgd by 2035. This consumptive 

35 use is approximately 8 percent of the total forecasted withdrawals within the watershed, and 

36 approximately 1.7 percent of the current mean annual discharge of the Tennessee River 

(i.e., 65,600 cfs (1,853 m3 37 /s), or 42,400 mgd) (NRC 2013c; TVA 2012g).

38 Water Quality Considerations

39 The concentration of chemical constituents in water samples collected in Chickamauga 

40 Reservoir adjacent to the SQN site are indicative of the cumulative impact of all upstream 

41 activities including industrial, agricultural, and municipal discharges. As presented in 

42 Section 3.5.1.3, the water quality of the reservoir is generally good. Nevertheless, the Hiwassee 

43 River embayment of Chickamauga Reservoir is identified by the Tennessee Department of 

44 Environment and Conservation (TDEC) as having an impaired use for fish consumption 

45 because of mercury, primarily attributable to atmospheric deposition and industrial sources. 

46 Upstream of SQN, Watts Bar Reservoir is listed as impaired for fish consumption because of 

47 polychlorinated biphenyls (PCBs) from industrial sources. Portions of the reservoir are also 

48 identified as impaired for fish consumption because of mercury and chlordane in contaminated 

49 sediments. The Emory River Arm of Watts Bar Reservoir is identified as impaired because of 
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1 arsenic, coal ash deposits, and aluminum, as well as mercury, PCBs, and chlordane 

2 (TDEC 2010, 2012). The Emory River Arm is the area of the reservoir most affected by the ash 

3 spill that occurred at TVA’s Kingston Fossil Plant in 2008.

4 As noted previously, further development in the basin and associated population growth is 

5 expected. Upstream development could lead to discharges to Chickamauga Reservoir that 

6 affect water quality. Development projects can result in water quality impacts if they increase 

7 sediment loading to nearby surface water bodies. The magnitude of cumulative impacts would 

8 depend on the nature and location of the actions relative to surface water bodies, the number of 

9 actions (facilities or projects), and whether facilities comply with regulating agency requirements 

10 (e.g., permitted discharge limits). However, the potential for unchecked development, 

11 particularly industrial development, would be limited during SQN’s license renewal term by 

12 TVA’s authority to regulate land use and development along the shoreline of the Tennessee 

13 River system (TVA 2013p). Moreover, new and modified industrial and large commercial 

14 facilities would be subject to regulation under the FWPCA. This would include 

15 TDEC-administered National Pollutant Discharge Elimination System (NPDES) permit limits on 

16 stormwater and point source discharges designed to be protective of surface water resources. 

17 Likewise, it is this regulatory framework that presently governs wastewater effluent and thermal 

18 discharges from SQN, WBN, and other major industrial facilities in the Tennessee River Basin. 

19 Climate Change Considerations With Respect to Water Resources

20 The NRC staff considered the U.S. Global Change Research Program’s (USGCRP’s) most 

21 recent compilation of the state of knowledge relative to global climate change effects 

22 (USGCRP 2009, 2014). For the Southeastern United States, the area of moderate to severe 

23 spring and summer drought increased by 12 percent and 14 percent, respectively, from 1975 to 

24 2008. Average temperatures have increased by 1.6 °F (0.9 °C) while annual precipitation has 

25 declined by about 8 percent. As part of its analysis, the NRC staff specifically considered the 

26 potential for climate change-related impacts on water resources and its implications specific to 

27 the Tennessee River Basin over the course of the SQN license renewal term. The operation of 

28 the dams and reservoirs by TVA on the river and its tributaries provide many benefits, but has 

29 resulted in increased water temperature and thermal stratification of some reservoirs during 

30 summer months. Water temperature in the Tennessee River above and below the SQN site 

31 fluctuates throughout the year in response to many factors. Air temperature and solar radiation 

32 are the dominant meteorological variables influencing river system water temperatures. For 

33 example, during July 1993, maximum air temperatures recorded in Chattanooga were above 

34 90 °F (32 °C) each day, with temperatures reaching as high as 104 °F (40 °C). During this 

35 period, all nine mainstem Tennessee River reservoirs had surface water temperatures that 

36 exceeded 86 °F (30 °C), and some had water temperatures as high as 90 °F (32 °C) 

37 (NRC 2013c). Relative to the Tennessee River system, historical records encompassing the 

38 Watts Bar–Chickamauga Reservoir Catchment Areas show a trend of increasing temperature 

39 over the last 40 years. Observations from TVA’s Sequoyah Meteorological Station for the years 

40 1972 through 2012 indicate an atmospheric warming trend. In general, the average daily 

41 minimum temperature has warmed slightly faster than the average daily mean and the average 

42 daily maximum. Since 1972 , linear regressions suggest that the average daily minimum 

43 temperature has increased about 3.4°F (1.9°C), whereas the average daily maximum has 

44 increased about 2.5°F (1.4°C) (TVA 2013i).

45 TVA has further analyzed the relationship between historical air temperature and river flow at 

46 Chattanooga, which is centrally located in the Tennessee River Basin. The analysis required 

47 the estimation of “natural” flow (i.e., the flow rate that would have occurred without dams and 

48 flow regulation, based on observed rainfall and runoff). The natural flow at the location of 

49 Chickamauga Dam on the Tennessee River provides a measure of the magnitude of drought in 
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1 the eastern part of the Tennessee River Basin. To obtain a measure of conditions when the 

2 river temperature is most likely to be extreme, TVA analyzed measured air temperature and 

3 natural flow for the warmest months of the year (i.e., June, July, and August from 1948 to 2012). 

4 Figure 4–1 shows the plot of the deviation in mean air temperature at the Chattanooga airport 

5 and the deviation in mean natural flow at Chickamauga Dam. While there is considerable 

6 scatter in the points, there is a general inverse relationship between the percent deviation from 

7 mean air temperature and the percent deviation from mean natural river flow (i.e., the highest air 

8 temperatures are associated with the lowest flow rates). Five of the most recent six data points 

9 (2007, 2008, 2010, 2011, and 2012) are in the quadrant of higher temperature and lower flow 

10 (TVA 2013i).

11 As part of the cumulative impacts analysis, the NRC staff evaluated the potential for rising river 

12 water temperatures. River water temperature is a complex function of many contributions 

13 including SQN operations, Tennessee River operating policy, land use, regulated withdrawals 

14 and effluent discharges, seasonality, regional meteorology, and the global climate system. 

15 Potential cumulative impacts with respect to elevated Tennessee River temperatures and the 

16 incremental addition of SQN thermal discharges was assessed using historical data and TVA

17 climate change scenario modeling.

18 TVA performed a modeling study to simulate the potential effect of climate change on the 

19 performance of SQN encompassing the proposed period of extended operations (2012 to 

20 2041). The principal model input data were: (1) 20 years of historical (1992-2011) river 

21 discharge, stage, temperature, and meteorology data; 2) an estimate of the potential future 

22 increase in air temperature and humidity in the Tennessee Valley due to climate change based 

23 on research by the Electric Power Research Institute (EPRI); and (3) a relationship between air 

24 temperature and water temperature during the warmest months of the year. The latter element 

25 reflects the results of a recent TVA study of extreme meteorology in the TVA reservoir system 

26 that found for a waterbody such as Chickamauga Reservoir, each 1°F (0.55°C) increase in air 

27 temperature generally increased the average water temperature in the reservoir by an amount 

28 between 0.25°F and 0.5°F (0.13 to 0.25°C). TVA’s model incorporates the thermal discharge 

29 (mixing zone) compliance model developed for managing SQN operations. It also incorporates 

30 an algorithm to make plant operational decisions to include cooling tower operation and 

31 generation load reductions necessary to comply with thermal discharge and ambient river 

32 temperature limits specified in SQN’s NPDES permit (TVA 2013i).

33 TVA’s modeling results indicate that by 2041, SQN helper cooling tower use may increase in 

34 certain years by about 70 percent compared to recent operational experience. The results 

35 identified the potential for plant derates (power reductions) and shutdown events to occur in 4 

36 of the 30 modeled years, although the duration of the simulated events was very small 

37 compared to the extent of the license renewal period. TVA noted that the model does not 

38 account for TVA’s ability to forecast and respond to extreme hydrothermal conditions in 

39 managing SQN operations. Therefore, TVA believes that the modeling results suggest that 

40 SQN’s cooling capacity will be adequate during the license renewal period (TVA 2013i).

41 Ultimately, elevated intake river water temperature can decrease the efficiency of the 

42 generators, increase helper cooling tower operations, and increase receiving water 

43 temperatures. If these occur during drought-induced low flow periods, decreases in SQN 

44 withdrawals (such as through plant derates) may be necessary to maintain Chickamauga 

45 Reservoir temperatures in accordance with SQN’s NPDES permit.
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1 Figure 4–1. Analysis of Hydrothermal Conditions for the Tennessee Valley Reflecting 

2 Observed Air Temperature and Estimated Natural River Flow at Chattanooga, Tennessee 

3 

4 Source: TVA 2013i

5 Consumptive water use from continued SQN operations will continue to be a very small 

6 percentage of the overall flow of the Tennessee River through Chickamauga Reservoir. Criteria 

7 imposed by TDEC, through SQN’s NPDES permit, will continue to limit SQN’s water 

8 withdrawals and thermal discharges. Potential cumulative impacts to surface water resources 

9 include prolonged drought and temperature increases. The magnitude of such future impacts 

10 within the Tennessee River System associated with climate change remains speculative. 

11 However, long-term warming could potentially affect navigation, power production, and 

12 municipal and industrial users, although the magnitude of the impact is uncertain. Therefore, 

13 the NRC staff concludes that the cumulative impacts from past, present, and reasonably 

14 foreseeable future actions on surface water resources during the license renewal term would be 

15 SMALL to MODERATE. This conclusion is based in part on the regulatory framework 

16 established by the State of Tennessee in managing surface water use and quality and the 

17 operation of the Tennessee River System by TVA to manage flows and to regulate water quality 

18 for designated uses.

19 4.16.3.2 Groundwater Resources

20 This section addresses the direct and indirect effects of license renewal on GW use and quality 

21 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

22 actions. Groundwater is not used at the SQN site. As described in Section 3.5.2.2 of this SEIS, 

23 TVA obtains water for SQN industrial and potable uses from the Hixson Utility District, a 

24 municipal supplier of water (TVA 2013a). The Hixson Utility District currently has an estimated 
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1 excess capacity of 12 mgd (45 million Lpd) (CHCRPA 2011). Potable water supplies around the 

2 SQN plant area are abundant and are expected to remain so over the period of extended 

3 operations (TVA 2013a, Table 2.10-1).

4 Historical releases of liquids containing tritium have not affected GW quality beyond the site 

5 boundary. A GW pathway has not been identified for tritium-contaminated GW to reach other 

6 drinking water users. As described in Sections 3.5.2.3 and 4.5.1.2 of this SEIS, a program is in 

7 place to safeguard GW quality. SQN operations have not affected and are not expected to 

8 affect the quality of GW in any aquifers that are a current or potential future source of water for 

9 offsite users. Considering ongoing activities and reasonably foreseeable actions, the NRC staff 

10 concludes that the cumulative impacts on GW use and quality during the SQN license renewal 

11 term would be SMALL.

12 4.16.4 Terrestrial Ecology

13 This section addresses past, present, and future actions that could result in cumulative impacts 

14 on the terrestrial species and habitats described in Sections 3.6 and 3.8, including protected 

15 terrestrial species. For purposes of this analysis, the geographic area considered in the 

16 evaluation includes the SQN site and surrounding region.

17 Historic Conditions

18 Section 3.6 discusses the ecoregion in which the SQN site lies—the Ridge and Valley 

19 ecoregion. Over the past 40 years, the amount of area developed into residential, commercial, 

20 or industrial uses has increased, and the amount of forested area has decreased. For example, 

21 forests declined from 57.3 percent in 1973 to 55.8 percent in 2000, whereas developed areas 

22 increased from 7.9 percent to 9.3 percent. The amount of agricultural land also decreased, from 

23 31.2 percent to 30.5 percent from 1973 to 2000. USGS (2012) determined that strong 

24 economic growth, especially near large urban centers such as Chattanooga, contributed to the 

25 increase in developed areas. Development is likely to continue in the reasonably foreseeable 

26 future as a result of new transmission lines, power plants, and residential and commercial 

27 activities.

28 Development, Urbanization, and Habitat Fragmentation

29 As the region surrounding the SQN site becomes more developed, habitat fragmentation will 

30 increase and the amount of forested and wetland areas are likely to decline. Transmission line 

31 corridors established for SQN transmission lines represent past habitat fragmentation because 

32 some of the corridors split otherwise continuous tracts of forested, scrub-shrub, or wetland 

33 habitats. Construction of transmission lines associated with new energy projects may also 

34 result in habitat fragmentation if the corridors are not collocated with existing right-of-ways or 

35 sited within previously developed areas. Edge species that prefer open or partially open 

36 habitats (similar to the area within and near a right-of-way corridor) will likely benefit from the 

37 fragmentation, while species that require interior forest or wetland habitat will likely decline.

38 Increased development will likely decrease the overall availability and quality of forested, 

39 scrub-shrub, and wetland habitats. Species that require larger ranges, especially predators, will 

40 likely suffer reductions in their populations. Similarly, species with threatened, endangered, or 

41 declining populations are likely to be more sensitive to declines in habitat availability and quality.

42 Parks and Wildlife Preserves

43 State parks and wildlife refuges located near SQN provide valuable habitat to native wildlife and 

44 migratory birds during the proposed license renewal period. As development and urbanization 
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1 increase habitat conversion and fragmentation, these protected areas will become ecologically 

2 more important as they provide large, continuous areas of minimally disturbed habitat.

3 Conclusion

4 Section 4.6 of this SEIS concludes that the impact from the proposed license renewal would not 

5 noticeably alter the terrestrial environment and, thus, would be SMALL. However, as 

6 environmental stressors, such as construction of new transmission lines, power plants, or 

7 residential areas, continue over the proposed license renewal term, certain attributes of the 

8 terrestrial environment (such as species abundance) are likely to change noticeably. The NRC 

9 staff does not expect these impacts to destabilize any important attributes of the terrestrial 

10 environment because such impacts will cause gradual change, which should allow the terrestrial 

11 environment to appropriately adapt. The NRC staff concludes that the cumulative impacts of 

12 the proposed license renewal of SQN plus other past, present, and reasonably foreseeable 

13 future projects or actions would result in MODERATE impacts to terrestrial resources.

14 4.16.5 Aquatic Ecology

15 This section addresses the direct and indirect effects of license renewal on aquatic resources 

16 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

17 actions. Section 4.7 of this document finds that the direct and indirect impacts on aquatic 

18 resources from the proposed license renewal, when considered in the absence of the aggregate 

19 effects, would be SMALL. The cumulative impact is the total effect on the aquatic resources of 

20 all actions taken, no matter who has taken the actions (the second principle of cumulative 

21 effects analysis in CEQ (1997)).

22 The geographic area of interest considered in the cumulative aquatic resource analysis depends 

23 on the particular cumulative impacts being discussed. Direct and indirect impacts from the SQN 

24 site are largely limited to the Chickamauga Reservoir because dams on the Tennessee River 

25 and its tributaries largely segment the biological communities. The direct and indirect effects of 

26 the continued operation of SQN would not be communicated in a discernible manner beyond 

27 Chickamauga Dam. The geographic area considered for cumulative impacts from closely sited 

28 power plants, as well as from activities such as dams, agriculture, and urban and industrial 

29 development, includes the entire Chickamauga Reservoir, as well as one reservoir above the 

30 site (Watts Bar Reservoir) and one below (Nickajack Reservoir). This area is largely defined by 

31 water use.

32 Actions other than relicensing that can affect aquatic resources can be placed into two groups. 

33 The first is those caused by closely sited power plants. The NRC staff considers other power 

34 facilities within the geographic area of interest as “closely sited” for the purposes of cumulative 

35 impact analyses if these plants can affect the aquatic resources at SQN. The second group 

36 includes multiple other activities that affect Chickamauga Reservoir, such as dams, agriculture, 

37 and urban and industrial development.

38 Closely Sited Power Plants

39 The analysis of effects from other power-producing facilities on the aquatic resources in the 

40 vicinity of the SQN site is limited to facilities in Chickamauga Reservoir, as well as one reservoir 

41 upstream (Watts Bar Reservoir) and one reservoir downstream (Nickajack Reservoir). These 

42 power-producing facilities are listed in Appendix G and include Watts Bar Nuclear Plant Unit 1 

43 (operating) and Unit 2 (pursuing a license), located 2 mi (3 km) downstream of Watts Bar Dam 

44 and approximately 44 mi (71 km) upstream of the SQN site; the Kingston Fossil Plant at the 

45 junction of Emory River and Clinch River, approximately 94 mi (151 km) upstream of the SQN 

46 site; and Raccoon Mountain Pumped-Storage Plant near Chattanooga. The two dams on either 
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1 end of Chickamauga Reservoir (Watts Bar and Chickamauga dams) are considered with the 

2 effects of other activities including impoundment of the river.

3 Raccoon Mountain pumped-storage plant withdraws water from Nickajack Reservoir, 

4 downstream of Chickamauga Dam, during periods of low water demand. The water is pumped 

5 to a reservoir on the top of Raccoon Mountain. TVA indicates that it takes 28 hours to fill the 

6 upper reservoir. Water is released through tunnels to Nickajack Reservoir when demand is 

7 high. The water running through the tunnels drives generators that produce power 

8 (TVA 2013q). The facility was built in the 1970s and the reservoir holds 60 million cubic yards

(46 million m3 9 ) of water (TVA2013p).

10 Watts Bar Nuclear Plant is a source of entrainment, impingement, and thermal stress in the 

11 same reservoir as SQN. WBN Unit 1 received an operating license in 1996. It is collocated with 

12 WBN 2, which applied for an operating license in 2009. The WBN units are pressurized water 

13 reactors designed with a total electrical generating capacity of 2,540 megawatts electric (MWe) 

14 and two natural-draft cooling towers. Although the operating license for Unit 2 has not yet been 

15 issued, the two units are designed to use the same intake and discharge structures. The 

16 original intake pumping station is located on the Chickamauga Reservoir at Tennessee River 

17 Mile (RM) 528.0. A supplemental condenser cooling-water intake, originally used for the Watts 

18 Bar Fossil Plant, is also used for operation of WBN Unit 1 and will be used for WBN 2. The 

19 supplemental condenser cooling-water intake is located above Watts Bar Dam at Tennessee 

20 RM 529.9 and pulls water from Watts Bar Reservoir. It operates by gravity flow such that the 

21 flow through the intake structure fluctuates in response to changes in the elevation of the water 

22 level in Watts Bar Reservoir (NRC2013c).

23 The total flow through the two operating units (including withdrawals from both the supplemental 

24 condenser cooling water intake and the intake pumping station) would be approximately 

237 mgd (12 m3 25 /s or 440 cfs), which is approximately 1.6 percent of the mean annual flow past 

26 the WBN site (see Table 3–1 for anticipated water use). When operating together, WBN Units 1 

and 2 would consume 33 mgd (1.8 m3 27 /s or 62 cfs), which is approximately 0.2 percent of the 

28 mean annual flow past the WBN site (NRC 2013d).

29 In compiling the EIS related to the operation of WBN 2 (NRC 2013c), the NRC staff considered 

30 cumulative entrainment and impingement from both units based on studies conducted during 

31 operation of WBN Unit 1. The total entrainment of fish eggs and larvae, using the most recent 

32 estimates available and assuming both intakes were withdrawing water from the same 

33 environment, is 2.45 percent for eggs (assuming 2 times the entrainment rate for the Intake 

34 Pumping Station (IPS) from the 2010–2011 study (TVA 2012e) combined with the supplemental 

35 condenser cooling water (SCCW) system intake entrainment rate) and 2.84 percent for larvae 

36 (assuming two times the entrainment rate of 0.43 percent from the 2010–2011 study 

37 (TVA2012e) for the IPS, combined with the entrainment rate for the SCCW). Current operation 

38 of the SCCW for WBN Unit 1 accounts for the largest portion of the entrainment rates. The 

39 NRC staff’s determination of impact levels was based on studies of impingement at both 

40 intakes, although the intakes draw water from populations in two different reservoirs. TVA 

41 researchers conducted two impingement studies at the intake pumping station on Chickamauga 

42 Reservoir. The first occurred in 1996 and 1997 (Baxter et al. 2010) and the second from 

43 March 2010 to March 2011 (TVA2012c). Small numbers of fish were impinged at the intake 

44 pumping station in 1996 and 1997. Larger numbers were impinged in the 2010 through 2011 

45 study, but they were almost entirely composed of gizzard shad and threadfin shad (over 

46 99 percent). TVA researchers conducted three impingement studies on the SCCW: (1) in 1974 

47 through 1975, during operation of the Watts Bar Fossil Plant (TVA 1976), (2) in 1999 and 2000 

48 (Baxter et al. 2001), and (3) in 2005 through 2007, as part of the 316(b) monitoring program 

49 (TVA 2007a). In the first study, shad constituted 73 percent of the fish collected. Bluegill was 
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1 the next most abundant fish species followed by freshwater drum and skipjack herring. In the 

2 second study, again the majority of fish impinged were gizzard shad and threadfin shad 

3 (75 percent) followed by bluegill (17.6 percent). In the third study over 99 percent of the fish 

4 impinged were threadfin and gizzard shad; however, the threadfin shad composed the majority, 

5 with estimates of greater than 5.3 million impinged during the first year of the study, and over 

6 211,000 the second year. The staff concluded that this high number of threadfin shad impinged 

7 likely resulted from weather conditions and the location of the SCCW system, which is on 

8 Watts Bar Dam. Overall, NRC staff concluded that the cumulative impact of operation of both 

9 WBN Units 1 and 2 would not destabilize or noticeably alter aquatic resources (NRC 2013d).

10 The Kingston Fossil Plant, near Kingston, Tennessee, is located on a peninsula at the junction 

11 of the Emory River and Clinch River, approximately 88 mi (142 km) upstream from the SQN 

12 site. TVA conducted impingement studies in 2004 through 2005 and 2005 through 2006, 

13 reporting 30 species impinged during the first year of the study and 33 in the second year. The 

14 estimated annual impingement extrapolated from weekly samples was 185,577 fish during the 

15 first year and 225,197 fish during the second year. Similar to impingement results for the 

16 SCCW, threadfin shad accounted for 95 percent of the 2-year total of fish TVA collected during 

17 an impingement study conducted from November 16, 2004, through November 16, 2006 

18 (TVA 2007b).

19 Historical entrainment studies (Schneider and Tuberville 1981) showed that, although the 

20 hydraulic entrainment of the Kingston Fossil Plant averaged 22.7 percent in 1975, the biological 

21 entrainment was significantly lower at 0.84 percent. This difference was attributed by TVA, at 

22 least partially, to the use of a skimmer wall. The NRC staff does not anticipate cumulative 

23 impacts from entrainment and impingement at the Kingston Fossil Plant to affect the fish 

24 population observed in the vicinity of the SQN site because the home ranges of most species 

25 are less than the migratory distance between the two locations. 

26 A nuclear facility is proposed for the Clinch River site, which is located upstream of the Kingston 

27 Fossil Plant, but between Watts Bar Dam and Melton Hills Dam. Although an application has 

28 not been submitted, the project is proposed to include up to six Babcock and Wilcox small 

29 modular reactor modules. A potential for impacts to aquatic resources exists, the magnitude of 

30 which is unknown, although, based on the design of the proposed units, it would be much 

31 smaller than that from a conventional nuclear power facility.

32 Thermal impacts beyond the SQN site may add to aquatic resources cumulative impact. The 

33 NRC staff also considered potential cumulative impacts as a result of the addition of thermal 

34 discharges from the Kingston Fossil Plant or the Watts Bar Nuclear Plant. All three facilities 

35 have NPDES permits that are granted by the State of Tennessee. The NRC relies on the State 

36 of Tennessee to protect the health of aquatic organisms by ensuring compliance with the 

37 NPDES permit requirements. Furthermore, because of the distances between these three sites, 

38 the travel time of water through the reservoirs, and the dissipation of heat from the discharge

39 plumes, the NRC staff considers these impacts to be independent of effects at SQN.

40 Chemical contamination from power producing facilities can also adversely affect aquatic 

41 resources. The chemical releases from Watts Bar Nuclear Plant are similar to those from SQN. 

42 The two nuclear plants control water chemistry for various plant water uses by adding biocides, 

43 algaecides, corrosion inhibitors, potential of hydrogen (pH) buffering, scale inhibitors, and 

44 dispersants. Similar to SQN, the NRC relies on the State of Tennessee to ensure compliance 

45 with the NPDES permit requirements at the WBN site (TDEC 2011, TVA2011d) such that 

46 aquatic resources of Chickamauga Reservoir would not be affected by chemical discharges 

47 resulting from operation of WBN, Units 1 and 2.
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1 Although NRC staff expects little effect on aquatic habitats from anticipated industrial and 

2 wastewater discharges if facilities comply with NPDES permit limitations, there is a case within 

3 the geographical area of interest where an accident occurred. In December 2008, a coal fly-ash 

4 slurry spill occurred at the Kingston Fossil Plant. The Tennessee Department of Health (TDOH) 

5 sampled water quality downstream of the Kingston Fossil Plant in response to the spill. It 

6 conducted the majority of sampling in the Clinch and Emory rivers. In addition, TDOH also 

7 sampled at Tennessee RM 568.2. According to the TDOH, except in the immediate vicinity of 

8 the coal ash release, the coal ash or the metals in the coal ash have not affected surface water

9 in the Watts Bar Reservoir, and concentrations of radiation are below the regulatory limits that 

10 protect public health. In addition, TDOH sampling and analysis of metals associated with coal 

11 ash indicate that metals in all other areas of the Emory River and Clinch River have remained 

12 below any health comparison values.

13 Although the TDEC and the Tennessee Wildlife Resource Agency advise citizens to avoid 

14 consuming striped bass and limit consumption of catfish and sauger in the Clinch and Emory 

15 rivers, the pollutants of concern in these rivers include PCBs and mercury from historical 

16 activities not related to TVA (TDOH 2009). The long-term hazards of PCBs and mercury to 

17 aquatic resources are discussed in Section 2.3.2.1. These PCBs can impair reproductive, 

18 endocrine, and immune system functions in fish, increase the incidence of lesions and tumors, 

19 and cause death. Mercury can adversely affect reproduction and development and cause 

20 death. The effects of contamination on the level of individual fish can alter population dynamics 

21 and destabilize natural populations and ecosystems.

22 Other Activities Including Dams, Agriculture, Urban and Industrial Development

23 Section 3.7 describes some of the changes that were made to the Tennessee River since the 

24 early 1900s. These changes include impoundment of the river. Historically, the Tennessee 

25 River was free flowing and flooded annually. Before 1936, the few power dams that obstructed 

26 streams in Tennessee backed up relatively small impoundments. In 1936, TVA completed its 

27 first reservoir on the Tennessee River—Norris Reservoir. Currently, TVA operates nine dams 

28 on the mainstem of the Tennessee River. The dams have fragmented the watershed, altered 

29 water temperatures, increased sedimentation, reduced dissolved oxygen concentrations, and 

30 altered flow regimes. This in turn has caused and will continue to cause extirpation of fish, 

31 mussels, and other aquatic resources (Etnier and Starnes 1993, Neves and Angermeier 1990, 

32 Neves et al. 1997). Other past actions that have changed and continue to change the aquatic 

33 fauna in the geographical region include introduction of nonnative species, overfishing of 

34 species such as paddlefish, harvesting of mussels, toxic spills, mining, and agriculture. 

35 Section 3.7 describes the introduction and success of nonnative and invasive aquatic fish, 

36 invertebrate, and plant species that have clearly destabilized and changed Tennessee River 

37 aquatic communities. The aquatic community in Chickamauga Reservoir, like many other 

38 aquatic communities, changes slowly in response to stress. This community has been changing 

39 for a long time, is changing now, and will probably continue to change for the foreseeable future. 

40 In their review of the Tennessee River, White et al. (2005) made the following observation: 

41 Because reservoirs create ecosystem conditions that did not exist previously in 

42 the basin, conceptually these are “new” ecosystems. Reservoir ecosystems do 

43 not reach the longitudinal and temporal equilibriums of the parent river..., 

44 producing conditions ripe for invasions of true nonnative plants and animals that 

45 are highly adaptable. Although most species occurred in the system prior to 

46 impoundment, the dominant species now are those adapted to a new set of 

47 environmental conditions.

48 The dams on the Tennessee River are barriers to fish migration, and the transport of fish, eggs, 

49 and larvae through the dams result in some mortality (Cada 1991, Watters 2000). Furthermore, 
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1 the placement of the dams altered the flow regimes and continues to alter the water quality, 

2 including the temperature of the river (as discussed in Section 3.5). For example, increasing the 

3 volume of water released from Watts Bar Dam is one of five options TVA can use to keep the 

4 thermal discharge from operation of WBN, Units 1 and 2, within the NPDES limits (NRC 2013c) 

5 If this option is chosen, the water released from Watts Bar Dam could have slight and 

6 indiscernible effects on the water levels in Tennessee River reservoirs and tributaries upstream 

7 and downstream of Watts Bar Dam, including in the vicinity of the SQN site, and slight and 

8 indiscernible effects on the aquatic resources in those reservoirs and tributaries.

9 The management of the impounded river as reservoirs, including the management of 

10 commercially and recreationally important fish, stocking of fish, and introduction of nonnative 

11 fish also serve as a stress on the native aquatic resources. Chapter 3 of this SEIS describes 

12 specific impacts on aquatic resources from reservoir impoundment, including the extirpation of 

13 aquatic resources, which is detectable and a symptom of ecosystem destabilization.

14 Operations at industrial sites can affect the chemicals that are released to the aquatic 

15 environment. For example, waste disposal activities at the DOE’s Oak Ridge Reservation, 

16 located on the Clinch River at Clinch RM 17.7, introduced PCBs, metals, organic compounds 

17 (including those with mercury), and radionuclides (including cesium-137) into local streams and, 

18 ultimately, into the Watts Bar Reservoir system. The highest discharges occurred in the 

19 mid-1950s. The mouth of the Clinch River is located at Tennessee RM 567.7, placing the 

20 Oak Ridge Reservation at approximately 100 mi (161 km) upstream of the Watts Bar Dam and 

21 140 mi (225 km) upstream of the SQN site. The highest concentrations of chemical and 

22 radioactive contaminants lie in the subsurface sediments where 40 to 80 cm (16 to 32 in.) of 

23 sediment covers the deposits (ATSDR 1996). Such legacy contaminants can adversely affect 

24 resources in the Tennessee River.

25 Other industrial sites with discharges that could contribute to cumulative impacts include 

26 Resolute Forest Products, a paper mill, and Olin Chlor Alkali Products (Olin 2013), a 

27 manufacturer of chlorine and caustic soda on the Hiwassee River, a tributary that empties into 

28 Chickamauga Reservoir upstream of the SQN site. The NRC staff expects little effect to aquatic 

29 habitats from industrial and wastewater discharges if facilities comply with NPDES permit 

30 limitations.

31 A preliminary study has been conducted for a toll bridge that would cross the Tennessee River 

32 in the vicinity of the SQN site to connect Highway 58 with Interstate 75 (Chattanoogan 2012). 

33 The project would require inwater work that would temporarily affect aquatic resources in the 

34 vicinity of the construction site. The study estimated that by 2021 between 9,900 and 

35 10,700 vehicles would cross per day. The staff assumes that the construction firm would use 

36 BMPs to minimize the effects of construction on aquatic resources and to minimize effects of 

37 runoff into the river during operation of the bridge.

38 Based on information TVA provided and the NRC staff’s independent review, the NRC staff 

39 concludes that the cumulative impacts on aquatic resources in Chickamauga Reservoir are 

40 LARGE based on past, present, and reasonably foreseeable future actions. The environmental 

41 effects are clearly noticeable and have destabilized important attributes of the aquatic resources 

42 in the vicinity of the SQN site. The incremental, site-specific impact from the continued 

43 operation of SQN during the license renewal period would be minor and not noticeable in 

44 comparison to cumulative impact on the aquatic ecology.

45 4.16.6 Historic and Cultural Resources

46 This section addresses the direct and indirect effects of license renewal on historic and cultural 

47 resources when added to the aggregate effects of other past, present, and reasonably 
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1 foreseeable future actions. The geographic area considered in this analysis is the APE

2 associated with the proposed undertaking, as described in Section 3.9.

3 The archaeological record for the region indicates prehistoric and historic occupation of the 

4 SQN site and its immediate vicinity. The completion of Chickamauga Reservoir in 1940 and the 

5 construction of SQN, Units 1 and 2, in 1970 resulted in destruction of cultural resources within 

6 the SQN site and surrounding area. Other historic land development in the vicinity of SQN also 

7 resulted in impacts on, and the loss of, cultural resources on the SQN site and its immediate 

8 vicinity. However, there remains the possibility for additional historic or cultural resources to be 

9 located within the SQN site. The present and reasonably foreseeable projects which could 

10 affect these resources reviewed in conjunction with license renewal are noted in Appendix G of 

11 this document. Direct impacts would occur if historic and cultural resources in the APE were 

12 physically removed or disturbed. Indirect visual or noise impacts could occur from new 

13 construction or maintenance. The following projects are located within the geographic area 

14 considered for cumulative impacts:

15  Chickamauga Dam water level fluctuation,

16  independent spent fuel storage installation (ISFSI) expansion,

17  tritium production,

18  use of highly enriched uranium (HEU) fuel,

19  use of mixed-oxide fuel (MOXF),

20  decommissioning of SQN, Units 1 and 2,

21  transmission lines maintenance or construction, and

22  future urbanization in the immediate vicinity of SQN.

23 As described in Section 4.9, no cultural resources would be adversely affected by SQN, Units 1 

24 and 2, license renewal activities as no associated changes or ground-disturbing activities would 

25 occur (TVA 2013a). Cultural resources on the SQN site are being managed through TVA BMPs

26 (e.g., procedures and training) and license renewal would have no contributory incremental 

27 effect on historic and cultural resources (TVA 2013b). Expansion of ISFSI, tritium production, 

28 use of HEU fuel, use of MOXF, decommissioning of SQN, Units 1 and 2, transmission lines, and 

29 future urbanization all have the potential to result in impacts on cultural resources through 

30 inadvertent discovery during ground-disturbing activities. The Chickamauga Dam has the 

31 potential to affect cultural resources because of the fluctuation of river water levels that may 

32 cause erosion impacts to resources located on the river banks. However, TVA has established 

33 processes and procedures to ensure cultural resources are considered in project planning 

34 during normal operation of SQN, Units 1 and 2, and these same processes and procedures are 

35 used throughout the TVA power properties. Therefore, the NRC staff concludes that the 

36 cumulative impact of the proposed license renewal when combined with other past, present, 

37 and reasonably foreseeable future activities on historic and cultural resources would be SMALL.

38 4.16.7 Socioeconomics

39 This section addresses socioeconomic factors that have the potential to be directly or indirectly 

40 affected by changes in operations at SQN in addition to the aggregate effects of other past, 

41 present, and reasonably foreseeable future actions. The primary geographic area of interest 

42 considered in this cumulative analysis is Hamilton and Rhea Counties, where approximately 

43 84 percent of SQN employees reside (see Table 3–22). This is where the economy, tax base, 
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1 and infrastructure would most likely be affected because SQN workers and their families reside, 

2 spend their incomes, and use their benefits within these counties.

3 As discussed in Section 4.8.10 of this SEIS, continued operation of SQN during the license 

4 renewal term would have no impact on socioeconomic conditions in the region beyond those 

5 that are already being experienced. Since TVA has no plans to hire additional workers during 

6 the license renewal term, overall expenditures and employment levels at SQN would remain 

7 relatively constant and unchanged, with no additional demand for permanent housing and public 

8 services. In addition, as employment levels and tax payments would not change, there would 

9 be no population- or tax revenue-related land-use impacts. Based on this and other information 

10 presented in preceding sections of Chapter 4 of this SEIS, there would be no additional 

11 contributory effect on socioeconomic conditions in the future from the continued operation of 

12 SQN on socioeconomic conditions in the region during the license renewal term beyond what is 

13 currently being experienced. Therefore, the only contributory effects would come from 

14 reasonably foreseeable future planned activities at SQN, unrelated to the proposed action 

15 (license renewal), and other reasonably foreseeable planned offsite activities. For example, 

16 residential development is forecast for the SQN area, but not to the point that population 

17 densities will be significant. Contributing to projected development is a provision to install 

18 sewage lines in part of the area (TVA 2013a).

19 4.16.7.1 Tritium Production and Use of Highly Enriched Uranium and Mixed-Oxide Fuel at SQN

20 The applicant stated in its ER that SQN has been selected by DOE for irradiation services for 

21 the production of tritium. Tritium production at SQN was studied in DOE’s EIS for tritium 

22 production in a commercial light water reactor (DOE 1999). Fewer than 10 additional workers 

23 per unit and some power plant modifications would be required to provide tritium production 

24 irradiation services to DOE. These additional workers and other transportation-related activities 

25 would increase traffic volumes on local roads near SQN. During reactor operations, irradiated 

26 tritium-producing burnable absorber rod assemblies, nonradioactive waste, and some additional 

27 low-level radioactive waste would be transported off site for processing and disposal. Should 

28 DOE select SQN for irradiation services, and the NRC approve a license amendment for this 

29 activity, the contributory socioeconomic effect of this action would be SMALL in the immediate 

30 vicinity of SQN. Furthermore, the use of HEU and MOXF would not create any contributory 

31 socioeconomic effects in the immediate vicinity of SQN.

32 4.16.7.2 Watts Bar Nuclear Power Plant Unit 2

33 The 1978 operating license FES evaluated the impacts from operating both WBN Units 1 and 2, 

34 concluding no significant socioeconomic impacts would occur from combined power plant 

35 operations. Since that time, the region around WBN, Units 1 and 2, has experienced economic 

36 growth and increases in population and housing.

37 Currently, TVA expects to employ 200 workers to operate WBN 2, which is the same number of 

38 operations workers projected in the 1978 FES (NRC 1978). However, this would be in addition 

39 to the 700 TVA personnel and 1,360 construction workers (PNNL 2009) currently employed at 

40 the WBN site (TVA 2008, 2010). Should WBN 2 become operational, the overall level of 

41 employment at the WBN site would be less than total current employment at the WBN site. The 

42 contributory socioeconomic effect of this action would be SMALL in the immediate vicinity of 

43 SQN.

44 4.16.7.3 Small Modular Reactor Modules at the Clinch River Site

45 The incremental socioeconomic effects of installing and operating small modular reactor (SMR) 

46 modules at the Clinch River site cannot be accurately estimated since the NRC has not received 

47 an application for a construction and operation license. However, installing and operating SMR 
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1 modules would create new employment and income opportunities resulting in temporary (during 

2 installation) and permanent (during operations) population increases in communities located 

3 near the Clinch River site. Employment-driven population growth would cause increased traffic 

4 volumes on local roads and increased demand for housing and local commercial and public 

5 services near the site. Should SMR modules be installed and operated at the Clinch River site, 

6 the contributory socioeconomic effect of this action could be SMALL in the immediate vicinity of 

SQN. 7 

8 4.16.7.4 Recreational Vehicle Trailer Park

9 Construction and operation of an RV trailer park directly across from SQN would both increase 

10 traffic volumes on roads near SQN as well as demand for commercial and public services. The 

11 RV trailer park will use the same municipal public water supply as SQN. The contributory 

12 socioeconomic effect of this action could be SMALL in the immediate vicinity of SQN.

13 4.16.7.5 Conclusion

14 When combined with other past, present, and reasonably foreseeable future activities, there will 

15 be no additional contributory effect on socioeconomic conditions from the continued operation of 

16 SQN during the license renewal period beyond what is currently being experienced. Therefore, 

17 the NRC staff concludes that the cumulative socioeconomic impact would be SMALL in the 

18 immediate vicinity of SQN.

19 4.16.8 Human Health

20 The NRC and EPA established radiological dose limits for protection of the public and workers 

21 from both acute and long-term exposure to radiation and radioactive materials. These dose 

22 limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.11.1, the 

23 doses resulting from operation of SQN are below regulatory limits and the impacts of these 

24 exposures are SMALL. For the purposes of this analysis, the geographical area considered is 

25 the area included within an 50-mi (80-km) radius of the SQN site. The only other nuclear power 

26 plant within the applicable geographical area is TVA’s Watts Bar Nuclear Plant (WBN) that is 

27 approximately 31 miles south-southwest of the SQN site. The WBN site contains an operating 

28 reactor, Unit 1, and Unit 2 that is under construction. In addition to storing its spent nuclear fuel 

29 in a storage pool, SQN also stores some of its spent nuclear fuel in an onsite independent spent 

30 fuel storage installation (ISFSI).

31 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 

32 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 

33 facilities, and transportation of fuel and waste. As discussed in Section 3.1.4.5 of this SEIS, 

34 SQN has conducted a radiological environmental monitoring program since 1971, well before 

35 commercial operation began in 1981. This program measures radiation and radioactive 

36 materials in the environment from SQN, its ISFSI, and all other sources, such as WBN. The 

37 NRC staff reviewed the radiological environmental monitoring results for the 5-year period from 

38 2008 to 2012 as part of the cumulative impacts assessment. The NRC staff’s review of TVA’s 

39 data showed no indication of an adverse trend in radioactivity levels in the environment from 

40 SQN, its ISFSI, or WBN. The data showed that there was no measurable impact to the 

41 environment from the operations at SQN and there were no contributory impacts from WBN.

42 As discussed in Section 3.1.4.6 of this SEIS, TVA may seek NRC approval to produce tritium at 

43 SQN for the DOE. In addition, TVA may seek NRC approval to use mixed oxide (MOX) fuel at 

44 SQN. Also, as discussed in Section 3.1.4.6, SQN is not producing tritium for the DOE and is not 

45 using MOX fuel. In order to conduct either of these actions, TVA is required to submit license 
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1 amendments to the NRC. The NRC would perform independent safety and environmental 

2 reviews of these actions to ensure the adequate protection of the public and the environment.

3 The NRC and the State of Tennessee will regulate any future development or actions in the 

4 vicinity of the SQN site that could contribute to cumulative radiological impacts.

5 Based on the NRC staff’s review of radiological environmental monitoring data, radioactive 

6 effluent release data, and the expected continued compliance with Federal radiation protection 

7 standards, the cumulative radiological impacts to SQN workers and members of the public from 

8 the operation of SQN during the renewal term would be SMALL.

9 4.16.9 Environmental Justice

10 The environmental justice cumulative impact analysis assesses the potential for 

11 disproportionately high and adverse human health and environmental effects on minority and 

12 low-income populations that could result from past, present, and reasonably foreseeable future 

13 actions, including SQN operations during the renewal term. Adverse health effects are 

14 measured in terms of the risk and rate of fatal or nonfatal adverse impacts on human health. 

15 Disproportionately high and adverse human health effects occur when the risk or rate of 

16 exposure to an environmental hazard for a minority or low-income population is significant and 

17 exceeds the risk or exposure rate for the general population or for another appropriate 

18 comparison group. Disproportionately high environmental effects refer to impacts or risks of 

19 impacts on the natural or physical environment in a minority or low-income community that are 

20 significant and appreciably exceed the environmental impact on the larger community. Such 

21 effects may include biological, cultural, economic, or social impacts. Some of these potential 

22 effects have been identified in resource areas presented in preceding sections of this SEIS. As 

23 previously discussed in this chapter, the impact from license renewal for all resource areas 

24 (e.g., land, air, water, ecology, and human health) would be SMALL.

25 As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 

26 adverse impacts on minority and low-income populations from the continued operation of SQN 

27 during the license renewal term. Because TVA has no plans to hire additional workers during 

28 the license renewal term, employment levels at SQN would remain relatively constant, and there 

29 would be no additional demand for housing or increased traffic. Based on this information and 

30 the analysis of human health and environmental impacts presented in the preceding sections, it 

31 is not likely there would be any disproportionately high and adverse contributory effect on 

32 minority and low-income populations from the continued operation of SQN during the license 

33 renewal term. Therefore, the only contributory effects would come from the other reasonably 

34 foreseeable future planned activities at SQN, unrelated to the proposed action (license 

35 renewal), and other reasonably foreseeable planned offsite activities.

36 4.16.9.1 Tritium Production and Use of Highly Enriched Uranium and Mixed-Oxide Fuel at SQN

37 Potential impacts to minority and low-income populations would mostly consist of environmental 

38 and socioeconomic effects (e.g., traffic, employment, and housing impacts). Radiation doses 

39 from plant operations after power plant modifications for irradiation services or the use of HEU 

40 and MOXF are expected to continue to remain well below regulatory limits. Noise and dust 

41 impacts from power plant modifications would be temporary and limited to onsite activities. 

42 Minority and low-income populations residing along site access roads could experience 

43 increased commuter vehicle traffic during shift changes. Increased demand for inexpensive 

44 rental housing during irradiation services-related power plant modifications could 

45 disproportionately affect low-income populations; however, because of the short duration of the 

46 work and the availability of housing, impacts to minority and low-income populations would be of 

47 short duration and limited.
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1 Based on this information and the analysis of human health and environmental impacts

2 presented in this section of the SEIS, irradiation services or the use of HEU and MOXF would 

3 not have disproportionately high and adverse human health and environmental effects on 

4 minority and low-income populations residing in the vicinity of SQN.

5 4.16.9.2 Watts Bar Unit 2

6 Potential impacts to minority and low-income populations would mostly consist of environmental 

7 and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing impacts). 

8 Radiation doses from WBN 2 power plant operations are expected to be similar to WBN Unit 1 

9 and well below regulatory limits. Increased demand for inexpensive rental housing during the 

10 completion of WBN 2 could disproportionately affect low-income populations; however, because 

11 of the short duration of the work and the availability of housing, impacts to minority and 

12 low-income populations would be of short duration and limited.

13 Based on this information and the analysis of human health and environmental impacts 

14 presented in this section of the SEIS, the contributory effects of WBN 2 operations would not 

15 cause any disproportionately high and adverse human health and environmental effects on 

16 minority and low-income populations residing in the vicinity of SQN.

17 4.16.9.3 Small Modular Reactor Modules at the Clinch River Site

18 Potential impacts to minority and low-income populations would mostly consist of environmental 

19 and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing impacts). 

20 Radiation doses from operating SMR modules at the Clinch River site are expected to be well 

21 below regulatory limits. Increased demand for inexpensive rental housing during the installation 

22 of SMR modules could disproportionately affect low-income populations; however, because of 

23 the short duration of the installation work and the availability of housing, impacts to minority and 

24 low-income populations would be of short duration and limited.

25 Based on this information and the analysis of human health and environmental impacts 

26 presented in this section of the SEIS, the contributory effects of SMR module operations at the 

27 Clinch River site would not cause any disproportionately high and adverse human health and 

28 environmental effects on minority and low-income populations residing in the vicinity of SQN.

29 4.16.9.4 Recreational Vehicle Trailer Park

30 Potential impacts to minority and low-income populations would mostly consist of environmental 

31 and socioeconomic effects during the construction of the RV trailer park (e.g., noise, dust, and 

32 traffic impacts). Noise and dust impacts during construction would be temporary and limited to 

33 onsite activities. These adverse effects would also be offset by the availability of low-income 

34 housing at the proposed RV trailer park. Minority and low-income populations residing nearby 

35 could also experience increased traffic on roads near their houses; however, impacts to minority 

36 and low-income populations would be limited to certain hours of the day and would be of short 

37 duration.

38 Based on this information and the analysis of human health and environmental impacts 

39 presented in this section of the SEIS, the contributory effects of the RV trailer park would not 

40 cause any disproportionately high and adverse human health and environmental effects on 

41 minority and low-income populations residing in the vicinity of SQN.

42 4.16.9.5 Conclusion

43 The NRC staff concludes that the contributory effects of this action, when combined with other 

44 past, present, and reasonably foreseeable future activities considered, would not cause any 

45 disproportionately high and adverse human health and environmental effects on minority and 

46 low-income populations residing in the vicinity of SQN.
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1 4.16.10 Waste Management 

2 This section describes waste management impacts during the license renewal term when added 

3 to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 

4 the purpose of this cumulative impacts analysis, the area within a 50-mi (80-km) radius of SQN 

5 was considered.

6 As with any major industrial facility, SQN generates waste as a consequence of normal 

7 operations. The expected waste generation rates during the license renewal term would be the 

8 same as during current operations, and radioactive waste (low-level, high-level, and spent 

9 nuclear fuel) and nonradioactive waste will continue to be generated. Hazardous waste would 

10 continue to be packaged and shipped to offsite Resource Conservation and Recovery Act 

11 (RCRA)-permitted treatment and disposal facilities. Typically, hazardous waste is not held in 

12 long-term storage at SQN. Hazardous wastes from SQN are transferred to TVA’s permitted 

13 hazardous waste storage facility (HWSF) in Muscle Shoals, Alabama, which serves as a central 

14 collection point for all TVA-generated hazardous wastes. It is then shipped to an approved 

15 licensed facility for disposition (TVA 2013a).

16 As discussed in Sections 3.1.4 and 3.1.5 of this SEIS, TVA maintains waste management 

17 programs for all radioactive and nonradioactive waste generated at SQN and is required to

18 comply with Federal and State permits and other regulatory requirements for the management 

19 of waste material. Current waste management activities at SQN would likely remain unchanged 

20 during the license renewal term. The existing onsite independent spent fuel storage installation

21 at SQN may be expanded to handle the additional spent nuclear fuel generated during the 

22 license renewal term; however, the impacts of this expansion would be addressed under a 

23 separate licensing action and associated NEPA review process (TVA 2013a). Nonradioactive 

24 and nonhazardous waste generated during the license renewal term would continue to be 

25 shipped off site by commercial haulers to licensed treatment and disposal facilities.

26 4.16.10.1 Tritium Production and Use of Mixed-Oxide Fuel at SQN

27 As discussed in Section 3.1.4, if SQN applies for and receives NRC approval to provide tritium

28 production services to DOE, power plant modifications will be required. These modifications 

29 would generate small amounts of construction and other nonradioactive waste. This waste 

30 material would be shipped off site by commercial haulers to licensed treatment and disposal 

31 facilities. During reactor operations, nonradioactive waste, and some additional low-level 

32 radioactive waste would be generated and transported off site for processing and disposal. 

33 Should SQN provide tritium production services during the license renewal term, the NRC staff 

34 concludes that the contributory effect of this action on waste management, would be SMALL in 

35 the immediate vicinity of SQN. Additionally, the use of HEU and MOXfuel would not result in 

36 any noticeable changes in the types or quantities of nonradioactive or radioactive waste. SQN’s 

37 waste management program would handle the waste in accordance with Federal and State 

38 requirements. The NRC staff concludes that the contributory effect of this action on waste 

39 management during the license renewal term would be SMALL.

40 4.16.10.2 Watts Bar Unit 2

41 The 1978 operating license FES evaluated the impacts from operating both WBN, Units 1 and 

42 2. Should WBN 2 become operational, waste management activities at the WBN site would be 

43 required to comply with Federal and State permits and other regulatory requirements for the 

44 management of waste material. The contributory effect of this action would be SMALL.
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1 4.16.10.3 Recreational Vehicle Trailer Park

2 Construction and operation of an RV trailer park directly across from SQN would generate 

3 volumes of commercial waste, but the operator of the park would be required to comply with 

4 Federal and State requirements for the management of waste material. The contributory effect 

5 of this action would be SMALL in the immediate vicinity of SQN.

6 4.16.10.4 Conclusion

7 Since current waste management activities at SQN would continue during the license renewal 

8 term, there would be no new or increased contributory effect beyond what is currently being 

9 experienced. Therefore, the only new contributory effects would come from reasonably 

10 foreseeable future planned activities at SQN, unrelated to the proposed action (license 

11 renewal), and other reasonably foreseeable planned offsite activities. All radioactive and

12 nonradioactive waste treatment and disposal facilities within 50 mi (80 km) of SQN would also 

13 be required to comply with Federal and State permits and other regulatory requirements. 

14 In addition, the waste management activities at other TVA nuclear power reactor sites 

15 (e.g., Watts Bar) as well as other industrial facilities generating radioactive and nonradioactive 

16 waste would also have to meet the same or similar requirements. Based on this information, 

17 the cumulative effect from continued waste management activities at SQN during the license 

18 renewal term would be SMALL.

19 4.16.11 Global Climate Change

20 This section addresses the impact of GHG emissions resulting from continued operation of SQN 

21 on global climate change when added to the aggregate effects of other past, present, and 

22 reasonably foreseeable future actions. The impacts of climate change on air, water, and 

23 ecological resources are discussed in Section 4.14.3. Climate is influenced by both natural and 

24 human-induced factors; the observed global warming (increase in Earth’s surface temperature) 

25 in the 21st century has been attributed to the increase in GHG emissions resulting from human 

26 activities (USGCRP 2009, 2014). Climate model projections indicate that future climate change 

27 is dependent on current and future GHG emissions (IPCC 2007b; USGCRP 2009, 2014). As 

28 described in Section 4.14.3.1, operations at SQN emit GHG emissions directly and indirectly. 

29 Therefore, it is recognized that GHG emissions from continued SQN operation may contribute to 

30 climate change.

31 The cumulative impact of a GHG emission source on climate is global. GHG emissions are 

32 transported by wind and become well-mixed in the atmosphere as a result of their long 

33 atmospheric lifetime. Therefore, the extent and nature of climate change is not specific to 

34 where GHGs are emitted. In April 2013, the EPA published the official U.S. inventory of GHG 

35 emissions, which identifies and quantifies the primary anthropogenic sources and sinks of 

36 GHGs. The EPA GHG inventory is an essential tool for addressing climate change and 

37 participating with the United Nations Framework Convention on Climate Change to compare the 

38 relative global contribution of different emission sources and GHGs to climate change. In 2011, 

39 the U.S. emitted 6,702.3 teragrams of carbon dioxide equivalents (CO2e) (6,702 million metric 

40 tons (MMT) CO2e) and since 1990 emissions have increased at an average annual rate of 

41 4 percent (EPA 2013e). In 2010 and 2011, the total amount of carbon dioxide equivalent 

42 (CO2e) emissions related to electricity generation was 2,303 teragrams (2,303 million metric 

43 tons (MMT)) and 2,200 teragrams (2,200 MMT), respectively (EPA 2013e). The Energy 

44 Information Administration (EIA) reported that, in 2010, electricity production in Tennessee was 

45 responsible for 48 MMT CO2e (EIA 2012). Facilities that emit 25,000 metric tons (MT) CO2e or 

46 more per year are required to report annually their GHG emissions to the EPA. These facilities 

47 are known as direct emitters and the data is publicly available in EPA’s facility-level information 
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1 on GHGs tool (FLIGHT). In 2011, FLIGHT identified eight facilities in Hamilton County, where 

2 SQN is located, that emitted a total of 818,014 MT CO2e (EPA 2013a). In 2011, FLIGHT 

3 identified 93 facilities in Tennessee that emitted a total of 55.8 MMT CO2e (EPA 2013b).

4 Appendix E provides a list of present and reasonably foreseeable projects that could contribute 

5 to GHG emissions. Permitting and licensing requirements and other mitigative measures can 

6 minimize the impacts of GHG emissions. For instance, in 2012 the EPA issued a final GHG 

7 Tailoring Rule to address GHG emissions from stationary sources under the CAA permitting 

8 requirements; the GHG Tailoring Rule establishes when an emission source will be subject to 

9 permitting requirements and control technology to reduce GHG emissions. Executive 

10 Order 13514 (Federal Leadership in Environmental, Energy, and Economic Performance) 

11 requires Federal agencies to set GHG emission reduction targets, relative to 2008 GHG 

12 emissions, by the year 2020. TVA, in accordance with this E.O. has developed a Strategic 

13 Sustainable Performance Plan that identifies the actions and measures that will be taken to 

14 reach GHG emission reduction targets by 2020 of its facilities (TVA 2012f). On June 25, 2013, 

15 the Executive Office of thePresident set forward a Climate Action Plan. The Climate Action Plan 

16 will reduce carbon pollution, prepare the United States for the impacts of climate change, and 

17 lead international efforts to combat global climate change. Future actions and steps taken to 

18 reduce GHG emissions, such as E.O. 13514 and the Climate Action Plan, will lessen the 

19 impacts on climate change.

20 EPA’s U.S. inventory of GHG emissions illustrates the diversity of GHG source emitters, such 

21 as electricity generation, industrial processes, and agriculture. GHG emissions resulting from 

22 operations at SQN range from 23,250 to 28,720 MT CO2e (Table 4–27). In comparing SQN’s 

23 GHG emission contribution to different emissions sources, whether it be total U.S. GHG 

24 emissions, emissions from electricity production in Tennessee, or emissions on a county level, 

25 GHG emissions from SQN are minor relative to these inventories; this is evident as presented in 

26 Table 4–28. Climate models indicate that short-term climate change (through the year 2030) is 

27 dependent on past GHG emissions. Therefore, climate change is projected to occur with or 

28 without present and future GHG emissions from SQN. The NRC staff concludes that the impact 

29 from the contribution of GHG emissions from continued operation of SQN on climate change 

30 would be SMALL. As discussed in Section 4.14.3.2, climate change and climate-related 

31 changes have been observed on a global level and climate models indicate that future climate 

32 change will depend on present and future GHG emissions. Based on continued increases in 

33 GHG emission rates, climate models project that Earth’s average surface temperature will 

34 continue to increase and climate-related changes will persist. Therefore, the cumulative impact 

35 of GHG emissions on climate change is noticeable but not destabilizing. The NRC staff 

36 concludes that the cumulative impacts from the proposed license renewal and other past, 

37 present, and reasonably foreseeable projects would be MODERATE.

38 4.16.12 Summary of Cumulative Impacts

39 The NRC staff considered the potential impacts resulting from the operation of SQN during the 

40 period of extended operation and other past, present, and reasonably foreseeable future actions 

41 near SQN. Potential cumulative impacts would range from SMALL to LARGE, depending on 

42 the resource. Table 4–29 summarizes the cumulative impacts on resource areas.
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1 Table 4–29. Comparison of GHG Emission Inventories

Source CO2e MMT/year

Global Fossil Fuel Combustion Emissions1 31,865.00

U.S. Emissions2 6,702.00

Tennessee3 55.80

Hamilton County4 0.82

SQN Emissions5 0.0029

1 According to the International Energy Agency in 2011 global CO2 emissions from fossil fuel combustion was 

31.6 Gt (IEA 2012); 31.6 Gt of CO2 is equivalent to 31,865 CO2e. 2 Source: EPA 2013e

3 GHG emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year (EPA 2013b)

4 GHG emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year (EPA 2013a)

5 Emissions include direct and indirect emissions from operation of SQN and the most conservative value is 

provided (2011 GHG inventory) (TVA 2013d; TVA 2013t).

2 Table 4–30. Summary of Cumulative Impacts on Resource Areas

Resource Area Cumulative Impact

Air Quality and 

Noise

Because there are no planned site refurbishments with the SQN license renewal, and 

no expected changes in air emissions, cumulative impacts in Hamilton County would 

be the result of changes to present-day emissions and emissions from reasonably 

foreseeable projects and actions. Various strategies and techniques are available to 

limit air quality impacts. Therefore, the cumulative impacts from the continued 

operation of SQN would be SMALL.

Water Resources

Consumptive surface water use from continued SQN operations will continue to be a 

very small percentage of the overall flow of the Tennessee River through Chickamauga 

Reservoir. Potential impacts to surface water resources include prolonged drought and 

temperature increases. Long-term warming could potentially affect navigation, power 

production, and municipal and industrial users, although the magnitude of the impact is 

uncertain. However, the regulatory framework established by the State of Tennessee 

in managing surface water use and quality and the operation of the Tennessee River 

System by TVA to manage flows and to regulate water quality for designated uses will 

continue to limit water withdrawals from and thermal discharges to the Chickamauga 

Reservoir. Therefore, the NRC staff concludes that the cumulative impacts from past, 

present, and reasonably foreseeable future actions on surface water resources during 

the license renewal term would be SMALL to MODERATE. SQN operations have not 

affected and are not expected to affect the quality of GW in any aquifers that are a 

current or potential future source of water for offsite users. Considering ongoing 

activities and reasonably foreseeable actions, the NRC staff concludes that the 

cumulative impacts on GW use and quality during the SQN license renewal term would 

be SMALL. Therefore, overall cumulative impact to water resources from continued 

operation of SQN would range from SMALL to MODERATE.
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Resource Area Cumulative Impact

Aquatic Ecology

NRC staff concludes that the cumulative impacts on aquatic resources in Chickamauga 

Reservoir are LARGE based on past, present and reasonably foreseeable future 

actions. The environmental effects are clearly noticeable and have destabilized 

important attributes of the aquatic resources in the vicinity of the SQN site. The 

incremental, site-specific impact from the continued operation of SQN during the 

license renewal period would be minor and not noticeable in comparison to cumulative 

impact on the aquatic ecology.

Terrestrial 

Ecology

Construction of new transmission lines, power plants, or residential areas over the 

proposed license renewal term have the potential to affect terrestrial resources. 

Habitat fragmentation will increase as the region surrounding the SQN site becomes 

more developed. Therefore, the cumulative impacts from the continued operation of 

SQN would be MODERATE.

Human Health

The NRC staff reviewed SQN’s radioactive effluent and environmental monitoring data 

from 2008 to 2012, and concluded the impacts of radiation exposure to the public from 

operation of SQN during the renewal term are SMALL. The cumulative radiological 

impacts from SQN, Units 1 and 2, and their potential production of tritium and use of 

MOX fuel, as well as its ISFSI, Watts Bar 1, and any future operating nuclear power 

plants are required to meet the radiation dose limits in 10 CFR Part 20 and EPA’s 40 

CFR Part 190. Therefore, the cumulative impacts from the continued operation of SQN 

would be SMALL.

Socioeconomics

As discussed in Section 4.9 of this SEIS, continued operation of SQN during the 

license renewal term would have no impact on socioeconomic conditions in the region 

beyond those already experienced. TVA has no plans to hire additional workers during 

the license renewal term; employment levels at TVA would remain relatively constant 

with no new demands for housing or increased traffic. Combined with other past, 

present, and reasonably foreseeable future activities, there will be no additional 

contributory effect on socioeconomic conditions from the continued operation of SQN 

during the license renewal period beyond what is currently being experienced. 

Therefore, the NRC staff concludes that the cumulative socioeconomic impact would 

be SMALL in the immediate vicinity of SQN.

Cultural 

Resources 

As described in Section 4.9, no cultural resources would be adversely affected by SQN, 

Units 1 and 2, license renewal activities as no associated changes or ground-disturbing 

activities will occur (TVA 2013a). Cultural resources on the SQN site are being 

managed through TVA BMPs (e.g., procedures and training) and license renewal would 

have no contributory incremental effect on historic and cultural resources. Therefore, 

combined with other past, present, and reasonably foreseeable future activities, the 

potential cumulative impacts on historic and cultural resources would be SMALL.

Environmental 

Justice

There would be no disproportionately high and adverse impacts to minority and 

low-income populations from the continued operation of SQN during the license 

renewal term.
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Resource Area Cumulative Impact

Waste 

Management and 

Pollution 

Prevention

Since current waste management activities at SQN would continue during the license 

renewal term, there would be no new or increased contributory effect beyond what is 

currently being experienced. Therefore, the only new contributory effects would come 

from reasonably foreseeable future planned activities at SQN, unrelated to the 

proposed action (license renewal), and other reasonably foreseeable planned offsite 

activities. All radioactive and nonradioactive waste treatment and disposal facilities 

within 50 mi (80 km) of SQN would also be required to comply with Federal and State 

permits and other regulatory requirements. In addition, the waste management 

activities at other TVA nuclear power reactor sites (e.g., Watts Bar) as well as other 

industrial facilities generating radioactive and nonradioactive waste would also have to 

meet the same or similar requirements. Based on this information, the cumulative 

effect from continued waste management activities at SQN during the license renewal 

term would be SMALL.

Global Climate 

Change

As discussed in Section 4.14.3, the NRC staff concludes that the impact from the 

contribution of GHG emissions from continued operation of SQN on climate change 

would be SMALL. As discussed in Section 4.14.3.2, 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. 

Because of continued increases in GHG emission rates, climate models project that 

Earth’s average surface temperature will continue to increase and climate-related 

changes will persist. Therefore, the cumulative impact of GHG emissions on climate 

change is 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, though 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 

15 exposed to radiation and chemicals associated with routine plant operations and the handling of 

16 nuclear fuel and waste material. Workers would have higher levels of exposure than members 

17 of the public, but doses would be administratively controlled and would not exceed standards or 
Environmental Consequences and Mitigating Actions

4-127

1 administrative control limits. In comparison, the alternatives involving the construction and 

2 operation of a non nuclear power generating facility would also result in unavoidable exposure 

3 to hazardous and toxic chemicals to workers and the public.

4 The generation of spent nuclear fuel and waste material, including low level radioactive waste, 

5 hazardous waste, and nonhazardous waste would be unavoidable. Hazardous and 

6 nonhazardous wastes would be generated at non nuclear power generating facilities. Wastes 

7 generated during plant operations would be collected, stored, and shipped for suitable 

8 treatment, recycling, or disposal in accordance with applicable Federal and state regulations. 

9 Due to the costs of handling these materials, power plant operators would be expected to carry 

10 out all activities and optimize all operations in a way that generates the smallest amount of 

11 waste possible.

12 4.17.2 Short-Term Versus Long-Term Productivity

13 The operation of power generating facilities would result in short term uses of the environment, 

14 as described in Chapter 4. “Short term” is the period of time that continued power generating 

15 activities take place.

16 Power plant operations require short term use of the environment and commitment of resources 

17 (e.g., land and energy), indefinitely or permanently. Certain short term resource commitments 

18 are substantially greater under most energy alternatives, including license renewal, than under 

19 the no action alternative because of the continued generation of electrical power and the 

20 continued use of generating sites and associated infrastructure. During operations, all energy 

21 alternatives entail similar relationships between local short term uses of the environment and 

22 the maintenance and enhancement of long term productivity.

23 Air emissions from power plant operations introduce small amounts of radiological and 

24 nonradiological constituents to the region around the plant site. Over time, these emissions 

25 would result in increased concentrations and exposure, but they are not expected to impact air 

26 quality or radiation exposure to the extent that public health and long term productivity of the 

27 environment would be impaired.

28 Continued employment, expenditures, and tax revenues generated during power plant 

29 operations directly benefit local, regional, and state economies over the short term. Local 

30 governments investing project generated tax revenues into infrastructure and other required 

31 services could enhance economic productivity over the long term.

32 The management and disposal of spent nuclear fuel, low level radioactive waste, hazardous 

33 waste, and nonhazardous waste requires an increase in energy and consumes space at 

34 treatment, storage, or disposal facilities. Regardless of the location, the use of land to meet 

35 waste disposal needs would reduce the long term productivity of the land.

36 Power plant facilities are committed to electricity production over the short term. After 

37 decommissioning these facilities and restoring the area, the land could be available for other 

38 future productive uses.

39 4.17.3 Irreversible and Irretrievable Commitments of Resources

40 This section describes the irreversible and irretrievable commitment of resources that have 

41 been noted in this SEIS. Resources are irreversible when primary or secondary impacts limit 

42 the future options for a resource. An irretrievable commitment refers to the use or consumption 

43 of resources that are neither renewable nor recoverable for future use. Irreversible and 

44 irretrievable commitment of resources for electrical power generation include the commitment of 
Environmental Consequences and Mitigating Actions

4-128

1 land, water, energy, raw materials, and other natural and man made resources required for 

2 power plant operations. In general, the commitment of capital, energy, labor, and material 

3 resources are also irreversible.

4 The implementation of any of the energy alternatives considered in this SEIS would entail the 

5 irreversible and irretrievable commitment of energy, water, chemicals, and—in some cases—

6 fossil fuels. These resources would be committed during the license renewal term and over the 

7 entire life cycle of the power plant, and they would be unrecoverable.

8 Energy expended would be in the form of fuel for equipment, vehicles, and power plant 

9 operations and electricity for equipment and facility operations. Electricity and fuel would be 

10 purchased from offsite commercial sources. Water would be obtained from existing water 

11 supply systems. These resources are readily available, and the amounts required are not 

12 expected to deplete available supplies or exceed available system capacities.

13 4.18 References

14 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

15 protection against radiation.”

16 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

17 production and utilization facilities.”

18 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

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

20 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

21 renewal of operating licenses for nuclear power plants.”

22 36 CFR Part 60. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

23 Part 60, “National register of historic places.”

24 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

25 Part 800, “Protection of historic and cultural properties.”

26 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

27 “Requirements for preparation, adoption, and submittal of implementation plans.”

28 40 CFR Part 60. Code of Federal Regulations, Title 40, Protection of Environment, Part 60, 

29 “Standards of performance for new stationary sources.” 

30 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

31 “Designation of areas for air quality planning purposes.”

32 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

33 “Environmental radiation protection standards for nuclear power operations.”

34 50 CFR 10.12. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 10, “General 

35 Provisions,” Subpart B– Definitions. 

36 50 CFR 22.3. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 22, “Eagle 

37 Permits,” Subpart A–Definitions.

38 50 CFR Part 72. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 72, 

39 “Immediate notification requirements for operating nuclear power reactors.”

40 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

41 “Interagency cooperation—Endangered Species Act of 1973, as amended.”
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41 Commission. Subject: Requests for additional information for the environmental review of the 

42 Sequoyah Nuclear Plant, Units 1 and 2, license renewal application. May 10, 2013. ADAMS 

43 No. ML13119A083.
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2 Control Desk. Subject: Response to NRC request for additional information regarding the 

3 environmental review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal 

4 Application (TAC Nos. MF0057 and MF0058). July 17, 2013. ADAMS No. ML13227A003.

5 [TVA] Tennessee Valley Authority. 2013i. Letter from J.W. Shea, Vice President, Nuclear 

6 Licensing, to Document Control Desk, U.S. Nuclear Regulatory Commission. Subject:

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8 Sequoyah Nuclear Plant, Units 1 and 2, license renewal application (TAC Nos. MF0057 and 

9 MF0058). July 23, 2013. ADAMS No. ML13206A385.

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12 Appendix E, Applicant’s Environmental Report, Operating License Renewal Stage.

13 Chattanooga, TN: TVA. January 7, 2013. ADAMS No. ML13024A010.

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15 Emissions. October 24, 2013. 1 p. ADAMS No. ML13289A247.

16 [TVA] Tennessee Valley Authority. 2013l. Letter from C. Jones, Senior Manager, to 

17 E.P. McIntyre, Jr., Executive Director, Tennessee Historical Commission. Subject: Sequoyah 

18 Nuclear Plant (SQN) operating license renewal, Site 40HA22 and revision to Phase I cultural 

19 resources survey final report, Hamilton County, Tennessee. September 6, 2013. ADAMS 

20 No. ML13281A806.

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25 Historian, to tribes. Subject: SQN operating license renewal, Site 40HA22 and revision to 

26 Phase I cultural resources survey final report, Hamilton County, Tennessee. 

27 September 11, 2013. ADAMS No. ML13296A491.

28 [TVA] Tennessee Valley Authority. 2013o. “TVA: Heritage.” Available at 

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37 [TVA] Tennessee Valley Authority. 2013s. “TVA: Water Supply.” Available at 

38 <http://www.tva.com/river/watersupply/faq.htm#7> (accessed 4 October 2013).

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40 No. ML13316A775

41 [TVAD] Tennessee Valley Authority Division of FFWD. 1969. Forestry Bulletin 143, June 1969.

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39 Acting THPO, to E. Larson, U.S. Nuclear Regulatory Commission. Subject: License Renewal 

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41 No. ML13084A357.

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2 hydrogeologic and instream habitat alterations. In Proceedings of the First Freshwater Mollusk 

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5-1 

1 5.0 CONCLUSION

2 This draft supplemental environmental impact statement contains the environmental review of 

3 the application for renewed operating licenses for Sequoyah Nuclear Plant, Units 1 and 2 

4 (SQN), submitted by Tennessee Valley Authority (TVA), as required by the Code of Federal 

5 Regulations (CFR), Part 51 of Title 10 (10 CFR Part 51), the U.S. Nuclear Regulatory 

6 Commission’s (NRC’s) regulations that implement the National Environmental Policy Act

7 (NEPA). This chapter presents conclusions and recommendations from the site-specific 

8 environmental review of SQN. 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 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 SQN would have SMALL impacts for the Category 2 issues 

15 applicable to license renewal at SQN. The NRC staff considered mitigation measures for each 

16 Category 2 issue, as applicable. The NRC staff concluded that no additional mitigation measure 

17 is warranted. 

18 5.2 Comparison of Alternatives

19 In Chapter 4, the staff considered the following alternatives to SQN license renewal:

20  no-action alternative, 

21  natural gas combined-cycle alternative,

22  super-critical pulverized coal alternative, 

23  new nuclear alternative, and

24  combination alternative (wind, solar)

25 Based on the summary of environmental impacts provided in Table 2–2, the NRC staff 

26 concluded that the environmental impacts of renewal of the operating licenses for SQN would 

27 be smaller than those of feasible and commercially viable alternatives. The no-action 

28 alternative, the act of shutting down SQN on or before its licenses expires, would have SMALL 

29 environmental impacts in most areas with the exception of socioeconomic impacts which would 

30 have SMALL to LARGE environmental impacts. Continued operations would have SMALL 

31 environmental impacts in all areas. The staff concluded that continued operation of the existing 

32 SQN is the environmentally preferred alternative.

33 5.3 Recommendation

34 The NRC’s preliminary recommendation is that the adverse environmental impacts of license 

35 renewal for SQN are not great enough to deny the option of license renewal for energy-planning 

36 decisionmakers. This recommendation is based on the following: 

37  the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic 

38 Environmental Impact Statement for License Renewal of Nuclear Plants, 

39  the Environmental Report submitted by TVA, 
Conclusion

5-2 

1  consultation with Federal, state, and local agencies,

2  the NRC staff’s environmental review, and

3  consideration of public comments received during the scoping process.
6-1 

1 6.0 LIST OF PREPARERS

2 Members of the U.S. Nuclear Regulatory Commission’s (NRC’s) Office of Nuclear Reactor 

3 Regulation (NRR) prepared this supplemental environmental impact statement (SEIS) with 

4 assistance from other NRC organizations and contract support from Pacific Northwest National 

5 Laboratory (PNNL), the Center for Nuclear Waste Regulatory Analyses (CNWRA) and a private 

6 contractor. Table 6–1 identifies each contributor’s name, affiliation, and function or expertise.

7 Table 6–1. List of Preparers

Name Affiliation Function or Expertise

NRC

D. Wrona NRR Management oversight

B. Wittick NRR Management oversight

D. Drucker NRR Project management

K. Folk NRR Surface water and alternatives

S. Klementowicz NRR Radiological, human health and alternatives

W. Ford NRR Groundwater, geology, soils and alternatives

M. Moser NRR Terrestrial ecology and alternatives

B. Grange NRR Special status species and habitats 

E. Larson NRR Cultural resources, cumulative impacts and alternatives

J. Rikhoff NRR Socioeconomic, environmental justice, and land use and 

alternatives

D. Logan NRR Aquatic ecology

N. Martinez NRR Air quality, meteorology, noise, greenhouse gas 

emissions and climate change, and alternatives

A. Travers NRR Alternatives

J. Dozier NRR Severe Accident Mitigation Alternatives

Contractor(a)(b)

S. Yabusaki PNNL Surface water and alternatives

T. O’Neil PNNL Cultural resources and alternatives

R. Krieg PNNL Aquatic ecology and special status species and habitats

J. Rishel PNNL Air quality, meteorology, noise and alternatives

D. Anderson PNNL Socioeconomic, environmental justice, and land use

R. Benke CNWRA Severe Accident Mitigation Alternatives

E. R. Schmidt Contractor Severe Accident Mitigation Alternatives

(a) PNNL is operated by Battelle for the U.S. Department of Energy. (b) CNWRA is a federally funded research and development center sponsored by the NRC.

7-1 

1 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS 

2 TO WHOM COPIES OF THIS SEIS ARE SENT

Name and Title Affiliation

Principal Chief Bill John Baker Tribal Nation—Cherokee Nation

Mr. Bili Anoatubby, Governor Tribal Nation—The Chickasaw Nation

Mr. Tarpie Yargee, Chief Tribal Nation—Alabama Quassarte Tribal Town

Principal Chief George Tiger Tribal Nation—Muscogee (Creek) Nation

Principal Chief Oscola Clayton Sylestine Tribal Nation—Alabama-Coushatta Tribe of Texas

Mr. George Scott, Town King Tribal Nation—Thlopthlocco Tribal Town

Chief Glenna J. Wallace Tribal Nation—Eastern Shawnee Tribe of Oklahoma

Chief Tiger Hobia Tribal Nation—Kialegee Tribal Town

Principal Chief Michell Hicks Tribal Nation—Eastern Band of the Cherokee Indians

Governor George Blanchard Tribal Nation—Absentee Shawnee Tribe of Oklahoma

Chief George G. Wickliffe Tribal Nation—United Keetoowah Band of Cherokee Indians in 

Oklahoma

Chairman James E. Billie Tribal Nation—Seminole Tribe of Florida

Chief Leonard M. Harjo Tribal Nation—Seminole Nation of Oklahoma

Reid Nelson, Director

Advisory Council on Historic Preservation

Office of Federal Agency Programs

1100 Pennsylvania Avenue, NW, Suite 803 

Washington, DC 20004

Cindy Dohner

Southeast Regional Director

U.S. Fish and Wildlife Service

1875 Century Blvd., Suite 400 

Atlanta, GA 30345-3319

Mary Jennings

Field Supervisor

U.S. Fish and Wildlife Service

Tennessee Ecological Services Field Office

446 Neal St.

Cookesville, TN 38501

Robbie Sykes

Fish and Wildlife Biologist

U.S. Fish and Wildlife Service

Tennessee Ecological Services Field Office

446 Neal St.

Cookesville, TN 38501

Mr. E. Patrick Mcintyre, Jr. 

Executive Director

Tennessee Historical Commission

Department Of Environment And Conservation

2941 Lebanon Road

Nashville, TN 37243-0442

Joseph W. Shea

Vice President, Nuclear Licensing

Tennessee Valley Authority

1101 Market Street, EB 9W

Chattanooga, TN 37402-2801
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent

7-2 

Name and Title Affiliation

Heinz Mueller, Chief

Environmental Assessment Branch 

U.S. Environmental Protection Agency, Region 4

Room 9T-25

Office of Environmental Accountability, Atlanta Federal Center

61 Forsyth Street, SW

Atlanta, GA 30303-3104

U.S. Environmental Protection Agency Sent via e-NEPA Web site

Scoping Participant Affiliation

Jaak Saame No affiliation provided

David Lochbaum Union of Concerned Scientists

PO Box 15316

Chattanooga, TN 37415-1271

Adelle Wood No affiliation provided

Jeannie Hacker-Cerulean No affiliation provided

Sylvia D. Aldrich No affiliation provided

Eric Blevins No affiliation provided

Tara Pilkinton No affiliation provided

Brian Paddock Sierra Club

Tim Anderson Blue Ridge Environmental Defense League (BREDL)

Gretel Johnston Bellefonte Efficiency & Sustainability Team (BEST), Mothers 

Against Tennessee River Radiation (MATRR)

Sandra Kurtz BEST/MATRR/BREDL

Yolanda Moyer No affiliation provided

Judith Canepa New York Climate Action Group

Tom Clements Friends of the Earth

Hardie Stulce Resident

Don Safer Tennessee Environmental Council, Tennessee Sierra

Kathleen Ferris Citizens to ENDIT 

Jimmy Green Southern Alliance for Clean Energy

Garry Morgan BEST/BREDL

Ann Harris Resident

Kristina Lambert BREDL
8-1 

1 8.0 INDEX

2 A 

3 accidents.........xxv, xxvi, 3-5, 3-10, 4-63, 4-65, 

4 4-66, 4-73, 4-114, A-12, A-13, A-14, A-15, A-16, 

5 A-18, A-20, A-22, A-25, A-26, A-27, F-1, F-2, 

6 F-4, F-12, F-16, F-17, F-19, F-24, F-31, F-39

7 Advisory Council on Historic Preservation 

8 (ACHP) ............xxi, 1-6, 4-49, 4-50, 4-137, 7-1, 

9 C-3, C-4 

10 aesthetic.......... 2-14, 3-108, 4-3, 4-4, 4-5, 4-6, 

11 4-85

12 alternatives .....i, xvii, xviii, 1-5, 2-1, 2-2, 2-3, 

13 2-4, 2-5, 2-10, 2-11, 2-13, 2-17, 2-19, 2-21, 

14 3-75, 4-1, 4-6, 4-13, 4-14, 4-15, 4-16, 4-21, 

15 4-25, 4-30, 4-44, 4-49, 4-54, 4-60, 4-64, 4-65, 

16 4-77, 4-78, 4-81, 4-86, 4-89, 4-90, 4-92, 4-96, 

17 4-126, 4-127, 4-128, 5-1, 6-1, A-1, A-3, A-4, 

18 A-5, A-6, A-7, A-9, A-23, C-2, F-1, F-19, F-26, 

19 F-43, F-44

20 archaeological resources........ 1-6, 2-4, 3-87, 

21 3-88, 3-89, 3-90, 3-91, 3-130, 4-116, D-2 

22 B 

23 biocide ............ 3-35

24 biological assessment ............ A-7, C-1, C-2 

25 biota.... 3-49, 4-100

26 boiling water reactor...xxi, 2-2 

27 burnup ............ 3-5 

28 C 

29 chronic effects ............ 4-61

30 Clean Air Act (CAA) ....xxi, 3-22, 3-23, 3-117, 

31 4-7, 4-8, 4-10, 4-94, 4-96, 4-103, 4-123, 4-129, 

32 4-131, A-3, A-20, B-2 

33 closed-cycle cooling... 2-7, 2-10, 2-11, 3-29, 

34 3-32, 4-22, 4-24, 4-44, 4-106

35 consumptive use......... 3-6, 3-32, 4-19, 4-21, 

36 4-22, 4-23, 4-24, 4-42, 4-106, A-29

37 cooling system ............xvi, xvii, xxii, 1-3, 1-5, 

38 2-4, 2-7, 2-8, 2-10, 2-11, 2-20, 3-5, 3-8, 3-32, 

39 3-52, 3-75, 4-16, 4-21, 4-22, 4-26, 4-27, 4-28, 

40 4-29, 4-31, 4-32, 4-33, 4-40, 4-42, 4-43, 4-44, 

41 4-72, 4-74, 4-76, 4-106, A-8, F-7, F-28, F-32, 

42 F-35, F-36, F-41, F-42

43 core damage frequency (CDF) ............ xxii, 

44 4-66, 4-67, 4-70, 4-71, 4-72, 4-74, F-1, F-2, F-3, 

45 F-6, F-7, F-8, F-9, F-10, F-11, F-13, F-14, F-15, 

46 F-16, F-17, F-18, F-23, F-24, F-26, F-27, F-28, 

47 F-34, F-40, F-43

48 Council on Environmental Quality (CEQ)

49 ............ xxii, 1-3, 3-108, 3-117, 4-27, 4-32, 4-94, 

50 4-111, 4-130

51 critical habitat. ............ 3-76, 3-78, 3-79, 3-80, 

52 3-81, 3-82, 3-83, 3-85, 3-87, 3-114, 4-45, 4-46, 

53 4-47, 4-48, B-3, C-1, C-2 

54 cultural resources....... xvii, 2-4, 3-87, 3-88, 

55 3-89, 3-90, 3-91, 3-125, 4-49, 4-50, 4-51, 4-52, 

56 4-53, 4-91, 4-100, 4-115, 4-116, 4-125, 4-141, 

57 A-9, B-1 

58 D 

59 decommissioning ....... A-3, A-5 

60 design-basis accident xxii, 4-1, 4-63, A-26, 

61 A-27

62 discharges...... 3-1, 3-5, 3-6, 3-8, 3-9, 3-10, 

63 3-11, 3-13, 3-21, 3-29, 3-30, 3-31, 3-32, 3-33, 

64 3-34, 3-35, 3-36, 3-52, 3-57, 3-59, 3-69, 3-70, 

65 3-104, 3-106, 4-16, 4-17, 4-18, 4-20, 4-21, 4-22, 

66 4-23, 4-31, 4-32, 4-41, 4-43, 4-44, 4-62, 4-92, 

67 4-105, 4-106, 4-107, 4-108, 4-112, 4-113, 

68 4-115, A-11

69 dose.... xxvii, 3-11, 3-12, 3-13, 3-14, 3-103, 

70 3-104, 3-113, 4-20, 4-68, 4-70, 4-71, 4-91, 

71 4-118, 4-125, A-12, A-13, A-14, A-16, A-17, 

72 A-20, F-1, F-4, F-20, F-21, F-26, F-27, F-28, 

73 F-39, F-40, F-43

74 dredging.......... 3-56, 3-75, 4-16, 4-21, 4-22, 

75 4-23, 4-24, 4-31, 4-42, 4-43, 4-44

76 E 

77 education........ 2-20, 3-89, 3-100, 4-54, A-20

78 electromagnetic fields ............ xxiii, 3-107, 

79 4-61, 4-78

80 endangered and threatened species .. xvii, 

81 1-6, 3-43, 3-44, 3-47, 3-114, 3-115, B-1, C-1 

82 Endangered Species Act (ESA)........... xvii, 

83 xxiii, 1-6, 1-7, 2-4, 3-42, 3-46, 3-72, 3-74, 3-75, 

84 3-114, 3-118, 4-44, 4-45, 4-46, 4-47, 4-48, 4-49, 

85 4-100, 4-128, 4-130, 4-132, B-3, C-1, C-2, C-3, 

86 C-5 
Index

8-2 

1 entrainment.....xvii, 3-8, 3-63, 3-75, 4-31, 4-32, 

2 4-33, 4-34, 4-36, 4-37, 4-38, 4-39, 4-40, 4-42, 

3 4-44, 4-112, 4-113, A-8 

4 environmental justice (EJ) ...... 2-4, 3-108, 

5 3-114, 3-115, 4-81, 4-82, 4-91, 4-119, 4-129, 

6 6-1, A-9 

7 essential fish habitat (EFH).....xxiii, 3-87, 

8 4-45, 4-46, 4-47, 4-48, 4-49, B-3, C-3 

9 eutrophication ............ 3-50, 3-75, 4-31, 4-100

10 evaporative loss .......... 4-99, 4-106

11 F 

12 Fish and Wildlife Coordination Act (FWCA)

13 ............ B-3 

14 G 

15 Generic Environmental Impact Statement 

16 (GEIS) . i, xv, xvi, xix, xxiv, 1-2, 1-3, 1-4, 1-5, 

17 1-6, 1-7, 2-1, 2-2, 2-3, 2-4, 2-7, 2-10, 2-11, 

18 2-17, 2-20, 2-26, 3-88, 3-95, 3-104, 3-106, 

19 3-124, 4-1, 4-2, 4-3, 4-4, 4-6, 4-7, 4-14, 4-16, 

20 4-20, 4-26, 4-31, 4-32, 4-42, 4-45, 4-49, 4-54, 

21 4-55, 4-56, 4-57, 4-61, 4-62, 4-63, 4-64, 4-81, 

22 4-86, 4-88, 4-89, 4-90, 4-91, 4-92, 4-93, 4-95, 

23 4-96, 4-136, 4-137, 5-1, A-1, A-17, A-19, A-21, 

24 A-22, A-26, A-27

25 greenhouse gases.......xxiv, 2-7, 2-8, 4-8, 

26 4-94, 4-129, 6-1, A-9 

27 groundwater ...xvii, xxiv, 3-16, 4-16, 4-64, A-9, 

28 A-11, A-27, B-1, E-4 

29 H 

30 hazardous waste .........xxv, 3-18, 3-104, 

31 3-113, 4-121, 4-127, B-3 

32 heat shock....... 4-42

33 high-level waste ..........xvi, 1-4, 4-86, 4-87, 

34 4-88, 4-90, A-29

35 I 

36 impingement... 3-8, 3-70, 3-75, 4-32, 4-33, 

37 4-34, 4-35, 4-36, 4-38, 4-39, 4-40, 4-42, 4-44, 

38 4-112, 4-113, 4-139, A-8 

39 independent spent fuel storage installation 

40 (ISFSI) . ............xxv, 3-1, 3-16, 3-21, 4-116, 

41 4-118, 4-121, 4-125, A-28, E-6, E-7 

42 Indian tribes.... 1-7, 3-108, 4-51, 4-81, 4-82

43 invasive species.......... 3-41, 3-71, 4-100, 

44 4-132

45 L 

46 long-term dose............ F-40

47 low-level waste............ 4-88, 4-90

48 M 

49 Magnuson-Stevens Fishery Conservation 

50 and Management Act (MSA) ... xxvii, 1-6, 1-7, 

51 3-117, B-3 

52 mitigation........ xvi, xxx, 1-3, 1-4, 1-5, 4-8, 

53 4-10, 4-11, 4-13, 4-47, 4-69, 4-78, 4-103, 4-126, 

54 4-137, 4-140, 5-1, A-3, D-2, F-5, F-12, F-16, 

55 F-25, F-26, F-30, F-34, F-38, F-44

56 mixed waste.... xxv, 3-11, 3-113, 4-87

57 N 

58 National Environmental Policy Act (NEPA)

59 ............ xvi, xxvii, 1-1, 1-7, 2-1, 2-7, 2-8, 3-108, 

60 3-117, 4-27, 4-32, 4-46, 4-50, 4-51, 4-86, 4-87, 

61 4-91, 4-121, 4-130, 4-131, 4-134, 4-136, 5-1, 

62 7-2, A-3, A-19, A-20, A-21, C-1, C-3, C-5 

63 National Marine Fisheries Service (NMFS)

64 ............ xxviii, 3-75, 3-87, 4-44, 4-46, 4-47, 

65 4-48, 4-49, 4-132, B-3, C-1, C-2, C-3, C-5 

66 National Pollutant Discharge Elimination 

67 System (NPDES) ......... xxviii, 3-5, 3-9, 3-29, 

68 3-32, 3-33, 3-34, 3-104, 3-106, 3-115, 3-116, 

69 3-122, 4-17, 4-18, 4-19, 4-21, 4-22, 4-23, 4-24, 

70 4-25, 4-27, 4-40, 4-41, 4-42, 4-43, 4-44, 4-62, 

71 4-107, 4-108, 4-109, 4-113, 4-114, 4-115, 

72 4-129, 4-133, 4-138, 4-139, 4-140, A-8, B-1, 

73 B-3, B-5, E-2, E-3, E-4, E-5, E-7 

74 Native American tribes............ 1-7, 4-51, 4-81, 

75 4-82

76 no-action alternative... i, xviii, 2-1, 2-3, 2-4, 

77 2-21, 4-32, 4-42, 4-46, 4-47, 4-48, 4-49, 4-87, 

78 5-1, A-6 

79 nonattainment ............ 3-22, 3-23 

80 O 

81 once-through cooling . ............ 3-5, 3-8, 3-32, 

82 4-16, 4-17, 4-18, 4-22, 4-26, 4-31, 4-32, 4-40, 

83 4-42, 4-106

84 P 

85 postulated accidents .. 4-1, 4-63, 4-81, A-27

86 power uprate .. 3-41

87 pressurized water reactor....... xxix, 4-112, 

88 A-7 
Index

8-3 

1 R 

2 radon .. 3-11, 3-16

3 reactor ............ xv, xxix, xxx, 2-1, 2-2, 2-10, 

4 3-1, 3-5, 3-9, 3-12, 3-13, 3-14, 3-15, 3-17, 3-19, 

5 3-20, 3-21, 3-38, 3-88, 3-104, 4-4, 4-5, 4-21, 

6 4-29, 4-50, 4-52, 4-54, 4-55, 4-56, 4-57, 4-58, 

7 4-59, 4-63, 4-64, 4-65, 4-66, 4-68, 4-74, 4-78, 

8 4-83, 4-86, 4-87, 4-92, 4-113, 4-117, 4-118, 

9 4-121, 4-122, 4-126, A-7, A-11, A-14, A-15, 

10 A-17, A-18, A-21, A-24, A-25, A-26, A-27, A-29, 

11 E-2, E-7, E-8, F-2, F-4, F-6, F-7, F-11, F-12, 

12 F-13, F-15, F-16, F-24, F-27, F-31, F-32, F-37, 

13 F-40, F-41

14 refurbishment . 2-2, 3-75, 3-104, 4-7, 4-23, 

15 4-26, 4-54, 4-94, 4-103, 4-104

16 replacement power .....xviii, 2-2, 2-3, 2-4, 2-7, 

17 2-8, 2-21, 4-12, 4-24, 4-83, 4-84, 4-90, 4-92, 

18 A-6, F-22, F-39, F-40

19 S 

20 salinity gradients......... 4-16

21 scoping............i, xv, xvi, xix, 1-1, 1-2, 1-5, 1-6, 

22 3-89, 4-1, 4-7, 4-14, 4-16, 4-20, 4-26, 4-31, 

23 4-50, 4-51, 4-54, 4-61, 4-86, 4-90, 4-92, 4-102, 

24 4-137, 5-2, A-1, A-2, A-6, A-17, A-22, A-27, 

25 C-4, C-5, D-1, D-2, E-6 

26 seismic ............ 3-10, 3-25, 3-28, 3-121, 4-64, 

27 4-70, A-26, F-11, F-12, F-13, F-16, F-23, F-24, 

28 F-25, F-26

29 severe accident mitigation alternative 

30 (SAMA) ............xvii, xxx, 4-65, 4-66, 4-68, 4-70, 

31 4-71, 4-72, 4-74, 4-76, 4-77, 4-78, 4-134, A-3, 

32 A-23, A-24, D-2, F-1, F-2, F-4, F-6, F-8, F-9, 

33 F-10, F-11, F-12, F-16, F-17, F-18, F-19, F-20, 

34 F-21, F-22, F-23, F-24, F-25, F-26, F-27, F-28, 

35 F-34, F-35, F-36, F-37, F-38, F-39, F-41, F-42, 

36 F-43, F-44, F-45

37 severe accidents .........xvii, xxx, 4-1, 4-63, 

38 4-64, 4-65, 4-66, 4-81, A-24, A-25, A-26, A-27, 

39 D-2, F-1, F-11, F-17, F-19, F-24, F-30, F-36, 

40 F-40, F-41

41 solid waste...... xviii, xxvii, 2-4, 2-17, 2-19, 

42 3-11, 3-15, 3-18, 3-103, 3-113, 4-91, 4-94, B-1, 

43 B-3, B-5 

44 spent fuel ........xvi, xxv, 1-4, 3-16, 4-86, 4-87, 

45 4-90, 4-91, A-11, A-14, A-24, A-25, A-27, A-28, 

46 E-7 

47 State Historic Preservation Office (SHPO)

48 ............xxx, 1-6, 3-91, 3-130, 4-50, 4-51, B-4 

49 State Pollutant Discharge Elimination 

50 System (SPDES) ......... B-1 

51 stormwater...... 3-29, 3-31, 3-33, 3-115, 4-21, 

52 4-22, 4-23, 4-24, 4-25, 4-27, 4-44, 4-107, B-5 

53 surface runoff . 3-30, 4-21, 4-23, 4-24, 4-25, 

54 4-97, 4-99, 4-100, 4-107, 4-115

55 surface water.. xxxi, 3-6, 3-29, 3-31, 3-32, 

56 4-16, 4-17, 4-18, 4-19, 4-21, 4-22, 4-23, 4-24, 

57 4-25, 4-27, 4-41, 4-42, 4-82, 4-91, 4-99, 4-105, 

58 4-106, 4-107, 4-109, 4-114, 4-124, A-29, B-1, 

59 B-3, E-4 

60 T 

61 taxes... 3-101, 4-55

62 Tennessee Department of Environment and 

63 Conservation.. xxxi, 3-9, 3-18, 3-19, 3-23, 

64 3-24, 3-31, 3-32, 3-33, 3-34, 3-41, 3-42, 3-43, 

65 3-47, 3-73, 3-87, 3-127, 4-18, 4-19, 4-27, 4-106, 

66 4-107, 4-109, 4-113, 4-114, 4-138, B-1, B-5, 

67 B-6, E-5 

68 Tennessee Department of Health........ xxxi, 

69 3-106
Index

8-4 

1 Tennessee Valley Authority ....i, xv, xvi, xvii, 

2 xix, xxxi, 1-1, 1-5, 1-6, 1-7, 1-8, 2-2, 2-3, 2-4, 

3 2-5, 2-6, 2-7, 2-8, 2-9, 2-10, 2-11, 2-12, 2-13, 

4 2-14, 2-15, 2-16, 2-17, 2-18, 2-20, 2-21, 2-24, 

5 2-26, 2-27, 3-1, 3-2, 3-3, 3-4, 3-5, 3-6, 3-7, 3-8, 

6 3-9, 3-10, 3-11, 3-13, 3-14, 3-15, 3-16, 3-17, 

7 3-18, 3-19, 3-20, 3-21, 3-22, 3-23, 3-24, 3-25, 

8 3-26, 3-28, 3-29, 3-30, 3-31, 3-32, 3-33, 3-34, 

9 3-35, 3-36, 3-37, 3-38, 3-39, 3-40, 3-41, 3-42, 

10 3-43, 3-44, 3-45, 3-46, 3-47, 3-48, 3-50, 3-51, 

11 3-52, 3-53, 3-54, 3-55, 3-56, 3-57, 3-58, 3-59, 

12 3-60, 3-61, 3-62, 3-63, 3-64, 3-69, 3-70, 3-74, 

13 3-76, 3-77, 3-78, 3-79, 3-80, 3-81, 3-82, 3-83, 

14 3-84, 3-85, 3-86, 3-87, 3-88, 3-89, 3-90, 3-91, 

15 3-92, 3-93, 3-95, 3-101, 3-102, 3-103, 3-104, 

16 3-106, 3-107, 3-108, 3-113, 3-118, 3-126, 

17 3-128, 3-129, 3-130, 3-131, 4-1, 4-4, 4-5, 4-7, 

18 4-8, 4-9, 4-10, 4-11, 4-12, 4-13, 4-14, 4-16, 

19 4-17, 4-18, 4-19, 4-20, 4-22, 4-23, 4-24, 4-25, 

20 4-26, 4-27, 4-29, 4-30, 4-31, 4-33, 4-34, 4-35, 

21 4-36, 4-37, 4-38, 4-39, 4-40, 4-41, 4-42, 4-43, 

22 4-44, 4-46, 4-47, 4-48, 4-49, 4-51, 4-52, 4-53, 

23 4-54, 4-55, 4-56, 4-57, 4-58, 4-59, 4-61, 4-62, 

24 4-65, 4-66, 4-68, 4-70, 4-71, 4-72, 4-76, 4-77, 

25 4-78, 4-82, 4-86, 4-90, 4-92, 4-94, 4-95, 4-96, 

26 4-97, 4-100, 4-102, 4-103, 4-104, 4-105, 4-106, 

27 4-107, 4-108, 4-109, 4-112, 4-113, 4-114, 

28 4-115, 4-116, 4-117, 4-118, 4-119, 4-121, 

29 4-122, 4-123, 4-124, 4-125, 4-126, 4-129, 

30 4-130, 4-134, 4-138, 4-139, 4-140, 4-141, 5-1, 

31 7-2, A-3, A-4, A-5, A-6, A-7, A-9, A-14, A-15, 

32 A-18, A-19, A-20, A-21, A-22, A-23, A-24, A-25, 

33 A-26, A-28, B-5, B-6, D-1, D-2, E-2, E-3, E-4, 

34 E-6, E-7, E-9, F-1, F-2, F-4, F-6, F-8, F-9, F-10, 

35 F-11, F-12, F-13, F-14, F-15, F-16, F-17, F-18, 

36 F-19, F-20, F-21, F-22, F-23, F-24, F-25, F-26, 

37 F-27, F-28, F-30, F-35, F-36, F-37, F-38, F-39, 

38 F-40, F-41, F-42, F-43, F-44, F-45, F-46, F-47

39 transmission line corridors..... 4-25

40 transmission lines....... 2-7, 2-8, 2-10, 2-21, 

41 3-19, 3-41, 3-48, 3-75, 3-88, 3-106, 3-107, 4-2, 

42 4-4, 4-7, 4-22, 4-25, 4-26, 4-27, 4-28, 4-30, 

43 4-50, 4-52, 4-53, 4-62, 4-110, 4-111, 4-116, 

44 4-125

45 tritium . ............ xxxi, 3-12, 3-17, 3-36, 3-38, 

46 4-20, 4-21, 4-110, 4-116, 4-117, 4-118, 4-121, 

47 4-125, A-9, A-10, A-11, E-6 

48 U 

49 U.S. Army Corps of Engineers ............ xxxi, 

50 3-123, 4-21, 4-22, 4-23, 4-24, 4-42, 4-43, 4-44, 

51 E-3, E-7, E-10

52 U.S. Department of Energy (DOE)....... xxii, 

53 xxiii, 2-4, 2-6, 2-7, 2-10, 2-11, 2-12, 2-14, 2-16, 

54 2-23, 2-24, 2-25, 2-26, 3-16, 3-17, 3-118, 4-61, 

55 4-115, 4-117, 4-118, 4-121, 4-129, 4-130, 

56 4-134, 4-135, 6-1, A-6, E-2, E-6, E-7, E-8 

57 U.S. Environmental Protection Agency (EPA)

58 ............ xxiii, 1-1, 2-1, 2-4, 2-8, 2-23, 2-24, 3-11, 

59 3-12, 3-13, 3-14, 3-22, 3-23, 3-24, 3-25, 3-32, 

60 3-38, 3-108, 3-113, 3-115, 3-118, 3-119, 4-8, 

61 4-9, 4-10, 4-11, 4-20, 4-27, 4-32, 4-33, 4-38, 

62 4-79, 4-93, 4-95, 4-96, 4-97, 4-98, 4-103, 4-118, 

63 4-122, 4-123, 4-124, 4-125, 4-126, 4-129, 

64 4-130, 4-131, 4-138, 5-1, 7-2, A-8, A-21, B-1, 

65 B-2, B-3, F-4, F-5, F-7, F-8, F-20

66 U.S. Fish and Wildlife Service (FWS).. xxiv, 

67 1-6, 1-7, 3-41, 3-42, 3-47, 3-48, 3-73, 3-74, 

68 3-75, 3-76, 3-77, 3-78, 3-79, 3-80, 3-81, 3-82, 

69 3-83, 3-85, 3-86, 3-87, 3-114, 3-115, 3-117, 

70 3-119, 3-120, 3-121, 3-125, 3-132, 4-44, 4-45, 

71 4-46, 4-47, 4-48, 4-49, 4-132, 7-1, B-3, C-1, 

72 C-2, C-3, C-5 

73 uranium........... xxi, xxiv, xxvii, xxxi, 2-6, 2-11, 

74 3-5, 3-17, 4-1, 4-3, 4-4, 4-5, 4-6, 4-29, 4-79, 

75 4-90, 4-91, 4-93, 4-116, A-12, A-13, A-24, A-27, 

76 A-29, E-7 

77 W 

78 wastewater...... 2-16, 3-10, 3-19, 3-33, 4-22, 

79 4-94, 4-105, 4-107, 4-114, 4-115, E-4, E-5, E-7 
1 APPENDIX A 

2 COMMENTS RECEIVED ON THE SQN ENVIRONMENTAL REVIEW 

A

A-1 

1 COMMENTS RECEIVED ON THE SQN ENVIRONMENTAL REVIEW

2 A.1 Comments Received During the Scoping Period

3 The scoping process for the environmental review of the license renewal application for 

4 Sequoyah Nuclear Plant, Units 1 and 2 (SQN) began on March 8, 2013, with the publication of 

5 the U.S. Nuclear Regulatory Commission’s (NRC’s) Notice of Intent to conduct scoping in the 

6 Federal Register (78 FR 15055). The scoping process included two public meetings held in 

7 Soddy-Daisy, Tennessee, on April 3, 2013. Approximately 80 people attended the meetings. 

8 After the NRC’s prepared statements pertaining to the license renewal process, the meetings 

9 were open for public comments. Attendees provided oral statements that were recorded and 

10 transcribed by a certified court reporter. A summary and transcripts of the scoping meetings are 

11 available using the NRC’s Agencywide Documents Access and Management System (ADAMS). 

12 ADAMS Public Electronic Reading Room is accessible at http://www.nrc.gov/reading13 rm/adams.html. The scoping meetings summary is listed under ADAMS Accession Number 

14 ML13108A146. Transcripts for the afternoon and evening meetings are listed under Accession 

15 Numbers ML13108A137 and ML13114A124, respectively. In addition to comments received 

16 during the public meetings, comments were also received electronically.

17 Each commenter was given a unique identifier, so every comment can be traced back to its 

18 author. Table A–1 identifies the individuals who provided comments and an accession number 

19 to identify the source document of the comments in ADAMS.

20 Specific comments were categorized and consolidated by topic. Comments with similar specific 

21 objectives were combined to capture the common essential issues raised by commenters. 

22 Comments fall into one of the following general groups: 

23  Specific comments that address environmental issues within the purview of 

24 the NRC environmental regulations related to license renewal. These 

25 comments address Category 1 (generic) or Category 2 (site-specific) issues 

26 identified in NUREG-1437, Generic Environmental Impact Statement for 

27 License Renewal of Nuclear Plants (GEIS) or issues not addressed in the

28 GEIS. The comments also address alternatives to license renewal and 

29 related Federal actions.

30  General comments in support of or opposed to nuclear power or license 

31 renewal or comments regarding the renewal process, the NRC’s regulations, 

32 and the regulatory process.

33  Comments that address issues that do not fall within or are specifically 

34 excluded from the purview of NRC environmental regulations related to 

35 license renewal. These comments typically address issues such as the need 

36 for power, emergency preparedness, security, current operational safety 

37 issues, and safety issues related to operation during the renewal period.

38 Comments that are general or outside the scope of the environmental review for SQN license 

39 renewal are not included here but can be found in the Scoping Summary Report (ADAMS 

40 Accession No. ML14041A118). To maintain consistency with the Scoping Summary Report, the 

41 unique identifier used in that report for each comment is retained in this Appendix A. Comments

42 addressed in this Appendix A are identified in the meeting transcripts and written comments 

43 provided at the end of the Scoping Summary Report. 
Appendix A

A-2 

1 Table A–1. Individuals Providing Comments During the Scoping Comment Period

2 Each commenter is identified along with their affiliation and how their comment was submitted.

Commenter Affiliation (if stated) ID Comment source ADAMS 

Number

Jaak Saame 1 Web ML13091A018

David Lochbaum Union of Concerned 

Scientists

2 Web ML13101A117

Adelle Wood 3 Web ML13116A292

Jeannie HackerCerulean

University of Tennessee at 

Chattanooga

4 Web ML13116A293

Sylvia D. Aldrich 5 Web ML13116A295

Eric Blevins 6 Web ML13116A296

Tara Pilkinton 7 Web ML13116A294

Brian Paddock Resident 8 Email

Evening meeting

ML13119A111

ML13114A124

Tim Anderson 9 Email

Evening meeting

ML13142A389

ML13114A124

Gretel Johnston Bellefonte Efficiency & 

Sustainability Team

Mothers Against Tennessee 

River Radiation

10 Email

Afternoon meeting

ML13119A113

ML13108A137

Sandra Kurtz Resident 11 Email

Afternoon meeting

Evening meeting

ML13119A203

ML13108A137

ML13114A124

Unknown name 

Initials: CS

12 Web ML13121A158

Yolanda Moyer 13 Web ML13130A238

Judith Canepa New York Climate Action 

Group

14 Web ML13130A239

Tom Clements Friends of the Earth 15 Mail ML13149A008

Hardie Stulce Resident 16 Afternoon meeting ML13108A137

Don Safer Resident 17 Afternoon meeting

Evening meeting

ML13108A137

ML13114A124

Kathleen Ferris Resident 18 Afternoon meeting

Evening meeting

ML13108A137

ML13114A124

Jimmy Green Resident 19 Evening meeting ML13114A124

Garry Morgan Non-Resident 20 Evening meeting ML13114A124

Ann Harris Resident 21 Evening meeting ML13114A124

Kristina Lambert BREDL 22 Mail ML13130A244

3 Comments received during the scoping comment period applicable to this environmental review 

4 were placed into 1 of 9 categories, which are based on topics contained in the SQN draft 

5 supplemental environmental impact statement (DSEIS). These categories and their 

6 abbreviation codes are listed in Table A–2.

7 The following pages contain the comments, identified by the commenter’s ID, comment number,

8 and comment issue category along with the NRC staff response. Comments are presented in 

9 the same order as listed in Table A–2.
Appendix A

A-3 

1 Table A–2. Issue Categories

2 Comments were divided into the 9 categories below, each with a unique abbreviation code.

Code Technical Issue

AL Alternatives

AE Aquatic Ecology

CC Climate Change

GW Groundwater

HH Human Health

LR License Renewal and NEPA Process

PA Postulated Accidents and SAMA

RW Radiological Waste

SW Surface Water

3 A.1.1 Alternatives

4 Comments:

5 8-4-AL: NEPA requires a hard look and that’s a very interesting test for a lawyer. What’s a hard 

6 look? And I’ve read hundreds of NEPA cases and it varies, but it does not appear here that 

7 there has been or so far an active consideration of what would be called the no action option 

8 which would be not to issue a license extension and to put the plant into a posture where it 

9 would be decommissioned at the termination of the existing license period.

10 8-6-AL: And secondly, the GAO did a similar study, full consideration of energy efficiency and 

11 better capital expense for planning. GAO, when they say we don’t think that TVA has really 

12 looked at the realistic potential for energy efficiency. So those are yet unoffered.

13 One other factor you should look at is that the USEC, the United States Enrichment 

14 Corporation, which is a shuck and a boondoggle and has been for years, to create nuclear fuel, 

15 has announced that it is closing this year. That represents five percent of the entire load and 

16 production of electricity. So we’re going to have a five percent decline this year apart from any 

17 other energy efficiency.

18 9-7-AL: We also request an evaluation process as to whether this "proposed" increase in 

19 demand for energy could not be met with any other form of energy, such as solar or hydro, an 

20 energy source that doesn’t carry the threat of a 25 mile dead zone for hundreds of years.

21 9-10-AL: In accordance with NEPA and Section 309 of the Clean Air Act, we ask for an 

22 evaluation of alternative modes of facility operations, including answering the question, can a 

23 portion or even all of this "proposed" energy demand be met more cost effective with 

24 environmentally friendly renewable energy, and ask that you evaluate alternative technologies 

25 and mitigation measures, and the environmental impact of these alternatives. 

26 10-1-AL: I come here today, first of all, I’d like to challenge a basic assumption that’s in this 

27 Environmental Report. And that is that the only alternative to extending this license is either to 

28 do nothing and decommission, which I would recommend, or to -- the other option is called, in 

29 your own words, as the "reasonable alternative energy sources" as an option. But the only 

30 options that are given in this study are nuclear and gas powered power plants.

31 And many, many studies -- and I’ve included them in the literature -- have addressed the 

32 issue of how to replace -- as we retire coal plants and nuclear plants, how we replace dirty 

33 energy with clean energy. And the first and foremost choice that we advocate is energy 

34 efficiency. 
Appendix A

A-4 

1 Energy efficiency cannot only replace all the power that’s being generated by Sequoyah 

2 at this time and quickly. It does not come on line slowly; it comes on line quickly and creates a 

3 lot of jobs and it’s less expensive by far than nuclear. But it also will improve the homes of the 

4 people of the Tennessee Valley. It will improve your lives by giving you smaller electric bills 

5 every month and as well as creating jobs and not fouling our nest and putting dangerous 

6 radioactive poisons into our ecosystem or fossil fuels either. 

7 So our first line we recommend is that this basic assumption that the only alternatives

8 are dirty fuels being looked at carefully and examined and that that assumption be renegotiated 

9 for the power plant. That, if in fact another option is taken, that that could be renewable energy 

10 or the first line we would recommend is energy efficiency. 

11 In a study by Georgia Tech and Duke University a couple of years ago asserted that 

12 energy efficiency programs in one decade in the South alone could create 380,000 new jobs. 

13 That’s between 2010 and 2020, 380,000 new jobs. It would lower electricity bills by 41 billion 

14 dollars. And all while eliminating the need for new power plants for two decades and saving 8.6 

15 billion gallons of fresh water. Now that’s a major environmental concern. And if this truly is an 

16 environmental study, I think that this has to be taken into consideration and considered as a 

17 viable modern alternative.

18 So we call first of all for energy efficiency.

19 10-14-AL: First, we think it is important to challenge the stated assumption that, "Possible 

20 alternatives to the proposed action (license renewal) include no action and reasonable 

21 alternative energy sources," given that only nuclear and gas power plants are considered as 

22 "reasonable alternative energy sources." We assert that Energy Efficiency and Renewable 

23 Energy are "reasonable alternative energy sources" that need to be identified and evaluated in 

24 the Supplemental Environmental Impact Statement (SEIS). To support our claim, we enter into 

25 the record multiple studies showing that Energy Efficiency Programs are definitively more 

26 economically viable and environmentally "reasonable alternative energy sources" than nuclear 

27 or gas power plants.

28 All of the power generated by Sequoyah can be replaced by energy efficiency alone and 

29 new power can be generated with renewable sources, such as wind or solar. In fact, Energy 

30 Efficiency Programs can readily replace the existing power and provide for future power needs – 

31 offering significantly more jobs, coming ‘on-line’ more quickly, and enhancing the quality of life 

32 of TVA rate-payers by improving the efficiency of our homes, reducing monthly electric bills, and

33 improving our environment by not emitting toxic waste. According to a Georgia Tech and Duke

34 University study, assertive energy efficiency programs in one decade in the south alone can

35 create 380,000 new jobs and lower utility bills by $41 billion, while eliminating the need for new

36 power plants for two decades, and saving 8.6 billion gallons of fresh water.

37 And if more energy does need to be generated, solar is now less expensive than 

38 nuclear, and a 2012 federal report on renewable energy states that Tennessee alone has the 

39 technical potential of generating well over 2 million GWh of utility scale solar power.

40 Rather than "reasonable alternative energy sources", we believe this false assumption of 

41 limited options is biased toward environmentally unsound choices requiring the use of dirty 

42 nuclear and fossil fuels rather than the best replacement of existing power - which is first and 

43 foremost that of demand reduction through energy efficiency and heat recycling, and secondly 

44 through environmentally sustainable renewable energy such as wind and solar. That the SEIS 

45 has not included these options with its nuclear and gas generation alternatives indicates how 

46 behind-the times TVA seems determined to remain, no matter what the cost to rate-payers or 
Appendix A

A-5 

1 the environment. The NRC should not accept this assessment of environmental impact without 

2 studying and reasonably adjusting these basic assumptions about viable alternatives.

3 10-21-AL: We know that energy efficiency programs can ‘supply’ the energy we need at less 

4 cost for TVA and at greater benefit to the people of this valley. We also know that renewable 

5 electricity can be generated for less money and with significantly less risk to human habitat. 

6 What we do not know is why the NRC continually enables an industry that is willing to gamble 

7 with human lives and habitats, despite the "reasonable alternative energy sources" of energy 

8 efficiency and renewables.

9 11-19-AL: I know that Gretel had just spoken about the decommissioning plans and the fact 

10 that there are only two alternatives mentioned, both of which either say decommission -- and we 

11 would recommend that -- or and build a new -- but the alternative also says if you want a new 

12 40-year licensed nuclear plant. But you can’t do it on the Sequoyah nuclear site. It’s already 

13 poisoned actually. So that doesn’t sound like a good plan. We wouldn’t recommend any more 

14 nuclear plants. 

15 The other is the gas fired generators to replace Sequoyah Nuclear Plant, but again not 

16 on the Sequoyah Nuclear Plant site because it’s sort of no man’s land when you get a nuclear 

17 plant. People can’t go there again. It’s kind of like a land grab, it seems to me, kind of giving 

18 away your land which can never be entered again because it always -- even in 

19 decommissioning, because it always has to be protected from the radiation. So you’re giving 

20 away to land to think about having nuclear plants. But if they’re going to be decommissioned, it 

21 has to be certainly safe, too. 

22 There are alternatives and I, too, would suggest that NRC consider other alternatives 

23 besides just those two.

24 11-26-AL: And the idea that we don’t need to replace that energy or that it could be replaced 

25 with solar alternative or other alternative energies.

26 11-38-AL: The SEIS states that there are only two feasible alternatives to consider meeting the 

27 need for power in the future? Alternatives: 1. Decommission SQN and build a new nuclear 

28 plant replacement with a 40-year license somewhere besides the SQN site. 2. Construct new 

29 natural gas-fired generators and infrastructure in place of SQN, but not on the SQN site. Can it 

30 be that TVA and NRC cannot think of any other alternatives such as shutting SQN down and 

31 meeting power demand and even baseload with solar, wind, energy efficiency, demand-side 

32 management, and other now-viable energy alternatives to name some? These will be cheaper, 

33 healthier and safer. Consider other alternatives.

34 14-7a-AL: We support the swift transfer to renewable energy technologies. Such a transfer is 

35 not only possible, it is possible now, and absolutely essential for the sustainability of human life. 

36 If Germany, Denmark, and other countries can do it, so can the United States.

37 17-8-AL: The other thing that I would like -- next thing I’d like the NRC to consider in this 

38 application is the need for the power from this risky type of power. Last year alone in 2012, 

39 according to the USA Today there was over 13,000 megawatts of wind power installed in the 

40 United States. That’s 13 reactors like Sequoyah. In one year without hearings like this, without 

41 the need to go through these types of procedures, without the risk to the public, without the 

42 evacuation plans, without the radioactive waste.

43 17-11-AL: So back to the need for it, the wind potential, the solar potential in the valley, at this 

44 point TVA is putting a restriction on the amount of solar that can be installed. There’s so much 

45 more potential to install solar and it won’t even cost TVA anything but the feed-in tariff. People 
Appendix A

A-6 

1 are willing to spend their own money, put these solar panels on their roofs. And TVA is putting 

2 a limit on how much solar power can go on people’s roofs.

3 17-12-AL: And there are credible sources. The National Renewal Energy Lab in Colorado, it’s 

4 a Department of Energy funded think tank on renewable energy. It says we can get all of our 

5 power in a reliable grid by 2040 -- or 80 percent of our power in a reliable grid by 2040 from all 

6 renewable sources. And that’s not with -- that’s without even evolving the renewable technology 

7 like it’s going to evolve.

8 17-22-AL: The lack of need, just this last year 2012, over 13,000 megawatts of wind power was 

9 put in place in the United States. It required no scoping hearings about massive releases of 

10 radiation. That’s 13 nuclear power plants the size of Sequoyah that have gone online in the 

11 U.S.

12 TVA has a proposal in front of them today for 3,500 megawatts of wind power to be 

13 brought in from Oklahoma by a private company on a direct current line through Arkansas and 

14 put into the TVA grid in Memphis to be used. That’s 3,500 megawatts. That’s both Sequoyah 

15 Plant and the Gallatin Steam Plant. That’s just scratching the surface of what wind can do. 

16 Solar energy is -- TVA is putting the brakes on solar every way that it can in every 

17 possible situation. Just look it up. There’s a budding solar energy industry in the Valley. A lot 

18 of jobs, a lot of installers, it’s jobs that can’t be exported. It’s jobs that will continue. And the 

19 people who have put solar on their roofs have guaranteed what their cost is going to be for 30 

20 years. TVA needs to encourage that instead of this license renewal.

21 19-1-AL: The main point I want to make is we wanted to make sure that the NRC is aware that 

22 TVA is beginning to enter into the process of developing an updated, integrated resource plan. 

23 Probably at the end of this year they’re going to get started seriously on that. This will inform 

24 the question of whether or not the power generated by this plant is needed. 

25 And so we would recommend that you closely follow the IRP process of TVA to see how 

26 that calculation plays out. Clearly not using this energy is going to be the most efficient way to 

27 go and the least environmental impact. And that’s the thing we’re always recommending, 

28 energy efficiency and renewable energy as a clean and preferred alternative.

29 Response: These comments concern renewable energy replacement power and energy 

30 efficiency alternatives to SQN and assert that the environmental impact statement should 

31 address the no-action alternative to license renewal at SQN. In evaluating alternatives to 

32 license renewal, the NRC staff considered energy technologies or options currently in 

33 commercial operation, as well as technologies not currently in commercial operation but likely to 

34 be commercially available by the time the current SQN operating licenses expire. 

35 The NRC staff evaluated 18 alternatives to the proposed action in the SQN DSEIS. Alternatives 

36 that could not provide the equivalent of SQN’s current generating capacity and, in some cases, 

37 those alternatives whose costs or benefits did not justify inclusion in the range of reasonable 

38 alternatives, were eliminated from detailed consideration. The NRC staff explained the reasons 

39 why each of these alternatives was eliminated from further consideration in section 2.3 of the 

40 SQN DSEIS. The 18 alternatives were narrowed to 4 alternatives considered in detail in 

41 sections 2.2.2.1–2.2.2.4 of the SQN DSEIS. The NRC staff evaluated the environmental 

42 impacts of these four alternatives and the no-action alternative in Chapter 4 of the SQN DSEIS. 

43 8-11-AL: Articles to be considered in the environmental review: GAO Report GAO-12-107 - 

44 Tennessee Valley Authority, Full Consideration of Energy and Efficiency and Better Capital 

45 Expenditures Planning Are Needed; and, Global Energy Partners’ Study Identifies Significant 

46 Energy Savings Potential for TVA Customers.
Appendix A

A-7 

1 10-10-AL: Article to be considered in the environmental review: Executive Summary Energy 

2 Efficiency in the South. 

3 10-11-AL: Article to be considered in the environmental review: GAO Report GAO-12-107 - 

4 Tennessee Valley Authority, Full Consideration of Energy and Efficiency and Better Capital 

5 Expenditures Planning Are Needed.

6 14-7b-AL: See the work of Mark Z. Jacobson, professor at Stanford University: Shifting the 

7 world to 100% clean, renewable energy by 2030 at 

8 http://news.stanford.edu/news/2009/october19/jacobson-energy-study-102009.html. 

9 Response: The NRC staff read and considered each of the articles and the web-site 

10 mentioned in the comments above. Most of the information in these articles is general in nature 

11 and was not used in development of the alternatives sections of the SQN DSEIS. However, the 

12 Global Energy Partners Study that TVA commissioned on energy efficiency potential was 

13 discussed in SQN DSEIS section 2.1.1.3.

14 A.1.2 Aquatic Ecology

15 Comments:

16 8-1-AE: I happen to also be the Tennessee Local Counsel for a Challenge to the Environmental 

17 Impact Statement for the Watch Bar 2 Unit, which is still under construction and for which there 

18 are still legal contentions pending as to the impact on water temperature and aquatic resources.

19 I suggest that the NRC staff take a close look at this because all of the aquatic impacts 

20 heretofore in the licensing of these reactors was done, based on modeling and not based on any 

21 real world measurements. Since then TVA has gone back and done a considerable amount of real 

22 world biological assessment and quite frankly, they have done a pretty good job of it.

23 And you might look at what they’ve done in terms of dealing with the Watts Bar 2 litigation 

24 contest and see if you don’t think they need to do the same thing with respect to the impacts of the 

25 cooling water and resulting hot water from the plants under consideration here.

26 Response: This comment suggests that the NRC closely consider a legal challenge concerning 

27 aquatic resources to construction of Watts Bar Nuclear Power Plant (WBN), Unit 2, for potential 

28 implications for the SQN license renewal application environmental review. 

29 WBN is located in southeastern Tennessee approximately 50 miles northeast of Chattanooga 

30 and is owned by TVA. The site has two Westinghouse-designed pressurized water reactors. 

31 WBN Unit 1 received a full power operating license in early 1996, and is presently the last 

32 power reactor to be licensed in the U.S. TVA suspended construction of WBN Unit 2 in 1985. 

33 In 2007, TVA informed NRC of its plan to resume construction of WBN Unit 2. The NRC staff is 

34 working towards supporting an operating license decision in 2015.

35 In May 2013, the NRC staff published “Final Environmental Statement Related to the Operation 

36 of Watts Bar Nuclear Plant, Unit 2, NUREG-0498”. 

37 On November 21, 2013 the NRC issued an Order extending the Watts Bar Unit 2 construction 

38 completion date to September 30, 2016 (78 FR 72120).

39 The contention this comment refers to alleged that the discussion of impacts to aquatic 

40 resources in TVA’s Final Environmental Statement was insufficient. 

41 The intervener who submitted the contention subsequently withdrew it based on its view that 

42 “the Nuclear Regulatory Commission (NRC) Staff’s recently-issued Final Environmental Impact 

43 Statement is responsive to the majority of concerns raised in Contention 7, and that any 
Appendix A

A-8 

1 remaining concerns are best addressed outside of the adjudicatory process.” This contention, 

2 Contention 7, is available at ADAMS Accession Number ML12066A185. The granting of the 

3 request to withdraw the contention is available at ADAMS Accession Number ML13198A195.

4 The NRC staff discussed the effect of SQN license renewal on water temperature and aquatic 

5 resources in SQN DSEIS section 4.7. The NRC staff also discussed the effects of WBN Unit 2 

6 and other possible stressors on ecological resources as part of cumulative impacts in SQN 

7 DSEIS section 4.16.

8 9-11-AE: We need a detailed report as to the entrainment and impingement impacts on marine 

9 life; the impacts of the cooling water discharges and thermal backwash operations and fish 

10 return systems, we ask that you look at retrofitting the current open loop cooling systems to 

11 mitigate these impacts.

12 11-9-AE: So I’m concerned about the use of that water, two-thirds of which does not go back into 

13 the river after it’s used to cool. The rest of it is hot and so we worry about the fish and the aquatic 

14 community there in that whole ecosystem. 

15 11-11-AE: And the rest goes back into the river and is hot. There are regulations about how hot it 

16 can be, but it is hot and it goes back into the river and affects the fish. Although as I’ve been told, 

17 fish can swim around the hot parts. But there are other macro invertebrates and small critters in 

18 the water that are called the drift community and they cannot swim around. They are subject to 

19 whatever they run into. So that’s a problem.

20 11-34-AE: The water returned to the river is carrying heat that has impacts for the aquatic 

21 ecosystem. While fish can move to avoid heated water plumes, the aquatic drift community and 

22 certain macroinvertebrates upon which fish feed cannot.

23 Response: These comments concern the effects of entrainment, impingement, thermal effluent 

24 and water loss on aquatic resources. The NRC staff described and examined the effects of 

25 entrainment, impingement, thermal effluent and water use conflicts on aquatic resources in 

26 SQN DSEIS sections 3.7 and 4.7. Regarding changes to the cooling water system, the 

27 U.S. Environmental Protection Agency and the State of Tennessee, not the NRC, oversee 

28 impacts at the cooling water intake structure and of the effluent through the National Pollution 

29 Discharge Elimination (NPDES) permitting process. The U.S. EPA and the State of Tennessee 

30 are responsible for protection of aquatic resources through the NPDES permitting process.

31 A.1.3 Climate Change

32 Comments: 

33 11-8-CC: And we have climate disruption – more storms, more problems that way.

34 11-13-CC: We cannot have nuclear plants using all that water that could be used for other 

35 uses. And it’s just evaporating into the air for the most and that is – that also causes climate 

36 change, climate disruptions as well. So I think we need to – I think that we are going to have 

37 continued drought conditions in between storms if the predictions are correct about that.

38 And we are also going to have hotter water and that has caused some shutdowns of 

39 nuclear plants already here in the Tennessee Valley. I know that Sequoyah and Watts Bar have 

40 both shut down because the water in the river was too hot to take the hot water that the nuclear 

41 plants were putting into it. So those shut-downs that are caused by climate should be a

42 significant environmental impact and should be considered as one of the possible things to 

43 analyze as to how that’s going to work.

44 11-22-CC: ...climate disruption patterns which should be updated.
Appendix A

A-9 

1 11-35-CC: In a climate unstable world, water will be THE ultimate constraining resource. We 

2 have already seen TVA’s nuclear plants shut down because of summer temperatures that 

3 prevented proper cooling. With temperatures rising scientists predict periods of excessive rain, 

4 severe drought conditions, and hotter temperatures in the summer here. Climate change must 

5 be addressed as an environmental impact for this SEIS.

6 Response: These comments express concerns over climate change impacts to the 

7 environment and to SQN. In SQN DSEIS section 4.15.3, the NRC staff discussed potential

8 impacts from climate change to: air quality; land use; water, terrestrial and aquatic resources; 

9 historic and cultural resources; socioeconomics; human health; and, environmental justice. In 

10 this section, the NRC staff also discussed greenhouse gas (GHG) emissions from the proposed 

11 SQN license renewal and alternatives to license renewal. The impact of GHG emissions 

12 resulting from continued operation of SQN during the proposed license renewal term on global 

13 climate change when added to the aggregate effects of other past, present, and reasonably 

14 foreseeable future actions are discussed in SQN DSEIS section 4.16.12.

15 A.1.4 Groundwater

16 Comments: 

17 3-7-GW: Other concerns include safety of drinking water ...

18 9-15-GW: Any study should include the impact of the more than thirty documented spills of

19 radioactive material into the water and food supply that have already occurred in the Tennessee 

20 Valley by this operator.

21 A local history of radioactive leaks into the groundwater and Tennessee River.

22 20100407 Browns Ferry Unit 3 Approximately 1,000 gallons of radioactively 

23 contaminated water leaked from Condensate Storage Tank No. 5 as workers were transferring 

24 water between condensate storage tanks. A worker conducting routine rounds observed water 

25 leaking from an open test valve near the top of CST No. 5.

26 20080105 Browns Ferry Unit 3 The condensate storage tank overflowed due to failed 

27 tank level instrumentation. The spilled water flowed into the sump in the condensate piping 

28 tunnel, triggering a high level alarm that prompted workers to initiate the search that discovered 

29 the overflow condition. Some of the spilled water may have permeated through the pipe tunnel 

30 into the ground.

31 20060700 Sequoyah Unit 1 An investigation to identify sources of tritium in groundwater

32 found detectable levels of tritium in the Unit 1 and Unit 2 refueling water storage tank moat 

33 water. 

34 20060700 Sequoyah Unit 2 An investigation to identify sources of tritium in groundwater

35 found detectable levels of tritium in the storage tank moat water.

36 20060200 Browns Ferry Unit 3 A soil sample taken from underneath the radwaste ball 

37 joint vault (located outside the radwaste doors) indicated trace levels of cobalt-60 and cesium38 137.

39 20060200 Browns Ferry Unit 1 A soil sample taken from underneath the radwaste ball 

40 joint vault (located outside the radwaste doors) indicated trace levels of cobalt-60 and cesium41 137. 

42 20060200 Browns Ferry Unit 2 A soil sample taken from underneath the radwaste ball 

43 joint vault (located outside the radwaste doors) indicated trace levels of cobalt-60 and cesium44 137.
Appendix A

A-10

1 20051100 Browns Ferry Unit 1 Tritium levels greater than baseline values were detected 

2 in an underground cable tunnel between the intake structure and the turbine building. Samples 

3 taken in January 2006 identified gamma emitters in addition to tritium (beta emitter).

4 20051100 Browns Ferry Unit 2 Tritium levels greater than baseline values were detected 

5 in an underground cable tunnel between the intake structure and the turbine building. Samples 

6 taken in January 2006 identified gamma emitters in addition to tritium (beta emitter).

7 20051100 Browns Ferry Unit 3 Tritium levels greater than baseline values were detected 

8 in an underground cable tunnel between the intake structure and the turbine building. Samples 

9 taken in January 2006 identified gamma emitters in addition to tritium (beta emitter).

10 20050000 Watts Bar Unit 1 The radwaste line was discovered to be leaking. 

11 20050300 Browns Ferry Unit 1 A leak in a pipe elbow on the east side of the cooling 

12 tower and an overflow of the cooling tower basin caused by malfunction of the system level 

13 indicators resulted in radioactive contamination of the concrete pad and ground around the 

14 tower.

15 20050300 Browns Ferry Unit 2 A leak in a pipe elbow on the east side of the cooling 

16 tower and an overflow of the cooling tower basin caused by malfunction of the system level 

17 indicators resulted in radioactive contamination of the concrete pad and ground around the 

18 tower.

19 20050300 Browns Ferry Unit 3 A leak in a pipe elbow on the east side of the cooling 

20 tower and an overflow of the cooling tower basin caused by malfunction of the system level 

21 indicators resulted in radioactive contamination of the concrete pad and ground around the 

22 tower.

23 20040000 Watts Bar Unit 1 The radwaste line was discovered to be leaking.

24 20030000 Watts Bar Unit 1 Beginning in 2003, tritium leaching into the ground from the 

25 plant has been found in site monitoring points.

26 20020400 Sequoyah Unit 1 Prior to excavation for the steam generator replacement 

27 crane foundation, sampling identified contaminated soil surrounding the Unit 1 refueling water 

28 storage tank moat drain.

29 20010100 Browns Ferry Unit 3 Tritium levels greater than baseline values were detected 

30 in an onsite monitoring well west of the Unit 3 condenser circulating water conduit in the 

31 radwaste loading area. 

32 19981200 Watts Bar Unit 1 Radioactively contaminated soil was discovered beneath the 

33 concrete radwaste pad.

34 19980100 Sequoyah Unit 2 Radioactively contaminated water overflowed the Unit 2 

35 additional equipment building sump and out the doorway to the ground outside.

36 19970500 Sequoyah Unit I Approximately 3,000 gallons of radioactively contaminated 

37 water spilled from the modularized transfer demineralization system when a conductivity probe 

38 failed. An estimated 600 to 1,000 gallons flowed through the railroad bay door to the ground 

39 outside.

40 19970500 Sequoyah Unit 2 Approximately 3,000 gallons of radioactively contaminated 

41 water spilled from the modularized transfer demineralization system when a conductivity probe 

42 failed. An estimated 600 to 1,000 gallons flowed through the railroad bay door to the ground 

43 outside.
Appendix A

A-11

1 19950500 Sequoyah Unit 2 Workers identified contaminated soil at the outfall of the Unit 

2 2 refueling water storage tank moat drain pipe.

3 19850000 Sequoyah Unit 1 Radioactively contaminated water leached through a 

4 concrete wall of the condensate demineralizer waste evaporator building into the ground.

5 19850000 Sequoyah Unit 2 Radioactively contaminated water leached through a 

6 concrete wall of the condensate demineralizer waste evaporator building into the ground.

7 19830116 Browns Ferry Unit 3 A leaking tube in a residual heat removal heat exchanger 

8 allowed radioactive water from the reactor coolant system to be released to the river at levels 

9 exceeding technical specification limits.

10 19780715 Browns Ferry Unit 1 After the unit was shut down for maintenance, the 

11 residual heat removal system was placed in operation to assist shut down cooling of the reactor

12 vessel water. Workers determined that a residual heat removal heat exchanger had a tube leak 

13 and that radioactively contaminated water was being discharged to the Tennessee River “at a 

14 rate above permissible limits.” 

15 19770104 Browns Ferry Unit 1 A leak in a residual heat removal heat exchanger allowed 

16 radioactive water to be released to the river at levels exceeding technical specification limits.

17 19731019 Browns Ferry Unit 1 About 1,400 gallons of liquid radwaste of unknown, 

18 unanalyzed concentration was inadvertently discharge to the river due to personnel error. The 

19 liquid radwaste tank was intended to be placed in recirculation mode but was mistakenly placed 

20 in discharge mode. Source; Union of concerned scientist and NRC

21 15-16 January 1983 Nearly 208,000 gallons of water with low-level radioactive 

22 contamination was accidentally dumped into the Tennessee River at the Browns Ferry power 

23 plant.

24 11-16-GW: So in both 2003 and in 2011, tritium was found in the ground water at Sequoyah.

25 Response: These comments concern impacts to groundwater from past actions and from the 

26 proposed license renewal of SQN. Documented spills (including tritium spills) are identified in 

27 section 3.5.2 and their impact on groundwater is described in section 4.5 of the SQN DSEIS.

28 The cumulative effect on groundwater from the aggregate of past, present, and reasonably 

29 foreseeable future actions over the proposed license renewal period is evaluated in 

30 section 4.16.3.2 of the SQN DSEIS. This section considers the total effect of actions that could 

31 impact groundwater (including both direct and indirect effects) no matter who has taken the 

32 actions (Federal, State, County, or private).

33 A.1.5 Human Health

34 Comments: 

35 3-5-HH: Certainly foremost in the public’s mind is the fear of harmful radiation exposure to

36 the public;

37 4-6-HH: We look forward to a decline in Leukemia rates after all the spent fuel is in casks.

38 5-6-HH: We look forward to a decline in Leukemia rates after all the spent fuel is in casks.

39 9-2-HH: Maybe the decision needs to be postponed for five years to reassess the needs and the 

40 dangers based upon real time, up-to-date health studies.
Appendix A

A-12

1 9-3-HH: We also ask that the Commission include the following internationally recognized study as 

2 a basis for any comprehensive human health impact studies. These reports show a positive link 

3 between increased cancer rates and the release of low, mid, and high level releases.

4 There are many studies regarding the fallout of Chernobyl and the true effects to the 

5 population that are not being considered. These reports even by the most conservative estimates 

6 state that over one million additional cancer cases have been attributed to that disaster – FOR 

7 YOU EIS TO SHOW NO HARMFUL EFFECTS can’t even be true due to the fact that even your 

8 own reports define an acceptable risk margin, to the population of one in 500 people therefore 

9 the fact is there are additional cancer rates that your report uses as a baseline and thus 

10 marginalizes. We just want the public to know the truth.

11 And the studies that should be included are the American Academy of Sciences 2008 

12 Biological Effects of Ionizing Radiation reports there’s no safe level of radiation.

13 European Committee on Radiation Risk argues that the existing risk model used by the 

14 NRC does not take internal exposure into account. High rates of internal exposure will mean a 

15 dramatic increase in cancer risks for Fukushima residents with as many as 400,000 additional 

16 cases predicted by this model by 2061.

17 The Office of Science and Financial Assistance Program Notice 9914, Low Dose Radiation, 

18 says, “Each unit of radiation, no matter how small, can cause cancer and most of the projected 

19 radiation exposures associated with human activity over the next 100 years will be low dose and 

20 low dose-rate radiation from medical tests, waste clean-up, and environmental isolation of 

21 materials associated with nuclear weapons and nuclear power production.” 

22 The German Federal Office of Radiation Protection titled Epidemiology Study of Childhood 

23 Cancer in the Vicinity of Nuclear Power Plants shows a causative link to young children developing 

24 cancer more frequently when they live near nuclear power plants.

25 The American Cancer Society states that ionizing radiation is a proven human carcinogen. 

26 And they go on to say that people living near or down-wind of a plant are known as down-winders.

27 Any EIS should include a comprehensive study as to the effects on the citizens and the 

28 commerce and the environment of having onsite storage, above ground storage of high level 

29 nuclear waste. Specifically the dangers of such storage and the fact that the storage site is already 

30 three times its designed capacity.

31 9-5-HH: The American Cancer society states “Ionizing radiation” is a proven human carcinogen 

32 (cancer causing agent). The evidence for this comes from many different sources, including 

33 studies of atomic bomb survivors in Japan, people exposed during the Chernobyl nuclear 

34 accident, people treated with high doses of radiation for cancer and other conditions, and 

35 people exposed to radiation at work, such as uranium miners and nuclear plant workers. “They 

36 go on to say, “people living near or downwind (also known as down winders) of nuclear facilities 

37 may also be exposed to radioactive byproducts. Levels of radiation are likely to be higher near 

38 these sites, but some radioactive particles enter the atmosphere and travel great distances, 

39 landing thousands of miles away from the facility.”

40 9-16-HH: Any EIS study should include the effects of storing nuclear material and waste on a 

41 site that is well over its design capacity, it should include a study as to how much the 

42 “background” radiation of the area will be increased based upon the increase in waste material 

43 and what is the long term and short effects as for the air, drinking water and food supply. In 

44 addition the study should include the health risk of and security risk of transporting the materials 

45 to other locations.
Appendix A

A-13

1 10-2-HH: And allowing radionuclides into our environment not only affects the food chain, but it 

2 affects our very DNA. It changes the structure of our genetic makeup. That’s a long range issue, 

3 you know, just one of these radionuclides – the power plant creates 200. When the uranium goes 

4 in, it creates 200 poisons that don’t exist in nature. 

5 Our body doesn’t know what to do with them, so they try and find the things that they most 

6 closely resemble, whether it be iodine or potassium or calcium. It tries to find that and it takes it up 

7 that way in the bones, in the thyroid, and different parts of the body. That’s what it does with these 

8 radionuclides. 

9 And they last for a very long time; some of them are short lived. But we’re talking about 

10 200. And some of them are extremely long lived. What is it? The iodine 129 lasts for – what is it, 

11 570,000,000 years is the half life? That’s 570,000,000 years, you know, that it’s dangerous.

12 11-20-HH: I want to talk about radiation doses and you have – NRC has radiation doses. They 

13 have established standards and those standards for radiation tell all the nuclear plants what 

14 level of dosages are okay, in their opinion, okay for you to receive. Some small amount that they 

15 consider absolutely safe and below that there’s no problem. And that’s how they figure out what 

16 the dosage is going to be and how they say there’s no public risk. But we all know that there is 

17 no safe dose of radiation because it’s cumulative.

18 11-27-HH: I wanted to talk a little bit here though about radiation doses. Apparently it seems that 

19 the statement that the public will continue at current levels associated with normal operations and 

20 that these doses also for the occupational doses to employees are going to remain the same when 

21 the license is renewed. So we don’t need to worry about that, but these doses are all well below 

22 the regulatory limits, they say. And so we don’t need to worry. 

23 Another 20 years of this is not good because in fact no dose of radiation is safe and it’s 

24 cumulative. So the additional time there is going to continue to expose us citizens in a growing 

25 population, urban population, with more and more of this radiation that is emitted on a daily basis 

26 from a nuclear power plant. 

27 The thing that happens is those daily radiation doses levels that they recommend seem to 

28 go up if there is more in the air and then they call it background radiation. But at Fukushima that’s 

29 what happened. When the accident happened, suddenly the people that were supposedly not 

30 supposed to receive a dose at a certain level, suddenly it was okay for those people to receive a 

31 higher level and that was the standard that they set. 

32 So the radiation standard seemed to change depending on how much is actually in the air. 

33 And our radiation background – so called background level – has been rising over these years. So 

34 it is cumulative. There is cancer risks even without the accident. 

35 And I think the other thing is that the radiation standard – and maybe NRC can look at this 

36 in overall – the standard for how much dosage you could get is based on a what they call, the 

37 Reference Man. And the Reference Man is a German white male, about five foot nine and – five 

38 foot four and 150, 170 pounds, something like that. 

39 Anybody qualify here?

40 The truth is that the studies now show that it is women and infants and fetuses that are 

41 more subject to radiation dose and cancer events.

42 So the problem is that the standard themselves are not right. And I think that really needs 

43 to be looked at.

44 11-39-HH: NRC found that radiation doses to the public will continue at current levels 

45 associated with normal operations and also for occupational doses to employees. We are told 
Appendix A

A-14

1 that the range of doses are all well below regulatory limits. Thus, it was concluded that since 

2 the range of dosages are well below regulatory limits, there is no significant additional impact if 

3 the license is renewed for another 20 years. The idea that we are all safe forever once one sets 

4 radiation exposure standards is not true. We know now that there is no safe dose of radiation 

5 and that those standards are likely to change as was done after Fukushima to protect the 

6 nuclear industry from public outrage. In fact, ionizing radiation is cumulative. There is cancer 

7 risk even without an accident. We have enough background radiation as is. A license to add 

8 human made radiation for another 20 years should not be granted.

9 12-6-HH: We look forward to a decline in Leukemia rates after all the spent fuel is in casks.

10 17-7-HH: The other major issue it’s been mentioned about the children. In doing research on this 

in a Reuter’s article from March 15th 11 , 2011, it quoted, it said between 12,000 and 83,000 children 

12 were born with congenital deformities according to the German physicians group IPPNW, between 

13 12,000 and 83,000 children born with deformities. Some of the deformities of these children, if you 

14 have the stomach for it, they’re horrible. They’re hardly human.

15 17-18-HH: It’s a nightmare stew of toxic substances that absolutely have to be protected from the 

16 biosphere. And we are not doing a good job of that. And that’s why the background radiation 

17 levels are increasing.

18 18-1-HH: For many decades we have been warned by physicians and public health officials, 

19 people like Helen Caldecott and Dr. John Gofman and Rosalie Bertell have told us the dangers of 

20 ionizing radiation to human health. We have been told that it damages DNA and causes mutations 

21 and that it is carcinogenic and especially to children. Now there’s no debating the issue that 

22 nuclear reactors do emit radiation. There are routine emissions; there are spills; there are 

23 accidents, some more serious than others. 

24 However, TVA and the NRC, I have yet to see a report that does not say, “No risk to the 

25 public,” after one of these things occurs. These reactors pollute the environment, the water, the air. 

26 The rain rains down radionuclides onto the grass, gets into our plants, into our food chain. 

27 There are many studies that have been done mostly abroad that show that people, 

28 especially children, who live near nuclear reactors have a higher incidence of cancer than the 

29 national averages or than people who live at a greater distance. Back in the 1980s there was one 

30 by at Sellafield in England that found clusters of leukemia and cancer. In Germany around the 

31 year 2010 was a government sponsored study that showed that the reactors tested there was 

32 almost double the rate of leukemia – well, over double the rate of leukemia and double the amount 

33 of other cancers in children. Another study at Chepstow, Wales, a very recent one, shows that 

34 three and a half times the risk of cancer to children than the national average. 

35 Now just this past week another study came out from Sacramento. It was done at 

36 Sacramento County, California, where there are approximately 1.4 million people living. Rancho 

37 Seco is a reactor that has been closed for 23, over 23 years. This study shows – by going through 

38 all the cancer records of the state of California, they have shown that there is a drop of cancer 

39 incidents in the 20 years since the closing. A very precise number, 4,319 fewer cases over that 20 

40 year period. And many of these are women, Hispanics, and children. Again children are some of 

41 the worst victims of radiation poisoning.

42 18-2-HH: National Academy of Sciences is currently carrying on a study of reactors in this country 

43 to see whether the cancer incidence is indeed higher or not. The NRC is sponsoring that study 

44 and it’s not yet completed. Yet the NRC is going ahead with relicensing before knowing all the 

45 facts regarding human health in the vicinity of these plants.
Appendix A

A-15

1 18-4-HH: For decades the public has been warned by physicians and public health officials of the 

2 dangers of ionizing radiation. And people like Doctor Helen Caldecott and Doctor Samuel Epstein 

3 are continuing to warn us of the dangers. 

4 We know that it causes changes in DNA that cause mutations. We know that it is 

5 carcinogenic and especially for children. And I suppose as a grandmother, the children are one of 

6 my main concerns. I’ve got two little daughters who live near Philadelphia, Pennsylvania and they 

7 are surrounded by nuclear reactors. So the things I’ve learned about cancer really are close to my 

8 heart. 

9 It doesn’t take a major accident for reactors to emit radiation. There are routine emissions 

10 that are required just to operate them safely, safer, more safely. There are spills. There are 

11 accidents and every time there are these – not catastrophic, but sometimes very close to 

12 catastrophic – events, TVA and NRC reassure the public there’s no danger. There’s no risk to the 

13 public. I don’t know how many times I’ve read that on the NRC website.

14 What these reactors are doing is polluting the environment. They pollute the water. They 

15 pollute the air. When rain falls through polluted air, the radiation is washed down into the ground. 

16 The plants become radioactive. The cows eat the plants. The radioactive iodine goes into the 

17 cows’ milk. The children drink the milk. It is not safe. This radiation is getting into our food chain. 

18 And since we eat lots of meat at the top of the food chain, we’re getting a lot of radiation just 

19 without the catastrophic event.

20 Now there are several studies, as Mr. Anderson pointed out. There was one back in the 

21 1980’s in Sellafield, England that showed that clusters of cancers and leukemia. More recently 

22 around 2010, the Germany government sponsored a study of the reactors in Germany and they 

23 found for children under five years old they had more than doubled the incidents of leukemia and 

24 almost double for other types of cancer. Another study more recent from that is from Chepstow in 

25 Wales. They found that children were at three and one-half times the risk if they lived close to a 

26 nuclear reactor as the national average.

27 Now these are instances of cancers close to the nuclear reactors, but there’s another study 

28 that came out; just last week it was released. It’s from California, Sacramento County, which has a 

29 population of 1.4 million. Rancho Seco Reactor closed over 23 years ago and some scientists 

30 have been going through the cancer registry for California trying to determine what has happened 

31 to the cancer rate. They used the last two months of the reactor’s operation and then they’ve been 

32 studying what’s been happening in the intervening 20 years. 

33 And what they found is that a very considerable drop in the cancer incidents since that time. 

34 They have found 4,319 fewer cancer cases over a 20 year period. That’s more people than died in 

35 the Twin Towers. And of the people who are most effected are women, Hispanics, and children.

36 18-5-HH: An NAS study – there is a National Academy of Science study being sponsored by the 

37 NRC right now to try to determine what the cancer incidence is around nuclear reactors. And of 

38 that study which is continuing now – I’m sorry, I’ve lost my train of thought – okay, that study is not 

39 yet completed. And it probably won’t be for several years. 

40 So in addition to other questions asked about the timing for this relicensing, my question is 

41 why not wait until that study is in to determine whether we should be relicensing aging reactors.

42 Response: The NRC’s mission is to protect the public health and safety and the environment 

43 from the effects of radiation from nuclear reactors, materials, and waste facilities. A discussion 

44 of these responsibilities beginning with the Atomic Energy Act of 1954 can be found on the NRC 

45 website at http://www.nrc.gov/about-nrc/history.html. The NRC’s regulatory limits for 

46 radiological protection are set to protect workers and the public from the harmful health effects 
Appendix A

A-16

1 (i.e., cancer and other biological impacts) of radiation on humans. The limits are based on the 

2 recommendations of standards-setting organizations. Radiation standards reflect extensive 

3 scientific study by national and international organizations. The NRC actively participates in and 

4 monitors the work of these organizations to keep current on the latest trends in radiation 

5 protection. If the NRC determines that there is a need to revise its radiation protection 

6 regulations, it will initiate a rulemaking. Members of the public who believe that the NRC should 

7 revise or update its regulations may request that the NRC do so by submitting a petition for 

8 rulemaking.

9 The NRC has based its dose limits and dose calculations on a descriptive model of the human 

10 body referred to as “standard man.” However, the NRC has always recognized that dose limits 

11 and calculations based on “standard man” must be informed and adjusted in some cases for 

12 factors such as age and gender. For example, the NRC has different occupational dose limits 

13 for pregnant women workers once they have declared (i.e., made known) they are pregnant 

14 because the rapidly developing human fetus is more radiosensitive than an adult woman. NRC 

15 dose limits are also much lower for members of the public, including children and elderly people, 

16 than for adults who receive radiation exposure as part of their occupation. Finally, NRC dose 

17 calculation methods have always included age-specific dose factors for each radionuclide in 

18 order to consider the varied sensitivity to radiation exposure by infant, child, and teen bodies, 

19 which are also generally smaller than adult bodies. In addition, the calculation methods have 

20 always recognized that the diets (amounts of different kinds of food) of infants, children, and 

21 teens are different from those of adults. NRC is currently updating 10 CFR Part 20 Standards 

22 for Radiation Protection and information about this rulemaking can be found at: 

23 http://www.nrc.gov/about-nrc/regulatory/rulemaking.html. 

24 BEIR VII is the seventh in a series of publications from the National Academies concerning 

25 radiation health effects, referred to as the Biological Effects of Ionizing Radiation (BEIR) 

26 reports. The BEIR VII report titled “Health Risks from Exposure to Low Levels of Ionizing 

27 Radiation: BEIR VII – Phase 2) (National Research Council 2006), focuses on the health effects 

28 of low levels of low linear energy transfer (LET) ionizing radiation. Low-LET radiation deposits 

29 less energy in the cell along the radiation path and is considered less destructive per radiation 

30 track than high-LET radiation. Examples of low-LET radiation, the subject of this report, include 

31 X-rays and γ-rays (gamma rays). Health effects of concern include cancer, hereditary diseases, 

32 and other effects, such as heart disease. The NRC accepts the linear, no-threshold (LNT) 

33 dose-response model (see additional information at 

34 http://www.nrc.gov/about-nrc/radiation/health-effects/rad-exposure-cancer.html). The BEIR VII 

35 Committee concluded that the current scientific evidence is consistent with the hypothesis that 

36 there is a LNT dose-response relationship between exposure to ionizing radiation and the 

37 development of cancer in humans. Having accepted this model, the NRC believes that this 

38 model is conservative when applied to workers and members of the public who are exposed to 

39 radiation from nuclear facilities. This is based on the fact that numerous epidemiological studies 

40 have not shown increased incidences of cancer at low doses. Some of these studies included: 

41 (1) the 1990 National Cancer Institute study (NCI 1990) of cancer mortality rates around 52 

42 nuclear power plants, (2) the University of Pittsburgh study that found no link between radiation 

43 released during the 1979 accident at the Three-Mile Island nuclear power station and cancer 

44 deaths among residents, and (3) the 2001 study performed by the Connecticut Academy of 

45 Sciences and Engineering that found no meaningful associations from exposures to 

46 radionuclides around the Haddam Neck nuclear power plant in Connecticut to the cancers 

47 studied. In addition, a position statement entitled “Radiation Risk in Perspective” by the Health 

48 Physics Society (August 2004) made the following points regarding radiological health effects: 

49 (1) Radiological health effects (primarily cancer) have been demonstrated in humans through 

50 epidemiological studies only at doses exceeding 5-10 rem delivered at high dose rates. Below 
Appendix A

A-17

1 this dose, estimation of adverse effect remains speculative; and (2) Epidemiological studies 

2 have not demonstrated adverse health effects in individuals exposed to small doses (less than 

3 10 rem delivered over a period of many years).

4 One of the SQN public scoping comments stated that, based on the BEIR VII report, there is no 

5 safe dose of radiation. The BEIR VII report (National Research Council 2006) makes no such 

6 assertion that there is no safe level of exposure to radiation. Rather, the conclusions of the 

7 report are specific to estimating cancer risk. The report does not make any statements about 

8 “no safe level or threshold.” However, the report did note that the “BEIR VII Committee said that 

9 the higher the dose, the greater the risk; the lower the dose, the lower the likelihood of harm to 

10 human health.” Further, the report notes that “[t]he Committee maintains that other health 

11 effects, such as heart disease and stroke, occur at high radiation doses but that additional data 

12 must be gathered before an assessment of any possible dose response can be made of 

13 connections between low doses of radiation and non-cancer health effects.” Although the LNT 

14 model is still considered valid, the BEIR VII Committee concluded that the current scientific 

15 evidence is consistent with the hypothesis that there is a linear dose-response relationship 

16 between exposure to ionizing radiation and the development of radiation-induced solid cancers 

17 in humans. Further, the Committee concluded “that it is unlikely that a threshold exists for the 

18 induction of cancers but notes that the occurrence of radiation-induced cancers at low doses will 

19 be small.” 

20 Although radiation may cause cancers at high doses, currently there are no reputable 

21 scientifically conclusive data that unequivocally establish the occurrence of cancer following 

22 exposure to low doses (i.e., below about 10 rem [0.1 Sv]). However, radiation protection 

23 experts conservatively assume that any amount of radiation may pose some risk of causing 

24 cancer or a severe hereditary effect and that the risk is higher for higher radiation 

25 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 

26 relationship between radiation dose and adverse impacts such as incidents of cancer. Simply 

27 stated, in this model any increase in dose, no matter how small, results in an incremental 

28 increase in health risk. This theory is accepted by the NRC as a conservative model for 

29 estimating health risks from radiation exposure, recognizing that the model probably over30 estimates those risks. Based on this theory, the NRC conservatively establishes limits for 

31 radioactive effluents and radiation exposures for workers and members of the public. Although 

32 the public dose limit in 10 CFR Part 20 is 100 mrem (1 mSv) for all facilities licensed by the 

33 NRC, the NRC has imposed additional constraints on nuclear power reactors. Each nuclear 

34 power reactor has enforceable license conditions that limit the total annual whole body dose to a 

35 member of the public outside the facility to 25 mrem (0.25 mSv). The amount of radioactive 

36 material released from nuclear power facilities is well measured, well monitored, and known to 

37 be very small. The doses of radiation that are received by members of the public as a result of 

38 exposure to nuclear power facilities are very low (i.e., less than a few millirem) such that 

39 resulting cancers attributed to the radiation have not been observed and would not be 

40 expected. As stated in the GEIS, the NRC believes the public and occupational impacts during 

41 the license renewal term would be SMALL.

42 Although a number of studies of cancer incidence in the vicinity of nuclear power facilities have 

43 been conducted, no studies to date accepted by the scientific community show a correlation 

44 between radiation dose from nuclear power facilities and cancer incidence in the general 

45 public. The following is a list of some of the most recent radiation health studies that the NRC 

46 recognizes: 

47 In 1990, at the request of Congress, the National Cancer Institute conducted a study of cancer 

48 mortality rates around 52 nuclear power plants and 10 other nuclear facilities. The study 

49 covered the period from 1950 to 1984, and evaluated the change in mortality rates before and 
Appendix A

A-18

1 during facility operations. The study concluded there was no evidence that nuclear facilities 

2 may be linked causally with excess deaths from leukemia or from other cancers in populations 

3 living nearby.

4 In June 2000, investigators from the University of Pittsburgh found no link between radiation 

5 released during the 1979 accident at Three Mile Island power plant and cancer deaths among 

6 nearby residents. Their study followed 32,000 people who lived within 5 miles of the plant at the 

7 time of the accident.

8 The American Cancer Society in 2000 concluded that although reports about cancer clusters in 

9 some communities have raised public concern, studies show that clusters do not occur more 

10 often near nuclear plants than they do by chance elsewhere in the population. Likewise, there 

11 is no evidence that links strontium-90 with increases in breast cancer, prostate cancer, or 

12 childhood cancer rates. Radiation emissions from nuclear power plants are closely controlled 

13 and involve negligible levels of exposure for nearby communities.

14 In 2000, the Illinois Public Health Department compared childhood cancer statistics for counties 

15 with nuclear power plants to similar counties without nuclear plants and found no statistically 

16 significant difference. 

17 The Connecticut Academy of Sciences and Engineering, in January 2001, issued a report on a 

18 study around the Haddam Neck nuclear power plant in Connecticut and concluded radiation 

19 emissions were so low as to be negligible and found no meaningful associations with the 

20 cancers studied.

21 In 2001, the Florida Bureau of Environmental Epidemiology reviewed claims that there are 

22 striking increases in cancer rates in southeastern Florida counties caused by increased 

23 radiation exposures from nuclear power plants. However, using the same data to reconstruct 

24 the calculations, on which the claims were based, Florida officials were not able to identify 

25 unusually high rates of cancers in these counties compared with the rest of the state of Florida 

26 and the nation.

27 On April 7, 2010, the NRC announced that it asked the National Academy of Sciences (NAS) to 

28 perform a state-of-the-art study on cancer risk for populations surrounding nuclear power 

29 facilities. The NAS has a broad range of medical and scientific experts who can provide the 

30 best available analysis of the complex issues involved in discussing cancer risk and commercial 

31 nuclear power plants. More information on its methods for performing studies is available at 

32 http://www.nationalacademies.org/studycommitteprocess.pdf. 

33 The NAS study will update the 1990 U.S. National Institutes of Health National Cancer Institute 

34 (NCI) report, “Cancer in Populations Living Near Nuclear Facilities” (NCI 1990). The study’s 

35 objectives are to (1) evaluate whether cancer risk is different for populations living near nuclear 

36 power facilities; (2) include cancer occurrence; (3) develop an approach to assess cancer risk in 

37 geographic areas that are smaller than the county level; and (4) evaluate the study results in the 

38 context of offsite doses from normal reactor operations. Phase I of the NAS study report was 

39 published on March 29, 2012 and is available on the NAS web site (http://www.nap.edu).

40 The NRC staff’s discussion on the impacts to human health from the operation of SQN during 

41 the proposed license renewal term is discussed in SQN DSEIS section 4.11.

42 9-8-HH: We need a real time public access monitoring systems, surrounding the plant in a 

43 concentric grid, showing the actual real time readings of radiation in the area, this needs to be 

44 done via the internet, through local government agencies and concerned citizens, in this manner 

45 we will not rely on the board or brass of TVA to let us know when there is an event or a release. 

46 There should be billboard size signs place on major thoroughfares that shows real time radiation 
Appendix A

A-19

1 levels for that sign location, so that daily commuters can become aware as to what’s the 

2 background levels and when there are unsafe levels in the area.

3 Response: The NRC considered the need for a review of emergency planning issues in the 

4 context of license renewal during its rulemaking proceedings on 10 CFR Part 54, which included 

5 public notice and comment. As discussed in the statement of consideration for rulemaking 

6 (56 FR 64966), the programs for emergency preparedness at nuclear power facilities apply to all 

7 nuclear power facility licensees and require the specified levels of protection from each licensee 

8 regardless of plant design, construction, or license date. Requirements related to emergency 

9 planning are in the regulations at 10 CFR 50.47 and Appendix E to 10 CFR Part 50. These 

10 requirements apply to all operating licenses and will continue to apply to facilities with renewed 

11 licenses. Through its standards and required exercises, the NRC reviews existing emergency 

12 preparedness plans throughout the life of any facility, keeping up with changing demographics 

13 and other site-related factors. Accordingly, the NRC has determined that there is no need for a 

14 special review of emergency planning issues in the context of an environmental review for 

15 license renewal (NRC 2006). Thus, decisions and recommendations concerning emergency 

16 preparedness at nuclear plants are ongoing and outside the regulatory scope of license 

17 renewal. 

18 Because this comment requests changes to the way in which radiation levels surrounding SQN 

19 are communicated to the public, the NRC staff has forwarded the comment to the 

20 Hamilton County, Tennessee, Office of Emergency Management asking Hamilton County to 

21 respond to this comment. 

22 A.1.6 License Renewal & NEPA Process

23 Comments: 

24 4-1-LR, 5-1-LR, and 12-1-LR: It is important that TVA retire the permits on Sequoyah 1 & 2. 

25 The permits are already 10 years past their original (recommended) termination dates.

26 14-1-LR: The plant has aged ten years past its intended lifespan. 

27 Response: These comments express concern that TVA should “retire the permits on 

28 Sequoyah 1 & 2”, that “the permits are already 10 years past their original (recommended) 

29 termination dates” and that SQN “has aged ten years past its intended lifespan.” This NRC staff 

30 response assumes that the “permits” mentioned in the comments above refer to the NRC 

31 operating licenses for SQN. The NRC operating licenses for SQN Units 1 and 2 will expire on 

32 September 17, 2020, and September 15, 2021, respectively. The Atomic Energy Act of 1954 

33 specifies that licenses for commercial power reactors can be granted for up to 40 years. The 

34 initial 40-year licensing period was based on economic and antitrust considerations rather than 

35 on technical limitations of the nuclear facility. The initial operating licenses (DPR-77 and DPR36 79) for SQN were granted for 40 years.

37 8-2-LR: First, I would call to your attention – and I think this has was raised in the questions. 

38 We seriously challenge that the assumptions in the Generic EIS are still valid. I think many of 

39 them are out of date and I was glad to hear that the GEIS is being revisited. It’s not clear to me 

40 how that fits in and how well that will be done to provide, in fact, an adequate foundation for the 

41 SEIS. And if the GEIS is still in ferment or is out of date, building an SEIS on a site specific 

42 basis on top of it, it seems to me, is legally questionable under the National Environmental 

43 Policy Act. 

44 9-1-LR: The citizens of the United States have a right under the National Environmental 

45 Protection Act of 1969 to request that the Generic Environmental Impact Statement be thrown 

46 out and a third party comprehensive risk analysis that takes all elements at such risks to the 
Appendix A

A-20

1 community, to our commerce, to the environment into account. A report that truly defines the 

2 human health effects of low dose exposures and mental stress to the population for living under 

3 such risks.

4 What are the true effects of cancer causing agents reaching into our environment?

5 What are the true impacts of increased permanent storage or production of high level 

6 nuclear waste? Due to the permanent storage issue this proposed action should be considered 

7 a major federal action and, therefore, require a new Environmental Impact Statement under 

8 Section 102 42 USC 4332.

9 NEPA, the Environmental Quality Improvement Act of 1970, has amended 

10 Section 42 USC 4371 and Section 309 of the Clean Air Act as amended under 42 USC 7609, 

11 and we hereby request the study.

12 Also any study under these rules should also include a comprehensive study to 

13 determine if there is this speculative energy demand and whether it could be met through other 

14 sources that are now viable, including renewable energy.

15 And the answer to that is, yes, we can, and, no, we don’t have a true need to build more 

16 reactors and can certainly phase out these 25 mile evac zones over the next decades.

17 We demand that Any EIS Studies will include – the long term health effects of low, mid 

18 and high level radiation on the surrounding community and the health effects on humans, born 

19 and unborn, and the effects to humans on the environment now and in the future – in addition, 

20 any action by a federal agency requiring a large burden on the area water supply should 

21 provide a comprehensive study as the effects of this massive water usage, including the effects 

22 to the marine and human life associated with the “scheduled releases” of various radioactive 

23 isotopes, and proposed average water temperature increases on the surrounding water supplies 

24 and how that relates back to human consumption, rights and the long term environmental 

25 impacts.

26 9-6-LR: In addition to a comprehensive study of the effects of these reactors to the public 

27 health, commerce and environment, I call for a comprehensive action plan to be presented to 

28 the public covering risk, and instructions on how to keep our families safe, how to manage our 

29 food supply and what we can do in the event of an event – all residents within the 25 Mile Evac 

30 Zone should be included in this education process – through all forms of media and psa’s. 

31 9-12-LR: We also request an impact statement from the United States Department of the 

32 Interior as and the Department of Justice as to the legitimacy of the generic impact study and 

33 we consider these actions a major event which would constitute and more through study under 

34 Section 102 [42 USC§ 4332]. Of NEPA. 

35 10-20-LR: It appears that the TVA SEIS staff as well as the concerned citizen activists who 

36 have focused on this request for a renewal license can only address a percentage of the issues 

37 that need to be identified and evaluated for our safety. The very volume of issues necessary to 

38 mitigate the hazards and Environmental Impact of extending the Sequoyah Nuclear Power Plant 

39 operating license another 50% beyond its design-basis life span, indicates the number of 

40 potential and known problems with this inherently dangerous radioactive technology – and its 

41 potential and already known deleterious impacts on the human environment.

42 11-2-LR: The original Environmental Impact Statement was done when the plant was first 

43 opened back in the 1980s and it seems like it’s time to really start from scratch, not just say that 

44 there’s been no significant environmental impact at this point because it’s operating for all this 

45 time and, gosh, we haven’t really had an accident yet. So we can just, we can just rely on that 
Appendix A

A-21

1 same Environmental Impact Statement and we can say that it’s going to be the same way for 

2 the next 20 years, 20 years starting in 2020, because that’s when the first license expires. 

3 So it’s questionable to think that there’s going to be no significant environmental impact 

4 in the future just because – and I don’t think it’s even reasonable to say there’s been no 

5 significant environmental impacts in the past 32 years. But still that’s what NRC is saying. So I 

6 think that we need to really begin from scratch again on that. I know there was one extension in 

7 between.

8 11-29-LR: The Supplemental Environmental Impact Statement should not be supplemental 

9 given that the original EIS goes back to the 1980s. I don’t think that NRC and TVA can say that 

10 in that time there has been ‘no significant environmental impact’ and not really start from 

11 scratch. To say because it’s been operating for 32 years without ‘significant environmental 

12 impact’ which is questionable in itself, is enough reason to give it a go-ahead for another 20 

13 years is faulty reasoning.

14 Response: These comments voice concerns with the license renewal process and that the 

15 GEIS is outdated and not comprehensive enough. The license renewal process is designed to 

16 assure safe operation of the nuclear power plant and protection of the environment during the 

17 license renewal term. Under the NRC’s environmental protection regulations in Title 10, 

18 Part 51, of the Code of Federal Regulations (10 CFR Part 51), which implement Section 102(2) 

19 of the National Environmental Policy Act (NEPA), renewal of a nuclear power plant operating 

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

21 To support the preparation of these EISs, the NRC issued the Generic Environmental Impact

22 Statement for License Renewal of Nuclear Plants (GEIS), NUREG-1437, in 1996. The original

23 1996 GEIS for license renewal was prepared to assess the environmental impacts associated

24 with the continued operation of nuclear power plants during the license renewal term. The 

25 intent was to determine which environmental impacts would result in essentially the same 

26 (generic) impact at all nuclear power plants, and which ones could result in different levels of 

27 impacts at specific plants and would require a plant-specific analysis to determine the impacts. 

28 For those issues that could not be generically addressed, the NRC would prepare plant-specific 

29 supplemental EISs (SEISs) to the GEIS.

30 As stated in the 1996 final rule that incorporated the findings of the GEIS in 10 CFR Part 51, the

31 NRC recognized that environmental impact issues might change over time, and that additional

32 issues may need to be considered. 

33 On June 20, 2013, the NRC published a final rule (78 FR 37282) revising its environmental 

34 protection regulation, 10 CFR Part 51, “Environmental protection regulations for domestic 

35 licensing and related regulatory functions.” Specifically, the final rule updates the potential 

36 environmental impacts associated with the renewal of an operating license for a nuclear power 

37 reactor for an additional 20 years. A revised GEIS, which updates the 1996 GEIS, provides the 

38 technical basis for the final rule. The revised GEIS specifically supports the revised list of NEPA

39 issues and associated environmental impact findings for license renewal contained in Table B–1 

40 in Appendix B to Subpart A of the revised 10 CFR Part 51. The revised GEIS and final rule 

41 reflect lessons learned and knowledge gained during previous license renewal environmental 

42 reviews. In addition, public comments received on the draft revised GEIS and rule and during 

43 previous license renewal environmental reviews were re-examined to validate existing 

44 environmental issues and identify new ones. 

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

46 reasonable period with clear requirements to assure safe plant operation for up to an additional 

47 20 years of plant life. The process for the license renewal application environmental review, as 
Appendix A

A-22

1 described in the NRC’s regulations in 10 CFR Part 51, offers two public comment periods. The 

2 process begins when an applicant submits the license renewal application that includes an 

3 Environmental Report. After accepting the application, the NRC staff issues a Notice of Intent to 

4 prepare a site-specific supplement to the generic environmental impact statement for license 

5 renewal (SEIS) and conduct scoping. The Notice of Intent is posted on the NRC website and 

6 published in the Federal Register. The NRC staff also schedules public scoping meetings in the 

7 vicinity of the facility. Based on the scoping process and the NRC staff’s independent review, a 

8 draft SEIS for public comment is issued. In addition, the NRC staff holds public meetings to 

9 discuss the findings in the draft SEIS and to obtain comments on it from the public and other 

10 interested stakeholders. The final SEIS incorporates appropriate comments and changes from 

11 the draft SEIS and includes an appendix that presents the comments received and the NRC 

12 staff responses to those comments. 

13 The major milestones of the SQN license renewal application environmental review are 

14 discussed in SQN DSEIS section 1.3.

15 The last sentence of comment 11-2-LR claims there was an “extension in between.” To date, 

16 there has been no extension of the SQN operating licenses.

17 9-14-LR: At the end of the day with the expiration of the operating license set to expire in 2020 

18 and 2021, I feel these actions are premature, and are being aggressively pushed upon the 

19 citizens without adequate time for discussions, without time to study the health and impacts of

20 Fukushima, and therefore again request additional public hearings on this issue as well as,

21 something other than a generic impact study that hasn’t been updated properly since like 1940.

22 Response: This comment voices concern that lessons learned from the Fukushima accident

23 be appropriately considered, that there be “additional public hearings on this issue” and that the 

24 GEIS is outdated. The immediately preceding response addresses the GEIS portion of this 

25 comment.

26 On March 11, 2011, a 9.0-magnitude earthquake struck Japan and was followed by a 45-foot 

27 tsunami, resulting in extensive damage to the nuclear power reactors at the Fukushima Dai-ichi 

28 facility. The NRC has taken significant action to enhance the safety of reactors in the 

29 United States based on the lessons learned from this accident. The NRC continues to evaluate 

30 and act on the lessons learned from the accident to ensure proper safety enhancements are 

31 appropriately considered and implemented at U.S. nuclear power plants. For further information 

32 on the NRC’s continued response to the Japan Nuclear Accident visit: 

33 http://www.nrc.gov/reactors/operating/ops-experience/japan-info.html

34 The public meeting at which the commenter made this comment was a scoping meeting to 

35 provide the public information about the license renewal process, to provide opportunities for 

36 public involvement, and to solicit input on the scope of NRC’s environmental review. The NRC 

37 staff held two public scoping meetings on TVA’s application for renewal of SQN’s operating 

38 licenses on April 3, 2013, in Soddy-Daisy, Tennessee

39 Another opportunity for public involvement regarding TVA’s application for renewal of SQN’s 

40 operating licenses will be the SQN DSEIS public comment period. This comment period will 

41 include two public meetings. These public meetings, as well as all NRC public meetings, will be 

42 posted on the NRC’s website at http://www.nrc.gov/public-involve.html. In addition, these two 

43 public meetings will be noticed in the Federal Register and advertised in local news media. 

44 Under the Atomic Energy Act, Congress established an adjudicatory process that promotes 

45 public involvement in hearings on a variety of civilian nuclear matters. Through this hearing 

46 process, independent judges on the Atomic Safety and Licensing Board Panel (ASLBP) hear 

47 and address concerns of individuals or entities that are directly affected by any licensing or 
Appendix A

A-23

1 enforcement action involving a facility that produces or uses nuclear materials. A 60-day 

2 opportunity to request a hearing regarding TVA’s application for renewal of SQN’s operating 

3 licenses began on March 5, 2013, and was noticed in the Federal Register (78 FR 14362), 

4 posted to the NRC public website and announced in a letter to the applicant made publicly 

5 available in ADAMS (ADAMS Accession Number ML13035A214).

6 17-20-LR: It is a fact that not one of these renewal applications has been denied. And I have 

7 people who have called it rubber stamped. I hope that the rubber stamping stops and this will 

8 be a very serious consideration.

9 21-10-LR: Delay in this extension will serve to show that the NRC has thrown away their rubber 

10 stamp.

11 Response: The NRC maintains focus on its mission to ensure adequate protection of public 

12 health and safety, to promote the common defense and security, and to protect the environment

13 with clearly defined requirements for license renewal. To date, the NRC has approved all of the 

14 applications for license renewal for which the review has been completed. Although the NRC 

15 can deny a request to renew a license if an applicant does not provide appropriate or adequate 

16 information in its initial application, the NRC can and does identify deficiencies in applications 

17 and allows applicants to correct and resubmit their applications or provide additional information 

18 to support an application. This process can continue until the NRC concludes that the 

19 application is sufficient to complete the review.

20 A.1.7 Postulated Accidents

21 Comments: 

22 2-1-PA: Environmental Report Section 4.21 addresses Severe Accident Mitigation

23 Alternatives. As stated in Section 4.21.3, a SAMA analysis is required for license renewal

24 unless one has previously been performed for other reasons. The Limerick nuclear plant in

25 Pennsylvania did a SAMA analysis as part of its initial licensing process. When its owner

26 applied for license renewal, it did not submit another SAMA analysis.

27 Page 4-65 explains TVA reviewed 309 SAMA candidates. 262 candidates were

28 screened out as either not being applicable to Sequoyah.

29 47 SAMA candidates underwent further analysis and TVA identified 9 potentially cost30 beneficial SAMAs for Unit 1 and 8 on Unit 2. As explained on page 4-66, because none of

31 these potentially cost-beneficial safety upgrades is related to aging management – the focus

32 of license renewal – none are required in TVA’s view.

33 Page 4-67 reports that TVA’s analysis of SAMAs 286 and 288 for both units

34 concluded that the “total averted cost risk from the sensitivity analyses is greater than the

35 implementation cost.” 

36 But Section 4.21.6 concludes that “None of the SAMAs are related to adequately

37 managing the effects of aging during the period of extended operation. Therefore, they do

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

39 As demonstrated by the Limerick case, SAMA analyses are not required for license 

40 renewal unless a SAMA analysis has not yet been done. Thus, the SAMA analysis is not

41 linked solely to aging management during a license renewal period.

42 The SAMA analysis is done for the Environmental Report. The Environmental R eport

43 considers alternatives to the proposed activity; namely, operating these reactors for 20 more

44 years.
Appendix A

A-24

1 The Environmental Report’s evaluation shows that operating these reactors without

2 these safety upgrades for 20 years is the wrong thing to do from a legal and moral

3 perspective. The Sequoyah licenses should not be renewed without these safety upgrades.

4 Response: This comment requests that license renewal not be granted until “safety upgrades” 

5 identified in TVA’s SQN Severe Accident Mitigation Alternatives (SAMA) analysis are 

6 implemented.

7 Pursuant to 10 CFR Part 54, the only changes that must be implemented by the applicant as

8 part of the license renewal process are those that are identified as being cost beneficial, that

9 provide a significant reduction in total risk, and that are related to adequately managing the

10 effects of aging during the period of extended operation. 

11 The NRC staff evaluated the identified potentially cost-beneficial SAMAs to determine if they are 

12 in the scope of license renewal (i.e. they are subject to aging management). This evaluation 

13 considers whether the systems, structures, and components (SSCs) associated with these 

14 SAMAs: (1) perform their intended function without moving parts or without a change in 

15 configuration or properties and (2) that these SSCs are not subject to replacement based on 

16 qualified life or specified time period. The NRC staff determined that these SAMAs do not relate 

17 to adequately managing the effects of aging during the period of extended operation. 

18 Therefore, they need not be implemented as part of license renewal in accordance with 

19 10 CFR Part 54. Section 4.11.1.2 and Appendix F of the SQN DSEIS provide the NRC staff’s 

20 review of TVA’s SAMA analysis. 

21 10-4-PA: Another deliberately fabricated beyond design basis ongoing event that has been 

22 mentioned earlier is this extended use of cooling pools to store the irradiated, spent – it’s called 

23 spent fuel, but it’s actually much more toxic than the uranium that goes into the reactors 

24 because it has been enriched in the process, creating these radionuclides I talked about earlier. 

25 In that the Homeland Security and Congress asked the National Academy of Sciences to 

26 do a study on this to decide whether it was dangerous, this overloading of the cooling pools, and 

27 they recommended that all of the fuel going into these cooling pools be removed after five years 

28 and put into dry cask storage which is considerably safer for all of us.

29 10-5-PA: According to a very well respected Robert Alvarez at the – I’m sorry, I’ve forgotten where 

30 he is – the Policy Institute of some sort. Anyway he wrote a study in 2012 and he quoted 

31 something that I think is worth requoting, “A severe pool fire,” – they said – first let me preface it 

32 that they had known for decades that severe accidents can occur in cooling pools. They’ve known 

33 that for decades. And he said, “A severe pool fire could render about 188 square miles around the 

34 nuclear reactor uninhabitable. Could cause as many as 28,000 cancer fatalities and cause 

35 59 billion dollars in damage according to a 1997 report for the NRC by Brookhaven National 

36 Laboratory.” 

37 Sequoyah has well over 1,000 metric tons of this higher irradiated radioactive trash and it’s 

38 very, very dangerous stuff. And it’s stored in these cooling pools. In fact, 75 percent has been 

39 piling up in these cooling pools for 30 years now. They’ve only moved a quarter of it into dry cask 

40 storage. Now that’s a better rate than Watts Bar, which is 100 percent in the cooling pools and 

41 Browns Ferry, which is 88 percent in the cooling pools. 

42 But basically they’re just saving a buck by keeping it in the pools and not putting it in the 

43 safer dry cask storage.

44 10-16-PA: Another deliberately fabricated “beyond-design-basis” ongoing event is the extended 

45 use of spent fuel cooling pools as storage tanks, rather than the temporary circulating cooling 

46 pools they were designed to be. As originally designed, and as recommended by a National 
Appendix A

A-25

1 Academy of Sciences study commissioned for Congress and Homeland Security in 2005, 

2 radioactive trash (or spent fuel) should be moved from the cooling pools into dry cask storage 

3 after 5 years, not continually packed into the vulnerable cooling pools. As Robert Alvarez states

4 in the 2012 submitted article, “Improving Spent-Fuel Storage at Nuclear Reactors,” nuclear 

5 safety studies for decades have said severe accidents can occur at spent fuel pools and the 

6 consequences could be catastrophic. “A severe pool fire could render about 188 square miles 

7 around the nuclear reactor uninhabitable, cause as many as 28,000 cancer fatalities, and cause 

8 $59 billion in damage, according to a 1997 report for the NRC by Brookhaven National 

9 Laboratory.”

10 Sequoyah has well over a thousand metric tons (about 2.5 million pounds) of highly 

11 radioactive waste with a history of improper storage. In 2010, for example, about 75% of 30 

12 years of spent fuel was being stored in cooling pools. While this is better than the 100% pool 

13 storage record at Watts Bar and the 88% record at Browns Ferry, this clearly indicates the lack 

14 of attention by the corporate culture of TVA to the maintenance and security warranted by a

15 nuclear power utility, which indicates a potential threat to our environment. The concentration of 

16 fuel, transfer and storage plans, and scheduled implementation of those plans needs to be 

17 identified and evaluated in the Safety Evaluation Report. 

18 11-24-PA: And the crowding of the radioactive fuel rods and the so called spent fuel pool which is 

19 actually a higher end radiation than when it started out in the reactor – when the rod started out in 

20 the reactor. That is a concern and we would advocate for moving those, the used fuel rods, after 

21 they cool and it takes about five years for them to cool. To remove those and put them in 

22 hardened cask waste cask storage. This radioactive trash doesn’t need to be in the pools where it 

23 actually has more chance of exploding.

24 17-10-PA: At Fukushima Unit 4, which is teetering and if it falls there are concerns by scientists 

25 that it will be a global environmental catastrophe if that Unit 4 if all the cesium in there spills and is 

26 spread. Well, the amount of cesium – amount of fuel rods in that pool is far less than the 796 

27 metric tons in the pools at Sequoyah right now. There’s also 378 metric tons in casks there.

28 Response: These comments concern the impacts of a spent nuclear fuel (SNF) accident. 

29 SQN stores its SNF in a spent fuel pool and in dry casks. The spent fuel pool is a structure 

30 constructed of steel-reinforced concrete walls with a stainless steel liner, and filled with water. 

31 The spent fuel pool is located inside the plant’s protected area. The NRC regularly inspects 

32 SQN’s spent fuel storage program to ensure the safety of the SNF stored in the spent fuel pool. 

33 For more information on NRC inspections, see the response to the radioactive waste comments 

34 later in this same section A.1.

35 Following the March 11, 2011, earthquake and tsunami at Japan’s Fukushima nuclear power 

36 plant, the NRC ordered licensees to: install additional instrumentation to monitor water levels in 

37 spent fuel pools, and, develop ways to easily maintain or restore spent fuel pool cooling in an 

38 emergency (Order EA-12-051,”ORDER MODIFYING LICENSES WITH REGARD TO 

39 RELIABLE SPENT FUEL POOL INSTRUMENTATION”, is available online at: 

40 http://pbadupws.nrc.gov/docs/ML1205/ML12056A044.pdf).

41 The NRC is evaluating how a spent fuel pool at a U.S. reactor similar to Fukushima might 

42 respond to an earthquake far more powerful than the one that struck Japan. A study published 

43 in 2013 found a one-in-10-million-years chance that a severe earthquake could cause a 

44 radioactive release from the spent fuel pool at that reactor. In that extremely unlikely case, the 

45 study found that existing procedures would keep the population around the plant safe. For 

46 further information on the NRC’s continued response to the Japan nuclear accident visit: 

47 http://www.nrc.gov/reactors/operating/ops-experience/japan-info.html. 
Appendix A

A-26

1 10-8-PA: And, okay, I want to show you something here. I notice in the ACRS that tornadoes 

2 were mentioned and they talked about their study. Basically they did their statistical work 

3 around two major periods. One was a 37-year period from 1950 to 1986 and there were 31 

4 tornadoes during that period in a 34-mile radius. And then the next period was the next 15 

5 years up to 2002 and there were 23 tornadoes during that period. That is nearly doubling the 

6 rate in that period time. And this only goes up to 2002. 

7 Okay, well, in 2011, as you can see, this is NOAA track of the tornadoes that came 

through the Tennessee Valley on April 27th 8 , 2011. And those circles are the 50-mile radius of 

9 our nuclear power plant in this valley. And Sequoyah had around 15 of them, it looks like here. 

10 Someone else may count it differently, but that’s what it looked like to me. 

11 And I noticed in your report that you did mention that and that TVA reported that three of 

12 them touched down within 10 miles of Sequoyah. Your statisticians predict unlikely odds of a direct 

13 hit on Sequoyah. But I tell you, I’m not real confident with gambling on this. There’s a lot of people 

14 whose lives are involved in this and I think we need to take it seriously.

15 Response: This comment voices concern with the environmental impacts of tornadoes at 

16 SQN. The NRC requires U.S. nuclear power plants to be designed, built and maintained to 

17 safely withstand a set of unlikely but harmful events such as equipment failure, pipe breaks, and 

18 severe weather; these are called design-basis requirements. In some cases, high winds, floods, 

19 and tornados may contribute to plant risk; however, these contributions are generally much 

20 lower than those from seismic and fire events. Section 4.11.1.2 of the SQN DSEIS discusses 

21 design-basis accidents and adopts the GEIS finding that the environmental impacts from 

22 externally initiated events such as tornadoes are small.

23 As part of the Fukushima lessons learned Tier 2 activities, the NRC plans to perform “other” 

24 external hazard reevaluations at NRC licensed power plants. “Other” external hazard 

25 reevaluations will reanalyze the potential effects of external hazards other than seismic and 

26 flooding events. “Other” external hazard reevaluations include severe weather (including 

27 tornadoes). The NRC staff expects to begin work on this topic as soon as significant resources 

28 become available, following implementation of Tier 1 actions related to seismic and flooding 

29 hazard walkdowns and reevaluations. Current status of this and other Fukushima related 

30 lesson learned activities are available at: 

31 http://www.nrc.gov/reactors/operating/ops-experience/japan-dashboard/priorities.html. 

32 17-1-PA: The plant safety and security in the TVA document that was sent out back in 2010 

33 says that, “Severe accidents are defined as accidents with substantial damage to the reactor

34 core and degradation of containment systems. Because the probability of a severe accident is 

35 very low, the NRC considers them too unlikely to warrant normal design controls to prevent or 

36 mitigate the consequences. Severe accident analyses consider both the risk for the severe 

37 accident and the offsite consequences.” 

38 What that means is that they just dismiss out of hand the possibility of a severe accident

39 and don’t consider it at all in the Environmental Impact Statement.

40 17-21-PA: The plant safety issues do not take into the effects – take into account the effects of 

41 serious accidents that’s beyond design basic accidents. And they just reject considering those 

42 out of hand in all of the Environmental Impact Statements. So it never gets considered what the 

43 possibility is in terms of a massive release of radiation. That’s not part of this process. It’s 

44 specifically excluded because it’s said to be so unlikely as to happen, but we’ve already seen it 

45 happen twice in our lifetimes.

46 22-2-PA: Based on historical experience with nuclear reactors, I believe that these facilities are

47 inherently dangerous. An accident at these nuclear reactors so close to my home could pose a 
Appendix A

A-27

1 grave risk to my property, health and safety. In particular, I am concerned that if an accident 

2 involving release of radioactive material were to occur, I could be killed or become very ill.

3 Response: These comments express concern for the potential adverse environmental impacts 

4 associated with accidents at SQN. The NRC studies potential severe accidents in great detail 

5 and develops requirements and guidance to ensure licensed nuclear power plants avoid severe 

6 accidents. Further, the NRC inspects against those requirements to ensure adequate protection 

7 of public health and safety, to promote the common defense and security, and to protect the 

8 environment.

9 The term “accident” refers to any unintentional event outside the normal plant operational 

10 envelope that results in a release or the potential for release of radioactive materials into the 

11 environment. Two classes of postulated accidents are evaluated in the generic environmental 

12 impact statement (GEIS). These are design-basis accidents and severe accidents. 

13 Design-basis accidents are those accidents that both the licensee and NRC staff evaluate to 

14 ensure that the plant can withstand without undue hazard to the health and safety of the public. 

15 A number of these accidents are not expected to occur during the life of the plant, but are 

16 evaluated to establish the design basis for the preventive and mitigative safety systems of the 

17 facility. The impacts of design-basis accidents were evaluated in the GElS and determined to 

18 be small for all plants. 

19 Severe nuclear accidents are those that are more severe than design-basis accidents because 

20 they could result in substantial damage to the reactor core, whether or not there are serious 

21 offsite consequences. In the GEIS, the staff assessed the impacts of severe accidents during 

22 the license renewal period, using the results of existing analyses and site-specific information to 

23 conservatively predict the environmental impacts of severe accidents for each plant during the 

24 renewal period. Based on information in the GEIS, the Commission found that “The 

25 probability-weighted consequences of atmospheric releases, fallout onto open bodies of water, 

26 releases to groundwater, and societal and economic impacts from severe accidents are small 

27 for all plants.”

28 Section 4.11.1.2 of the SQN DSEIS provides the NRC staff analysis of postulated accidents. 

29 A.1.8 Radiological Waste

30 Comments: 

31 4-2-RW, 5-2-RW, and 12-2-RW: We require that all nuclear material be interred in casks and 

32 left on site.

33 11-18-RW: Spent fuel storage, you know, spent fuel is radioactive fuel that uranium that has been 

34 used in the reactor and then it becomes actually more radioactive and it is taken out of the reactor 

35 and put into this fuel pool. And the rods that where the uranium fuel is – this is highly radioactive 

36 rods – are put into the fuel pool. And what’s happening is it’s getting more and more crowded

37 because they don’t know what to do with the waste. 

38 Where shall we put the radioactive waste since there’s no place to ship it to? There’s no 

39 setup for that. And besides why have two places that are radioactive when you can just leave it on 

40 site here at Sequoyah? But how much more should we be making? So the crowding of the rods is 

41 a problem. 

42 And when they take the rod density, there’s more opportunity for accidents when the rods 

43 are so much closer together and fission can happen. So where do we put it? These are the things 

44 that I think that the scoping should include. Where are we going to put those rods and keep the 
Appendix A

A-28

1 crowding smaller? And is the Watts Bar radioactive waste also going to be supported to 

2 Sequoyah, which has – I think is true. 

3 And has the proposed independent spent fuel storage building been put in place and is it 

4 secure enough? 

5 Further, are there plans to put things into hardened cask storage so that they are safer than 

6 they are in the fuel pool?

7 11-37-RW: Spent fuel storage is inadequately protected as rod density in the fuel pool 

8 increases. This rod crowding is a serious safety concern. Why have 20 more years of 

9 radioactive spent fuel? There are many questions that should be adequately analyzed and 

10 answered: Where do we put it and how will it be monitored and managed? Is the Watts Bar 

11 radioactive waste going to be transported to SQN as well? Has the proposed Independent 

12 Spent Fuel Storage Building been put in place and is it secure enough?

13 17-9-RW: At Sequoyah there’s currently 1,174 metric tons of this high level radioactive waste. It’s 

14 easily one to three million times more radioactive than when the fuel went into the reactors. This is 

15 not just spent fuel; this stuff is a nightmare.

16 Response: These comments concern the impacts of spent nuclear fuel (SNF) on the 

17 environment and human health. SQN stores its SNF in its spent fuel pool and in dry casks. 

18 The spent fuel pool is a structure constructed of steel-reinforced concrete walls with a stainless 

19 steel liner, and filled with water. The spent fuel pool is located inside the plant’s protected area. 

20 The NRC regularly inspects SQN’s spent fuel storage program to ensure the safety of the SNF

21 stored in the spent fuel pool. The NRC’s safety requirements for the storage of SNF during 

22 licensed operations, including requirements related to the spacing of spent fuel rods in the pool, 

23 ensure that the expected increase in the volume of SNF during the license renewal term can be 

24 safely stored on site. 

25 The latest NRC inspection of activities associated with the SQN spent fuel pool was performed 

26 in January 2014. As reported on page 14 of the SEQUOYAH NUCLEAR PLANT – NRC 

27 INTEGRATED INSPECTION REPORT 05000327/2013005 AND 05000328/2013005 (ADAMS 

28 Accession No. ML14038A346) dated February 7, 2014: No findings associated with the SQN 

29 spent fuel pool were identified.

30 SQN also stores SNF in NRC approved dry cask canisters made of leak-tight welded and bolted 

31 steel at the SQN Independent Spent Fuel Storage Installation (ISFSI). A typical dry cask 

32 storage system is detailed at the following website: 

33 http://www.nrc.gov/waste/spent-fuel-storage/diagram-typical-dry-cask-system.html. 

34 The NRC regularly inspects SQN’s dry cask storage system to ensure it complies with NRC 

35 requirements. The latest NRC inspection of the SQN ISFSI was performed in January 2014.

36 As reported on page 27 of the SEQUOYAH NUCLEAR PLANT – NRC INTEGRATED 

37 INSPECTION REPORT 05000327/2013005 AND 05000328/2013005 (ADAMS Accession 

38 No. ML14038A346) dated February 7, 2014: No findings associated with the SQN ISFSI were 

39 identified.

40 TVA plans to construct and operate an ISFSI at Watts Bar Nuclear Plant (WBN) to store WBN 

41 SNF. A detailed description of the proposed ISFSI is contained in the “Independent Spent Fuel 

42 Storage Installation, Watts Bar Nuclear Plant, Draft Environmental Assessment, dated April 7, 

43 2014, available on line at: http://www.tva.gov/environment/reports/spent_fuel_storage/

44 Draft%20EA%20WBN%20ISFSI%20Public%20Review%20April%207%202014.pdf. TVA has 

45 not informed the NRC staff of any plans to transfer spent fuel from WBN to SQN. 
Appendix A

A-29

1 Spent nuclear fuel is discussed in SQN DSEIS section 3.1.4. The NRC’s evaluation of impacts 

2 from the onsite storage of SNF, offsite radiological impacts of SNF and high-level waste

3 disposal, and, the uranium fuel cycle are addressed in Chapter 4 of the SQN DSEIS. 

4 10-12-RW: Article to be considered during the environmental review: “Improving Spent-Fuel 

5 Storage at Nuclear Reactors.”

6 Response: The NRC staff read and considered the article in the comment above. The 

7 information in this article is not within the scope of the license renewal application environmental 

8 review and therefore was not used in development of the SQN DSEIS. 

9 A.1.9 Surface Water

10 Comments: 

11 11-7-SW: It’s also I’m especially concerned about water use. And we have climate 

12 disruption -- more storms, more problems that way. And we also have growing industry, 

13 business people that use the water in addition to the drinking water, most of which comes from 

14 the Tennessee River for Chattanooga.

15 And a nuclear plant uses seven -- if it’s a 1,000 megawatt and Sequoyah is a little bigger 

16 than seven thousand fourteen hundred -- 714,740 gallons per minute. So I’m concerned about 

17 the use of that water, two-thirds of which does not go back into the river after it’s used to cool.

18 11-10-SW: I was talking to you earlier about the water usage and how much water comes out 

19 of the river, every minute, 714,740 gallons per minute when the plant is operating. And two 

20 thirds of that goes up into the air through the cooling towers that we’re all so familiar with.

21 11-12-SW: And in fact, it’s water that’s going to be the constraining resource in the future. We 

22 cannot have nuclear plants using all that water that could be used for other uses. And it’s just 

23 evaporating into the air for the most ...

24 11-33-SW: In this age of climate disruption, water quality and quantity is of prime importance. 

25 Nuclear Plants use inordinate amounts of water each day when operating and about two-thirds 

26 is evaporated through the cooling towers and is not returned to the river. The Union of 

27 Concerned Scientists tells us that the typical 1,000 MW-electric nuclear power reactor can use 

28 up to a whopping 714,740 gallons per minute. This is water that could be used by other 

29 businesses, industries, and for drinking water.

30 19-2-SW: There’s some other environmental issues I just wanted to mention that are tied 

31 specifically to the Sequoyah Plant. One is the water requirements. That’s been a big issue 

32 recently, the amount of water that these plants take in and the temperature rise. I’m sure you’re 

33 looking at that.

34 Response: These comments concern the impact on surface water from SQN. SQN DSEIS 

35 sections 3.1.3 and 3.5.1 contain a description of the consumptive use of surface water at SQN. 

36 Consumptive water use during the proposed license renewal term of SQN will continue to be a 

37 very small percentage of the overall flow of the Tennessee River through the Chickamauga 

38 Reservoir. The potential impact of SQN license renewal activities on surface water resources is 

39 described in section 4.5.1.1 of the SQN DSEIS.

40 The cumulative effect on surface water resources by the aggregate of past, present, and 

41 reasonably foreseeable future actions over the proposed license renewal term is evaluated in 

42 section 4.16.3.1 of the SQN DSEIS. This section considers the total effect of actions that could 

43 impact the surface water (including both direct and indirect effects) no matter who has taken the 

44 actions (Federal, State, County, or private).

1 APPENDIX B 

2 APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

B

B-1 

1 APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

2 The Atomic Energy Act of 1954 (AEA), as amended (42 USC § 2011 et seq.), authorizes the 

3 U.S. Nuclear Regulatory Commission (NRC) to enter into agreement with any State to assume 

4 regulatory authority for certain activities (see 42 USC § 2012 et seq.). For example, through the 

5 Agreement State Program, Tennessee assumed regulatory responsibility over certain 

6 byproduct, source, and quantities of special nuclear materials not sufficient to form a critical 

7 mass. The Division of Radiological Health, Tennessee Department of Environment and 

8 Conservation (TDEC), administers the Tennessee Agreement State Program. 

9 In addition to carrying out some Federal programs, state legislatures develop their own laws. 

10 State statutes supplement, as well as implement, Federal laws for protection of air, water 

11 quality, and groundwater (GW). State legislation may address solid waste management 

12 programs, locally rare and endangered species, and historic and cultural resources.

13 The Clean Water Act (33 USC § 1251 et seq., herein referred to as CWA) allows for primary 

14 enforcement and administration through state agencies, given that the state program is at least 

15 as stringent as the Federal program. The state program must conform to the CWA and to the 

16 delegation of authority for the Federal National Pollutant Discharge Elimination System

17 (NPDES) program from the U.S. Environmental Protection Agency (EPA) to the state. The 

18 primary mechanism to control water pollution is the requirement for direct dischargers to obtain 

19 an NPDES permit, or in the case of states where the authority has been delegated from the 

20 EPA, a State Pollutant Discharge Elimination System permit, under the CWA. In Tennessee, 

21 TDEC issues and enforces NPDES permits.

22 One important difference between Federal regulations and certain state regulations is the 

23 definition of waters that the state regulates. Certain state regulations may include underground 

24 waters, whereas the CWA only regulates surface waters. In Tennessee, TDEC is charged with 

25 conserving, managing and protecting surface water and GW resources (TDEC 2014). 

26 B.1 Federal and State Environmental Requirements

27 Sequoyah Nuclear Plant (SQN) is subject to Federal and State requirements for its 

28 environmental program.

29 Table B–1 lists the principle Federal and State environmental regulations and laws associated 

30 with the environmental review of the SQN license renewal application. 
Appendix B

B-2 

1 Table B–1. Federal and State Environmental Requirements

Law/regulation Requirements

Current operating license and license renewal

Atomic Energy Act (42 

U.S.C. § 2011 et seq.)

This Act is the fundamental U.S. law on both the civilian and the military 

uses of nuclear materials. On the civilian side, it provides for both the 

development and the regulation of the uses of nuclear materials and 

facilities in the United States. The Act requires that civilian uses of nuclear 

materials and facilities be licensed, and it empowers the NRC to establish 

by rule or order, and to enforce, such standards to govern these uses as 

“the Commission may deem necessary or desirable in order to protect 

health and safety and minimize danger to life or property.”

10 CFR Part 51. Title 10 

Code of Federal 

Regulations (10 CFR)

Part 51, Energy

“Environmental Protection Regulations for Domestic Licensing and 

Related Regulatory Functions.” This part contains environmental 

protection regulations applicable to the NRC’s domestic licensing and 

related regulatory functions.

10 CFR Part 54 “Requirements for Renewal of Operating Licenses for Nuclear Power 

Plants.” This part focuses on managing adverse effects of aging rather 

than noting all aging mechanisms. The rule is intended to ensure that 

important systems, structures, and components will maintain their 

intended function during the period of extended operation.

10 CFR Part 50 “Domestic Licensing of Production and Utilization Facilities.” Regulations 

that the NRC issues under the AEA, as amended (68 Stat. 919), and 

Title II of the Energy Reorganization Act of 1974 (88 Stat. 1242), provide

for the licensing of production and utilization facilities. This part also gives 

notice to all persons who knowingly supply—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 § 50.5.

Air quality protection

Clean Air Act (CAA) 

(42 USC § 7401 et seq.)

The CAA is a comprehensive Federal law that regulates air emissions. 

Among other things, this law authorizes EPA to establish National Ambient 

Air Quality Standards (NAAQS) to protect public health and public welfare 

and to regulate emissions of hazardous air pollutants. EPA has 

promulgated NAAQS for six criteria pollutants: sulfur dioxide, nitrogen 

dioxide, carbon monoxide (CO), ozone, lead, and particulate matter. All 

areas of the United States must maintain ambient levels of these 

pollutants below the ceilings established by the NAAQS.

Tennessee Air Quality Act 

(Tennessee Code Title 68, 

Chapter 201)

The Tennessee Air Quality Act authorizes the setting of ambient air quality 

standards as necessary to protect the public health and welfare and

emission standards for the purpose of controlling air contamination, air 

pollution, and the sources of air pollution.
Appendix B

B-3 

Law/regulation Requirements

Water resources protection

Clean Water Act (CWA) 

(33 USC § 1251 et seq.) 

and the NPDES

(40 CFR 122)

The CWA establishes the basic structure for regulating discharges of 

pollutants into the waters of the United States and regulating quality 

standards for surface waters. 

Wild and Scenic River Act 

(16 USC § 1271 et seq.)

The Wild and Scenic River Act created the National Wild and Scenic 

Rivers System, which was established to protect the environmental values 

of free flowing streams from degradation by affecting activities, including 

water resources projects.

Safe Drinking Water Act

(SDWA) (42 USC § 300f 

et seq.)

The SDWA is the principal Federal law that ensures safe drinking water for 

the public. Under the SDWA, EPA is required to set standards for drinking 

water quality and oversees all states, localities, and water suppliers that 

implement these standards.

Tennessee Water Quality 

Control Act (Tennessee 

Code Chapter 69, Chapter 

3, Part 1)

Water quality regulations for National Pollutant Discharge Elimination 

System (NPDES) Permits, State Permits, Water Quality Based Effluent 

Limitations and Water Quality Certification. 

Waste management and pollution prevention

Resource Conservation and 

Recovery Act (RCRA) 

(42 USC § 6901 et seq.)

RCRA gives EPA authority to control hazardous waste. Before a material 

can be classified as a hazardous waste, it first must be a solid waste as 

defined under the Resource Conservation and Recovery Act (RCRA). 

Hazardous waste is classified under Subtitle C of the RCRA. Parts 261, 

“Identification and Listing of Hazardous Waste,” and 262, “Standards 

Applicable to Generators of Hazardous Waste,” of 40 CFR contain all 

applicable generators of hazardous waste regulations. 

Pollution Prevention Act 

(42 USC § 13101 et seq.)

The Pollution Prevention Act formally established a national policy to 

prevent or reduce pollution at its source whenever feasible. The Act 

supplies funds for state and local pollution prevention programs through a 

grant program to promote the use of pollution prevention techniques by 

business.

Protected species

Endangered Species Act

(ESA) (16 USC § 1531 

et seq.)

The ESA forbids any government agency, corporation, or citizen from 

taking (e.g., harming or killing) endangered animals without an 

Endangered Species Permit. The ESA also requires Federal agencies to 

consult with the U.S. Fish and Wildlife Service or National Marine 

Fisheries Service if any Federal action may adversely affect any listed 

species or designated critical habitat.

Magnuson–Stevens Fishery 

Conservation and 

Management Act (MSA) 

(P.L. 94-265), as amended 

through January 12, 2007

The Magnuson–Stevens Fishery Conservation and Management Act 

(MSA) includes requirements for Federal agencies to consider the impact 

of Federal actions on essential fish habitat (EFH) and to consult with the 

National Marine Fisheries Service if any activities may adversely affect 

EFH. 

Fish and Wildlife 

Coordination Act

(16 USC § 661 et seq.)

To minimize adverse impacts of proposed actions on fish and wildlife 

resources and habitat, the Fish and Wildlife Coordination Act requires that 

Federal agencies consult Government agencies regarding activities that 

affect, control, or modify waters of any stream or bodies of water. It also 

requires that justifiable means and measures be used in modifying plans 

to protect fish and wildlife in these waters.
Appendix B

B-4 

Law/regulation Requirements

Historic preservation

National Historic 

Preservation Act (NHPA) 

(16 USC § 470 et seq.)

The National Historic Preservation Act (NHPA) directs Federal agencies to 

consider the impact of their actions on historic properties. To comply with 

NHPA, Federal agencies must consult with State Historic Preservation 

Officers and, when applicable, tribal historic preservations officers. NHPA 

also encourages state and local preservation societies.

1 B.2 Operating Permits and Other Requirements

2 Table B–2 lists the permits and licenses issued by Federal, State, and local authorities for 

3 activities at SQN.
Appendix B

B-5 

1 Table B–2. Licenses and Permits

Permit Number Dates Responsible Agency

Operating license DPR-77 Issued: 9/17/1980

Expires: 9/17/2020 

NRC

Operating license DPR-79 Issued: 9/15/1981 

Expires: 9/15/2021

NRC

NPDES Permit TN0026450 Expires: 10/31/2013 

Permit administratively 

continued - renewal 

application pending.

TDEC 

401 Water Quality

Certification

None – part of the 

NPDES permit

Expires: 10/31/2013

Permit administratively 

continued - renewal 

application pending.

TDEC

Discharge of stormwater to 

waters of the State

TNR 050015 Expires: 05/14/14

Permit administratively 

continued - renewal 

application pending.

TDEC

Air Permit - Operation of 

emergency generators

4150-20200102-

11C

Expires: 07/17/17 Chattanooga–Hamilton 

County Air Pollution Control 

Bureau (CHCAPCB)

Air Permit - Operation of 

Unit 1 cooling tower

4150-30600701-

01C

Expires: 07/17/17 CHCAPCB

Air Permit - Operation of 

Unit 2 cooling tower

4150-30600701-

03C

Expires: 07/17/17 CHCAPCB

Air Permit - Operation of 

insulation saws A and B

4150-30700804-

06C

Expires: 07/17/17 CHCAPCB

Air Permit - Operation of 

auxiliary boilers A and B

4150-10200501-

08C

Expires: 07/17/17 CHCAPCB

Air Permit - Operation of 

carpenter shop

4150-30703099-

09C

Expires: 07/17/17 CHCAPCB

Air Permit - Operation of 

abrasive blasting operation

4150-30900203-

10C

Expires: 07/17/17 CHCAPCB

Asbestos removal for 

individual, non-scheduled 

renovations

3034 Expires: 12/31/14 CHCAPCB

Hazardous waste generator 

identification

TN5640020504 Expires: None TDEC

Disposal of solid waste DML 331050021 Expires: None TDEC

Shipment of radioactive

material to a Tennessee 

disposal/processing facility

T-TN002-L13 Expires: 12/31/2014 TDEC

Source: TVA 2013
Appendix B

B-6 

1 B.3 References

2 [TDEC] Tennessee Department of Environment and Conservation. 2014. Water Resources 

3 home page. Available at <http://www.tennessee.gov/environment/water/> (accessed 

4 13 May 2014).

5 [TVA] Tennessee Valley Authority. 2013. Sequoyah Nuclear Plant, Units 1 and 2, License 

6 Renewal Application, Appendix E, Applicant’s Environmental Report, Operating License 

7 Renewal Stage. Chattanooga, TN: TVA. January 7, 2013. 783 p. Agencywide Documents 

8 Access and Management System No. ML130240007, Parts 2 through 8 of 8.
1 APPENDIX C 

2 CONSULTATION CORRESPONDENCE

C

C-1 

1 CONSULTATION CORRESPONDENCE

2 C.1 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 Sequoyah Nuclear Plant, Units 1 and 2 (SQN) 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 SQN 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 SQN 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 cumulative effects and 

8 alternatives to the proposed action. This section includes information pursuant to 

9 50 CFR 402.12(f)(4) and (5).

10 C.1.3 Chronology of ESA Section 7 Consultation

11 Upon receipt of Tennessee Valley Authority’s license renewal application, the NRC staff 

12 considered whether any Federally listed or proposed species or designated or proposed critical 

13 habitats may be present in the action area (as defined at 50 CFR 402.02) for the proposed SQN 

14 license renewal. No species under the NMFS’s jurisdiction occur within the action area. 

15 Therefore, the NRC staff did not consult with the NMFS. With respect to species under the 

16 FWS’s jurisdiction, the NRC staff compiled a list of ESA-protected species and critical habitats 

17 within the vicinity of the facility and requested the FWS’s concurrence with this list in 

18 accordance with the ESA section 7 regulations at 50 CFR 402.12(c) in a letter dated 

19 March 20, 2013. The FWS concurred with the NRC staff’s list in its letter dated July 3, 2013. 

20 The NRC staff used this list as a starting point for its analysis of effects to Federally listed 

21 species and critical habitat, which appears in Sections 3.8 and 4.8 of this SEIS. In Section 3.8, 

22 the NRC staff concludes that no ESA-protected species or critical habitat occur in the action 

23 area. In Section 4.8, the NRC staff concludes that the proposed agency action would have no 

24 effect on any ESA-protected species or critical habitat. FWS (2013) does not typically provide 

25 its 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 SQN license renewal. Nonetheless, because this SEIS constitutes the NRC’s 

28 biological assessment, the NRC staff will submit a copy of this SEIS, upon its issuance, to the 

29 FWS for review in accordance with 50 CFR 402.12(j).

30 Table C–1 lists the letters, e-mails, and other correspondence related to the NRC’s ESA

31 obligations with respect to its review of the SQN license renewal application. This table will be 

32 updated in the final SEIS, as applicable, to include correspondence transpiring between the 

33 issuance of the draft and final SEIS.
Appendix C

C-3 

1 Table C–1. ESA Section 7 Consultation Correspondence

Date Sender and 

Recipient

Description ADAMS 

Accession 

No. (a)

March 20, 2013 M. Wong (NRC)

to C. Dohner (FWS)

Request for concurrence with list of Federally 

listed species and habitats for the proposed 

SQN license renewal

ML13079A186

June 5, 2013 B. Grange (NRC)

to M. Jennings (FWS)

Request for update on the status of FWS’s 

review of the NRC’s list of Federally listed 

species and habitats

ML13177A193

July 3, 2013 M. Jennings (FWS)

to M. Wong (NRC)

Concurrence with NRC’s list of Federally

listed species and habitats

ML13184A228

July 15, 2013 B. Grange (NRC)

to R. Sykes (FWS)

Request for clarification on whether to include 

white fringeless orchid in the NRC’s analysis 

of effects to Federally listed species and 

habitats

ML13197A395

July 15, 2013 R. Sykes (FWS)

to B. Grange (NRC)

Reply to request for clarification on whether to 

include white fringeless orchid in the NRC’s 

analysis of effects to Federally listed species 

and habitats

ML13197A395

(a) These documents can be accessed through the NRC’s Agencywide Documents Access and Management 

System (ADAMS) at http://adams.nrc.gov/wba/. 

2 C.2 Essential Fish Habitat Consultation

3 The NRC must comply with the Magnuson–Stevens Fishery Conservation and Management 

4 Act, as amended, (16 U.S.C. §1801–1884, herein referred to as Magnuson–Stevens Act) for 

5 any actions authorized, funded, or undertaken, or proposed to be authorized, funded, or 

6 undertaken that may adversely affect essential fish habitat (EFH).

7 In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that NMFS has not designated 

8 EFH under the Magnuson–Stevens Act in the Chickamauga Reservoir, and that the proposed 

9 SQN license renewal would have no effect on EFH. Thus, the Magnuson–Stevens Act does not 

10 require the NRC to consult with NMFS for the proposed SQN license renewal.

11 C.3 National Historic Preservation Act of 1966 Consultation

12 The National Historic Preservation Act (NHPA) requires Federal agencies to consider the effects 

13 of their undertakings on historic properties and consult with applicable state and Federal 

14 agencies, tribal groups, and individuals and organizations with a demonstrated interest in the

15 undertaking before taking action. Historic properties are defined as resources that are eligible 

16 for listing on the National Register of Historic Places. The historic preservation review process 

17 (Section 106 of the National Historic Preservation Act of 1966, as amended) is outlined in 

18 regulations issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800. 

19 In accordance with 36 CFR 800.8(c), the NRC has elected to use the NEPA process to comply 

20 with its obligations under Section 106 of the NHPA.
Appendix C

C-4 

1 Table C–2 lists the chronology of consultations and consultation documents related to the NRC 

2 Section 106 review. The NRC staff is required to consult with the noted agencies and 

3 organizations in accordance with the statutes listed above.

4 Table C–2. NHPA Correspondence

Date Sender and Recipient Description

ADAMS 

Accession 

No. (a)

March 14, 2013

M. Wong (NRC) to R. Nelson (ACHP) Request for scoping

comments/notification of 

Section 106 review

ML13058A315

March 14, 2013

M. Wong (NRC) to E.P. McIntyre, Jr., 

Tennessee Historical Commission

Request for scoping

comments/notification of 

Section 106 review

ML13058A180

March 15, 2013

M. Wong (NRC) to B. John Baker, 

Cherokee Nation

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to B. Anoatubby, The 

Chickasaw Nation

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to T. Yargee, 

Alabama Quassarte Tribal Town

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to G. Tiger, 

Muscogee (Creek) Nation

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to O.C. Sylestine, 

Alabama–Coushatta Tribe of Texas

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to G. Scott, 

Thlopthlocco Tribal Town

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to G.J. Wallace, 

Eastern Shawnee Tribe of Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to T. Hobia, Kialegee 

Tribal Town

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to M. Hicks, Eastern 

Band of the Cherokee Indians

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to G. Blanchard, 

Absentee Shawnee Tribe of 

Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to G.G. Wickliffe, 

United Keetoowah Band of Cherokee

Indians in Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 15, 2013

M. Wong (NRC) to J. E. Billie, 

Seminole Tribe of Florida

Request for scoping

comments/notification of 

Section 106 review

ML13058A243
Appendix C

C-5 

Date Sender and Recipient Description

ADAMS 

Accession 

No. (a)

March 15, 2013

M. Wong (NRC) to L. M. Harjo, 

Seminole Nation of Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML13058A243

March 25, 2013

L. LaRue-Baker, United Keetoowah 

band of Cherokee Indians in 

Oklahoma to E. Larson (NRC)

Response to request for 

scoping comments ML13084A357

April 30, 2013

M. Wong (NRC) to the Eastern 

Tennessee Historical Society

Request for scoping

comments/notification of 

Section 106 review

ML13112A141

May 6, 2013

M. Wong (NRC) to The Tennessee 

Historical Society

Request for scoping

comments/notification of 

Section 106 review

ML13113A301

(a)These documents can be accessed through the NRC’s ADAMS at http://adams.nrc.gov/wba/. 

1 C.4 References

2 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

3 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

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

5 [FWS] U.S. Fish and Wildlife Service. 2013. “Consultations: Frequently Asked Questions.”

6 Available at <http://www.fws.gov/endangered/what-we-do/faq.html#8> (accessed 

7 20 June 2014).

8 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 

9 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 

10 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 

11 Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf> 

12 (accessed 8 July 2013).

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

14 16 U.S.C. §1801–1884.

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

1 APPENDIX D 

2 CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE
D
D-1 

1 CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE

2 This appendix contains a chronological listing of correspondence between the U.S. Nuclear 

3 Regulatory Commission (NRC) and external parties as part of its license renewal 

4 application (LRA) environmental review for Sequoyah Nuclear Plant, Units 1 and 2 (SQN) other 

5 than consultation correspondence and comments received during the scoping process. 

6 Consultation correspondence is listed and discussed in Appendix C of this supplemental 

7 environmental impact statement (SEIS). Scoping comments are provided and addressed in 

8 Appendix A of this SEIS and in the Scoping Summary Report (see Table D–1 below). All 

9 documents are available electronically from the NRC’s Public Electronic Reading Room found 

10 on the Internet at the following Web address: http://www.nrc.gov/reading-rm.html. From this 

11 site, the public can gain access to the NRC’s Agencywide Documents Access and Management 

12 System (ADAMS), which provides text and image files of the NRC’s public documents in 

13 ADAMS. The ADAMS accession number for each document is included in the following table. 

14 D.1 Environmental Review Correspondence

15 Table D–1 lists the environmental review correspondence, by date, beginning with the request 

16 by Tennessee Valley Authority (TVA) to renew the operating license for SQN.
Appendix D

D-2 

1 Table D–1. Environmental Review Correspondence

Date Correspondence Description ADAMS No.

January 7, 2013 Transmittal of SQN LRA from TVA to NRC ML13024A004

February 8, 2013 Receipt and availability of SQN LRA ML13016A489

February 26, 2013

Determination of acceptability and sufficiency for 

docketing, proposed review schedule, and opportunity 

for a hearing regarding the application from TVA, for 

renewal of the operating licenses for SQN

ML13035A214

March 12, 2013

Notice of intent to prepare an environmental impact 

statement and conduct scoping process for license 

renewal for SQN

ML13056A161

March 20, 2013 Forthcoming meeting to discuss the license renewal 

process and environmental scoping for SQN ML13067A331

April 3, 2013 Transcript from afternoon public scoping meeting ML13108A137

April 3, 2013 Transcript from evening public scoping meeting ML13108A138

March 26, 2013 Transmittal of environmental audit plan to TVA ML13067A244

May 23, 2013 

Transmittal of environmental and severe accident

mitigation alterative (SAMA) requests for additional 

information (RAIs)

ML13119A083

June 7, 2013 Transmittal of revised environmental and SAMA RAIs ML13136A358

July 17, 2013 TVA response to SAMA RAIs ML13227A003

July 23, 2013 TVA response to environmental RAIs ML13206A385

August 7, 2013 Environmental audit summary ML13120A198

September 20, 2013 TVA transmittal of documents in support of 

environmental review ML13289A108

September 20, 2013

TVA transmittal of documents regarding archaeological,

protected species and habitats and terrestrial ecology 

resources in support of environmental review

ML13282A585

February 10, 2014 Schedule change letter ML14007A470

March 4, 2014 Schedule change letter ML14059A347

April 24, 2014 Scoping Summary Report ML14041A118
1 APPENDIX E 

2 ACTIONS AND PROJECTS CONSIDERED IN CUMULATIVE ANALYSIS

E-1 

1 ACTIONS AND PROJECTS CONSIDERED IN CUMULATIVE ANALYSIS

2 E.1 Actions and Projects Considered in Cumulative 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 Sequoyah Nuclear Plant, Units 1 and 2 (SQN). Not all actions or 

6 projects listed in this appendix are considered in each resource area because of the uniqueness 

7 of the resource and its geographic area of consideration.
Appendix E

E-2 

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

Project Name Summary of Project Location With 

Respect to SQN

Status

Nuclear projects

WBN Units 1 and 2 Nuclear power plant

Two 1,123-MWe 

Westinghouse four-loop 

reactors 

Soddy Daisy, TN

Approximately 

45 mi (72 km) 

northeast

Operational

WBN Unit 1 is currently 

licensed to continue 

operations through 

November 11, 2035 

(NRC 2014a). WBN Unit 2 

construction 80% 

complete; completion 

projected for 

December 2015 

(TVA 2014j).

Major NPDES permit 

No. TN0020168

Clinch River Site Up to six Babcock & 

Wilcox mPower design 

small modular reactor

(SMR) modules

Roane County, TN 

Approximately 

65 mi (104 km)

northeast

Proposed

Application not yet 

submitted, but construction 

permit expected in 

December 2015 

(TVA 2013b)

Oak Ridge Reservation Research and 

manufacturing park 

including Oak Ridge 

National Laboratory, the 

East Tennessee 

Technology Park, the 

Y-12 National Security 

Complex, and the TRU 

Waste Processing Facility

Oak Ridge, TN

Approximately 

35 mi (56 km)

northeast

Operational (DOE 2012)

Bellefonte Nuclear Plant, 

Units 1 and 2

Nuclear power plant

Two 1,260-MWe Babcock 

and Wilcox-designed 

pressurized light water 

reactors

Scottsboro, AL

Approximately 

89 mi (143 km)

southwest

Deferred

Bellefonte Units 1 and 2 

construction permits were 

issued 

December 24, 1974. The 

construction permit for 

Unit 1 has been extended 

to October 1, 2020

(AP 2011; TVA 2013a).

Bellefonte Nuclear Plant, 

Units 3 and 4

Nuclear power plant

Two 1,148-MWe 

Westinghouse four-loop 

reactors

Scottsboro, AL

Approximately 

89 mi (143 km)

southwest

Deferred

Application for two new 

nuclear units submitted 

October 30, 2007

(NRC 2014b)
Appendix E

E-3 

Project Name Summary of Project Location With 

Respect to SQN

Status

Coal-fired energy projects

Kingston Fossil Plant Nine-unit coal-fired plant

1,398 MW

Kingston, TN

Approximately 

25 mi (40 km)

northeast

Operational

NPDES permit 

No. TN0005452

(TVA 2014e)

Bull Run Fossil Plant Single-generator coal-fired 

plant

870 MW

Oak Ridge, TN

Approximately 

46 mi (74 km)

northeast

Operational

NPDES permit 

No. TN0005410

(TVA 2014b)

Dams and hydroelectric energy projects

Watts Bar Dam Hydroelectric power plant

on the Tennessee River

Five units totaling 182 MW

Spring City, TN 

Approximately 

31 mi (51 km)

northeast

Operational (TVA 2014i)

Apalachia Dam Hydroelectric power plant 

on the Hiwassee River

Two units totaling 82 MW

Murphy, NC

Approximately 

45 mi (73 km) east

Operational (TVA 2014a)

Chickamauga Dam Hydroelectric power plant 

on the Tennessee River

Four units totaling

119 MW

Flood control for the city of 

Chattanooga, TN 

Future Chickamauga Lock 

replacement (stalled 

because of funding issues; 

some construction 

complete)

Chattanooga, TN

Approximately 

11 mi (19 km)

southwest

Operational (TVA 2014c)

Proposed lock 

replacement, but stalled 

because of funding issues

Some preconstruction 

complete (USACE 2014)

Nickajack Dam Hydroelectric power plant 

on the Little Tennessee 

River

Four units totaling 

106 MW

Marion County, TN

Approximately 

34 mi (55 km) 

southwest

Operational (TVA 2014f)

Raccoon Mountain 

Pumped-Storage Plant

Hydroelectric power plant

Four units totaling 

1,616 MW

Chattanooga, TN

Approximately 

20 mi (32 km)

southwest

Operational (TVA 2014h)

Ocoee Dam #1 Hydroelectric power plant 

on the Ocoee River

Five generating units 

totaling 24 MW

Benton, TN 

Approximately 

27 mi (43 km)

south-southeast

Operational

Minor NPDES permit

No. TN0027499

(TVA 2014g)
Appendix E

E-4 

Project Name Summary of Project Location With 

Respect to SQN

Status

Dams and hydroelectric energy projects (continued)

Watts Bar Dam Safety 

Modifications

Installation of permanent 

measures for safety 

deficiencies related to 

maximum flood events

May include removing 

temporary barriers, 

installing permanent 

modifications in the form 

of a combination of 

concrete floodwalls, raised 

earthen embankments or 

berms and gap closure 

barriers

Upstream from 

Watts Bar Dam in 

the vicinity of the 

Watts Bar Dam 

Recreation Area

Potential 

construction 

staging area 

downstream of 

dam and adjacent 

to the lock canal

Final EIS published 

May 2013 (TVA 2014d)

Current status of TVA

Watts Bar Dam safety 

modifications is provided in 

Enclosure 3 of a letter from 

TVA to NRC dated 

4/25/14, available at 

http://pbadupws.nrc.gov/

docs/ML1412/

ML14122A219.pdf. 

Water supply and treatment facilities

Dayton, TN, sewage 

treatment plant

Wastewater treatment 

facility on Chickamauga 

Lake

Approximately 

17 mi (27 km)

southwest

Operational

Major NPDES permit 

No. TN0020478

(EPA 2014a)

Dayton, TN, water supply Withdraws water from 

Chickamauga Lake 

Reservoir

Approximately 

19 mi (30 km)

northeast

Operational (City of 

Dayton 2014)

Loudon Utilities Board Withdraws water from the 

Tennessee River

Approximately 

53 mi (85 km)

northeast

Operational

Planning to expand 

capacity (LUB 2014)

Kingston sewage treatment 

plant

Sewage treatment 

facilities on the Lower 

Clinch River

Roane County, TN

Approximately 

53 mi (84 km)

northeast

Operational

Major NPDES permit 

No. TN0061701

(EPA 2014a)

Roane County wastewater

plant

Sewage treatment 

facilities on the Lower 

Clinch River

Roane County, TN

Approximately 

54 mi (87 km)

northeast

Operational

Major NPDES permit 

No. TN0024473

(EPA 2014a)

Watts Bar Utility District Withdraws groundwater

and purchases surface 

water

Approximately 

61 mi (99 km)

northeast

Operational (WBUD 2013)

Moccasin Bend wastewater

treatment plant

Wastewater treatment 

facility on Chickamauga 

Lake

Chattanooga, TN 

Approximately 

19 mi (30 km)

southwest

Operational

Major NPDES permit 

No. TN0024210

(EPA 2014a)

Tennessee American Water Withdraws water from the 

Tennessee River

Chattanooga, TN

Approximately 

17 mi (28 km)

southwest

Operational (TAW 2014)

Cleveland Utilities sewage 

treatment plant

Wastewater treatment 

facility on the Hiwassee 

River

Cleveland, TN

Approximately 

17 mi (28 km)

northeast

Operational

Major NPDES permit 

No. TN0024121

(EPA 2014a)
Appendix E

E-5 

Project Name Summary of Project Location With 

Respect to SQN

Status

Manufacturing facilities

General Shale Brick, Inc.,

Plant 42

Brick and structural clay 

tile manufacturing

Spring City, TN

Approximately 

35 mi (57 km)

northeast

Operational

Major air permit 

No. 4714300116; minor

NPDES permit 

Nos. TN0079839 and 

TN0079863 (EPA 2014a, 

2014b)

Resolute Forest Products 

(formerly AbiBow)

Integrated pulp and paper 

mill on the Hiwassee River

Calhoun, TN

Approximately 

20 mi (32 km) east

Operational

Major NPDES permit 

No. TN0002356

(EPA 2014a, 2014b)

Olin Chemical Corporation Manufacturer of chlorine 

and caustic soda on the 

Hiwassee River

Charleston, TN

Approximately 

18 mi (29 km) east

Operational

Major NPDES permit 

No. TN0002461

(EPA 2014a)

Various minor NPDES

wastewater discharges

Various businesses with 

smaller wastewater

discharges 

Within 10 mi

(16 km)

Operational (EPA 2014a)

Transportation

Tennessee Toll Bridge Proposed bridge and 

highway linking 

U.S. Highway 27 at 

Sequoyah Access Road to 

Interstate 75

Within 15 mi

(24 km)

In planning stages by 

Tennessee Department of 

Transportation 

(CHCRPA 2011)

Parks and recreation sites

Harrison Bay State Park 485 ha (1,200 ac) on 

40 mi (60 km) of 

Chickamauga Lake 

shoreline with various 

parks, trails, boat 

launches, campgrounds, 

swimming areas

Approximately 3 mi

(5 km) southwest

Managed by Tennessee 

Department of 

Environment and 

Conservation (TDEC)

(TSP 2013c)

Booker T. Washington 

State Park

142 ha (353 ac) near 

Chattanooga with a bike 

trail, boat launches, and 

swimming area

Approximately 9 mi 

(14 km) southwest

Managed by TDEC (TSP 

2013a)

Yuchi Wildlife Refuge 957 ha (2,364 ac) with 

small game hunting

Approximately 

28 mi (45 km)

northeast

Managed by the 

Tennessee Wildlife 

Resources Agency

(TWRA) (TWRA 2014a)

Watts Bar Wildlife 

Management Area

1,570 ha (3,880 ac) with 

big and small game 

hunting

Includes both 

Thief Neck Island 

and Long Island

Approximately 

46 and 54 mi

(75 and 87 km)

northeast

Managed by the TWRA 

(TWRA 2014b)
Appendix E

E-6 

Project Name Summary of Project Location With 

Respect to SQN

Status

Parks and recreation sites (continued)

Recreational Areas Various parks, boat 

launches, campgrounds, 

swimming areas on 

Chickamauga Lake

Within 10 mi

(16 km)

Operational

Chickamauga Wildlife 

Management Area

1,620 ha (4,000 ac) in 

Bradley, Hamilton, 

McMinn, Meigs, and Rhea 

Counties

Big and small game 

hunting

Throughout the 

region, includes 

Yellow Creek, 

Washington Ferry, 

McKinley Branch, 

Goodfield Creek, 

Cottonport, Shelton 

Bottoms, Moon 

Island, Gillespie 

Bend, Mud Creek, 

New Bethel, Sale 

Creek, and Soddy 

Creek wildlife 

management areas

Managed by the TWRA 

(TWRA 2014c)

Cumberland Trail State 

Scenic Trail

A 300-mi (480-km)

backcountry hiking trail 

from Cumberland Gap 

National Park, KY, to 

Chickamauga 

Chattanooga National 

Military Park

Throughout region Approximately 175 mi

(280 km) of the trail has 

been constructed. 

Managed by the 

Cumberland Trail 

Conference (TSP 2013b)

Sequoyah projects

ISFSI expansion ISFSI currently licensed 

on SQN plant site; may 

require expansion in the 

future

SQN site No immediate plans 

(TVA 2013a)

Production of tritium SQN plant selected by 

DOE for purchase of 

irradiation services. 

Addition of employees 

(fewer than 10 employees 

per unit) and plant 

modifications. Irradiated 

tritium-producing burnable 

absorber rod assemblies, 

nonradioactive waste, and 

some additional low-level 

radioactive waste would 

be transported off site for 

processing and disposal.

SQN site Notice of intent to prepare 

and EIS published in 2011, 

with accompanying 

scoping meetings held in 

October 2011. Draft EIS 

not yet published for public 

comment (NNSA 2012; 

TVA 2013a) 
Appendix E

E-7 

Project Name Summary of Project Location With 

Respect to SQN

Status

Sequoyah projects (continued)

Use of highly enriched 

uranium (HEU) fuel

TVA plans to acquire

28 metric tons of HEU 

from the DOE for

downblending to BLEU 

and use as reactor fuel at 

SQN through 2022.

SQN site EA with finding of no 

significant impact finished 

in 2011 (TVA 2013a)

Use of mixed-oxide fuel 

(MOXF)

SQN is a potential site for 

DOE’s surplus Pu 

dispositioning. Fabricating 

MOXF entails mixing Pu

with depleted UO, 

manufacturing the fuel into 

pellets, and loading the 

pellets into fuel 

assemblies for use in 

nuclear reactors.

SQN site TVA is coordinating with 

the DOE on the EIS.

Draft closed for comment 

in October 2012

Currently preparing final 

EIS (NNSA 2014; 

TVA 2013a)

Other projects

Future Urbanization Construction of housing 

units and associated 

commercial buildings; 

roads, bridges, and rail; 

and water and wastewater

treatment and distribution 

facilities and associated 

pipelines as described in 

local land-use planning 

documents. Industrial 

parks in Chattanooga, the

fastest growing city in TN.

Throughout region Construction would occur 

in the future, as described 

in State and local land-use 

planning documents

(CHCRPA 2014)

RV Park RV park directly across 

from SQN site. Land was 

previously undeveloped. 

Is on same municipal 

water supply as SQN.

Directly across 

from SQN

Operational (Allstays 2014)

Key: ac = acres; BLEU = blended low-enriched uranium; 

CHCRPA = Chattanooga–Hamilton County Regional Planning Agency; DOE = Department of Energy; 

EA = environmental assessment; EIS = environmental impact statement; 

EPA = U.S. Environmental Protection Agency; ha = hectares; HEU = highly enriched uranium; 

ISFSI = independent spent fuel storage installation; LUB = Loudon Utilities Board; MOXF = mixed-oxide fuel; 

MW = megawatts; MWe = megawatts electric; NNSA = National Nuclear Security Administration; 

NPDES = National Pollutant Discharge Elimination System; NRC = U.S. Nuclear Regulatory Commission; 

Pu = plutonium; RV = recreational vehicle; SMR = small modular reactor; 

SQN = Sequoyah Nuclear Plant, Units 1 and 2; TAW = Tennessee American Water; TRU = transuranic; 

TSP = Tennessee State Parks; TVA = Tennessee Valley Authority; 

TWRA = Tennessee Wildlife Resources Agency; UO = uranium oxide; 

USACE = United States Army Corps of Engineers; WBN = Watts Bar Nuclear Power Plant; 

WBUD = Watts Bar Utility District

Sources: Allstays 2014; AP 2011; CHCRPA 2011, 2014; City of Dayton 2014; DOE 2012; EPA 2014a. 2014b; 

LUB 2014; NNSA 2012, 2014; NRC 2014a, 2014b; TAW 2014; TSP 2013a, 2013b, 2013c; TVA 2013a, 2013b, 

2014a, 2014b, 2014c, 2014d, 2014e, 2014f, 2014g, 2014h, 2014i, 2014j; TWRA 2014a, 2014b, 2014c; 

USACE 2014; WBUD 2013
Appendix E

E-8 

1 E.2 References

2 [Allstays] Allstays LLC. 2014. “Sequoyah RV Park: A Campground near Soddy-Daisy 

3 Tennessee.” Available at <http://www.allstays.com/Campgrounds-details/35706.htm> (accessed 

4 May 2014). 

5 [AP] Associated Press. 2011. “NRC extends construction permit for northeast Alabama’s 

6 Bellefonte Nuclear Plant.” September 30, 2011. Available at 

7 <http://blog.al.com/wire/2011/09/nrc_extends_construction_permi.html> (accessed May 2014).

8 [CHCRPA] Chattanooga–Hamilton County Regional Planning Agency. 2011. Central Hamilton 

9 County Scenario Planning Study. May 2011. 77 p. Available at 

10 <http://www.chcrpa.org/Projects/Central_Hamilton_County_Scenario_Planning_Study/Hamilton

11 County_CHCSPS_FinalReport_051611.pdf> (accessed May 2014). 

12 [CHCRPA] Chattanooga–Hamilton County Regional Planning Agency. 2014.” Strategic 

13 Long-Range Planning.” Available at <http://www.chcrpa.org/Comprehensive_Planning.htm>

14 (accessed May 2014). 

15 City of Dayton. 2014. “Water Department—City of Dayton, Tennessee.” Available at 

16 <http://www.daytontn.net/water.php> (accessed May 2014). 

17 [DOE] U.S. Department of Energy. 2012. “Oak Ridge Reservation Facilities.” Available at 

18 <http://www.oakridge.doe.gov/external/publicactivities/emergencypublicinformation/

19 oakridgereservationfacilities/tabid/321/default.aspx> (accessed May 2014). 

20 [EPA] Environmental Protection Agency. 2014a. “Envirofacts search results: Facilities with 

21 permits and discharges to waters of the United States.” March 18, 2014. Available at 

22 <http://www.epa.gov/enviro/index.html> (accessed May 2014). 

23 [EPA] Environmental Protection Agency. 2014b. “Envirofacts search results: Facilities that 

24 produce and release air pollutants.” Available at <http://www.epa.gov/enviro/index.html>

25 (accessed May 2014). 

26 [LUB] Loudon Utilities Board. 2014. “Home Page.” Available at <http://www.loudonutilities.org/>

27 (accessed May 2014). 

28 [NNSA] National Nuclear Security Administration. 2012. “Surplus Plutonium Disposition 

29 Supplemental Environmental Impact Statement.” October 11, 2012. Available at

30 <http://nnsa.energy.gov/aboutus/ouroperations/generalcounsel/nepaoverview/nepa/

31 spdsupplementaleis> (accessed May 2014). 

32 [NNSA] National Nuclear Security Administration. 2014. “SEIS for the Production of Tritium in a 

33 Commercial Light Water Reactor.” Available at 

34 <http://nnsa.energy.gov/aboutus/ouroperations/generalcounsel/nepaoverview/nepa/tritiumseis>

35 (accessed May 2014). 

36 [NRC] U.S. Nuclear Regulatory Commission. 2014a. “Watts Bar Nuclear Plant, Unit 1.” 

37 May 14, 2014. Available at <http://www.nrc.gov/info-finder/reactor/wb1.html> (accessed 

38 May 2014). 

39 [NRC] U.S. Nuclear Regulatory Commission. 2014b. “Bellefonte Nuclear Station, Units 3 and 4 

40 Application.” February 25, 2014. Available at 

41 <http://www.nrc.gov/reactors/new-reactors/col/bellefonte.html> (accessed May 2014). 
Appendix E

E-9 

1 [TAW] Tennessee American Water. 2014. “Tennessee American Water.” May 28, 2014. 

2 Available at <http://www.amwater.com/tnaw/> (accessed May 2014). 

3 [TSP] Tennessee State Parks. 2013a. “Booker T. Washington State Park.” Available at 

4 <http://tnstateparks.com/parks/about/booker-t-washington> (accessed May 2014). 

5 [TSP] Tennessee State Parks. 2013b. “Cumberland Trail State Park.” Available at 

6 <http://tnstateparks.com/parks/about/cumberland-trail> (accessed May 2014). 

7 [TSP] Tennessee State Parks. 2013c. “Harrison Bay State Park.” Available at 

8 <http://tnstateparks.com/parks/about/harrison-bay> (accessed May 2014). 

9 [TVA] Tennessee Valley Authority. 2013a. Sequoyah Nuclear Plant, Units 1 and 2—License 

10 Renewal. Knoxville, TN: TVA. January 7, 2013. 2,353 p. Agencywide Documents Access and 

11 Management System No. ML130240007.

12 [TVA] Tennessee Valley Authority. 2013b. “TVA: News Release.” February 20, 2013. Available 

13 at <http://www.tva.com/news/releases/janmar13/smr_agreement.html> (accessed May 2014). 

14 [TVA] Tennessee Valley Authority. 2014a. “Apalachia.” Available at 

15 <http://www.tva.gov/lakes/aph_r.htm> (accessed May 2014). 

16 [TVA] Tennessee Valley Authority. 2014b. “Bull Run Fossil Plant.” Available at 

17 <http://www.tva.gov/sites/bullrun.htm> (accessed May 2014). 

18 [TVA] Tennessee Valley Authority. 2014c. “Chickamauga.” Available at 

19 <http://www.tva.gov/lakes/chh_r.htm> (accessed May 2014). 

20 [TVA] Tennesse Valleey Authority. 2014d. “Environmental Reviews.” Available at 

21 <http://www.tva.com/environment/reports/dam_safety/index.htm> (accessed May 2014). 

22 [TVA] Tennessee Valley Authority. 2014e. “Kingston Fossil Plant.” Available at 

23 <http://www.tva.gov/sites/kingston.htm> (accessed May 2014). 

24 [TVA] Tennessee Valley Authority. 2014f. “Nickajack.” Available at 

25 <http://www.tva.gov/lakes/njh_r.htm> (accessed May 2014). 

26 [TVA] Tennessee Valley Authority. 2014g. “Ocoee No. 1.” Available at 

27 <http://www.tva.gov/lakes/o1h_r.htm> (accessed May 2014). 

28 [TVA] Tennessee Valley Authority. 2014h. “Raccoon Mountain Pumped-Storage Plant.”

29 Available at <http://www.tva.gov/sites/raccoonmt.htm> (accessed May 2014). 

30 [TVA] Tennessee Valley Authority. 2014i. “Watts Bar.” Available at 

31 <http://www.tva.gov/lakes/wbh_r.htm> (accessed May 2014). 

32 [TVA] Tennessee Valley Authority. 2014j. “Watts Bar Nuclear Project.” Available at 

33 <http://www.tva.com/power/nuclear/wattsbar_unit2.htm> (accessed May 2014). 

34 [TWRA] Tennessee Wildlife Resources Agency. 2014a. “Tennessee Watchable Wildlife: Yuchi 

35 WMA.” Available at <http://www.tnwatchablewildlife.org/watchareadetails

36 .cfm?uid=09071611212262890®ion=Yuchi_WMA&statearea=East_Tennessee> (accessed 

37 May 2014). 

38 [TWRA] Tennessee Wildlife Resources Agency. 2014b. “Tennessee Watchable Wildlife: 

39 Watts Bar WMA—Long Island Unit.” Available at

40 <http://www.tnwatchablewildlife.org/watchareadetails.cfm?uid=09072713580319569®ion

41 =Watts_Bar_WMA_-_Long_Island_Unit&statearea=East_Tennessee> (accessed May 2014). 
Appendix E

E-10

1 [TWRA] Tennessee Wildlife Resources Agency. 2014c. “Tennessee Watchable Wildlife: 

2 Chickamauga WMA—Cottonport Unit.” Available at <http://www.tnwatchablewildlife.org/

3 watchareadetails.cfm?uid=10011713393549426®ion

4 =Chickamauga_WMA_-_Cottonport_Unit&statearea=East_Tennessee> (accessed May 2014). 

5 [USACE] U.S. Army Corps of Engineers. 2014. Nashville District: Missions: Current Projects: 

6 Construction: Chickamauga Lock Replacement Project.” Available at 

7 <http://www.lrn.usace.army.mil/Missions/CurrentProjects/Construction/

8 ChickamaugaLockReplacementProject.aspx> (accessed May 2014). 

9 [WBUD] Watts Bar Utility District. 2013. “Watts Bar Utility District.” Available at 

10 <http://www.wbud.org/> (accessed May 2014). 
1 APPENDIX F 

2 NRC STAFF EVALUATION OF SEVERE ACCIDENT MITIGATION 

3 ALTERNATIVES

F-1 

1 U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

2 SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR SEQUOYAH 

3 NUCLEAR STATION IN SUPPORT OF LICENSE RENEWAL 

4 APPLICATION REVIEW 

5 F.1 Introduction

6 Tennessee Valley Authority (TVA) submitted an assessment of severe accident mitigation 

7 alternatives (SAMAs) for the Sequoyah Nuclear Station (SQN) Units 1 and 2 in Section 4.21 and 

8 Attachment E of the Environmental Report (ER) (TVA 2013d). This assessment was based on 

9 the most recent revision to SQN probabilistic risk assessment (PRA) for each unit, including an 

10 internal events model and a plant-specific offsite consequence analysis performed using the 

11 WinMACCS Version 3.6.0 computer code, and insights from the SQN individual plant 

12 examination (IPE) submittals (TVA 1992, 1998) and individual plant examination of external 

13 events (IPEEE) submittals (TVA 1995, 1999). In identifying and evaluating potential SAMAs, 

14 TVA considered SAMAs that addressed the major contributors to core damage frequency (CDF) 

15 and population dose at SQN, SAMA-related industry documentation, plant-specific 

16 enhancements not in published industry documentations, as well as insights and SAMA 

17 candidates from potential improvements at twelve other plants. TVA initially identified a list of 

18 309 potential SAMAs. This list was reduced to 47 unique SAMA candidates by eliminating 

19 SAMAs that: were not applicable to SQN; had already been implemented at SQN; were 

20 combined into a more comprehensive or plant-specific SAMA; had excessive implementation 

21 cost; is related to a non-risk significant system; or related to in-progress implementation of plant 

22 improvements that address the intent of the SAMA. From the baseline analysis, TVA concluded 

23 in the ER that nine and eight candidate SAMAs are potentially cost-beneficial for Units 1 and 2, 

24 respectively. From a sensitivity analysis (TVA 2013d, Attachment E), TVA identified an 

25 additional seven and nine candidate SAMAs as potentially cost beneficial for Units 1 and 2, 

26 respectively.

27 As a result of the review of the SAMA assessment, the U.S. Nuclear Regulatory Commission 

28 (NRC) staff issued requests for additional information (RAIs) to TVA by letter dated 

29 June 7, 2013 (NRC 2013). Key questions concerned: changes and updates to Level 1 and 

30 Level 2 PRA models that most affected CDF; differences in CDF values and importance 

31 measures; systems shared between both units and influences from events at one unit on the 

32 other unit; the impact of open items and issues from the peer review of the PRA; the assignment 

33 of representative accident scenarios and release categories considering the set of containment 

34 event tree (CET) end states; the impact of recent external flooding developments on external 

35 event conclusions; potential effects of weaknesses in the fire analysis; new information on fire36 initiated events; and further information on the cost-benefit analysis of several specific candidate 

37 SAMAs and low-cost alternatives. In response to the NRC staff RAI, TVA submitted additional 

38 information by a letter dated July 17, 2013 (TVA 2013c), and provided further information on the 

39 key questions. The TVA’s responses addressed the NRC staff’s concerns and resulted in the 

40 identification of four additional potentially cost-beneficial SAMAs that apply to both units.

41 An assessment of the SAMAs for SQN is presented below.

42 F.2 Estimate of Risk for SQN

43 The TVA’s estimates of offsite risk at SQN are summarized in Section F.2.1. The summary is 

44 followed by the NRC staff’s review of TVA’s risk estimates in Section F.2.2.
Appendix F

F-2 

1 F.2.1 TVA’s Risk Estimates

2 Two distinct analyses are combined to form the basis for the risk estimates used in the SAMA

3 analysis: (1) the SQN Level 1 and 2 PRA models, which are essentially new models and (2) a 

4 supplemental analysis of offsite consequences and economic impacts (essentially a Level 3 

5 PRA model) developed specifically for the SAMA analysis. The SAMA analysis is based on the 

6 most recent SQN Level 1 and Level 2 PRA models available at the time of the ER, referred to 

7 as the SQN SAMA model (TVA 2013d). The scope of this SQN PRA does not include 

8 external events.

The SQN Unit 1 CDF is approximately 3.0×10−5 9 per reactor-year while the Unit 2 CDF is 

approximately 3.5×10−5 10 per reactor-year. These values were used as the baseline CDF in the 

11 SAMA evaluations (TVA 2013d). The CDF is based on the risk assessment for internally 

12 initiated events, which includes internal flooding. TVA did not explicitly include the contribution 

13 from external events within the SQN risk estimates; however, it did account for the potential risk 

14 reduction benefits for individual SAMAs associated with external events by multiplying the 

15 estimated benefits for internal events by a factor of 2.9 for Unit 1 and 2.6 for Unit 2. This is 

16 discussed further in Sections F.2.2 and F.6.2.

17 The breakdown of CDF by initiating event is provided in Table F–1. As shown in these tables, 

18 Internal Flooding, Loss of All Component Cooling Water (CCW) and Stuck Open Safety/Relief 

19 Valve are the dominant contributors to the CDF in both units. Station blackout (SBO) and 

20 anticipated transients without scram (ATWS) are not listed explicitly in Table F–1 because 

21 multiple initiators contribute to their occurrence. SBO contributes about 13 percent and 

10 percent to the total CDF for Units 1 and 2, respectively (3.9×10−6 22 per reactor-year and 

3.6×10−6 23 per reactor-year), while ATWS contribute about 14 percent and 12 percent to the total 

CDF for Units 1 and 2, respectively (4.1×10−6 24 per reactor-year for each unit). Note that in a 

25 subsequent correction to the ATWS model, TVA indicated that ATWS contribute about 

26 2 percent and 2.3 percent to the total CDF for Units 1 and 2, respectively (TVA 2013c). This is 

27 discussed in more detail in Section F.2.2.1.

28 The Level 2 SQN PRA model that forms the basis for the SAMA evaluation is essentially a new 

29 model for SQN. The Level 2 model was developed with a focus on the quantification of large 

30 early release frequency (LERF) but does include the development of other end states. The 

31 Level 2 model utilizes CETs containing both phenomenological and systemic events. The core 

32 damage sequences from the Level 1 PRA are binned into plant damage states (PDSs) based 

33 on similar characteristics that influence the accident progression following core damage. These 

34 bins provide the interface between the Level 1 and Level 2 CET analyses. The CETs are linked 

35 directly to the Level 1 event trees and CET nodes based on the PDS.
F-3

Appendix F

1 Table F–1. SQN Units 1 and 2 CDF for Internal Events

Initiating Event

Unit 1 CDF

(per year)

Unit 1

Percent CDF

Contribution1

Unit 2 CDF

(per year)

Unit 2

Percent CDF

Contribution1

Internal Flooding 1.7×10−5 56 2.3×10−5 66

Loss of All CCW 3.6×10−6 12 3.2×10−6 9

Stuck Open Safety/Relief Valve 2.3×10−6 8 2.5×10−6 7

Secondary Side Break Outside of Containment 1.3×10−6 4 1.4×10−6 4

Losses of Main Feedwater 9.3×10−7 3 6.9×10−7 2

Reactor Trip 9.2×10−7 3 9.1×10−7 3

Loss of Train A CCW2 9.0×10−7 3 7.6×10−7 2

Loss of Instrument Boards 7.4×10−7 2 5.7×10−7 2

Other Initiating Events3 6.8×10−7 2 5.6×10−7 2

Loss of Offsite Power 6.5×10−7 2 3.9×10−7 1

Turbine Trip 5.1×10−7 2 5.1×10−7 1

Small Loss of Coolant Accident (LOCA) 3.9×10−7 1 4.5×10−7 1

Total CDF (Internal Events) 3.0×10−5 100 3.5×10−5 100

1 Percentages were rounded to the nearest whole percent for reporting and may not sum to 100 percent because of round off error. 2 Train A is listed as Train 1A for Unit 1 and Train 2A for Unit 2. 3 Multiple initiating events with each contributing less than 1 percent. 
Appendix F

F-4 

1 The CET considers the influence of physical and chemical processes on the integrity of the 

2 containment and on the release of fission products once core damage has occurred. Each CET 

3 sequence was assigned to one of seven end state categories. Four of these categories 

4 represent LERF with the remaining representing late and small early releases and an intact 

5 containment. These end states were subsequently grouped into 12 release categories (or 

6 release modes) that provide the input to the Level 3 consequence analysis. The frequency of 

7 each release category was obtained by summing the frequency of the individual accident

8 progression CET endpoints binned into the release category. The determination of the 

9 characteristics for each release category was based on representative accident scenarios that 

10 reflect the core damage and containment behavior for the dominant sequence or sequences 

11 within a PDS and the dominant Level 2 sequence within the release category. The source 

12 terms for the representative scenarios were based on a SEQSOR emulation spreadsheet 

13 methodology. The results of this analysis for SQN are provided in Table E.1–15 of ER 

14 Attachment E (TVA 2013d).

15 TVA computed offsite consequences for potential releases of radiological material using the 

16 WinMACCS Version 3.6.0 code and analyzed exposure and economic impacts from its 

17 determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 

18 site-specific input values for core radionuclide inventory, source term and release 

19 characteristics, site meteorological data, projected population distribution and growth within a 

20 50-mile radius, emergency response evacuation modeling, and economic data. Because of the 

21 similarity of the reactor cores at Watts Bar Unit 1, SQN Unit 1, and SQN Unit 2, the radionuclide 

22 inventory for the SQN SAMA analysis is based on the core inventory for Watts Bar Unit 1 

23 multiplied by the power ratio of the SQN Unit 1 power of 1,148 MWe to the Watts Bar Unit 1 

24 power of 1,123 MWe (TVA 2013d, Attachment E). Although the SQN Unit 2 power was slightly 

25 lower at 1,126 MWe, the same core inventory for SQN Unit 1 was used for the SQN Unit 2 

26 consequence analysis. The estimation of onsite impacts (in terms of cleanup and 

27 decontamination costs and occupational dose) is based on guidance in NUREG/BR–0184 

28 (NRC 1997b).

29 In the ER, the applicant estimated the dose risk to the population within 80 km (50 mi) of the 

30 SQN site to be 0.450 person-sievert (Sv) per year (45.0 person-rem per year) for Unit 1 and 

31 0.439 person-Sv per year (43.9 person-rem per year) for Unit 2 (TVA 2013d, Tables E.1-20 and 

32 E.1-21). The breakdown of the population dose risk by containment release mode is 

33 summarized in Table F–2. Late containment failure releases and large early releases caused 

34 by containment isolation failures accounted for approximately 79 and 75 percent of the 

35 population dose risk at Units 1 and 2, respectively. Late containment failure releases alone 

36 contributed approximately 47 and 45 percent of the population dose risk at Units 1 and 2. Late 

37 containment failure releases and large early releases caused by containment isolation failures 

38 accounted for approximately 85 and 83 percent of the offsite economic cost risk (OECR) at 

39 Units 1 and 2, respectively. Late containment failure releases alone contributed approximately 

40 58 and 56 percent of the OECR at Units 1 and 2.
F-5

Appendix F

1 Table F–2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk for Internal Events

Release Mode Population Dose Risk1 Offsite Economic Cost Risk

ID2

Frequency (per year) Person-rem/yr

Percent 

Contribution3 $/yr

Percent

Contribution3

Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2

Ia 4.1×10−8 4.6×10−8 1.2×10−1 1.3×10−1 <1 <1 2.3×10+2 2.6×10+2 <1 <1

Ib 9.7×10−7 9.5×10−7 2.5×10+0 2.5×10+0 6 6 5.2×10+3 5.1×10+3 5 5

Ic 2.7×10−7 3.9×10−7 7.0×10−1 1.0×10+0 2 2 1.4×10+3 2.1×10+3 1 2

IIa 3.3×10−6 3.3×10−6 1.2×10+1 1.2×10+1 26 27 2.2×10+4 2.2×10+4 23 24

IIb 6.3×10−7 3.3×10−7 2.2×10+0 1.1×10+0 5 3 4.2×10+3 2.2×10+3 4 2

IIc 6.5×10−8 6.3×10−8 1.3×10−1 1.2×10−1 <1 <1 2.9×10+2 2.8×10+2 <1 <1

IId 4.8×10−8 6.8×10−8 1.1×10−1 1.5×10−1 <1 <1 2.4×10+2 3.4×10+2 <1 <1

III 6.4×10−7 7.4×10−7 5.9×10+0 6.7×10+0 13 15 7.0×10+3 8.1×10+3 7 9

IVa 1.8×10−5 1.7×10−5 1.9×10+1 1.9×10+1 42 43 5.0×10+4 4.9×10+4 52 53

IVb 2.2×10−6 1.2×10−6 2.2×10+0 1.2×10+0 5 3 5.7×10+3 3.2×10+3 6 3

Va 2.1×10−6 2.0×10−6 2.8×10−1 2.7×10−1 1 1 2.6×10+2 2.5×10+2 <1 <1

Vb 1.1×10−6 1.9×10−6 1.5×10−1 2.5×10−1 <1 1 1.3×10+2 2.3×10+2 <1 <1

Totals 4.5×10+1 4.4×10+1 100 100 9.7×10+4 9.3×10+4 100 100 1 Unit Conversion Factor: 1 Sv = 100 rem 2 Release Category Descriptions

I – Large early releases with containment failures

II – Large early releases with containment isolation failures

III – Large early releases with containment bypass

IV – Late containment failure release

V – Small early release with some mitigation 3 Percentages are rounded to the nearest whole percent for reporting and may not sum to 100 percent because of roundoff error. 
Appendix F

F-6 

1 F.2.2 Review of TVA’s Risk Estimates

2 The TVA’s determination of offsite risk at SQN is based on the following three major elements of 

3 analysis:

4  essentially new Level 1 and 2 risk models that replace the original 1992 and 

5 revised 1998 IPE submittals (TVA 1992, 1998), 

6  the external event analyses of the 1995 and 1999 IPEEE submittals 

7 (TVA 1995, 1999), and

8  the combination of offsite consequence measures from WinMACCS analyses 

9 with release frequencies and radionuclide source terms from the Level 2 PRA 

10 model.

11 Each analysis element was reviewed to determine the acceptability of TVA’s risk estimates for 

12 the SAMA analysis, as summarized further in this section.

13 F.2.2.1 Internal Events CDF Model

14 The NRC staff’s review of the SQN IPE is described in an NRC letter dated May 15, 1995 

15 (NRC 1995). From its review of the IPE submittal, NRC staff concluded that the IPE process 

16 was acceptable in meeting the intent of Generic Letter (GL) 88-20 (NRC 1988). Although no 

17 vulnerabilities were identified in the IPE, 11 enhancements or improvements were identified. 

18 Based on the disposition of the Phase I SAMA candidates discussed in ER Section E.2.2, nine 

19 of these improvements have been implemented and two were retained as potential SAMAs for 

20 further analysis.

The internal events CDF value from the 1992 IPE (1.7×10−4 21 per reactor-year) is above the 

22 average and near the maximum of the values reported for other Westinghouse 4-loop plants. 

23 Figure 11.6 of NUREG–1560 (NRC 1997a) shows that the IPE-based total internal events CDF 

for Westinghouse 4-loop plants range from 3×10−6 per year to 2×10−4 24 per year, with an average 

CDF for the group of 6×10−5 25 per year. It is recognized that other plants have updated the values 

26 for CDF subsequent to the IPE submittals to reflect modeling and hardware changes. The 

internal events CDF result for SQN used for the SAMA analysis (3.0×10−5 per year and 3.5×10−5 27

28 per year for Units 1 and 2, respectively) is near the average for other plants of similar vintage.

29 It is noted that the SQN was one of the units analyzed in considerable detail in the 

30 NUREG–1150 analysis of the risk of five nuclear power plants (NRC 1990b). NUREG–1150 

indicated the mean internal events CDF for SQN was 4×10−6 31 per year, which is very similar to 

32 the current TVA estimate. It should be noted, however, that the NUREG–1150 value does not 

33 include internal flooding, which, as seen above, accounts for about 50 percent of the current 

34 CDF estimates.

35 There have been seven (six plus the draft of the initial cutset and fault tree analysis (CAFTA) 

36 model) revisions to the SQN Level 1 model since the 1992 IPE submittal. A listing of the 

37 changes made to the SQN PRA since the original IPE submittal was provided in the ER and in 

38 response to an NRC staff RAI (TVA 2013c, 2013d), as summarized in Table F–3. A comparison 

39 of internal events CDF between the 1992 IPE and the current PRA model indicates a decrease 

of about a factor of five in the total CDF (from 1.7×10−4 per reactor-year to 3.0×10−5 40 and 

3.5×10−5 41 per reactor-year for Units 1 and 2 respectively). This reduction can be attributed to 

42 incorporation of plant-specific data, improved modeling details, and removal of conservatism.
Appendix F

F-7 

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

RA 

Model

Summary of Significant Changes

from Prior Model

CDF (per year) LERF (per year)

Unit 1 Unit 2 Unit 1 Unit 2

1992 

(IPE)

1.7×10−4

(same model)

2.7×10−6

(same model)

1995 

(R1)

Incorporation of a crosstie line from the 480-V Board Room 1A 

to the 480-V Board Room 1B and a crosstie line from 480-V 

Board Room 2A to the 480-V Board Room 2B for 120-V 

alternating current inverters room cooling

Requantification of operator action “Align High-Pressure 

Recirculation, Given Auto Swapover Succeeds” because of 

revision of the procedures and training programs applicable to 

this operator action

Revision of the success criteria for component cooling system

(CCS) Train A 

Removal of CCS mechanical seal cooling requirement for 

successful operation of the safety injection, residual heat 

removal (RHR), and centrifugal charging pumps

3.8×10−5

(same model)

6.1×10−7

(same model)

2000 

(R2)

Modification of steam generator level control valves for the 

turbine-driven auxiliary feedwater pump (TDAFWP) fail open on 

a loss of plant air

Revision of success criteria for bleed and feed cooling to 

require one power operated relief valve (PORV)

Reviewed reactor coolant pump (RCP) seal failure and electric 

power recovery models against current plant and industry data

Review and revision of emergency raw cooling water (ERCW) 

strainer maintenance

Lowering of model quantification cutoff value from 10−9 to 10−12

6.3×10−6

(same model)1

1.1×10−7

(same model)1

2003 

(R3)

Update to human action analysis and error rates

Separation of reactor trip failure (ATWS) and steam generator 

tube rupture into individual event tree modules

Review of various systems analyses to confirm current system 

installation and operation, included necessary changes to 

system modeling or success criteria

Revision of plant compressed air fault trees to address 

replacement of C and D air compressors with new, 

higher-capacity units

1.3×10−5

(same model)1

2.6×10−7

(same model)1

2006 

(R4)

Incorporation of plant-specific data collected by the 

Maintenance Rule program and comments made by the plant 

system engineers

Model changes to permit calculation of Fussel-Vesely 

importance values

Verification, update, and reevaluation of human actions

1.8×10−5

(same model)1

3.9×10−7

(same model)1

2011

Draft

CAFTA2

Complete revision of the Revision 4 model including conversion 

from the RISKMAN software platform into CAFTA–peer 

reviewed February 2011

6.5×10−5 6.3×10−5 2.5×10−6 3.1×10−6
Appendix F

F-8 

RA 

Model

Summary of Significant Changes

from Prior Model

CDF (per year) LERF (per year)

Unit 1 Unit 2 Unit 1 Unit 2

2011 

(PRA 

CAFTA 

R0)2

Created new core damage sequences to account for pressure 

relief for transients 

Performed Bayesian update of basic event probabilities that 

were significant contributors to risk

Reclassified 480 gpm (gallon-per-minute) seal loss-of-coolant 

accidents (LOCAs) as small-break LOCAs

Added requirement for cold-leg accumulators for certain LOCAs

Human-error probabilities were recalculated to account for 

dependency on recovery actions for both cognitive and 

execution steps

Incorporated shutdown board crosstie logic

Revised ERCW success criteria

Added mutually exclusive logic for operator actions to trip RCP

on a loss of offsite power, eliminating erroneous block valve 

isolation events and prohibited CCS test and maintenance 

events

Refined analysis of internal flooding to eliminate overly 

conservative effects and incorporated new Electric Power 

Research Institute standard for pipe rupture frequencies

3.0×10−5 3.6×10−5 4.4×10−6 4.6×10−6

SAMA

Model3

Relatively minor revision to the Level 2 model to (1) ensure 

proper accounting for Level 1 sequences with large 

containment isolation failures in isolation LERF Level 2 

sequences and (2) add success logic of the Level 2 sequences 

and additional top logic to group sequences for the 

quantification of release categories

No changes made to the Level 1 model logic

Higher truncation limit used for both the Level 1 and LERF 

quantification

3.0×10−5 3.5×10−5 5.9×10−6 5.9×10−6

1 The same PRA model was used for both units. 2 CDF truncation of 1×10−12/yr. LERF truncation of 

1×10−13/yr. 3 CDF truncation of 1×10−11/yr. LERF truncation of 

1×10−12/yr.

PRA = Probabilistic Risk Assessment

CDF = core damage frequency

LERF = large early release frequency

IPE = Individual plant examination

R0 = Revision 0; R1 = Revision 1; R2 = Revision 2; 

R3 = Revision 3; R4 = Revision 4

1 The NRC staff considered the peer reviews and other assessments performed for the SQN 

2 PRA, and the potential impact of the review findings on the SAMA evaluation. The most 

3 relevant of these is the peer review of the Draft SQN CAFTA model. The Level 1 and LERF 

4 models in this draft were assessed against the ASME/ANS PRA Standard 

5 (ASME/ANS RA–Sa–2009) (ASME 2009) and Regulatory Guide (RG) 1.200 Revision 2 

6 (NRC 2009a). In the ER TVA quoted the overall conclusions of the peer review as follows:

7 The review of the SQN PRA was completed with the attached documentation. 

8 The outstanding issues primarily pertain to quantification results and 

9 documentation issues. The overall conclusions of the peer review team 

10 regarding the SQN PRA are as follows:

11 • The overall model structure is robust and well-developed, but needs 

12 refinement,

13 • Documentation is thorough, detailed, and well organized such that 

14 comparison with the standard is facilitated,

15 • The processes and tools utilized for the SQN PRA are at the state of the 

16 technology and generally consistent with Capability Category II, and

17 • The PRA maintenance and update program includes all necessary 

18 processes and does a very good job of tracking pending changes.
Appendix F

F-9 

1 The SQN PRA does meet the ASME/ANS PRA Standard. The SQN PRA has 

2 issues which have been documented in Appendix C and should be addressed to 

3 improve the quality of the PRA model.

4 TVA stated that the findings from the peer review have been addressed, incorporated in the 

5 model, and are considered resolved. Changes required as a result of resolving findings were 

6 incorporated into the CAFTA Revision 0 model which was approved on June 3, 2011. In the 

7 ER, TVA provided summaries of the 32 findings and their resolution.

8 The NRC staff reviewed the description and resolution of each of the peer review findings and 

9 asked TVA to respond to several RAIs where the stated resolution was not considered 

10 adequate or needed clarification. Based on the licensee's RAI responses, the staff is satisfied 

11 that the concerns raised in the RAIs have been resolved. The RAIs and the licensee responses 

12 are summarized as follows:

13  With regard to Finding 1-10, the resolution indicates that the Level 2 PRA 

14 model assumes that feedwater (FW) will always be supplied to a ruptured 

15 steam generator if FW is available. In response to an NRC staff RAI to 

16 assess the significance of this assumption, TVA indicated that this 

17 assumption has no impact on the SAMA analysis since no credit is taken for 

18 radionuclide scrubbing for releases from the ruptured steam generator 

19 (TVA 2013c).

20  With regard to Finding 1-14, concerning the inclusion of post-maintenance 

21 test starts in the SQN data set, the resolution is not clear as to whether these 

22 test starts were eliminated from the data used in SAMA PRA or not. In 

23 response to an RAI, TVA confirmed that they had been removed from the 

24 success data used in the SQN data analysis (TVA 2013c).

25  With regard to Finding 1-15, concerning certain deficiencies in the general 

26 transient event tree including: (1) not considering the impact of specific 

27 initiating events like loss of offsite power (LOOP) and loss of DC that may 

28 prevent power-operated relief valve (PORV) operation and challenge the 

29 pressurizer safety valves and (2) the lack of a separate tree for SBO events 

30 results in not addressing the operation of systems such as charging and 

31 auxiliary feedwater (AFW) following power recovery, the resolution addresses 

32 the modeling of PORV and pressurizer safeties but not the latter issue. In 

33 response to an RAI to discuss the impact of not addressing the operation of 

34 systems such as charging and AFW following power recovery, TVA estimated 

that this resulted in a CDF underestimate of approximately 2.5×10−8 35 per year 

36 or 0.08 percent and concluded this impact is negligible with respect to the 

37 CDF and SAMA analysis. This estimate was obtained from the product of the 

38 total frequency of SBO events with successful offsite power recovery and the 

39 conditional core damage probability (CCDP) given an RCP seal LOCA 

40 (TVA 2013c).

41  With regard to Finding 4-3, concerning the inclusion of non-water internal 

42 flooding sources, the resolution indicated that the glycol system was the only 

43 non-water system that could be of concern for internal flooding. In response 

44 to an RAI, TVA indicated that the glycol system was included in the PRA 

45 model but subsequently screened out because of the impacted flood areas 

having a CDF below the 1×10−9 46 per year screening criteria (TVA 2013c).

47 The SQN SAMA model reflects SQN design, component failure, and unavailability data as of 

48 November 30, 2009. In response to an NRC staff RAI, TVA indicated that there were a total of 
Appendix F

F-10

1 17 design changes resulting from TVA’s review of fire-induced multiple circuit faults for 

2 compliance with RG 1.189, Revision 2 (NRC 2009b). Three of these design changes were 

3 determined to affect the SQN internal events PRA model. A sensitivity study indicated that the 

impact on the CAFTA Rev. 0 model result was negligible (approximately 3×10−9 4 per year for 

CDF and 1×10−10 5 per year for LERF (TVA 2013c)). In addition, TVA is installing new Unit 

6 Station Service Transformers (USSTs) for each SQN unit and has replaced Unit 2 steam 

7 generators. TVA indicated that these changes would have minimal impact on the results of the 

SAMA analysis. The impact of the USST change was determined to be 1×10−9 8 per year for 

CDF and 1×10−10 9 per year for LERF (TVA 2013c). While the replacement Unit 2 steam 

10 generators have improved heat transfer characteristics, no change in safety analysis is needed 

11 and thus the change would not be expected to impact the SAMA analysis (TVA 2013c).

12 In response to an NRC staff RAI to identify the systems shared between the two units and to 

13 describe how these systems are modeled and how shared system unavailability is accounted 

14 for, TVA indicated that the emergency raw cooling water (ERCW), B train of the CCW, plant 

15 control air, auxiliary control air, electric power offsite supply and the raw cooling water systems 

16 are shared between units. The SQN PRA is a dual-unit model. For the shared systems, the 

17 models include components of both units, and the system models are combined and 

18 incorporated in the PRA model as appropriate for each unit. The only shared system whose 

19 availability is impacted by a unit outage is the CCS, which was accounted for by flag events. 

20 TVA indicated that all shared systems are modeled with the most restrictive success criteria 

21 based on a dual unit initiating event (TVA 2013c). Based on its review of the LRA and the RAI 

22 response, the staff believes that the unavailability of shared components to be modeled 

23 adequately for SAMA purposes. 

24 In response to an NRC staff RAI on the consideration of influences in the PRA for one plant 

25 from internal flooding occurrences at the other plant, TVA indicated that such effects were 

26 incorporated in the PRA model by using input from an internal flooding database that identifies 

27 all the plant areas impacted by each flood source. In addition, for internal flooding situations 

28 where tripping of the second unit is not required unless there is a subsequent failure to isolate, it 

29 was conservatively assumed that both units were tripped at the start of the event (TVA 2013c).

30 The NRC staff noted in an RAI that, as can be seen from Table F–1, the CDF values for the two 

31 units are in some cases significantly different. In response, TVA described the more significant 

32 reasons for the differences as being:

33  for internal flooding, the difference is caused by the asymmetries in pipe 

34 routing, leading to floods having a greater impact on one unit versus the other 

35 unit, and

36  for the loss of all CCS, the difference is caused by the differing number of 

37 valves that could plug/fail close in the CCS for the two units.

38 The NRC staff also noted in an RAI that the LOOP initiator contributes only 1 to 2 percent to the 

39 CDF while SBO contributes 10 to 13 percent and that the Level 1 importance analysis does not 

40 include any events for failure of the emergency diesel generators (EDGs) and asked TVA to 

41 explain the reasons for this unusual result. In response TVA indicated that most of the SBO 

42 CDF contribution results from internal flooding events that result in loss of both 6.9-kV shutdown 

43 boards and thus an SBO, and that LOOP contributes only about 15 percent of the total SBO 

44 CDF frequency. The EDGs at SQN are of relatively low importance because of the ERCW 

45 success criteria, which for a LOOP requires failure of all ERCW pumps to lead to failure of the 

46 EDGs, leading to an SBO. In addition, SQN has a utility bus that allows, under certain 

47 circumstances, one unit to receive emergency power from the other unit’s EDG (TVA 2013c).
Appendix F

F-11

1 In response to an NRC staff RAI to discuss the modeling of a LOOP, TVA stated that the SQN 

2 PRA did not model a consequential LOOP. TVA provided the results of a study, which indicated 

3 that the risk would increase by 0.3 percent if the consequential LOOP were included 

4 (TVA 2013c). The NRC staff concludes that this would have no impact on the selection of cost5 beneficial SAMAs.

6 As stated above, TVA indicated in the ER that ATWS events make up 12 and 14 percent of the 

7 CDF for the two SQN units. In response to an NRC staff RAI to explain this unusually high 

8 contribution, TVA identified several areas where ATWS modeling in the SAMA PRA resulted in 

9 an overestimation of the ATWS contribution to CDF. In reviewing the ATWS modeling, TVA 

10 concluded that the unfavorable exposure time, the fraction of the operating cycle in which the 

11 amount of pressure relief available is not sufficient to prevent exceeding the design pressure for 

12 the primary system, was erroneously included twice and resulted in the overestimation of this 

13 contribution to CDF. Further, TVA found that a majority of the cutsets involving failure of the 

14 pressure relief valves were caused by battery depletion. Because these are not applicable to an 

15 ATWS, the resulting CDF is overestimated. Also, certain features of the power dependency of 

16 the reactor protection system were found to be in error particularly for internal flooding 

17 sequences. TVA indicated that correcting the modeling in these areas resulted in an ATWS 

18 contribution to CDF of 2 percent for Unit 1 and 2.3 percent for Unit 2 (TVA 2013c). The staff is 

19 satisfied with TVA’s RAI response because TVA’s results are conservative and offset other 

20 non-conservatisms, as discussed below. 

21 In the ER, TVA briefly described the process and procedures for assuring that the PRA models 

22 adequately reflect the as-built and as-operated plant configurations. The PRA Program 

23 procedure delineates the responsibilities of both corporate and site personnel and provides 

24 guidelines for the initiation of, and the data collection for, PRA model updates. The PRA 

25 Procedure implements the PRA Program requirements by elaborating on responsibilities, 

26 establishing the technical qualifications for PRA personnel (analysts), and providing specific 

27 guidance for the PRA update. Overall, they define the process for implementing regularly 

28 scheduled and interim PRA model updates, for tracking issues identified as potentially affecting 

29 the PRA models (e.g., because of changes in the plant, errors or limitations identified in the 

30 model, industry operational experience), and for controlling the model and associated computer 

31 files. The PRA Procedure includes requirements for a review of PRA model updates. Individual 

32 work products (such as a system notebook) are reviewed and checked by a second qualified 

33 PRA analyst after preparation, followed by review and approval by the PRA supervisor. After

34 completion of the update, a review is performed by a technically qualified individual that reviews 

35 changes to the model to ensure that the intent and execution of the change were both accurate 

36 and complete.

37 Given that the SQN internal events PRA model has been peer-reviewed and the peer review 

38 findings were all addressed and that, as discussed above, TVA has satisfactorily addressed 

39 NRC staff questions regarding the PRA resolving the concerns raised by the RAIs, the NRC 

40 staff concludes that the internal events Level 1 PRA model is of sufficient quality to support the 

41 SAMA evaluation.

42 F.2.2.2 External Events

43 As indicated above, the SQN PRA does not include external events. The SAMA submittal cites 

44 the SQN IPEEE to assess the impact of seismic events, internal fire events, and other external 

45 events. The SQN IPEEE was submitted in 1995 (TVA 1995), in response to Supplement 4 of 

46 GL 88-20 (NRC 1991a), and a revised fire analysis was submitted in 1999 (TVA 1999). No 

47 fundamental weaknesses or vulnerabilities to severe accident risk in regard to the external 

48 events were identified in the SQN IPEEE. In a letter dated February 21, 2001 (NRC 2001), the 
Appendix F

F-12

1 NRC staff stated that on the basis of the staff reviews of the PRA and IPEEE submittal, the staff 

2 concludes that TVA’s IPEEE process is capable of identifying the most likely severe accidents 

3 and severe accident vulnerabilities and, therefore, the SQN IPEEE has met the intent of 

4 Supplement 4 to GL 88-20.

5 The SQN IPEEE seismic analysis was a Seismic Margin Assessment (SMA) following NRC 

6 guidance (NRC 1991a, 1991b). The SMA was performed using a Safe Shutdown Equipment 

7 List (SSEL) with plant walkdowns in accordance with the guidelines and procedures 

8 documented in Electric Power Research Institute (EPRI) Report NP–6041–SL (EPRI 1991). 

9 The components on the SSEL were then evaluated for seismic capacity. This evaluation was 

10 based upon a review of the plant’s seismic qualification documentation, development of new 

11 floor response spectra, conducting detailed plant walkdowns and performing selected high 

12 confidence in low probability of failure (HCLPF) calculations. Included in the seismic evaluation 

13 was the integrity of containment isolation systems.

14 The IPEEE submittal (TVA 1995) states:

15 In summary, the equipment reviewed for SQN during the systematic evaluation of 

16 the seismic event proved to be overall rugged in nature and of a sufficient 

17 capacity to provide assurance of continued functionality for the Review Level 

18 Earthquake (RLE). Only the RHR heat exchanger anchorage welding was 

19 reported to have a HCLPF less than the 0.30g prescribed by the RLE, and this 

20 component is presently scheduled to be upgraded as discussed in section 7.1.

21 The IPEEE submittal did not identify any seismic vulnerability beyond five configuration-related 

22 items that had been or were being addressed. Corrective action for four of the five were 

23 completed at the time of IPEEE preparation with corrective action for the fifth, the residual heat 

24 removal (RHR) heat exchanger anchorage, scheduled for implementation in October 1995. The 

25 IPEEE transmittal letter confirmed that the RHR anchorage corrective action had been 

26 completed and identified one additional modification that had been completed. The Phase I 

27 SAMA candidate list discussed in ER Section E.2.2 indicates that all five original corrective 

28 actions have been implemented.

29 In the ER, TVA stated:

30 As originally evaluated, assuming a ground level RLE of 0.3g, the overall plant 

31 HCLPF capacity at SQN was determined to be at least 0.27g. In response to an 

32 NRC request for additional information (RAI), certain components were 

33 reevaluated assuming a RLE defined by a NUREG/CR–0098 spectral shape 

34 anchored to 0.30g at rock. The limiting recomputed component HCLPF values 

35 range from 0.23g to 0.29g.

36 The TVA responses (TVA 2012b) to the Fukushima Near-Term Task Force Report 

37 Recommendation 2.3: Seismic Response Report states that 

38 The statuses of all IPEEE outliers which were not corrected through physical 

39 modification were resolved through re-calculation of the appropriate HCLPF 

40 capacities. The 480V Shutdown Transformers required a minor anchorage 

41 modification. All IPEEE outliers are now resolved and have minimum HCLPF 

42 Capacities above 0.3g.

43 The TVA further indicated that the seismic design of SQN will be further evaluated by the 

44 ongoing Fukushima project requirements (NRC 2012). Also, the improved external flooding 

45 mitigation provided by installing additional equipment to provide secondary FW and reactor

46 coolant system (RCS) makeup to both units, all housed in a hardened bunker building, will 

47 provide mitigation capability for a seismic-event risk reduction (TVA 2013c). The improved 

48 external flood mitigation being planned is discussed in more detail below.
Appendix F

F-13

1 Given that the SMA approach used for the SQN IPEEE seismic assessment does not produce a 

2 CDF, TVA used the results of an August 2010 NRC report, “Generic Issue 199 (GI–199), 

3 Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern 

4 United States on Existing Plants” (NRC 2010) to estimate a seismic CDF. This assessment 

determined that the weakest link model seismic risk for SQN Units 1 and 2 is 5.1×10−5 5 per year. 

6 This is based on a simplified methodology using an SQN plant HCLPF of 0.3g and the 2008 

7 U.S. Geological Survey (USGS) seismic hazards curve. The NRC staff agrees that the use of 

8 this seismic CDF is appropriate for determining the seismic contribution to the external event 

9 multiplier. 

10 The SQN IPEEE internal fire assessment utilized the methodology of the fire-induced 

11 vulnerability evaluation (FIVE) methodology (EPRI 1992). This methodology utilizes a 

12 progressive screening approach consisting of:

13  qualitative screening based on lack of safe shutdown components and lack of 

14 plant trip initiators,

15  initial quantitative screening using area-specific fire frequencies and 

16 assuming all fires engulf the entire fire area, and

17  detailed quantitative screening considering the zone of influence of fires and, 

18 for some areas, fire severity and suppression.

19 In the last step, the main control room was evaluated using the guidance in the EPRI Fire PRA 

20 Implementation Guide (EPRI 1994).

21 Fires inside containment were screened out on the basis of low-combustible loads and limited 

22 safe shutdown equipment and cables in accordance with FIVE guidance. For the quantitative 

23 screening steps CCDPs were determined using the Revision 1 IPE internal events PRA with 

24 increasing refinements concerning the extent of fire damage and recovery actions and a 

screening CDF criteria of 1×10−6 25 per year (TVA 1999).

26 The detailed quantification step initially did not take credit for any equipment not specifically 

27 credited in the SQN Fire Protection Report. This revealed that the results for a large number of 

28 fire areas were overly conservative as no credit was taken for feed-and-bleed cooling. When 

29 credit for feed-and-bleed cooling was taken based on walkdown and cable routing information, a 

30 large number of additional areas were screened out. Subsequently, the analysis was further 

31 refined considering fire severity and the potential for suppression using an event-tree approach. 

32 The fire CDF for each of the fire areas evaluated in the final stage of screening is given in Table 

F–4. All of these had CDFs less than the 1×10−6 33 -per-year screening criteria. The estimated fire 

CDF for these areas is 5.8×10−6 34 per reactor-year (TVA 2013d).

35 The Technical Evaluation Report prepared to support the NRC staff evaluation of the SQN 

36 IPEEE (NRC 2001) concludes that there are several weaknesses in the fire analysis that could 

37 lead to optimistic results. Also, it was observed that the cable spreading room was screened 

38 out because of lack of fire sources, and this resulted in missing important lessons about the 

39 effects of a cable spreading room fire. While this observation appears to be not strictly true 

40 because a cable spreading room fire was analyzed in the SQN IPEEE, the analysis assumed 

41 there was no failure of safe shutdown equipment.

42 In response to an NRC staff RAI to address these weaknesses and observations, TVA indicated 

43 that the first weakness, associated with the application of severity factors that could lead to 

44 double counting the impact of fire suppression, had been adequately addressed in the response 

45 to IPEEE RAI for both SQN and Watts Bar Unit 1, which used the same fire methodology, with 

46 the conclusion that no double counting occurred (TVA 2013c).
Appendix F

F-14

1 For the second weakness, associated with a concern over the potential for incorrectly assuming 

2 independence between human actions in the main control room fire, TVA described the control 

3 room modeling which incorporated control room evacuation with the potential for later recovery. 

4 While involving some human actions, the assessment of these events are CCDPs primarily 

5 involving hardware failures. Considering this and that the time differences between initial 

6 evacuation at 15 minutes and recovery after 60 minutes, TVA concluded that the modeling was 

7 acceptable (TVA 2013c).

8 With regard to the cable spreading room fire, TVA indicated that in the IPEEE an extensive fire 

9 in the cable spreading room is assumed to be not credible because of the lack of fire ignition 

10 sources and the presence of fire detection and suppression capability. The IPEEE analysis is 

11 considered to be a screening analysis. TVA provided in the RAI response another analysis of 

12 the cable spreading room that considered fires of varying severities and credit for the installed 

13 detection and suppression systems, as well as fire brigade response that yielded a fire CDF

14 slightly less than that shown in Table F–4 (TVA 2013c).

15 In response to an NRC staff RAI to assess recent fire research and guidance in 

16 NUREG/CR–6850 (NRC 2005), TVA cited a December 2010 industry assessment (Nuclear 

17 Energy Institute (NEI) 2010) that concluded, “Based on the results and insights from industry 

18 fire PRAs, it has been identified that the methods described in 

19 NUREG/CR–6850/EPRI TR–1011989 contain excess conservatisms that bias the results and 

20 skew insights. While the prior frequently asked question process made some incremental 

21 progress in addressing areas of excessive conservatism, many more remain in need of 

22 enhancement.” TVA indicated that, based on this assessment, the results of initial NUREG/CR–

23 6850 analyses should not be used to draw conclusions about the IPEEE fire risk estimates. 

24 While the NRC staff does not necessarily agree with the conclusions of the NEI assessment, the 

25 staff’s concerns have been resolved as discussed in the following paragraph.

26 In the RAI response, TVA also points out that the fire CDF makes up only a relatively small 

27 portion of the external events multiplier (approximately 10 percent) and thus the multiplier is not 

28 sensitive to changes in the fire CDF (TVA 2013c). The external event multiplier is discussed in 

29 more detail in the last two paragraphs of this subsection. Considering that (1) the SQN fire 

30 model has been reviewed by the NRC staff for the IPEEE, that TVA has satisfactorily addressed 

31 NRC staff RAIs regarding the fire analysis resolving the concerns raised by the RAIs, (2) the 

32 internal events model excluding internal flooding upon which the IPEEE fire CDF is based has a 

CDF (3.4×10−5 per year) that is about three times the current estimate (1.3×10−5 33 per year), and 

34 (3) TVA has made a number of plant modifications to reduce the probability of some 

35 fire-induced multiple spurious operations as described above, the NRC staff concludes that the 

36 IPEEE fire model provides an acceptable basis for identifying and evaluating the benefits of 

37 SAMAs.
Appendix F

F-15

1 Table F–4. Significant Fire Areas at SQN Included in Final Screening Phase and Their 

2 Corresponding CDF

Fire Area Description

Compartment CDF

(per year)

Percent

Contribution1 to 

Unscreened Fire 

CDF

Corridor 9.8×10−7 17

Main Control Room/Control Room 9.3×10−7 16

Corridor 5.5×10−7 9

Unit 2 Auxiliary Instrument Room 3.8×10−7 7

Unit 1 Auxiliary Instrument Room 3.8×10−7 6

Cable Spreading Room (Only or Upper) 3.7×10−7 6

Electrical Equipment Room/Auxiliary Relay Room 3.7×10−7 6

480-V Board Room 1B 3.6×10−7 6

250-V Battery Board Room 1 & 2 and Corridor 2.5×10−7 4

480-V Board Room 2B 2.5×10−7 4

480-V Shutdown Board Room 1B2 1.9×10−7 3

480-V Shutdown Board Room 2A2 1.8×10−7 3

Computer Room 1.6×10−7 3

6.9-kV Shutdown Board Room B 1.5×10−7 3

Mechanical Equipment Room 8.2×10−8 1

Auxiliary Control Room 8.0×10−8 1

250-V Battery Room No. 1 5.7×10−8 1

480-V Shutdown Board Room 1A2 4.5×10−8 1

Personnel and Equipment Access Room 4.4×10−8 1

6.9-kV Shutdown Board Room A 2.0×10−8 <1

480-V Shutdown Board Room 1A1 1.1×10−8 <1

Total 5.8×10−6

1 Percentages were rounded to the nearest whole percent for reporting and may not sum to 100 percent because 

of roundoff error.

3 The SQN IPEEE analysis of high winds, floods, and other external events followed the 

4 recommendations in GL 88-20, Supplement 4. The methodology employed a screening 

5 approach following the criteria of the 1975 Standard Review Plan (SRP). The IPEEE submittal 

6 indicated that the IPEEE evaluation revealed that the plant meets the 1975 SRP criteria for High 

7 Winds, Floods and Transportation and Nearby Facilities Accidents and no recommendations for 

8 plant improvements resulted (TVA 1995). The staff approved this evaluation in the SER on the 

9 IPEEE (NRC 2001).

10 The NRC staff notes that, since 2008 TVA has been updating the flood hazard analyses for a 

11 number of its nuclear sites, including SQN (TVA 2013a), and as a result has made and is 

12 continuing to make a number of improvements to its plants (TVA 2012a). In addition to 

13 analyses and improvements associated with the existing licensing bases, TVA is conducting the 

14 comprehensive flood hazard reanalysis required by the NRC in its letter issued March 12, 2012, 

15 pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Part 50.54(f), to all power 

16 reactor licensees and holders of construction permits in active or deferred status (NRC 2012).
Appendix F

F-16

1 In response to an NRC staff RAI to discuss the recent external flooding developments and 

2 infrastructure plans, TVA indicated in an April 16, 2013, letter (TVA 2013a) as updated by a 

3 July 1, 2013, letter (TVA 2013b) that TVA committed to design and install improved flood 

4 mitigation systems at SQN Units 1 and 2. The installed systems will be in addition to the flood 

5 mode systems currently described in the Sequoyah Nuclear Plant Updated Final Safety 

6 Analysis Report, as supplemented by the improvements described in TVA’s letter dated 

7 June 13, 2012 (TVA 2012a). The flood mitigation systems will incorporate improvements to 

8 flood mitigation at SQN through the installation of new components and may utilize certain 

9 elements of the Fukushima Dai-ichi mitigation equipment (FLEX). The systems will provide for 

10 the following key safety functions for both units:

11  reactor decay heat removal and

12  RCS makeup and criticality control.

13 These systems will be installed in a new hardened structure that will ensure a minimum of 15 ft 

14 of margin above the current probable maximum flood levels. The final building design will

15 include consideration of risk improvements for scenarios other than flooding (TVA 2013a, 

16 2013b, 2013c). The NRC staff notes that these new systems will significantly reduce the risk 

17 associated with external floods and, as well, be expected to reduce the risk from other 

18 external events.

19 As indicated in the ER, a multiplier of 2.9 for Unit 1 and 2.6 for Unit 2 was used to adjust the 

20 internal event risk benefit associated with a SAMA to account for external events. This 

21 multiplier was based on a fire CDF equal to the sum of the fire-zone CDF values in the final 

phase of screening or approximately 5.8×10−6 per year, a seismic CDF of 5.1×10−5 22 per year and 

23 the assumption that other external events are negligible. This results in a ratio of external to 

24 internal event CDFs of 1.9 for Unit 1 and 1.6 for Unit 2 or multipliers of 2.9 and 2.6 for Units 1 

25 and 2, respectively.

26 Given that the SQN IPEEE external events assessments has been reviewed by the NRC staff, 

27 that TVA has satisfactorily addressed NRC staff questions regarding the assessment, and TVA 

28 is committed to design and install improved flood mitigation systems at SQN Units 1 and 2, the 

29 NRC staff concludes that the external events assessments, combined with the results of the 

30 analysis of the impacts of new fire and seismic information, is of sufficient quality to support the 

31 SAMA evaluation.

32 F.2.2.3 Level 2 Fission Product Release Analysis

33 The NRC staff reviewed the general process used by TVA to translate the results of the Level 1 

34 PRA into containment releases, as well as the results of the Level 2 analysis, as described in 

35 the ER and in responses to NRC staff RAI (TVA 2013c). As stated above, the Level 2 SQN 

36 PRA model that forms the basis for the SAMA evaluation is essentially a completely new model. 

37 TVA indicated that the Level 2 model was developed with a focus on the quantification of LERF 

38 but does include the development of other end states (TVA 2013d). The model was based on 

39 enhancements to NUREG/CR–6595 (NRC 2004) and included quantification of containment 

40 threats resulting from high-pressure failure of the reactor vessel and hydrogen 

41 deflagrations/detonations as well as additional detail on the treatment of interfacing-systems 

42 loss-of-coolant accident (ISLOCA) and induced steam generator tube rupture. 

43 The PDSs provide the link between the Level 1 and Level 2 CET analyses. In the PDS 

44 analyses, Level 1 results are grouped together according to characteristics that influence the 

45 accident progression following core damage including: containment bypass or not, RCS

46 pressure and wet or dry steam generator. All Level 1 core damage sequences are directly 
Appendix F

F-17

1 linked into the Level 2 CETs and the PDS bins were used at the various branch points of the 

2 CETs to screen out sequences not applicable to that particular branch (TVA 2013c). 

3 The CETs consisted of 18 questions (or events or nodes), which link each PDS to the 

4 appropriate portion of the CET or determine the appropriate containment failure type and end 

5 state category. This results in seven end state categories, four of which are large early 

6 releases, one each for late releases, small early releases and an intact containment. The CET 

7 end states are then binned into 12 release categories, shown in Table F–2, which represent 

8 similar containment failure modes and release timing and are used in the Level 3 consequence 

9 analysis. The Intact end state is not included as a release category because it is assumed to 

10 have an insignificant impact on the consequences of a severe accident. The frequency of each 

11 release category was obtained by summing the frequency of the individual Level 2 sequences 

12 assigned to each release category.

13 A Modular Accident Analysis Program (MAAP) 4.0.7 model of accident progression was used to 

14 support the Level 2 model development including determining (TVA 2013c): 

15  calculated time to vessel failure,

16  ex-vessel cooling success,

17  seal table–molten core interaction,

18  uncertainty associated with the availability of the ice condenser,

19  modeling of the availability of the containment air recirculation fans,

20  core damage stopping prior to vessel failure,

21  time to hydrogen detonation,

22  hydrogen concentrations,

23  direct containment heating,

24  timing of early containment vessel failure,

25  effectiveness of containment heat removal,

26  base mat melt through timing, and

27  timing of operator action.

28 In the ER, TVA indicated that as the Level 2 model for SQN was developed with a focus on the 

29 quantification of LERF, the quantification of the non-LERF end states is not as accurate as 

30 would be obtained from a more rigorous Level 2 model. Normally, the total of all end state 

31 release frequencies would be equal to the total CDF. For the SQN SAMA model the total of all 

32 release category frequencies, excluding the intact end state, is almost equal to the total CDF for 

33 Unit 1 and about 80 percent of the total CDF for Unit 2 (TVA 2013a). In response to an NRC 

staff RAI, TVA provided the intact end state frequencies (1.45×10−5 per year and 2.38×10−5 34 per 

35 year for Units 1 and 2, respectively) and indicated that the total release category frequency is 

36 between 43 percent and 46 percent higher than the internal event CDF (TVA 2013c).

37 In several places in the ER, the accuracy of the Level 2 model is discussed. In ER 

38 Section E.1.2.1 it is stated:

39 The event tree nodes and split fractions were reviewed to ensure that the 

40 consequences, in terms of release frequencies, would be larger than would be 

41 expected with a fully developed Level 2 model.
Appendix F

F-18

1 and in ER Section E.1.2.3.2

2 Quantification of the SQN SAMA Model results in release frequencies that are 

3 over predicted.

4 In response to an NRC staff RAI to discuss the reasons for the inaccuracies and the over

5 prediction of the release category frequencies, TVA described the steps taken in the SAMA

6 model to improve the accuracy and reduce the over prediction. These included adding 

7 sequence success logic to the CET and correcting the containment isolation logic. TVA 

8 attributed the remaining over prediction to the treatment of success branches within the event 

9 trees and the use of the minimum cutset upper bound approximation in the cutset quantification 

10 process. While this quantification provides a close approximation to the top event probability 

11 when the individual basic events are small (i.e., the rare event approximation), when they are 

12 not small the result is an over prediction of the top event probability (TVA 2013c). The NRC 

13 staff has reviewed TVA’s responses and concludes that the use of these release categories in 

14 the SAMA analyses is acceptable because they are expected to be higher than the true values 

15 and will, therefore, result in a conservative assessment.

16 In response to an NRC staff RAI on the treatment of scrubbed and unscrubbed releases from 

17 steam generator tube ruptures (SGTRs) and the absence of SGTR initiators in the Level 2 

18 importance analysis results (TVA 2013d, ER Section E.1.2.1), TVA indicated that the SQN 

19 SGTR model was based on a model developed by Westinghouse for such events 

20 (WCAP 15955). This model was then modified by crediting additional plant-specific 

21 considerations that applied to SQN. The change that resulted in the biggest difference was the 

22 crediting of the use of manual handwheels to open the steam generator atmospheric relief 

23 valves to depressurize/cooldown the primary side. TVA indicated that the SQN model 

24 incorporates four SGTR initiators, one for each loop. While the modeling of four initiators results 

25 in the individual events being below the importance analysis cutoffs, the NRC staff notes that, 

26 based on the RAI response, the total of all the SGTR initiating events is still below the 

27 importance cutoff. The NRC staff notes that all of the SGTR CDF sequences are included in 

28 Release Category III along with non-SBO ATWS events. This release category takes no credit 

29 for scrubbing of releases. Based on its review of TVA’s submissions, the staff concludes that 

30 this treatment and the erroneously high ATWS frequency, discussed above in Section F.2.2.1, 

31 result in an acceptable inclusion of SGTR events in the SQN SAMA risk and cost-benefit 

32 analysis.

33 In response to the NRC staff RAI to describe the Level 2 modeling of small isolation failures to 

34 show that the potential for large early releases is properly considered for small isolation failure 

35 sequences, TVA provided the results of a sensitivity analysis in which the Release Category V 

36 (small early release) frequency was proportionally redistributed to Release Category I (large 

37 early release caused by early containment failure), Release Category III (large early release

38 caused by containment bypass) and Release Category IV (late containment failure) based on 

39 their relative magnitudes. This resulted in a Release Category V frequency of zero, no change 

40 to Release Category II, and an increase in the frequency of Release Categories I, III, and IV 

41 (TVA 2013c). The results of this sensitivity analysis on the cost benefit of the SAMAs are 

42 described in Section F.6.2 below. In an RAI, the NRC staff noted that in the ER, Release 

43 Category V includes small containment isolation failures and that the frequency of this release 

44 category makes up approximately 10 percent of the total frequency of all release categories and 

45 is larger than the frequency of Release Category I, which is identified as a large early release 

46 (refer to Table F–2 above). It is further noted that, because it is expected that a small isolation 

47 failure would not prevent large early containment failure caused by events such as hydrogen 

48 detonation or direct containment heating, the LERF and resulting risks may be underestimated. 
Appendix F

F-19

1 Source terms for use in the Level 3 consequence analysis are based on the dominant accident

2 sequence that contributes to each release category. The release fractions were determined for 

3 each representative sequence using a spreadsheet version of the SEQSOR computer code. 

4 SEQSOR was used to calculate the release fractions for the NUREG–1150 analysis of 

5 Sequoyah (NRC 1990b). The SEQSOR methodology determines release fractions using a 

6 parametric approach with probabilistic data blocks based on supporting first principle analyses 

7 as well as expert panel judgments. SEQSOR determines the mean release fractions for each 

8 representative sequence that makes up each release category using input release 

9 characteristics describing the representative scenario and parametric data included in the code. 

10 The same data blocks were used in the SEQSOR emulator, except where processes or 

11 equipment that needed to be considered for this analysis were not included in the 

12 NUREG/CR–4551 analyses. TVA states that the SEQSOR emulator was independently 

13 reviewed prior to its use in the Watts Bar Unit 2 analysis of severe accident mitigating design 

14 alternatives (SAMDA) (TVA 2011a, 2011b). The release characteristics used for the SQN 

15 SAMA analysis are provided in response to an NRC staff RAI (TVA 2013c).

16 TVA described the representative sequences for each release category, the basis for their 

17 selection, and their use in determining the input parameters for the SEQSOR methodology, in 

18 response to an NRC staff RAI. That RAI requested TVA to provide a discussion of the 

19 representative accident scenarios used for the determination of the release characteristics for 

20 each of the release categories and the steps taken to ensure that the benefit of a SAMA is not 

21 underestimated for situations in which a SAMA impacts scenarios that could have a lower 

22 (non-dominant) frequency but significantly larger consequence than that for the representative 

23 scenario. The TVA states that the representative accident scenarios were selected based on 

24 the definitions of the release categories and on their frequency contribution to those release 

25 categories. In order to ensure that the effects of SAMAs were not underestimated, the input 

26 parameters for SEQSOR were stated to be conservatively selected for each release category. 

27 The other release characteristics (e.g., time of release, warning time, and release energy) that 

28 were input to WinMACCS were also stated to be conservatively selected (TVA 2013c). Release 

29 timing and duration for each release category were conservatively determined from the results 

30 of MAAP 4.0.7 code analysis. The energy of release for each release category was determined 

31 from the NUREG/CR–4551 analysis of Sequoyah (NRC 1990a).

32 The NRC staff review of this information along with the SEQSOR inputs (TVA 2013c) and the 

33 resulting release category characteristics (TVA 2013d, Table E.1–15) concluded that the 

34 number of release categories, the representative scenarios used and the determination of 

35 SEQSOR inputs is adequate for the Level 2 SAMA analysis.

36 As indicated above, the current SQN Level 2 PRA model is a complete revision of that utilized in 

37 the IPE. In response to an NRC staff RAI regarding the steps taken to ensure the technical 

38 adequacy of the new Level 2 model, TVA indicated that the changes made to the Level 2 model 

39 for the SAMA analysis were documented in a calculation by its contractor (Enercon), and 

40 performed in accordance with their procedures. This calculation was subjected to an internal 

41 review and a separate peer review by an individual with extensive SAMA and Level 2 

42 experience prior to its submittal to TVA for review. All comments were incorporated prior to the 

43 final approval of the calculation. The changes were added to TVA’s model change tracking 

44 program and subsequently were incorporated into the SQN Level 2 Model of Record in 

45 accordance with TVA procedures (TVA 2013c). 

46 From its review of the Level 2 PRA methodology, TVA’s responses to NRC staff RAI, and the 

47 peer review of the LERF portion of the model, the NRC staff concludes that, with the exception 

48 of the treatment of small early releases caused by small isolation failures, the Level 2 PRA as 

49 used in the SAMA analysis provides an acceptable basis for evaluating the benefits associated 
Appendix F

F-20

1 with various SAMAs. The treatment of small early releases because of small isolation failures is 

2 the subject of a sensitivity analysis whose impact on the SAMA analysis is discussed in 

3 Section F.6.2 below.

4 F.2.2.4 Level 3 Consequence Analysis

5 The TVA used the WinMACCS Version 3.6.0 code to determine the offsite consequences from 

6 potential releases of radioactive material (TVA 2013d). As described in Section F.2.1, TVA 

7 considered differences in generated power and adjusted the core inventory from a plant of 

8 similar design, Watts Bar Unit 1, to determine the core inventory for SQN Units 1 and 2.

9 The NRC staff reviewed the process used by TVA to extend the containment performance 

10 (Level 2) portion of the PRA to an assessment of offsite consequences (Level 3 PRA model). In 

11 the Level 3 analysis, release fractions and release categories, discussed in Section F.2.2.3, are 

12 combined with the calculated core inventory to yield a source term of radionuclide releases from 

13 containment to the outside environment. In response to an NRC staff RAI, TVA provided 

14 release category frequencies for the Phase II SAMA candidates (TVA 2013c). Checks 

15 performed by NRC staff using this information are described in Section F.6.2.

16 The TVA presented the major input parameter values and assumptions used in the offsite 

17 consequence analyses in the ER (TVA 2013d, Attachment E). The TVA considered site-specific 

18 meteorological data for the calendar years 2003 through 2005 and selected meteorological data 

19 from 2005 for the analysis as input to the WinMACCS code because they resulted in the highest 

20 release quantities (TVA 2013d, Attachment E). Meteorological data was acquired from the SQN

21 meteorological monitoring system and the U.S. Environmental Protection Agency. 

22 Meteorological data included wind speed, wind direction, atmospheric stability class, 

23 precipitation, and atmospheric mixing heights.

24 In response to an NRC RAI on the source of precipitation data, modeling of precipitation events, 

25 and precipitation influence on calculated doses, TVA provided details and illustrated that the 

26 2005 meteorological data resulted in the highest population dose risk, economic risk, and 

27 modified maximum averted cost-risk (MMACR) for the calendar years of 2003 through 2005 

28 (TVA 2013c). Consistent with guidance in NRC (1990b), plume washout in the last grid interval 

29 was invoked in the calculations performed by TVA. Compared to the average precipitation rates 

30 recorded during precipitation events in 2003 through 2005, TVA selected a significantly greater 

31 precipitation rate for plume washout (TVA 2013c). Because increased precipitation rates 

32 translate into increased population doses and economic costs, NRC staff finds TVA’s 

33 overestimation in precipitation rate for plume washout to be conservative and acceptable. 

34 The TVA estimated missing meteorological data by data substitution. For 1 hour of missing 

35 data, interpolation was performed with valid data immediately before and after the data gap. 

36 For data gaps greater than 1 hour, data were replaced with data from days with similar 

37 meteorological conditions immediately before and after the data gap. In response to questions 

38 on the amount of missing data, TVA indicated that the percentages of missing data were 3.1, 

39 2.6, and 0.8 percent for calendar years 2003 through 2005, respectively. The NRC staff 

40 considers these percentages of missing data to be reasonable and the methods used to 

41 substitute missing data to be acceptable for use in the SAMA analysis. Additionally, the sources 

42 of data and models for atmospheric dispersion used by the applicant are appropriate for 

43 calculating consequences from potential airborne releases of radioactive material. The NRC 

44 staff notes that results of previous SAMA analyses have shown little sensitivity to year-to-year 

45 differences in meteorological data and concludes that the selection of the 2005 meteorological 

46 data for use in the SAMA analysis is appropriate.
Appendix F

F-21

1 The TVA projected population distribution and expected growth within a radius of 80 km (50 mi) 

2 out to the year 2041 and used the areal weighting from the SECPOP2000 Version 3.13.1 code 

3 to populate the spatial elements of the computer model (TVA 2013d, Attachment E). In 

4 response to an NRC staff RAI on estimated population distribution, TVA provided the total 

5 population distribution for year 2011 (TVA 2013c). The TVA reported a total population of 

6 1,190,197 within a radius of 80 km (50 mi). In the ER, the total estimated population for the 

7 year 2041 was 1,537,408, which represents an increase of 29 percent compared to the 

8 population in year 2011. The TVA also used data on Tennessee, North Carolina, Alabama, and 

9 Georgia state tourism to calculate a transient to permanent population ratio to increase the 

10 projected population to account for visitors (TVA 2013d, Attachment E). The NRC staff 

11 considers the methods and assumptions for estimating population reasonable and acceptable 

12 for purposes of the SAMA evaluation.

13 For the 16-km (10-mi) emergency planning zone at SQN, TVA considered information from the 

14 Tennessee Multi-Jurisdictional Regional Emergency Response Plan in its determination of 

15 evacuation delay time and travel speed (TVA 2013d, Attachment E). The response plan 

16 indicated that 100 percent of the population would be prepared to evacuate within 105 minutes 

17 from a potential release, which includes 75 minutes for notification and 30 minutes for 

18 preparation following notification of an evacuation order. For the baseline Level 3 calculation 

19 (TVA 2013d, ER Tables E.1–20 and E.1–21), TVA estimated 95 percent of the population within 

20 the emergency planning zone would evacuate with an evacuation speed of 2.2 meters per 

21 second (TVA 2013d, ER Tables E.1–22 and E.1–23). 

22 In response to an NRC staff RAI on evacuation parameter values, TVA affirmed that the 

23 evacuation assessment considered site-specific conditions for SQN (TVA 2013c). Compared to 

24 the evacuation speed recommended in the Tennessee Multi-Jurisdictional Regional Emergency 

25 Response Plan, TVA reduced the average evacuation speed by a factor of 2 to account for 

26 roadway congestion on local roads with low evacuation capacities. The evacuation speed was 

27 reduced by another factor of 2 to account for anticipated population increases in the 16-km 

28 (10-mi) emergency planning zone during the period of extended operation (TVA 2013c). The 

29 TVA performed sensitivity analyses for different evacuation population fractions and evacuation 

30 speeds. Consequence deviations were found to be small. Specifically, the calculated dose risk 

31 increased by less than 2 percent when the evacuation fraction was reduced from 95 percent to 

32 90 percent (TVA 2013d, ER Table E.1–23), and the dose risk increased by about 6 percent 

33 when the evacuation speed was reduced from 2.2 meters per second to 1.6 meters per second 

34 (TVA 2013d, ER Table E.1–22). As described by TVA, evacuation applies to the emergency 

35 planning zone with a lower population compared to other areas surrounding SQN. The much 

36 larger population outside of the emergency planning zone does not evacuate and accounts for a 

37 majority of the total population dose (TVA 2013c). For these reasons, the total population dose 

38 is not directly proportional to the fraction of individuals in the emergency planning zone who do 

39 not evacuate.

40 In response to an NRC staff RAI on evacuation sensitivity, TVA provided additional information, 

41 which showed relatively small contributions to total population doses from the doses received by 

42 evacuating members of the public in the 16-km (10-mi) emergency planning zone and 

43 substantiated the low sensitivity of the calculated dose risk to the evacuating population fraction 

44 (TVA 2013c). Because TVA used site-specific information, applied more pessimistic (lower) 

45 fractions for the evacuating population in the emergency planning zone compared to guidance 

46 values (NRC 1997b), and considered the effect of population increases on evacuation 

47 parameter values, NRC staff concludes that the evacuation assumptions and analysis are 

48 reasonable and acceptable for the purposes of the SAMA analysis at SQN.
Appendix F

F-22

1 The TVA calculated land values using an economic multiplier with economic data from 2002. 

2 The economic multiplier was based on the slope of the consumer price index between 1970 and 

3 2010. The TVA extrapolated this slope to the year 2041 to obtain an economic multiplier of 

4 2.0329. The TVA compared regional agricultural data from the 2007 U.S. Census of Agriculture 

5 with the generic data in SECPOP2000 code. The TVA found that the generic data 

6 corresponded to higher crop values and selected them for use in the analysis to add 

7 conservatism. The NRC staff accepts the applicant’s approach for price adjustments made to 

8 older land value data and selection of generic crop data when those data would lead to more 

9 conservative results. The NRC staff finds the data sources used by the applicant in the Level 3 

10 analysis to be appropriate for the SAMA analysis. 

11 The TVA estimated present dollar values based on the internal events PRA at SQN. Offsite 

12 economic and offsite exposure costs provided the greatest contributions; together, they 

13 accounted for about 76 percent and 72 percent of the total dollar value for Units 1 and 2, 

14 respectively. For the baseline discount rate of 7 percent, offsite economic costs contributed 

15 about 39 percent to the total dollar value for Unit 1 and 37 percent to the total dollar value for 

16 Unit 2 (TVA 2013d, ER Table E.1–32). Compared to the total dollar value, offsite population 

17 doses contributed about 36 percent for Unit 1 and 35 percent for Unit 2. Onsite exposure, 

18 onsite cleanup, and replacement power costs collectively contributed 24 percent for Unit 1 and 

19 28 percent for Unit 2. Section F.6 provides more detailed information on the cost-benefit 

20 calculation and its evaluation.

21 Based on its review of TVA’s submissions, the NRC staff concludes that TVA’s methodology to 

22 estimate offsite consequences for SQN provides an acceptable basis to assess the risk 

23 reduction potential for candidate SAMAs. Accordingly, the NRC staff based its assessment of 

24 offsite risk on the CDFs, population doses, and offsite economic costs reported by TVA.

25 F.3 Potential Plant Improvements

26 The process for identifying potential plant improvements, an evaluation of that process, and the 

27 improvements evaluated in detail by TVA are discussed in this section.

28 F.3.1 Process for Identifying Potential Plant Improvements 

29 The TVA’s process for identifying potential plant improvements (SAMAs) consisted of the 

30 following elements: 

31  review of industry documents, including NEI 05-01 (NEI 2005) and 12 other 

32 plant SAMA analyses for potential cost-beneficial SAMA candidates,

33  review of potential plant improvements identified in the SQN IPE and IPEEE, 

34 and

35  review of the risk-significant events in the current SQN PRA Levels 1 and 2 

36 models for modifications to include in the comprehensive list of SAMA

37 candidates.

38 Based on this process, an initial set of 309 candidate SAMAs, referred to as Phase I SAMAs, 

39 were identified. In Phase I of the evaluation, TVA performed a qualitative screening of the initial 

40 list of SAMAs and eliminated SAMAs from further consideration using the following criteria:

41  The SAMA is not applicable to SQN.

42  The SAMA has already been implemented at SQN.
Appendix F

F-23

1  The SAMA is similar in nature and could be combined with another SAMA 

2 candidate.

3  The SAMA has an estimated implementation cost in excess of the MMACR.

4  The SAMA is related to non-risk significant systems. 

5  A plant improvement that addresses the intent of the SAMA is already in 

6 progress.

7 Based on this screening, a total of 262 SAMAs were eliminated leaving 47 for further evaluation. 

8 The remaining SAMAs, referred to as Phase II SAMAs, are listed in Tables E.2–1 and E.2–2 of 

9 Attachment E to the ER (TVA 2013d). In Phase II, a detailed evaluation was performed for each 

10 of the 47 remaining SAMA candidates, as discussed in Sections F.4 and F.6. 

11 F.3.2 Review of TVA’s Process 

12 The TVA’s efforts to identify potential SAMAs included explicit consideration of potential SAMAs 

13 primarily for internal events because the current SQN PRA does not include external events. 

14 Potential SAMAs for external events were included based on the SQN IPEEE probabilistic 

15 analysis of internal fires and deterministic analysis of seismic and other external events.

16 The initial SAMA list was developed primarily from the review of generic industry SAMAs 

17 (NEI 2005), as well as SAMAs from 11 previous license renewal applications and the SAMDA 

18 analysis for the Watts Bar Nuclear Power Plant (WBN), Unit 2, operating license application and 

19 the associated generic environmental impact statements. To this list, a number of SAMAs were 

20 added based on improvements identified in the IPE and IPEEE. Finally, SAMAs were added 

21 based on the review of the SQN PRA Level 1 and Level 2 LERF results.

22 The TVA provided a tabular listing of the Level 1 PRA basic event CDF importances down to a 

23 risk reduction worth (RRW) of 1.005. The SAMAs impacting these basic events would have the 

24 greatest potential for reducing risk. An RRW of 1.005 for an event corresponds to a reduction in 

25 CDF of approximately 0.5 percent given 100 percent reliability of a SAMA that eliminates the 

26 basic event. Based on the maximum averted cost-risk (MACR) including external events and 

27 uncertainty (see Section F.6.1), this corresponds to a potential maximum benefit including 

28 uncertainty of $97,000 for SQN Unit 1 and $88,000 for Unit 2. The NRC staff noted in an RAI 

29 that this potentially precludes identifying simple procedure changes that according to ER 

30 Section E.2.3 might cost $50,000. The TVA responded to the RAI by extending the reviews of 

31 the CDF importances down to RRWs corresponding to a benefit of $50,000. No additional 

32 SAMA candidates were identified (TVA 2013c).

33 In response to an NRC staff RAI that noted there were several risk-significant events in the 

34 importance listings for which there were no Phase II SAMAs identified, TVA provided further 

35 information as follows (TVA 2013c):

36  For five events (PTSFD1PMP_0030142, PTSFR1PMP_0030142, 

37 TM_1PMP_003001AS, TM_1PMP0030118A, PMAFD1PMP_00300118) 

38 representing failures and unavailabilities of the turbine-driven and 

39 motor-driven AFW pumps, Phase I SAMA 223 “Improve reliability of AFW 

40 pumps and valves” is identified as an applicable SAMA. This SAMA was 

41 dispositioned as follows:

42 The SQN AFW systems meet reliability and unavailability goals established in the 

43 maintenance rule program. To improve reliability there are initiatives to upgrade 

44 the Terry Turbine Governor Controls and Governor Valve stem material; obtain 

45 spares for MDAFWP, TDAFWP, MDAFWP motor; replace Bailey 550 
Appendix F

F-24

1 transmitters to increase the reliability of holding as found and as left tolerances. 

2 Therefore, implementation of this SAMA is an ongoing process at SQN.

3 In addition, TVA pointed out that the new reactor decay heat removal system that 

4 will be installed to address external flooding issues will significantly reduce the 

5 importance of the listed AFW events.

6  For event AFWOP3, representing the failure of operators to depressurize and 

7 cool down the vessel so that low pressure injection can be used following a 

8 small or medium loss of coolant accident with failure of high pressure 

9 recirculation, three previously implemented Phase I SAMAs to improve the 

10 capacity to cool down and depressurization were described. In addition, two 

11 Phase II SAMAs: 103 (Institute simulator training for severe accident

12 scenarios) and 283 [Initiate frequent awareness training for plant 

13 operators/maintenance/testing staff on important human actions, including 

14 dependent (combination) events, for plant risk] that are applicable to this 

15 event were identified and discussed.

16 The staff noted, for basic events %1RTIE and %1TTIE, representing a general reactor trip and a 

17 turbine trip, respectively, the ER states that Phase II SAMA 218, to increase the reliability of 

18 power supplies, has been evaluated. In response to an NRC staff RAI to discuss the potential 

19 for other SAMAs to reduce the general reactor trip and turbine trip frequency, TVA discussed 

20 the implementation of a trip reduction program focused on these two initiators. TVA estimated 

21 that such a program would result in a decrease in frequency of, at most 20 percent. This 

22 translates into a benefit of approximately $65,000 when 95th percentile uncertainty is 

23 considered. Based on previous TVA experience with the development and implementation of 

24 reliability studies, a trip reduction program is estimated to cost between $550,000 and 

25 $1,250,000. Based on the estimated cost to implement a trip reduction program and the 

26 minimal benefit gained, this potential SAMA would not be cost beneficial (TVA 2013c).

27 TVA also provided and reviewed the basic events with LERF RRWs down to 1.005. All basic 

28 events in the Level 2 LERF listing were reviewed to identify potential SAMAs and all were 

29 addressed by one or more Phase II SAMAs except those that are phenomena-based split 

30 fractions for which no SAMA would be appropriate. The staff notes that because LERF makes 

31 up only about 40 percent of the total cost risk, LERF basic events with RRW less than about 

32 1.006 would not be expected to be cost beneficial unless they are also important to CDF. 

33 For SQN, SGTRs do not appear in the importance analyses results because they are below the 

34 cutoff used to identify risk-significant events to be addressed by SAMAs. The NRC staff notes 

35 that a number of SGTR-related SAMAs were considered by TVA from its review of generic 

36 SAMAs, as well as cost-beneficial SAMAs from other plants’ SAMA analyses. These SAMAs 

37 were either screened out as having been implemented at SQN or having excessive cost or were 

38 included in the Phase II analysis and found to be cost beneficial. Thus, the NRC staff concludes 

39 that, even if the SGTR is more important than shown in the SQN PRA based on the discussion 

40 in Section F.2.2.3, this would not change the SQN determination of cost-beneficial SAMAs.

41 The TVA also considered the potential plant improvements described in the SQN IPE and 

42 IPEEE in the identification of plant-specific candidate SAMAs. The SQN IPE identified 11 

43 enhancements (TVA 1992). The NRC staff review of the Phase I SAMA candidate list during 

44 the April 2013 audit indicated that nine were screened as already implemented, one was 

45 retained for Phase II and one was combined with another SAMA that was retained for Phase II.

46 The SQN IPEEE identified five seismic-related improvements (plus minor maintenance 

47 housekeeping issues) (TVA 1995). The NRC staff review of the Phase I SAMA candidate list 
Appendix F

F-25

1 during the April 2013 audit indicated that all five improvements were listed as having been 

2 implemented.

3 The ER Section E.1.1.1 and the SQN IPEEE Safety Evaluation Report (SER) (NRC 2001) 

4 indicate that the limiting plant component HCLPF is 0.23g. The NRC staff noted that this is less 

5 than the RLE of 0.3g. Further, the Technical Evaluation Report supporting the SER indicates 

6 there are 12 components with HCLPFs below the RLE. While NRC concluded that the SQN 

7 IPEEE meets the intent of GL 88-20, Supplement 4, the result above indicates that there are 

8 some components, which should be examined for the identification of potential cost-beneficial 

9 SAMAs. In response to an NRC staff RAI to discuss the actions taken on these 12 items, the 

10 final HCLPF values, if available, and the potential for cost-beneficial SAMAs for these SQN 

11 components, TVA stated that each of the 12 noted components were re-analyzed. Eleven of 

12 the components met the 0.3g requirement. One component, the 480-V shutdown transformer, 

13 required a minor modification to the anchorage, which is complete. All IPEEE outliers are now 

14 resolved and have minimum HCLPF capacities above 0.3g. Also, TVA indicated that the other 

15 low-margin outliers were reviewed to determine if other minor modifications are possible. No 

16 modifications that might be cost-beneficial were identified (TVA 2013c).

17 As indicated, the SQN IPEEE utilized an SMA, which provided no quantitative risk information 

18 and limited deterministic seismic capacities for SQN systems, structures, or components. It is 

19 thus not possible to identify and evaluate SQN-specific SAMAs to mitigate seismic risk. The 

20 recent seismic walkdowns and reassessment of seismic capacities provided assurance that all 

21 IPEEE outliers are now resolved and have minimum HCLPF capacities above the RLE of 0.3g 

22 (TVA 2012b). In addition, the continuing evaluations in response to Recommendation 2.3 of 

23 The Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident will 

24 provide further opportunities to identify any seismic vulnerabilities at SQN. Given the above and 

25 the NRC staff observation that SAMAs to mitigate the impact of seismic events are expected to 

26 be relatively costly and therefore are not likely to be cost beneficial, the staff concludes that the 

27 exclusion of seismic-specific SAMAs from the License Renewal evaluation is acceptable.

28 In response to an NRC staff RAI, TVA also considered SAMAs for the 14 largest fire risk 

29 contributors based on the IPEEE evaluation, whose results are summarized in Table F–4. 

30 SAMA 287 (Protect, re-route, or modify circuits to upgrade core damage mitigation capability for 

31 fires that result in main control room evacuation) involved reducing the risk from fires in four of 

32 the important fire areas (Unit 1 Auxiliary Instrument Room, Unit 2 Auxiliary Instrument Room, 

33 Main Control Room, and Relay Room). For the other important fire areas, TVA provided an 

34 assessment that indicated the benefit of a SAMA that would eliminate 30 percent of the risk of 

35 the most important fire area would be $26,000. Because this is well below the minimum 

36 estimated hardware cost of $100,000, TVA concluded that cost-beneficial SAMAs for the 

37 individual fire areas would not be expected (TVA 2013c). The NRC staff notes that while this

38 $26,000 value does not include the impact of uncertainty, raising the maximum benefit of 

39 eliminating 30 percent of the risk of the most important fire areas to $65,000 does not change 

40 the conclusion.

41 In response to an NRC staff RAI on the screening criterion for excessive implementation cost 

42 indicated in the ER (TVA 2013d, ER Section E.2.2), TVA indicated that the Phase I screening 

43 on excessive implementation cost did not specifically include the impact of the uncertainty 

44 multiplier. The TVA described an additional review of the Phase I SAMA candidates screened 

45 as having excessive implementation cost that was performed to identify any candidates that 

46 should be reconsidered with the uncertainty multiplier of 2.5 applied. The Phase I candidates 

47 were grouped into categories based on how the potential SAMA would affect the plant. The 

48 categories were SGTR, Injection Capabilities, Containment Response/Venting, Reactor Vessel, 

49 and alternating current (AC)/SBO. A bounding maximum potential benefit was developed for 
Appendix F

F-26

1 each of the categories. These potential benefits, including the uncertainty multiplier, were used 

2 to perform a review of the SAMA candidates that had previously been screened based on high 

3 implementation costs. All those previously screened remained screened considering the 

4 conservative maximum benefit that included the uncertainty (TVA 2013c).

5 At the onsite audit in April 2013, the NRC staff reviewed the Phase I candidate SAMA list. This 

6 review included an assessment of the completeness of the list as well as the Phase I screening 

7 disposition of each candidate SAMA. All of the NRC staff questions were resolved satisfactorily, 

8 and on the basis of this information and the discussions above, the NRC staff concludes that the 

9 set of SAMAs evaluated in the ER, together with those identified in response to NRC staff RAI, 

10 addresses the major contributors to both internal and external event CDF. 

11 The NRC staff questioned the applicant about additional potentially lower-cost or more-effective 

12 alternatives to some of the SAMAs evaluated (NRC 2013). Individual questions and the results

13 of TVA’s responses on the potentially cost-beneficial SAMAs are summarized in Section F.6.2.

14 The NRC staff notes that the set of SAMAs submitted is not all-inclusive, because additional, 

15 possibly even less expensive, design alternatives can always be postulated. However, the NRC 

16 staff concludes that the benefits of any additional modifications are unlikely to exceed the 

17 benefits of the modifications evaluated and that the alternative improvements would not likely 

18 cost less than the least expensive alternatives evaluated, when the subsidiary costs associated 

19 with maintenance, procedures, and training are considered.

20 The NRC staff concludes that TVA used a systematic and comprehensive process for 

21 identifying potential plant improvements for SQN, and that the set of SAMAs evaluated in the 

22 ER, together with those evaluated in response to NRC staff inquiries, is reasonably 

23 comprehensive and, therefore, acceptable. The NRC staff evaluation included reviewing 

24 insights from the SQN plant-specific risk studies that included internal initiating events as well as 

25 fire, seismic and other external initiated events, and reviewing plant improvements considered in 

26 previous SAMA analyses. 

27 The NRC staff also notes that the new improved flood mitigation systems to be installed at SQN 

28 Units 1 and 2, discussed above, would be expected to reduce the risk from all external events 

29 and possibly some internal events. The new systems are, thus, effectively additional SAMAs to 

30 which TVA has committed.

31 F.4 Risk Reduction Potential of Plant Improvements

32 In the ER, the applicant evaluated the risk-reduction potential of the 47 SAMAs that were not 

33 screened out in the Phase I analysis and retained for the Phase II evaluation. The SAMA

34 evaluations were performed using generally conservative assumptions.

35 Except for one SAMA associated with internal fires, TVA used model requantification to 

36 determine the potential benefits for each SAMA. The CDF, population dose, and offsite 

37 economic cost reductions were estimated using the SQN SAMA PRA model for the nonfire 

38 SAMAs. The changes made to the model to quantify the impact of SAMAs are detailed in 

39 Section E.2.3 of Attachment E to the ER (TVA 2013d). Bounding evaluations were performed to 

40 address specific SAMA candidates or groups of similar SAMA candidates. For the fire-related 

41 SAMA 287, the benefit was determined by assuming that the CCDP and the associated CDF for 

42 the four fire compartments involved was reduced by a factor of 10. The evaluation assumed 

43 that all release category frequencies were reduced by the same percentage as CDF. The 

44 reduced CDF and release category frequencies were then used to determine the reduction in 

45 population dose and offsite economic cost in a manner similar to all other SAMAs (TVA 2013c). 

46 The NRC staff notes that the above, as applied by TVA, included increasing the benefit by the
Appendix F

F-27

1 external event multiplier, which is a significant conservatism because the SAMA would only 

2 impact the fire CDF and not the CDF from nonfire internal events or other external events. 

3 Table F–5 includes the assumptions made to estimate the risk reduction for each of the 

4 evaluated SAMAs, the estimated risk reduction in terms of percent reduction in CDF, population 

5 dose risk and OECR, and the estimated total benefit (present value) of the averted risk. The 

6 estimated benefits reported in Table F–5 reflect the combined benefit in both internal and 

7 external events. The determination of the benefits for the various SAMAs is further discussed in 

8 Section F.6.

9 The NRC staff noted in an RAI that for some SAMAs the benefit for the two units is considerably 

10 different (e.g., SAMAs 32 and 68). In response, TVA attributed the differences as being caused 

11 by the differing impacts of internal flooding on the two units (TVA 2013c).

12 The benefit for SAMA 8 (increase training on response to loss of two 120-V AC busses) was 

13 determined by eliminating the inadvertent actuation of safety injection. In response to an NRC 

14 staff RAI to identify any other impacts of the loss of the two busses that would benefit from the 

15 training, TVA indicated that additional analyses, with various assumptions regarding 120-V AC 

16 busses, were performed to assess the benefit of increased training upon loss of two busses. In 

17 most analyses, the averted cost risk exceeded $50,000. Therefore, this SAMA candidate will be 

18 retained by TVA for consideration as a potentially cost-beneficial SAMA (TVA 2013c). 

19 Also, relative to SAMA 8, the NRC staff noted that the RRW for loss of a single 120-V AC bus is 

20 given, but there is no value for the common cause failure of both busses. In response to an RAI 

21 to discuss this omission, TVA responded that loss of an electrical bus is considered to be a 

22 passive event and it is TVA practice not to model common cause failures of passive events. 

23 Further loss of a single 120-V AC bus will cause a reactor trip (TVA 2013c). Given that SAMA 

24 has been retained as a potentially cost-beneficial SAMA and that simultaneous loss of both 

25 120-V AC busses is considered unlikely, the NRC staff determined this issue is resolved for the 

26 SQN SAMA analysis.

27 The NRC staff noted in an RAI that the impact of adding the gas turbine in SAMA 14 was found 

28 to be only a 0.35-percent and 0.1-percent reduction in CDF for Units 1 and 2, respectively. 

29 In response to the RAI to explain why this is so small considering that SBO is about 10 percent 

30 of the CDF, TVA responded that the benefit is small because a majority of SBOs are caused by

31 internal flooding and adding a gas turbine would not mitigate these sequences. Also, the 

32 availability at SQN of a utility bus that allows, under certain circumstances, one unit to receive 

33 emergency power from the other unit’s EDG reduces the importance of emergency power 

34 supplies (TVA 2013c).

35 For SAMA 70 (install accumulators for turbine-driven auxiliary feedwater pump (TDAFWP) flow 

36 control valves), it was indicated that a bounding analysis was performed by eliminating the 

37 failure of the existing flow-control valves. In response to an NRC staff RAI to confirm that this 

38 analysis included the failure caused by lack of air, TVA responded that the analysis assumed 

39 success of the human action to restore the TDAFWP speed control following the initiator and 

40 loss of air. An additional analysis has been performed to completely eliminate all failures of the 

41 AFW-level control valves (including air and human actions) that resulted in a small increase in 

42 benefit. The ER concluded that this SAMA is cost-beneficial based on the original analysis, 

43 hence this increase did not impact the SAMA assessment (TVA 2013c).
F-28

Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN 1 

Percentage risk reductions are presented for CDF, population dose risk (PDR), and OECR. Potentially cost-ben2 

shown in bold. 3 

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percen

Risk Reductio

CDF PDR OECR CDF PDR O

8—Increase training on response to 

loss of two 120-V AC buses

$50,000 <0.1% 0.0% 0.0% >$50,000║

$573 

($1,430) #

<0.1% 0.0% 

Assumption: To assess the benefit of increased training on loss of two 120-V AC buses causing inadvertent actuation sign

actuation of safety injection was removed from the model. In response to an RAI, determined by TVA to be potentially cos

14—Install a gas turbine generator $3,350,000 2.4% $125,000 

($313,000)#

0.1% 1.1% 

Assumption: A new event, failure of the gas turbine generator, was added to the diesel generator supply logic so that failu

generators and failure of the gas turbine generator are required to lose power to the shutdown boards. The failure probab

generator was assumed to be 4.54×10−2.

32—Automatically align emergency 

core cooling system to recirculation†

$2,100,000 13.4% 4.2% 2.9% $458,00 

($1,144,000)#

31.8% 8.9% 

Assumption: A bounding analysis was performed by eliminating the failure of the manual action required to align high-pres

(HARR1) by setting the event to false.

45—Enhance procedural guidance 

for use of cross-tied component 

cooling pumps

$50,000 0.8% 1.1% 1.2% $83,700 

($209,000)#

0.6% 1.1% 

Assumption: The fault trees for the CCW system were modified to reflect that failure of multiple pumps was required to ce

respective heat exchanger train.

46—Add a service water pump $1,043,000 0.7% 1.1% 1.1% $78,700 

($197,000)#

0.3% 0.5% 

Assumption: A new service water pump with failure on demand and fail to run basic events was added to the model unde

gates.
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

Appendix F

F-29

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

55—Install an independent RCP seal 

injection system, with dedicated diesel

$8,233,000 3.0% 4.0% 4.0% $290,000 

($724,000)#

2.4% 2.5% 2.9% $184,000 

($460,000)#

56—Install an independent RCP seal 

injection system, without dedicated 

diesel

$8,233,000 3.0% 4.0% 4.0% $290,000 

($724,000)#

2.4% 2.5% 2.9% $184,000 

($460,000)#

Assumption: The analysis was performed by adding a new seal injection system to the fault tree logic such that RCP seal injection failure would 

require failure of the new system and both centrifugal charging pumps. No power dependencies were included as part of this addition to the 

model.

68—Add a motor-driven FW pump $10,000,000 20.4% 13.1% 11.9% $1,112,000 

($2,781,000)#

33.3% 13.9% 11.6% $1,303,000 

($3,259,000)#

Assumption: A bounding analysis was performed by removing the initiating events for total and partial loss of FW. Additionally, the fault tree was 

modified to include an additional FW pump. The failure probability of the pump was assumed to be 0.05, and no dependencies on power or 

other support system was modeled.¶

70—Install accumulators for 

TDAFWP flow control valves

$256,000 6.1% 4.9% 3.2% $348,000 

($870,000)#

5.12% 5.01% 3.33% $311,000 

($779,000)#

Assumption: A bounding analysis was performed by eliminating the failure of the existing flow control valves.

71—Install a new condensate storage 

tank

$1,710,000 1.2% 2.9% 2.5% $179,000 

($448,000)#

<0.1% 0.0% 0.0% $509 

($1,270)#

Assumption: A bounding analysis was performed by assuming that long term makeup to the tank was always available.

79—Replace existing pilot-operated 

relief valves with larger ones

$100,000 <0.1% 0.0% 0.0% $318 

($796)#

0.0% 0.0% 0.0% $0 

($0)#

Assumption: The analysis was performed by modifying the fault tree logic such that failure to establish RCS bleed with pilot operated relief 

valves using safety injection pumps would require the failure of both pilot operated relief valves instead of just one RCS feed and bleed using 

centrifugal charging pumps currently only requires one pilot operated relief valve to function properly, therefore, no change was made to the fault 

tree logic for feed and bleed using centrifugal charging pumps.

83—Add a switchgear room 

high-temperature alarm 

$100,000 <0.1% 0.0% 0.0% $764 

($1,910)#

<0.1% 0.0% 0.1% $3,990 

($9,970)#

Assumption: A bounding analysis was performed by eliminating the failure of the ventilation fans in the 480-V transformer room, thereby 

maintaining a proper temperature in the room.
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

F-30

Appendix F

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

87—Replace service and instrument 

air compressors with more reliable 

compressors

$886,000* 6.5% 4.2% 2.8% $326,000 

($815,000)#

5.6% 4.3% 2.9% $293,000 

($732,000)#

Assumption: A bounding analysis was performed by eliminating the failure of cooling to the compressors. This includes compressors 

for the auxiliary compressed air system and the compressed air system. In response to an RAI, determined by TVA to be potentially cost 

beneficial.

88—Install nitrogen bottles as 

backup gas supply for safety relief 

valves†

$100,000 3.5% 0.2% 0.2% $78,100 

($195,000)#

3.1% 0.5% 0.2% $79,000 

($198,000)#

Assumption: A bounding analysis was performed by modifying the atmospheric relief valve fault tree logic for all four valves to remove their 

dependence on compressed air.

103—Institute simulator training for 

severe accident scenarios

$8,000,000 5.3% 4.4% 4.9% $372,000 

($930,000)#

6.6% 5.0% 5.5% $397,000 

($993,000)#

Assumption: A bounding analysis was performed by reducing the failure probability of important human actions as well as the dependency 

factors for the important human actions..

105—Delay containment spray 

actuation after a large LOCA

$100,000 6.8% 2.7% 1.8% $257,000 

($641,000)#

16.0% 5.0% 3.8% $539,000 

($1,348,000)#

106—Install automatic containment 

spray pump header throttle valves

$100,000 6.8% 2.7% 1.8% $257,000 

($641,000)#

16.0% 5.0% 3.8% $539,000 

($1,348,000)#

249—High-volume makeup to the 

refueling water storage tank†

$565,000 6.8% 2.7% 1.8% $257,000 

($641,000)#

16.0% 5.0% 3.8% $539,000 

($1,348,000)#

Assumption: A bounding analysis was performed by changing the model so that the refueling water storage tank was always available. This 

included removing refueling water storage tank rupture, as well as failure to deliver flow from the refueling water storage tank to containment 

spray pumps A and B. In addition, the failure probability of the human action to align high-pressure recirculation (HARR1), was decreased by 

half to account for the increased time that the operator would have to perform this action.

109—Install a passive hydrogen control 

system

$3,736,000 <0.1% 14.4% 16.1% $893,000 

($2,232,000)#

0.0% 15.0% 17.0% $811,000 

($2,029,000)#

Assumption: A bounding analysis was performed by eliminating the failure of the existing hydrogen mitigation system from Level 2 

model logic.

111—Install additional pressure or leak 

monitoring instruments for detection of 

ISLOCAs

$190,000 0.1% 0.7% 0.3% $30,100 

($75,300)#

<0.1% 0.7% 0.3% $26,800 

($66,900)#
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

Appendix F

F-31

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

239—Install additional instrumentation 

for ISLOCA detection

$190,000 0.1% 0.7% 0.3% $30,100 

($641,000)#

<0.1% 0.7% 0.3% $26,800 

($66,900)#

Assumption: A bounding analysis was performed by removing the letdown line, RHR legs, RHR pump seal, RHR supply, refueling water storage 

tank piping, safety injection legs, and safety injection pump seals ISLOCA initiating events from the model.

112—Add redundant and diverse limit 

switches to each containment isolation 

valve

$692,000 <0.1% 0.0% 0.0% $255 

($636)#

0.0% 0.0% 0.0% $0 

($0)#

Assumption: A bounding analysis was performed by adding a manual action to the fault tree logic at each containment isolation valve with a 

failure probability of 10−2. 

136—Install motor generator set trip 

breakers in control room

$100,000 0.2% 0.4% 0.3% $25,600 

($64,000)#

0.2% 0.5% 0.3% $22,500 

($56,200)#

137—Provide capability to remove 

power from the bus powering the 

control rods

$100,000 0.2% 0.4% 0.3% $25,600 

($64,000)#

0.2% 0.5% 0.3% $22,500 

($56,200)#

Assumption: A bounding analysis was performed by eliminating the failure of the manual action to trip the reactor using the main control room 

hand switch (HAEB1). Additionally, the probability of failure to trip the reactor, given sold state protection system (HART1) was reduced by half. 

This reduced the probability for failure of this manual action to below the original cognitive error probability, and is thus conservative.

147—Install digital large break 

loss-of-coolant-accident protection 

system

$2,700,000 0.1% 0.0% 0.0% $2,230 

($5,570)#

<0.1% 0.0% 0.0% $1,700 

($4,240)#

Assumption: A bounding analysis was performed by removing the initiating events for large break and medium break LOCAs on each cold leg.

160—Implement procedures for 

temporary heating, ventilation, and 

air conditioning (HVAC)‡

$300,000 9.1% 7.8% 9.1% $665,000 

($1,661,000)#

5.0% 2.3% 2.5% $220,000 

($550,000)#

Assumption: The analysis was performed by adding a human action to provide temporary cooling (failure frequency of 10−1) for the following 

areas given cooler/ventilation failure: turbine-driven auxiliary feedwater pump room; RHR pump rooms A and B; safety injection pump rooms A 

and B, containment spray room; centrifugal charging pump cooler rooms A and B; and space coolers A and B for boric acid transfer pump and 

AFW pumps.
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

F-32

Appendix F

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

161—Provide backup ventilation for the 

EDG rooms

$1,000,000* 0.5% 1.3% 1.1% $81,100 

($203,000)#

0.2% 0.7% 0.6% $38,300

($95,700)#

Assumption: A bounding analysis was performed by eliminating failure of the dampers and exhaust fans which provide ventilation to the EDGs

and electric board room.

167—Provide an independent power 

supply for the air return fans

$100,000 <0.1% 0.0% 0.0% $255 

($636)#

0.0% 0.0% 0.0% $0 

($0)#

Assumption: The analysis was performed by removing the power dependency of the containment fans on the 480-V boards to simulate an 

independent power supply.

188—Implement modifications to the 

compressed air system to increase the 

capacity of the system

$2,782,200 11.2% 5.3% 3.5% $467,000 

($1,167,000)#

9.7% 5.5% 3.8% $424,000 

($1,060,000)#

Assumption: To assess the benefit of increasing the capacity of the system, the failure probability of the compressors and dryers for the 

compressed air and auxiliary compressed air systems was set to zero. The probability of the dyers and compressors being in maintenance was 

also set to zero to represent improved reliability of the system 

215—Provide a means to ensure RCP

seal cooling so that RCP seal LOCAs

are precluded for SBO events

$1,500,000 47.5% 46.2% 54.1% $3,832,000 

($9,580,000)#

38.5% 44.2% 53.2% $3,234,000 

($8,085,000)#

Assumption: This analysis was used to evaluate the change in plant risk from providing a means to ensure RCP seal cooling so that RCP seal 

LOCAs are precluded for SBO events. The analysis was performed by adding an additional seal cooling system to the logic “anded” with the 

existing RCP thermal barrier cooling logic. The new seal cooling system with independent power source was given an unavailability of 0.05 

which is representative of a single pump train system.

218—Improve reliability of power 

supplies to reduce reactor trip 

frequency

$500,000 2.8% 1.8% 2.2% $168,000 

($420,000)#

2.2% 1.8% 2.0% $141,000 

($352,000)#

Assumption: To assess the benefit of replacing or improving power supplies, the failure probabilities of all batteries, battery chargers, buses, 

circuit breakers, and transformers were decreased by ten percent. Additionally, the frequencies of loss of offsite power events because of 

switchyard centered and plant centered events were also decreased by 10 percent.

226—Install a permanent, self-powered 

pump to backup normal charging pump

$2,700,000 3.0% 4.2% 4.2% $303,000 

($757,000)#

2.4% 2.7% 3.0% $193,000 

($483,000)#
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

Appendix F

F-33

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

240—Install permanent dedicated 

generator for normal charging pump

$2,000,000 3.0% 4.2% 4.2% $303,000 

($757,000)#

2.4% 2.7% 3.0% $193,000 

($483,000)#

Assumption: A bounding analysis was performed by eliminating the failure of both centrifugal charging pumps.

254—Install an alternate fuel oil tank 

with gravity feed capability

$150,000 0.2% 0.4% 0.4% $29,100 

($72,800)#

<0.1% 0.2% 0.2% $12,900 

($32,400)#

Assumption: To assess the potential benefit, diesel generator fail to run events (including common cause failures) were decreased by ten 

percent.

268—Perform an evaluation of the 

CCW system/AFW area cooling 

requirements

$313,000 29.5% 26.9% 31.7% $2,269,000 

($5,673,000)#

21.3% 26.0% 31.5% $1,881,000 

($4,704,000)#

Assumption: The analysis was performed by eliminating the failure of the CCW system and AFW space coolers.

275—Install spray protection on 

MDAFWPs and pump space coolers†

$800,000 8.0% 6.9% 8.0% $587,000 

($1,467,000)#

17.8% 8.4% 8.9% $792,000 

($1,979,000)#

Assumption: A bounding analysis was performed by eliminating spray initiators from the MDAFWPs, and space coolers used to cool MDAFWPs.

276—Replace one or more existing 

steam generator atmospheric relief 

valves with a valve of different design or 

manufacturer

$1,233,000 1.6% 0.4% 0.2% $49,300 

($123,000)#

2.0% 0.5% 0.2% $56,200 

($140,000)#

Assumption: A bounding analysis was performed by eliminating all of the common cause failures of steam generator atmospheric relief valves.

277—Improve reliability of control rod 

mechanisms

$1,218,780 1.3% 2.9% 1.7% $156,000 

($391,000)#

1.1% 3.0% 1.7% $139,000 

($348,000)#

Assumption: The analysis was performed by decreasing the probability of control rods failing to insert by an order of magnitude.

278—Improve the reliability of the RHR

pumps and improve maintenance 

procedures to reduce potential for 

common cause failure

$345,000 3.3% 0.7% 0.8% $106,000 

($264,000)#

2.9% 1.1% 1.2% $116,000 

($291,000)#

Assumption: The analysis was performed by decreasing by half the probabilities of RHR pumps failure on demand, fail to run, common cause, 

and unavailability because of maintenance events.
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

F-34

Appendix F

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

279—Improve internal flooding

response procedures and training to 

improve the response to internal 

flooding events

$400,000 5.3% 7.3% 7.1% $520,000 

($1,301,000)#

14.9% 10.0% 9.8% $796,000 

($1,990,000)#

Assumption: The analysis was performed by reducing the overall failure probability of important flooding human actions, with the flood multiplier 

for important human actions reduced by a factor of two.

283—Provide frequent awareness 

training to plant staff on important 

human actions

$345,000 5.3% 4.4% 4.9% $372,000 

($930,000)#

6.6% 5.0% 5.5% $397,000 

($993,000)

#

Assumption: A bounding analysis was performed by reducing the failure probability of important human actions by ten percent. The human error 

probability (HEP) dependency factors for important human actions were also improved by ten percent.

284—Reduce the probability that the 

pressurizer safety relief valves fail to 

reclose following a water pressure relief 

event

$1,566,800 2.40% 0.67% 0.82% $88,900 

($222,000)#

1.8% 0.5% 0.5% $60,900 

($152,000)#

Assumption: A bounding analysis was performed by eliminating the failure of the pressurizer safety relief valves to reseat after a water pressure 

event.

285—Protect important equipment in 

the turbine building from internal 

flooding†

$955,000* 8.8% 5.8% 5.0% $478,000 

($1,196,000)#

7.6% 6.2% 5.3% $439,000

($1,099,000)#

Assumption: The analysis was performed by adding a factor to the flooding initiators that resulted in reduced spray damage to the turbine 

building distribution boards and the raw cooling water pumps to simulate addition of spray shields. The spray shield was given a failure 

probability of 10−3.

286—Install flood doors to prevent 

water propagation in the electric 

board room†,§

$4,695,000* 10.8% 26.0% 22.4% $1,611,000 

($4,028,000)#

9.1% 26.9% 23.5% $1,454,000 

($3,634,000)#

Assumption: The analysis was performed by removing the failure of important equipment from certain floods to simulate watertight doors.

287—Protect, reroute, or modify circuits 

to upgrade core damage mitigation

capability for fires that result in main 

control room evacuation

$2,000,000 5.2% 5.1% 5.2% $398,000 

($994,000)#

4.4% 4.3% 4.4% $308,000 

($771,000)#

Assumption: This SAMA is evaluated by assuming the CCDP for the four fire zones impacted is reduced by an order of magnitude to 7.4×10−3

and the change in risk is proportional to the equivalent change in internal events CDF.
Table F–5. SAMAs Cost/Benefit Analysis for Units 1 and 2 of the SQN (continued)

Appendix F

F-35

Individual SAMA and Assumption

Cost 

Estimate

Unit 1 Percent

Risk Reduction

Unit 1 

Internal and

External 

Benefit

Unit 2 Percent

Risk Reduction

Unit 2 

Internal and

External 

CDF PDR OECR CDF PDR OECR Benefit

288—Install spray protection on CCW

system pumps and CCW

system/AFW space coolers†,§

$1,809,000* 8.9% 9.8% 11.6% $793,000 

($1,982,000)#

6.9% 9.6% 11.4% $669,000 

($1,674,000)#

Assumption: A bounding analysis was performed by eliminating spray initiator events from the CCW system pumps and CCW system/AFW

space coolers fault tree logic.

289—Install backup cooling system

for CCW system/AFW space coolers†

$2,219,000* 21.7% 19.1% 22.6% $1,629,000 

($4,072,000)#

13.7% 16.0% 19.2% $1,164,000 

($2,909,000)#

Assumption: The analysis was performed by adding a backup space cooler to the fault tree logic, such that failure of the existing and backup 

coolers is required for failure of the CCW system and AFW space coolers.

# Value in parentheses represents the larger benefit calculated in the sensitivity analysis (TVA 2013d, Attachment E, Tables E.2-3 and E.2-4) 

* TVA identified that implementation costs could be shared between Units 1 and 2 for this SAMA and considered the combined total averted cost risk from both 

Units 1 and 2 in the cost-benefit evaluation.

† By assessing the sensitivity analysis and the resulting increases in estimated benefits (shown in parentheses), TVA considered the following additional SAMAs 

to be potentially cost beneficial for either one or both of the units: SAMA 32 (Unit 2), SAMA 88 (Units 1 and 2), SAMA 160 (Unit 2), SAMA 249 (Units 1 and 2), 

SAMA 275 (Units 1 and 2), SAMA 285 (Units 1 and 2), SAMA 286 (Units 1 and 2), SAMA 288 (Units 1 and 2), and SAMA 289 (Units 1 and 2).

‡ For the baseline results presented in this table, SAMA 160 was considered potentially cost beneficial for Unit 1 only. However, TVA considered SAMA 160 to 

be potentially cost beneficial for Unit 2 based on the sensitivity results (shown in parentheses).

§ SAMAs 286 and 288 were considered to be potentially cost beneficial; because implementation costs could be shared between Units 1 and 2 and the 

sensitivity analysis results for the combined total averted cost risk from both units (shown in parentheses) exceeded the SAMA implementation cost.

║ Additional analyses performed by TVA for the loss of two busses indicated that averted cost risk could exceed $50,000 (TVA 2013c). 

¶ TVA clarified that although the intent of this SAMA was to increase the availability of main FW pumps, the analysis was conservatively performed to increase 

the availability of both main FW pumps and AFW pumps (TVA 2013c).
Appendix F

F-36

1 For SAMA 83 (add a switchgear room high-temperature alarm), it was stated that a bounding 

2 analysis was performed by eliminating the failure of the ventilation fans in the 480-V 

3 Transformer Room, thereby maintaining a proper temperature in the room. In response to an 

4 NRC staff RAI to confirm that this room is the only one impacted by loss of switchgear heating, 

5 ventilation, and air conditioning (HVAC), TVA responded that the 480-V Transformer Room is 

6 the only one impacted by the loss of the switchgear HVAC and that other HVAC improvements 

7 are addressed by SAMA 160 (Implement Procedures for Temporary HVAC) and SAMA 161 

8 (Provide backup ventilation for the EDG rooms, should their normal HVAC supply fail) 

9 (TVA 2013c). 

10 For SAMA 103 (institute simulator training for severe accident scenarios), it was stated that a 

11 bounding analysis was performed by reducing the failure probability of important human actions 

12 and that the human error probability (HEP) dependency factors for important human actions 

13 were also improved. In response to an NRC staff RAI to identify the HEPs reduced and the 

14 amount of the reduction, TVA listed the individual human actions and the dependency factors 

15 and indicated that they were each reduced by 10 percent.

16 SAMA 268 (perform an evaluation of the CCS/AFW area cooling requirements) originated from 

17 the SQN IPE and is strictly to perform an analysis of the cooling requirements. In response to 

18 an NRC staff RAI, TVA indicated that if area cooling is found to be required then SAMA 289 

19 (install backup cooling system for the CCS/AFW Space Coolers) would address this 

20 requirement. SAMA 289 was determined to be potentially cost-beneficial in the sensitivity 

21 analyses. If the result of the SAMA 268 evaluation is that CCS/AFW cooling is not required then 

22 SAMA 289 would no longer need to be considered (TVA 2013c). 

23 The NRC staff has reviewed TVA’s bases for calculating the risk reduction for the various plant 

24 improvements and concludes, with the above clarifications, that the rationale and assumptions 

25 for estimating risk reduction are reasonable and generally conservative (i.e., the estimated risk 

26 reduction is higher than what would actually be realized). Accordingly, the NRC staff based its

27 estimates of averted risk for the various SAMAs on TVA’s risk reduction.

28 F.5 Cost Impacts of Candidate Plant Improvements

29 The TVA estimated the costs of implementing the 47 Phase II SAMAs through the use of other 

30 licensees’ estimates for similar improvements and the development of site-specific cost 

31 estimates where appropriate.

32 The TVA indicated the following cost ranges were utilized based on the review of previous 

33 SAMA applications and an evaluation of expected implementation costs at SQN.

Type of Change Estimated Cost Range

Procedural only $50K

Procedural change with engineering or training required $50K to $200K

Procedural change with engineering and testing or training required $200K to $300K

Hardware modification $100K to >$1,000K

34 TVA stated that the SQN site-specific cost estimates were based on the engineering judgment 

35 of project engineers experienced in performing design changes at the facility and were 

36 compared, where possible, to estimates developed and used at plants of similar design 

37 and vintage.
Appendix F

F-37

1 In response to an NRC staff RAI to provide further information as to what was included in the 

2 SQN cost estimates, TVA indicated that the cost estimates were done in 2012 dollars and 

3 included contingency costs and capital overhead. Cost estimates from past projects were used 

4 when applicable. For cost estimates that were not based directly on past projects, itemized cost 

5 estimates were developed, where applicable and appropriate. Specific hardware costs from 

6 recent projects such as piping, valves, electrical cable, and switchgear were used when 

7 applicable. Engineering estimates were based on typical man-hours costs for design changes. 

8 Training costs were developed based on the man-hours needed to prepare operator training 

9 materials. Cost input was received from the electrical, mechanical, and civil disciplines as 

10 required. The cost estimates were reviewed by the project manager or the discipline 

11 engineering managers (or both), when warranted. Replacement power, lifetime maintenance, 

12 escalation and inflation were not considered in the estimate (TVA 2013c).

13 In response to an NRC staff RAI to discuss how sharing the engineering and design costs 

14 between the two SQN units would affect the cost-benefit analysis, TVA indicated that, as stated 

15 in the ER, for plant modifications that would provide benefit to both units (e.g., SAMA 286: 

16 Install Flood Doors to Prevent Water Propagation in the Electric Board Room), the averted cost 

17 risk from Units 1 and 2 were combined to provide a total averted cost risk for the plant. Thus, 

18 the implementation costs for these SAMAs were assumed to be shared between the two units. 

19 In the response, TVA indicated that the other Phase II SAMAs found not to be cost beneficial in 

20 the base analysis fall into three categories as follows:

21 (1) The SAMAs were found to be cost beneficial in the sensitivity analysis and the 

22 sharing of costs is not an issue.

23 (2) The combined internal and external benefit, including uncertainty for the two units, is 

24 less than the single unit estimated cost, and therefore, cost sharing is not an issue.

25 (3) Five Phase II SAMA candidates do not fall into either of the categories above. They 

26 are SAMA 109 (install a passive hydrogen control system), SAMA 136 (install motor 

27 generator set trip breakers in control room), SAMA 137 (provide capability to remove 

28 power from the bus powering the control rods), SAMA 218 (improve reliability of 

29 power supplies to reduce reactor trip), and SAMA 278 (improve reliability of the RHR 

30 pumps and improve maintenance procedures to reduce potential for common cause 

31 failure). 

32 For SAMA 109, the combined 95th percentile benefit only slightly (14 percent) 

33 exceeds the single unit estimated cost and TVA judges that cost sharing would not 

34 be sufficient to make this SAMA cost beneficial. For SAMAs 136 and 137 the 

35 combined 95th percentile benefit only slightly (20 percent) exceeds the single unit 

36 estimated cost. For these SAMAs the implementation cost was originally based on 

37 the minimum hardware cost of $100,000. Upon further review TVA concluded that 

38 the actual cost would be greater than $100,000 and that neither SAMAs 136 nor 137 

39 would be cost beneficial even if the costs were 100-percent shared. For SAMA 218, 

40 TVA estimated that approximately 75 percent of the implementation cost involved 

41 hardware and unit-specific costs that could not be shared. This resulted in 

42 SAMA 218 not being cost beneficial even at the 95th percentile benefit. For 

43 SAMA 278, TVA indicated that, while a large portion of the implementation cost could 

44 be shared, the likelihood is that some hardware costs would be required. In addition, 

the benefit calculation conservatively assumed that all the fail-to_ 45 run, fail-to-start, 

46 common-cause, and unavailability-caused-by-maintenance events for all of the RHR 

47 pumps could be reduced by 50 percent. Given this, TVA considered that this SAMA 

48 may be potentially cost beneficial if a significant portion of the cost could be shared. 
Appendix F

F-38

1 However, TVA stated that the planned modification to improve external flooding 

2 mitigation, which includes an additional train of decay heat removal, will significantly 

3 reduce the benefit of this SAMA to the point where it would not be expected to be 

4 cost beneficial (TVA 2013c).

5 Based on the foregoing, the NRC staff concludes that the potential impact of cost sharing 

6 between SQN units has been adequately explored and no change in the cost-beneficial status 

7 of the Phase II SAMAs would be expected because of potential cost sharing.

8 The NRC staff reviewed the applicant’s cost estimates, presented in Tables E.2-1 and E.2-2 of 

9 Attachment E to the ER. For certain improvements, the NRC staff also compared the cost 

10 estimates to estimates developed elsewhere for similar improvements, including estimates 

11 developed as part of other licensees’ analyses of SAMAs for operating reactors.

12 The staff noted in an RAI that for SAMA 188 (implement modifications to the compressed air 

13 system to increase the capacity of the system) the cost estimate is $2,800,000 compared to 

14 $900,000 for SAMA 87 (replace the service and instrument air compressors with more reliable 

15 compressors). TVA responded that the reason for the higher cost is because of the higher 

16 capacity of the SAMA 188 replacement compressors compared to the SAMA 87 replacement 

17 compressors, which were taken to be the same size as the originals but with air cooling instead 

18 of service water cooling (TVA 2013c).

19 The NRC staff noted that for two SAMAs (161 and 284), the source of the cost estimates in ER 

20 Tables E.2-1 and E.2-2 was stated to be the minimum hardware cost of $100,000. The staff 

21 also noted that the actual estimated costs given in those same tables for those SAMAs were

22 $1,000,000 and $1,566,800 (respectively). The staff asked the applicant to explain this 

23 discrepancy. The applicant explained that the stated minimum hardware cost was an error; the 

24 correct costs were estimated by SQN to be $1,000,000 for SAMA 161 and $1,566,800 for 

25 SAMA 284. (TVA 2013c).

26 With the above clarifications, NRC staff concludes that the cost estimates provided by TVA are 

27 sufficient and appropriate for use in the SAMA evaluation.

28 F.6 Cost-Benefit Comparison

29 The TVA’s cost-benefit analysis and the NRC staff’s review are described in the 

30 following sections.

31 F.6.1 TVA’s Evaluation 

32 The methodology used by TVA was based primarily on NRC’s guidance for performing 

33 cost-benefit analysis (i.e., NUREG/BR–0184, Regulatory Analysis Technical Evaluation 

34 Handbook (NRC 1997b)). As described in Section E.1.5.4 of the ER (TVA 2013d), the MMACR 

35 was determined for each SAMA according to the following formula, which the staff accepts as 

36 mathematically equivalent to the formula in the NUREG/BR–0184:

37 MMACR = EEM (WPHA + WEA + WO + WCD + WRP) 

38 where

39 EEM = external event multiplier (unitless)

40 WPHA = present value of averted offsite exposure cost ($)

41 WEA = present value of averted offsite economic cost ($)

42 WO = present value of averted onsite exposure cost ($)
Appendix F

F-39

1 WCD = present value of averted onsite cleanup cost ($) 

2 WRP = present value of averted replacement power cost ($)

3 The TVA’s derivation of each of the associated costs is presented separately in this section. 

4 For each SAMA, the applicant’s analysis determined percentage reductions in population dose

5 risk (PDR%), offsite economic cost risk (OECR%), and onsite cost risk (OCR%). The internal 

6 and external benefit from the implementation of an individual SAMA is determined from these 

7 percentage reductions and their associated present value costs according to the following 

8 formula:

9 SAMA Benefit = EEM [(PDR%WPHA + OECR%WEA + OCR% (WO + WCD + WRP)] 

10 For each SAMA, the estimated benefit is compared to the cost of implementation. If the cost of 

11 implementing the SAMA is larger than the benefit associated with the SAMA, the SAMA is not 

12 considered to be cost beneficial. If the cost of implementing the SAMA is smaller than the 

13 benefit associated with the SAMA, the SAMA is considered to be cost beneficial.

14 Sensitivity analyses performed by the applicant can lead to increases in the calculated benefits. 

15 Two sensitivity cases were developed by TVA: one used a discount rate of 3 percent and 

16 another used an alternative value for failure probability to explicitly account for uncertainty and 

17 include margin into cost-benefit evaluation. Additional details on the sensitivity analysis are 

18 presented in Section F.6.2. 

19 Averted Offsite Exposure Cost (WPHA) 

20 TVA defined WPHA cost as the monetary value of accident risk avoided from population doses 

21 after discounting (TVA 2013d, Attachment E). The WPHA costs were calculated using the 

22 following formula:

23 WPHA = Averted public dose risk (person-rem per year)

24 × monetary equivalent of unit dose ($2,000 per person-rem)

25 × present value conversion given in the equation on p. 5.27 for C when a facility 

26 is already operating (NRC, 1997b) 

27 As stated in NUREG/BR–0184 (NRC 1997b), it is important to note that the monetary value of 

28 the public health risk after discounting does not represent the expected reduction in public 

29 health risk because of a single accident. Rather, it is the present value of a stream of potential 

30 losses extending over the remaining lifetime (in this case, the 20-year renewal period) of the 

31 facility. Thus, it reflects the expected annual loss caused by a single accident, the possibility 

32 that such an accident could occur at any time over the renewal period, and the effect of 

33 discounting these potential future losses to present value. For a discount rate of 7 percent and 

34 a 20-year license renewal period, TVA calculated WPHA costs of $968,661 for Unit 1 and 

35 $944,983 for Unit 2 because of internal events (TVA 2013d, ER Table E.1-32).

36 Averted Offsite Economic Cost (WEA)

37 TVA defined WEA as the monetary value of risk avoided from offsite property damage after 

38 discounting (TVA 2013d, Attachment E). The WEA values were calculated using the 

39 following formula:
Appendix F

F-40

1 WEA = Annual offsite property damage risk before discounting in dollars per year

2 × present value conversion given in equation on p. 5.27 for C for an operational 

3 facility (NRC, 1997b) 

4 For a discount rate of 7 percent and a 20-year license renewal period, TVA calculated WEA costs 

5 of $1,044,001 for Unit 1 and $1,002,026 for Unit 2 because of internal events (TVA 2013d, ER 

6 Table E.1-32).

7 Averted Onsite Exposure Cost (WO)

8 TVA defined WO as the avoided onsite exposure (TVA 2013d, Attachment E). Similar to the 

9 WPHA calculations, the applicant calculated costs for immediate onsite exposure. Long-term 

10 onsite exposure costs were calculated consistent with guidance in the regulatory analysis 

11 handbook (NRC 1997b), which included an additional term for accrual of long-term doses.

12 TVA derived the values for averted occupational exposure from information provided in 

13 Section 5.7.3 of the Regulatory Analysis Handbook (NRC 1997b). Best estimate values 

14 provided for immediate occupational dose (3,300 person-rem) and long-term occupational dose 

15 (20,000 person-rem over a 10-year cleanup period) were used. The present value of these 

16 doses was calculated using the equations provided in the handbook in conjunction with a 

17 monetary equivalent of unit dose of $2,000 per person-rem, a real discount rate of 7 percent, 

18 and a time period of 20 years to represent the license renewal period. Immediate and long-term 

19 onsite exposure costs were summed to determine WO cost. TVA calculated WO costs of 

20 $11,267 for Unit 1 and $13,357 for Unit 2 because of internal events (TVA 2013d, ER Table 

21 E.1-32).

22 Averted Onsite Cleanup Cost (WCD) 

23 TVA defined WCD as the avoided cost for cleanup and decontamination of the site (TVA 2013d, 

24 Attachment E). The applicant derived the values for WCD based on information provided in 

25 Section 5.7.6 of NUREG/BR–0184, the regulatory analysis handbook (NRC 1997b). 

26 Averted cleanup and decontamination costs were calculated using the following formula:

27 WCD = Annual CDF × present value of cleanup costs per core damage event × present 

28 value conversion factor.

29 The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 

the regulatory analysis handbook to be $1.5×109 30 (undiscounted). This value was converted to 

31 present costs over a 10-year cleanup period and integrated over the term of the proposed 

32 license extension. TVA calculated WCD costs of $343,669 for Unit 1 and $407,410 for Unit 2 

33 because of internal events (TVA 2013a, ER Table E.1–32).

34 Averted Replacement Power Cost (WRP) 

35 TVA defined WRP as the avoided costs of replacement power (TVA 2013d, Attachment E). 

36 Long-term replacement costs were calculated using the following formula:

37 WRP = Annual CDF × present value of replacement power for a single event 

38 × factor for remaining service years for which replacement power is required

39 × reactor power scaling factor

40 TVA based its calculations on the net electric output for each SQN unit, specifically 1,148 

41 megawatt-electric (MWe) for Unit 1 and 1,126 MWe for Unit 2, and scaled up from the 910 MWe 

42 reference plant in NUREG/BR–0184 (NRC 1997b). TVA calculated WRP costs of $294,637 for 

43 Unit 1 and $342,590 for Unit 2 because of internal events (TVA 2013a, ER Table E.1–32).
Appendix F

F-41

1 Modified Maximum Averted Cost Risk (MMACR)

2 Using the above equations, TVA estimated the total present dollar value equivalent associated 

3 with completely eliminating severe accidents caused by internal events, referred to as the 

4 MACR, to be about $2,662,235 for Unit 1 and $2,710,366 for Unit 2 (TVA 2013a, ER 

5 Table E.1–32). To account for the risk contributions from external events and yield the internal 

6 and external benefit, TVA selected EEM values of 2.9 for Unit 1 and 2.6 for Unit 2 (TVA 2013d, 

7 Attachment E) as discussed further in Section F.6.2. By multiplying MACR and EEM, TVA 

8 estimated MMACR to be about $7,720,482 for Unit 1 and $7,046,951 for Unit 2 (TVA 2013a, ER 

9 Table E.1–32). As described above in the SAMA benefit formula, components of the MMACR 

10 calculation factor into the benefit determination for individual SAMAs.

11 TVA’s Results

12 If the implementation costs for a candidate SAMA 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 cost beneficial. The TVA’s baseline cost-benefit 

15 analysis identified nine and eight candidate SAMAs as potentially cost-beneficial for Units 1 and 

16 2, respectively. From a sensitivity analysis, TVA identified an additional seven and nine 

17 candidate SAMAs as potentially cost beneficial for Units 1 and 2, respectively. Results of the 

18 cost-benefit evaluation are presented in Table F–5. Considering the results from the baseline 

19 and sensitivity analyses, the full set of potentially cost-beneficial SAMAs for SQN is:

20  SAMA 32 (Unit 2 only): Add the ability to automatically align emergency core 

21 cooling system to recirculation mode upon refueling water storage tank 

22 depletion.

23  SAMA 45 (Units 1 and 2): Enhance procedural guidance for use of cross-tied 

24 component cooling pumps.

25  SAMA 70 (Units 1 and 2): Install accumulators for turbine-driven auxiliary 

26 feedwater pump flow control valves.

27  SAMA 88 (Units 1 and 2): Install nitrogen bottles as backup gas supply for 

28 safety relief valves.

29  SAMA 105 (Units 1 and 2): Delay containment spray actuation after a large 

30 LOCA.

31  SAMA 106 (Units 1 and 2): Install automatic containment spray pump header 

32 throttle valves.

33  SAMA 160 (Units 1 and 2): Implement procedures for temporary HVAC.

34  SAMA 215 (Units 1 and 2): Provide a means to ensure reactor coolant pump 

35 (RCP) seal cooling in order that RCP seal LOCAs are precluded for station 

36 blackout events.

37  SAMA 249 (Units 1 and 2): High-volume makeup to the refueling water 

38 storage tank.

39  SAMA 268 (Units 1 and 2): Perform an evaluation of the component cooling 

40 water system/auxiliary feedwater (CCS/AFW) area cooling requirements.

41  SAMA 275 (Units 1 and 2): Install spray protection on motor-driven AFW 

42 pumps and space coolers.
Appendix F

F-42

1  SAMA 279 (Units 1 and 2): Improve internal flooding response procedures 

2 and training to improve the response to internal flooding events.

3  SAMA 283 (Units 1 and 2): Initiate frequent awareness training for plant 

4 operators/maintenance/testing staff on important human actions, including 

5 dependent (combination) events, for plant risk.

6  SAMA 285 (Units 1 and 2): Protect important equipment in the turbine 

7 building from internal flooding.

8  SAMA 286 (Units 1 and 2): Install flood doors to prevent water propagation in 

9 the electric board room.

10  SAMA 288 (Units 1 and 2): Install spray protection on component cooling 

11 pumps and space coolers.

12  SAMA 289 (Units 1 and 2): Install backup cooling system for CCS and AFW 

13 space coolers.

14 The TVA indicated that these potentially cost-beneficial SAMAs will be considered in the design 

15 process. In the list above, the following SAMAs were identified by TVA to be potentially cost 

16 beneficial because of the resulting increases in estimated benefits from sensitivity 

17 considerations: SAMA 32 (Unit 2), SAMA 88 (Units 1 and 2), SAMA 160 (Unit 2), SAMA 249 

18 (Units 1 and 2), SAMA 275 (Units 1 and 2), SAMA 285 (Units 1 and 2), SAMA 286 (Units 1 and 

19 2), SAMA 288 (Units 1 and 2), and SAMA 289 (Units 1 and 2). Although SAMA 286 (Units 1 

20 and 2) and SAMA 288 (Unit 2) had estimated benefits that did not exceed the individual unit 

21 cost for estimated implementation as shown in Table F–5, these SAMAs were identified as 

22 potentially cost beneficial as a result of TVA’s consideration of shared implementation costs 

23 between Units 1 and 2 and use of the combined total averted cost risk from both Units 1 and 2 

24 in the cost-benefit evaluation. Additional SAMA candidates determined by TVA to be potentially 

25 cost beneficial in response to NRC staff RAI are highlighted in Section F.7.

26 F.6.2 Review of TVA’s Cost-Benefit Evaluation 

27 During its review of the cost-benefit analysis performed by TVA, NRC staff compared the 

28 applicant’s approach with guidance in NUREG/BR–0184 (NRC 1997b) and discount rate 

29 guidelines in NEI 05-01 (NEI 2005). NEI guidance states that two sets of estimates should be 

30 developed for discount rates of 7 percent and 3 percent (NEI 2005). The TVA performed 

31 assessments using both discount rates. The TVA provided a base set of results using a 

32 discount rate of 7 percent and a 20-year license renewal period. For the other types of potential 

33 sensitivity analyses suggested (NEI 2005), NRC staff finds that sensitivity analyses for plant 

34 modifications, peer review findings or observations, and evacuation speed have been 

35 adequately addressed in the baseline analysis, including the applicant’s responses to NRC staff 

36 RAI, as discussed in this appendix. As previously indicated, TVA performed the cost-benefit 

37 evaluation using an analysis time period of 20 years. Because TVA explicitly accounted for 

38 uncertainty in its sensitivity analysis by applying a multiplication factor of 2.5 and the results of 

39 the sensitivity analysis were used to identify additional potentially beneficially SAMAs, NRC staff 

40 finds that an additional sensitivity analysis for a time frame longer than 20 years is not 

41 necessary. Although longer timeframes would increase estimated benefits compared to 

42 baseline results, it is unlikely that influences from a longer timeframe would exceed the factor of 

43 2.5 already considered by TVA. Based on its review of the applicant’s cost-benefit evaluation, 

44 NRC staff determined that the applicant’s approach is consistent with the guidance and 

45 acceptable.
Appendix F

F-43

1 The applicant considered possible increases in benefits from analysis uncertainties on the 

2 results of the SAMA assessment. In the ER (TVA 2013d, Attachment E), TVA indicated that the 

95th 3 percentile value of the SQN CDF was greater than the mean CDF by a factor of 2.14 for 

4 Unit 1 and by a factor of 2.26 for Unit 2. A multiplication factor of 2.5 was conservatively 

5 selected by the applicant to account for uncertainty. This multiplication factor was applied in 

6 addition to separate multiplication factors of 2.9 and 2.6 for CDF increases caused by external 

7 events at Units 1 and 2, respectively (TVA 2013d, Attachment E). The TVA’s assessment 

8 accounted for the potential risk-reduction benefits associated with both internal and external 

9 events. NRC staff considers the multipliers of 2.5 for uncertainty at both units, 2.14 for external 

10 events at Unit 1, and 2.26 for external events at Unit 2 provide adequate margin and are 

11 acceptable for the SAMA analysis. Because SQN is a two unit plant, the applicant identified 

12 SAMAs for which implementation costs could be shared between Units 1 and 2 and considered 

13 the combined total averted cost risk in the cost-benefit evaluation. NRC agrees that 

14 consideration of shared costs is appropriate because additional SAMAs can be identified as 

15 potentially cost beneficial.

16 Using TVA information on the release category frequencies (TVA 2013c), NRC staff checked 

17 the calculations of percentage reductions in CDF, population dose risk, and OECR, as well as 

18 the calculations of internal and external benefit for selected SAMA candidates. By applying the 

19 formula for SAMA benefit presented in Section F.6.1 and comparing the results with those 

20 presented in the ER (TVA 2013d, Tables E.2-1 and E.2-2), NRC staff found the results to be in

21 agreement and within small roundoff errors.

22 As discussed above in Section F.2.2.3, TVA’s treatment of small early releases involving small 

23 isolation failures potentially results in an underestimation of the consequences and the benefit of 

24 the SAMAs. A sensitivity analysis was performed by TVA to determine the effect of this 

25 potential underestimation on the SAMA assessment. The results of this analysis indicated there

26 is an increase in benefit, but this increase did not identify any additional cost-beneficial SAMAs 

27 (TVA 2013c).

28 The TVA’s baseline cost-benefit analysis identified nine and eight candidate SAMAs as 

29 potentially cost-beneficial for Units 1 and 2, respectively. From a sensitivity analysis, TVA 

30 identified an additional seven and nine candidate SAMAs as potentially cost beneficial for 

31 Units 1 and 2, respectively. In response to NRC RAI, TVA identified four additional SAMA

32 candidates as potentially cost beneficial for both units. These additional cost-beneficial SAMAs 

33 arose from the NRC evaluation of the baseline analysis for SAMAs 8 and 87 as well as from 

34 questioning from NRC staff on potentially lower cost alternatives. Specifically, NRC staff asked 

35 the applicant to evaluate potentially lower-cost alternatives to several candidate SAMAs 

36 (NRC 2013), as summarized below:

37  Automate the tripping of RCPs on loss of CCW for basic event HASE2 (and 

38 others) involving RCP seal cooling failures.

39  Opening doors and/or stage portable fans for SAMA 289 involving installing 

40 backup cooling for the component cooling water system (CCS)/AFW space 

41 coolers.

42  Installing spray shields for events %690.0-A01-1_067_S and 

43 %669.0-A01_067_S representing the initiator for ERCW spray events in room 

44 690.0-A1 and room 669.0-A01 in the auxiliary building.

45  Use portable pump to provide water for the AFW system for SAMA 71 (Install 

46 a new condensate storage tank).
Appendix F

F-44

1  Use temporary ventilation, opening doors, etc. for SAMA 161 (Provide 

2 backup ventilation for the EDG rooms, should their normal HVAC supply fail).

3  Purchase or manufacture a “gagging device” that could be used to close a 

4 stuck-open steam generator safety valve for a SGTR event prior to core 

5 damage.

6 In its response to these questions (TVA 2013c), TVA determined (1) automatically tripping the 

7 RCP on loss of CCW as well as (2) manufacturing a gagging device for a steam generator 

8 safety valve and developing a procedure or work order for closing a stuck-open valve would be 

9 considered as potentially cost beneficial SAMAs. The TVA response for the other alternatives

10 included additional discussion on the relationship to other SAMA candidates, future design 

11 changes to improve the external flood mitigation, and cost-benefit justifications. From its review 

12 of the original SAMA analysis and additional information, the NRC staff agrees with TVA’s

13 disposition of the above lower cost alternatives.

14 F.6 Conclusions

15 TVA considered 309 candidate SAMAs based on risk-significant contributors at SQN from 

16 updated probabilistic safety assessment models, SAMA-related industry documentation, 

17 plant-specific enhancements not in published industry documentations, and its review of SAMA 

18 candidates from potential improvements at twelve other plants. Phase I screening reduced the 

19 list to 47 unique SAMA candidates by eliminating SAMAs that were not applicable to SQN, had 

20 already been implemented at SQN, were combined into a more comprehensive or plant-specific 

21 SAMA, had excessive implementation cost, had a very low benefit, or related to in-progress 

22 implementation of plant improvements that address the intent of the SAMA.

23 For the remaining SAMA candidates, TVA performed a cost-benefit analysis with results shown 

24 in Table F–5. The baseline cost-benefit analysis identified nine and eight candidate SAMAs as 

25 potentially cost beneficial for Units 1 and 2, respectively. From a sensitivity analysis, TVA 

26 identified an additional seven and nine candidate SAMAs as potentially cost beneficial for 

27 Units 1 and 2, respectively. In response to NRC staff RAI, TVA identified four additional SAMA 

28 candidates as potentially cost beneficial for both units. These additional cost-beneficial SAMAs 

29 arose from the NRC evaluation of the baseline SAMA analysis and questioning on potentially 

30 lower-cost alternatives. In response to NRC staff RAI on the SAMA analyses, TVA indicated 

31 that SAMA 8 to increase training on response to loss of two 120-V AC busses and SAMA 87 to 

32 replace service and instrument air compressors with more reliable compressors will be retained 

33 as potentially cost beneficial for both units (TVA 2013c). In its response to questions on 

34 potentially lower-cost alternatives, TVA identified two additional SAMA candidates as potentially 

35 cost beneficial for (1) human actions to automatically trip the RCP on loss of CCW and 

36 (2) manufacturing a gagging device for a steam generator safety valve and developing a 

37 procedure or work order for closing a stuck-open valve (TVA 2013c).

38 As mentioned in Section F.3.2, the new improved flood mitigation systems to be installed at 

39 SQN Units 1 and 2 would be expected to reduce the risk from all external events and possibly 

40 some internal events. These new systems are additional plant improvements to which TVA has 

41 separately committed (TVA 2013a) as part of SQN’s current licensing basis. 

42 NRC staff reviewed TVA’s SAMA analysis and concludes that, subject to the discussion in this 

43 appendix, the methods used and implementation of the methods were sound. On the basis of 

44 the applicant’s treatment of SAMA benefits and costs, NRC staff finds that the SAMA 

45 evaluations performed by TVA are reasonable and sufficient for the license renewal submittal.
Appendix F

F-45

1 The staff concurs with TVA’s conclusion that 20 candidate SAMAs are potentially cost beneficial 

2 for SQN Unit 1 and 21 candidate SAMAs are potentially cost beneficial for SQN Unit 2, which 

3 was based on generally conservative treatment of costs, benefits, and uncertainties. This 

4 conclusion of a moderate number of potentially cost-beneficial SAMAs is consistent with a 

5 moderately large population within 80 km (50 mi) of SQN and moderate level of residual risk 

6 indicated in the SQN PRA. Because the potentially cost-beneficial SAMAs do not relate to 

7 aging management during the period of extended operation, they do not need to be 

8 implemented as part of license renewal pursuant to 10 CFR Part 54.

9 F.7 References

10 [ASME and ANS] American Society of Mechanical Engineers and American Nuclear Society.

11 2009. Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency 

12 Probabilistic Risk Assessment for Nuclear Power Plant Applications. New York City, NY: ASME. 

13 ASME/ANS RA-Sa-2009. February 2, 2009.

14 [EPRI] Electric Power Research Institute. 1991. A Methodology for Assessment of Nuclear 

15 Power Plant Seismic Margin. Rev. 1. Palo Alto, CA: Jack R. Benjamin and Associates, 

16 Inc., et al. NP-6041-SL. August 1991.

17 [EPRI] Electric Power Research Institute. 1992. Fire-Induced Vulnerability Evaluation (FIVE). 

18 Palo Alto, CA: Professional Loss Control, Inc. TR-100370. April 1992.

19 [EPRI] Electric Power Research Institute. 1994. EPRI Fire PRA Implementation Guide. Draft. 

20 Palo Alto, CA: Parkinson, W.J., et al. EPRI Report Project 3385-01. January 1994.

21 [NEI] Nuclear Energy Institute. 2005. Severe Accident Mitigation Alternative (SAMA) Analysis 

22 Guidance Document. Rev. A. Washington, DC: NEI. NEI 05-01. November 2005. Agencywide 

23 Documents Access and Management System (ADAMS) No. ML060530203.

24 [NEI] Nuclear Energy Institute. 2010. Roadmap for Attaining Realism in Fire PRA. Washington, 

25 DC: NEI. December 2010. ADAMS No. ML110210990.

26 [NRC] U.S. Nuclear Regulatory Commission. 1988. Individual Plant Examination for Severe 

27 Accident Vulnerabilities. Generic Letter 88-20. November 23, 1988. ADAMS No. ML031470299.

28 [NRC] U.S. Nuclear Regulatory Commission. 1990a. Evaluation of Severe Accident Risks:

29 Sequoyah, Unit 1. Vol. 5, Rev. 1, Part 1. Washington, DC: NRC. NUREG/CR–4551, 

30 SAND86-1309. December 1990. ADAMS No. ML070540074.

31 [NRC] U.S. Nuclear Regulatory Commission. 1990b. Severe Accident Risks: An Assessment for 

32 Five U.S. Nuclear Power Plants. Washington, DC: NRC. NUREG–1150. ADAMS 

33 Nos. ML040140729 and ML120960691.

34 [NRC] U.S. Nuclear Regulatory Commission. 1991a. Individual Plant Examination of External 

35 Events (IPEEE) for Severe Accident Vulnerabilities. Washington, DC: NRC. Generic Letter 

36 No. 88-20, Supplement 4. June 28, 1991. ADAMS No. ML031150485.

37 [NRC] U.S. Nuclear Regulatory Commission. 1991b. Procedural and Submittal Guidance for the 

38 Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities. 

39 Washington, DC: NRC. NUREG–1407. May 1991. ADAMS No. ML063550238.

40 [NRC] U.S. Nuclear Regulatory Commission. 1995. Letter from David E. LaBarge to Oliver D. 

41 Kingsley, TVA. Subject: Review of Sequoyah Nuclear Plant Individual Plant Examination 

42 Submittal (TAC No. M74468 and M74469). May 15, 1995.
Appendix F

F-46

1 [NRC] U.S. Nuclear Regulatory Commission. 1997a. Individual Plant Examination Program:

2 Perspectives on Reactor Safety and Plant Performance Parts 2–5 Final Report. Vol. 2.

3 Washington, DC: NRC. NUREG–1560. December 31, 1997. ADAMS No. ML0635550228.

4 [NRC] U.S. Nuclear Regulatory Commission. 1997b. Regulatory Analysis Technical Evaluation 

5 Handbook. Washington, DC: NRC. NUREG/BR–0184. ADAMS No ML050190193.

6 [NRC] U.S. Nuclear Regulatory Commission. 2001. Letter from Ronald W. Hernan to 

7 J.A. Scalice, TVA. Subject: Sequoyah Nuclear Plant, Units 1 and 2—Review of Sequoyah 

8 Individual Plant Examination of External Events Submittal (TAC No. M83674 and M83675).

9 February 21, 2001.

10 [NRC] U.S. Nuclear Regulatory Commission. 2004. An Approach for Estimating the Frequencies 

11 of Various Containment Failure Modes and Bypass Events. Rev. 1. Washington, DC: NRC. 

12 NUREG/CR–6595. October 2004.

13 [NRC] U.S. Nuclear Regulatory Commission. 2005. EPRI/NRC-RES Fire PRA Methodology 

14 for Nuclear Power Facilities. Vols. 1 and 2. Washington, DC: NRC. NUREG/CR–6850.

15 September 2005. ADAMS Nos. ML052580075 and ML052580118.

16 [NRC] U.S. Nuclear Regulatory Commission. 2009a. An Approach for Determining the 

17 Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities. 

18 Regulatory Guide 1.200, Rev. 2. March 2009. ADAMS No. ML090410014.

19 [NRC] U.S. Nuclear Regulatory Commission. 2009b. Fire Protection for Nuclear Power Plants. 

20 Regulatory Guide 1.189, Rev. 2. October 2009. ADAMS No. ML092580550.

21 [NRC] U.S. Nuclear Regulatory Commission. 2010. NRC Information Notice 2010-18: Generic 

22 Issue 199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central and 

23 Eastern United States on Existing Plants. Washington, DC: NRC. September 2, 2010. ADAMS 

24 No. ML101970221.

25 [NRC] U.S. Nuclear Regulatory Commission. 2012. Letter from Eric J. Leeds to All Power 

26 Reactor Licensees. Subject: Request for information pursuant to Title 10 of the Code of Federal 

27 Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task 

28 Force Review of Insights from the Fukushima Dai-ichi Accident. March 12, 2012. ADAMS 

29 No. ML12053A340.

30 [NRC] U.S. Nuclear Regulatory Commission. 2013. Letter from David Drucker to J.W. Shea, 

31 TVA. Subject: Revised requests for additional information for the environmental review of the 

32 Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application. June 7, 2013. ADAMS 

33 No. ML13136A358.

34 [TVA] Tennessee Valley Authority. 1992. Letter from Mark O. Medford to U.S. NRC Document 

35 Control Desk. Subject: Sequoyah Nuclear Plant (SQN)—Response to Generic Letter 

36 (GL) 88-20, “Individual Plant Examination for Severe Accident Vulnerabilities”—10CDF50.54(f).

37 September 1, 1992. Available via the NRC Public Document Room by e-mail to 

38 pdr.resource@nrc.gov. 

39 [TVA] Tennessee Valley Authority. 1995. Letter from R.H. Shell to U.S. NRC Document Control 

40 Desk. Subject: Sequoyah Nuclear Plant (SQN)—Generic Letter (GL) 88-20, Supplement 4, 

41 “Individual Plant Examinations of External Events (IPEEE) for Severe Accident Vulnerabilities”—

42 10CDF50.54(f). June 29, 1995. Available via the NRC Public Document Room by e-mail to 

43 pdr.resource@nrc.gov. 
Appendix F

F-47

1 [TVA] Tennessee Valley Authority. 1998. Letter from Pedro Salas to U.S. NRC Document 

2 Control Desk. Subject: Sequoyah Nuclear Plant (SQN)—Update to Generic Letter (GL) 88-20, 

3 “Individual Plant Examinations for Severe Accident Vulnerabilities”—10CDF50.54(F)—Revised 

4 Individual Plant Examination. February 20, 1998. Available via the NRC Public Document Room 

5 by e-mail to pdr.resource@nrc.gov. 

6 [TVA] Tennessee Valley Authority. 1999. Letter from Pedro Salas to U.S. NRC Document 

7 Control Desk. Subject: Sequoyah Nuclear Plant (SQN)—Generic Letter (GL) 88-20, 

8 Supplement 4, “Individual Plant Examinations of External Events (IPEEE) for Severe Accident 

9 Vulnerabilities”—10CDF50.54(f)—Revised Response for Internal Fires. September 1, 1999.

10 Available via the NRC Public Document Room by e-mail to pdr.resource@nrc.gov. 

11 [TVA] Tennessee Valley Authority. 2011a. Letter from David Stinson to U.S. NRC Document 

12 Control Desk. Subject: Watts Bar Nuclear Plant (WBN)—Unit 2—Response to Request for 

13 Additional Information Item Numbers 2, 3, 5 and 15 Regarding Severe Accident Management 

14 Alternative Review (TAC MD8203). May 25, 2011. ADAMS No. ML11147A099.

15 [TVA] Tennessee Valley Authority. 2011b. Letter from David Stinson to U.S. NRC Document 

16 Control Desk. Subject: Watts Bar Nuclear Plant (WBN)—Unit 2—Response to Request for 

17 Additional Information Regarding Severe Accident Management Alternative Review (SAMDA) 

18 (TAC MD8203). June 17, 2011. ADAMS No. ML11171A510.

19 [TVA] Tennessee Valley Authority. 2012a. Letter from J.W. Shea to U.S. NRC Document 

20 Control Desk. Subject: Commitments Related to Updated Hydrologic Analysis Results for 

21 Sequoyah Nuclear Plant, Units 1 and 2, and Watts Bar Nuclear Plant, Unit 1. June 13, 2012.

22 ADAMS No. ML12171A053.

23 [TVA] Tennessee Valley Authority. 2012b. Letter from J.W. Shea to U.S. NRC Document 

24 Control Desk. Subject: Tennessee Valley Authority (TVA)—Response to NRC Request for 

25 Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding the 

26 Sequoyah Nuclear Plant Seismic Walkdown Results of Recommendation 2.3 of the Near-Term 

27 Task Force Review of Insights from the Fukushima Dai-ichi Accident. November 27, 2012.

28 ADAMS Nos. ML12342A132, ML12342A133, and ML12342A134.

29 [TVA] Tennessee Valley Authority. 2013a. Letter from Preston D. Swafford to U.S. NRC 

30 Document Control Desk. Subject: Commitment to Install Improved Flood Mitigation Systems.

31 April 16, 2013. ADAMS No. ML13108A107.

32 [TVA] Tennessee Valley Authority. 2013b. Letter from J.W. Shea to U.S. NRC Document 

33 Control Desk. Subject: Progress Update on Improved Flood Mitigation Systems. July 1, 2013.

34 ADAMS No. ML13189A135.

35 [TVA] Tennessee Valley Authority. 2013c. Letter from J.W. Shea to U.S. NRC Document 

36 Control Desk. Subject: Response to NRC Request for Additional Information Regarding the 

37 Environmental Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal 

38 Application (TAC Nos. MF0057 and MF0058). July 17, 2013. ADAMS No. ML13227A003.

39 [TVA] Tennessee Valley Authority. 2013d. Letter from J.W. Shea to U.S. NRC Document 

40 Control Desk. Subject: Sequoyah Nuclear Plant, Units 1 and 2 License Renewal (ADAMS 

41 No. ML13024A004). Enclosure 6: Appendix E: Environmental Report. Section 4.21, Severe 

42 Accident Mitigation Alternatives (ADAMS No. ML13024A007). Attachment E: Severe Accident 

43 Mitigation Alternatives Analysis. In the “Applicant’s Environmental Report, Operating License 

44 Renewal Stage” (ADAMS No. ML13024A010). January 7, 2013.






UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

------------------

OFFICIAL BUSINESS
NUREG-1437

Supplement 53

Draft

Generic Environmental Impact Statement for License Renewal of Nuclear Plants 

Regarding Sequoyah Nuclear Plant, Units 1 and 2