NUREG-1437 

Supplement 42 

Generic Environmental 

Impact Statement for 

License Renewal of 

Nuclear Plants 

Supplement 42 

Regarding Duane Arnold 

Energy Center 

Draft Report for Comment 

Office of Nuclear Reactor Regulation 
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NUREG-1437 

Supplement 42 

Generic Environmental 

Impact Statement for 

License Renewal of 

Nuclear Plants 

Supplement 42 

Regarding Duane Arnold 

Energy Center 

Draft Report for Comment 

Manuscript Completed: January 2010 

Date Published: February 2010 

Office of Nuclear Reactor Regulation 

February 2010 iii Draft NUREG-1437, Supplement 42 

1 Proposed Action Issuance of a renewed operating license, DPR-49, for Duane Arnold 

2 Energy Center (DAEC), in Linn County, Iowa, near the town of Palo. 

3 Type of Statement Draft Supplemental Environmental Impact Statement 

4 Agency Contact Charles Eccleston 

5 U.S. Nuclear Regulatory Commission 

6 Office of Nuclear Reactor Regulation 

7 Mail Stop O-11F1 

8 Washington, D.C. 20555-0001 

9 Phone: 301-415-8537 

10 Email: Charles.Eccleston@nrc.gov 

11 Comments Any interested party may submit comments on this supplemental 

12 environmental impact statement. Please specify NUREG-1437, 

13 Supplement 42, draft, in your comments. Comments must be received by 

14 April 19, 2010. Comments received after the expiration of the comment 

15 period will be considered if it is practical to do so, but assurance of 

16 consideration of late comments will not be given. Comments may be 

17 emailed to DuaneArnoldEIS@nrc.gov or mailed to: 

18 Chief; Rulemaking and Directives Branch 

19 Division of Administrative Services 

20 Mailstop TWB-5B01M 

21 U.S. Nuclear Regulatory Commission 

February 2010 v Draft NUREG-1437, Supplement 42 

1 ABSTRACT 

2 This draft supplemental environmental impact statement (SEIS) has been prepared in response 

3 to an application submitted by FPL Energy Duane Arnold, LLC (FPL-DA) to renew the operating 

4 license for Duane Arnold Energy Center (DAEC) for an additional 20 years. 

5 This draft supplemental environmental impact statement provides a preliminary analysis that 

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

7 action. Alternatives considered include replacement power from a new supercritical coal-fired 

8 generation or natural gas combined-cycle generation plant; this is followed by a combination of 

9 alternatives that includes some energy conservation/energy efficiency measures, natural 

10 gas-fired capacity, and a wind power component. The analysis also evaluates the environmental 

11 effects that could occur if the U.S. Nuclear Regulatory Commission (NRC) takes no action to 

12 issue a renewed license for DAEC (No-Action alternative). Section 8.4 explains why the staff 

13 dismissed many other alternatives from in-depth consideration. 

14 The preliminary recommendation is that the Commission determine that the adverse 

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

16 of license renewal for energy-planning decision makers would be unreasonable.

February 2010 vii Draft NUREG-1437, Supplement 42 

1 TABLE OF CONTENTS 

2 ABSTRACT......................................................................................................................................... v 

3 TABLE OF CONTENTS.................................................................................................................... vii 

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

5 TABLES ............................................................................................................................................ xii 

6 EXECUTIVE SUMMARY .................................................................................................................. xv 

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

8 1.0 PURPOSE AND NEED FOR ACTION.................................................................................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 .......................................................................1-2 

12 1.4 Generic Environmental Impact Statement......................................................................1-3 

13 1.5 Supplemental Environmental Impact Statement ............................................................1-5 

14 1.6 Cooperating Agencies....................................................................................................1-6 

15 1.7 Consultations..................................................................................................................1-6 

16 1.8 Correspondence.............................................................................................................1-7 

17 1.9 Status of Compliance .....................................................................................................1-8 

18 1.10 References...................................................................................................................1-10 

19 2.0 AFFECTED ENVIRONMENT...............................................................................................2-1

20 2.1 Facility and Site Description and Proposed Plant Operation during the 

21 Renewal Term................................................................................................................2-2

22 2.1.1 Reactor and Containment Systems..........................................................................2-6 

23 2.1.2 Radioactive Waste Management..............................................................................2-8 

24 2.1.2.1 Radioactive Liquid Waste ................................................................................2-8

25 2.1.2.2 Radioactive Gaseous Waste ...........................................................................2-9

26 2.1.2.3 Radioactive Solid Waste................................................................................2-10

27 2.1.2.4 Nonradioactive Hazardous Waste Streams...................................................2-11

28 2.1.2.5 Mixed Waste..................................................................................................2-12

29 2.1.2.6 Pollution Prevention and Waste Minimization................................................2-12

30 2.1.3 Facility Operation and Maintenance.......................................................................2-13 

31 2.1.4 Power Transmission System..................................................................................2-13 

32 2.1.5 Cooling and Auxiliary Water Systems ....................................................................2-17 

33 2.1.6 Facility Water Use and Quality ...............................................................................2-17 

34 2.1.6.1 Groundwater Use ..........................................................................................2-17

35 2.1.6.2 Surface Water Use ........................................................................................2-18

36 2.2 Affected Environment...................................................................................................2-20

37 2.2.1 Land Use ................................................................................................................2-20 

38 2.2.2 Air and Meteorology ...............................................................................................2-21 

39 2.2.2.1 Air Quality ......................................................................................................2-22

40 2.2.3 Groundwater Resources ........................................................................................2-23 

41 2.2.4 Surface Water Resources ......................................................................................2-24 

42 2.2.5 Description of Aquatic Resources ..........................................................................2-28 

43 2.2.5.1 Benthic Macroinvertebrates...........................................................................2-28
Table of Contents 

Draft NUREG-1437, Supplement 42 viii February 2010 

1 2.2.5.2 Freshwater Mussels ......................................................................................2-29

2 2.2.5.3 Fish................................................................................................................2-29

3 2.2.6 Description of Terrestrial Resources ......................................................................2-30 

4 2.2.7 Protected Species ..................................................................................................2-32 

5 2.2.7.1 Aquatic Species.............................................................................................2-32

6 2.2.7.2 Terrestrial Species.........................................................................................2-34

7 2.2.8 Socioeconomic Factors ..........................................................................................2-40 

8 2.2.8.1 Housing .........................................................................................................2-41

9 2.2.8.2 Public Services ..............................................................................................2-42

10 2.2.8.3 Offsite Land Use............................................................................................2-43

11 2.2.8.4 Aesthetics and Noise.....................................................................................2-44

12 2.2.8.5 Demography ..................................................................................................2-45 

13 2.2.8.6 Economy .......................................................................................................2-48

14 2.2.9 Historic and Archaeological Resources..................................................................2-50 

15 2.2.9.1 Cultural Background ......................................................................................2-50

16 2.2.9.2 Historic and Archaeological Resources.........................................................2-52

17 2.3 Related Federal and State Activities ............................................................................2-53 

18 2.4 References...................................................................................................................2-54 

19 3.0 ENVIRONMENTAL IMPACTS OF REFURBISHMENT .......................................................3-1 

20 3.1 References.....................................................................................................................3-3 

21 4.0 ENVIRONMENTAL IMPACTS OF OPERATION .................................................................4-1

22 4.1 Land Use........................................................................................................................4-1 

23 4.2 Air Quality.......................................................................................................................4-1 

24 4.3 Groundwater...................................................................................................................4-2 

25 4.3.1 Generic Groundwater Issues....................................................................................4-2 

26 4.3.2 Groundwater Use Conflicts (Plants That Use More Than 100 [378 Liter] 

27 Gallons per Minute) ..................................................................................................4-3 

28 4.3.3 Groundwater Use Conflicts (Makeup from a Small River)........................................4-3 

29 4.4 Surface Water ................................................................................................................4-4 

30 4.4.1 Water Use Conflicts..................................................................................................4-5 

31 4.5 Aquatic Resources .........................................................................................................4-6 

32 4.6 Terrestrial Resources.....................................................................................................4-7 

33 4.7 Threatened and Endangered Species............................................................................4-7 

34 4.7.1 Aquatic Species........................................................................................................4-8 

35 4.7.2 Terrestrial Species ...................................................................................................4-8

36 4.8 Human Health ................................................................................................................4-8 

37 4.8.1 Generic Human Health Issues..................................................................................4-9 

38 4.8.2 Microbiological Organisms – Public Health ............................................................4-11 

39 4.8.3 Electromagnetic Fields – Acute Shock...................................................................4-13 

40 4.8.4 Electromagnetic Fields – Chronic Effects...............................................................4-14 

41 4.9 Socioeconomics ...........................................................................................................4-15 

42 4.9.1 Generic Socioeconomic Issues ..............................................................................4-15 

43 4.9.2 Housing Impacts.....................................................................................................4-16 

44 4.9.3 Public Services: Public Utility Impacts....................................................................4-17 

45 4.9.4 Offsite Land Use.....................................................................................................4-18

46 4.9.4.1 Population-Related Impacts ..........................................................................4-18

47 4.9.4.2 Tax-Revenue-Related Impacts......................................................................4-18

48 4.9.5 Public Services: Transportation Impacts ................................................................4-19 

49 4.9.6 Historic and Archaeological Resources..................................................................4-19 
Table of Contents 

February 2010 ix Draft NUREG-1437, Supplement 42

1 4.9.7 Environmental Justice ............................................................................................4-22 

2 4.9.7.1 Minority Population in 2000 ...........................................................................4-23

3 4.9.7.2 Low-Income Population in 2000 ....................................................................4-26 

4 4.9.7.3 Analysis of Impacts........................................................................................4-28

5 4.9.7.4 Subsistence Consumption of Fish and Wildlife .............................................4-28

6 4.10 Evaluation of New and Potentially Significant Information ...........................................4-30 

7 4.11 Cumulative Impacts......................................................................................................4-30 

8 4.11.1 Land Use ................................................................................................................4-31 

9 4.11.2 Cumulative Air Quality Impacts ..............................................................................4-31 

10 4.11.3 Cumulative Impacts on Water Resources ..............................................................4-32 

11 4.11.4 Cumulative Impacts on Aquatic Resources............................................................4-33 

12 4.11.5 Cumulative Impacts on Terrestrial Resources........................................................4-34 

13 4.11.6 Cumulative Human Health Impacts........................................................................4-36 

14 4.11.7 Cumulative Socioeconomic Impacts.......................................................................4-37 

15 4.11.8 Historic and Archaeological Resources Cumulative Impacts .................................4-37 

16 4.11.9 Summary of Cumulative Impacts............................................................................4-38 

17 4.12 References...................................................................................................................4-40 

18 5.0 ENVRONMENTAL IMPACTS OF POSTULATED ACCIDENTS ...............................................5-1 

19 5.1 Design Basis Accidents..................................................................................................5-1

20 5.2 Severe Accidents ...........................................................................................................5-2 

21 5.3 Severe Accident Mitigation Alternatives.........................................................................5-3 

22 5.3.1 Introduction...............................................................................................................5-3 

23 5.3.2 Estimate of Risk ......................................................................................................5-4 

24 5.3.3 Potential Plant Improvements...................................................................................5-6 

25 5.3.4 Evaluation of Risk Reduction and Costs of Improvements.......................................5-6 

26 5.3.5 Cost-Benefit Comparison .........................................................................................5-7 

27 5.3.6 Conclusions..............................................................................................................5-8 

28 5.4 References.....................................................................................................................5-8 

29 6.0 ENVIRONMENTAL IMPACTS OF THE URANIUM FUEL CYCLE, SOLID WASTE 

30 MANAGEMENT, AND GREENHOUSE EMISSIONS ..........................................................6-1 

31 6.1 The Uranium Fuel Cycle.................................................................................................6-1 

32 6.2 Greenhouse Gas Emissions...........................................................................................6-2 

33 6.2.1 Existing Studies........................................................................................................6-3 

34 6.2.2 Conclusions: Relative GHG Emissions ....................................................................6-9 

35 6.3 References...................................................................................................................6-10 

36 7.0 ENVIRONMENTAL IMPACTS OF DECOMMISSIONING ...................................................7-1 

37 7.1 Decommissioning...........................................................................................................7-1 

38 7.2 References.....................................................................................................................7-3 

39 8.0 ENVIRONMENTAL IMPACTS OF ALTERNATIVES ...........................................................8-1

40 8.1 Supercritical Coal-Fired Generation...............................................................................8-3 

41 8.1.1 Air Quality.................................................................................................................8-5 

42 8.1.2 Groundwater Use and Quality ..................................................................................8-9 

43 8.1.3 Surface Water Use and Quality................................................................................8-9 

44 8.1.4 Aquatic and Terrestrial Ecology................................................................................8-9 

45 8.1.5 Human Health ........................................................................................................8-10 

46 8.1.6 Socioeconomics .....................................................................................................8-11 

47 8.1.7 Waste Management ...............................................................................................8-15 
Table of Contents 

Draft NUREG-1437, Supplement 42 x February 2010 

1 8.2 Natural Gas Combined-Cycle Generation....................................................................8-16 

2 8.2.1 Air Quality...............................................................................................................8-17 

3 8.2.2 Groundwater Use and Quality ................................................................................8-19 

4 8.2.3 Surface Water Use and Quality..............................................................................8-20 

5 8.2.4 Aquatic and Terrestrial Ecology..............................................................................8-20 

6 8.2.5 Human Health ........................................................................................................8-21 

7 8.2.6 Socioeconomics .....................................................................................................8-21 

8 8.2.7 Waste Management ...............................................................................................8-25 

9 8.3 Combination Alternative ...............................................................................................8-25 

10 8.3.1 Air Quality...............................................................................................................8-26 

11 8.3.2 Groundwater Use and Quality ................................................................................8-28 

12 8.3.3 Surface Water Use and Quality..............................................................................8-28 

13 8.3.4 Aquatic and Terrestrial Ecology..............................................................................8-29 

14 8.3.5 Human Health ........................................................................................................8-30 

15 8.3.6 Socioeconomics ....................................................................................................8-30 

16 8.3.7 Waste Management ...............................................................................................8-34 

17 8.4 Alternatives Considered But Dismissed .......................................................................8-35 

18 8.4.1 Offsite Coal- and Gas-Fired Capacity.....................................................................8-35 

19 8.4.2 Coal-Fired Integrated Gasification Combined-Cycle ..............................................8-35 

20 8.4.3 New Nuclear...........................................................................................................8-36 

21 8.4.4 Energy Conservation/Energy Efficiency .................................................................8-36 

22 8.4.5 Purchased Power ...................................................................................................8-37 

23 8.4.6 Solar Power............................................................................................................8-37 

24 8.4.7 Wood Waste...........................................................................................................8-37

25 8.4.8 Hydroelectric Power ...............................................................................................8-38 

26 8.4.9 Wave and Ocean Energy .......................................................................................8-38 

27 8.4.10 Geothermal Power .................................................................................................8-38 

28 8.4.11 Municipal Solid Waste ............................................................................................8-38 

29 8.4.12 Biofuels...................................................................................................................8-39 

30 8.4.13 Oil-Fired Power ......................................................................................................8-39 

31 8.4.14 Fuel Cells ...............................................................................................................8-39 

32 8.4.15 Delayed Retirement................................................................................................8-40 

33 8.5 No-Action Alternative....................................................................................................8-40 

34 8.5.1 Air Quality...............................................................................................................8-41 

35 8.5.2 Groundwater Use and Quality ................................................................................8-41 

36 8.5.3 Surface Water Use and Quality..............................................................................8-41 

37 8.5.4 Aquatic and Terrestrial Resources .........................................................................8-41 

38 8.5.5 Human Health ........................................................................................................8-42 

39 8.5.6 Socioeconomics .....................................................................................................8-42 

40 8.5.7 Waste Management ...............................................................................................8-43 

41 8.6 Alternatives Summary ..................................................................................................8-43 

42 8.7 References...................................................................................................................8-46 

43 9.0 CONCLUSION .....................................................................................................................9-1

44 9.1 Environmental Impacts of License Renewal ..................................................................9-1 

45 9.1.1 Other Environmental Impacts...................................................................................9-2 

46 9.2 Comparison of Environmental Impacts of License Renewal and Alternatives ...............9-2 

47 9.3 Special Considerations Pursuant to Section 102(C) of NEPA .......................................9-3 

48 9.3.1 Unavoidable Adverse Environmental Impacts..........................................................9-3 

49 9.3.2 Relationship between Local Short-term Uses of the Environment and the 

50 Maintenance and Enhancement of Long-Term Productivity.....................................9-5 
Table of Contents 

February 2010 xi Draft NUREG-1437, Supplement 42

1 9.3.3 Irreversible and Irretrievable Commitments of Resources .......................................9-6 

2 9.4 Recommendations .........................................................................................................9-7

3 9.5 References.....................................................................................................................9-7 

4 

5 10.0 LIST OF PREPARERS ......................................................................................................10-1 

6 11.0 INDEX ................................................................................................................................11-1

7 APPENDIXES 

8 Appendix A - Comments Received On The Duane Arnold Energy Center 

9 Environmental Review ........................................................................................................ A-1

10 Appendix B - National Environmental Protection Agency Issues For License Renewal 

11 Of Nuclear Power Plants..................................................................................................... B-1

12 Appendix C - Applicable Regulations, Laws, And Agreements ...................................................... C-1 

13 Appendix D - Consultation Correspondences................................................................................. D-1 

14 Appendix E - Chronology Of Environmental Review Correspondence........................................... E-1 

15 Appendix F - U.S. Nuclear Regulatory Commission Staff Evaluation Of Severe Accident 

16 Mitigation Alternatives For Duane Arnold Energy Center In Support Of License 

17 Renewal Application Review............................................................................................... F-1

18 FIGURES 

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

20 Figure 1-2. Environmental Issues Evaluated during License Renewal..........................................1-5 

21 Figure 2-1. Location of Duane Arnold Energy Center, within a 6-Mile Radius...............................2-1 

22 Figure 2-2. Plant Site, Switchyard, and Transmission Lines..........................................................2-2 

23 Figure 2-3. Duane Arnold Energy Center Property Boundaries and Facility Layout......................2-3 

24 Figure 2-4. Location of Duane Arnold Energy Center, within a 50-Mile Radius.............................2-5 

25 Figure 2-5. Simplified Design of a Boiling Water Reactor..............................................................2-7 

26 Figure 2-6. The Process of Nuclear Fission...................................................................................2-7 

27 Figure 2-7. Duane Arnold Energy Center Transmission Line System .........................................2-15 

28 Figure 4-1. Aggregate Minority Population within a 50-Mile Radius of 

29 Duane Arnold Energy Center ....................................................................................4-25 

30 Figure 4-2. Low-Income Population within a 50-Mile Radius of 

31 Duane Arnold Energy Center ....................................................................................4-27
Table of Contents 

Draft NUREG-1437, Supplement 42 xii February 2010 

1 TABLES 

2 Table I-1. Comparison of the Impacts of the DAEC License Renewal and its Three 

3 Reasonable Alternatives............................................................................................... xx 

4 Table 1-1. List of persons who are sent a copy of this draft SEIS................................................1-8 

5 Table 1-2. Licenses and Permits ..................................................................................................1-9 

6 Table 2-1. Duane Arnold Energy Center Transmission Lines ....................................................2-16 

7 Table 2-2. Monthly Flow Rates between 1903 and 2008 ...........................................................2-19 

8 Table 2-3. Chemical Additives Listed in National Pollutant Discharge Elimination 

9 System Application....................................................................................................2-26 

10 Table 2-4. Listed Aquatic Species ..............................................................................................2-34 

11 Table 2-5. Listed Terrestrial Species..........................................................................................2-37 

12 Table 2-6. Duane Arnold Energy Center Permanent Employee Residence 

13 by County in 2006......................................................................................................2-41 

14 Table 2-7. Housing in Linn and Benton Counties, Iowa..............................................................2-41 

15 Table 2-8. Major Public Water Supply Systems in Linn and Benton Counties ...........................2-42 

16 Table 2-9. Population and Percent Growth in Linn and Benton Counties, Iowa, 

17 from 1970 to 2000 and Projected for 2010 and 2040................................................2-45 

18 Table 2-10. Demographic Profile of the Population in the Duane Arnold Energy Center 

19 Region of Influence in 2000.......................................................................................2-46 

20 Table 2-11. Seasonal Housing within 50 Miles of Duane Arnold Energy Center, 2000................2-46 

21 Table 2-12. Migrant Farm Worker and Temporary Farm Labor within 50 Miles of 

22 Duane Arnold Energy Center. ...................................................................................2-47 

23 Table 2-13. Major Employers in Linn County in 2006...................................................................2-48 

24 Table 2-14. Income Information for the Duane Arnold Energy Center 

25 Region of Influence, 2007..........................................................................................2-48 

26 Table 2-15. Property Tax Revenues in Linn County, 2005 to 2008..............................................2-49 

27 Table 2-16. Historic and Archaeological Sites in the Duane Arnold Energy Center 

28 Associated Transmission Lines.................................................................................2-53 

29 Table 3-1. Category 1 Issues for Refurbishment Evaluation ........................................................3-2 

30 Table 3-2. Category 2 Issues for Refurbishment Evaluation ........................................................3-3 

31 Table 4-1. Category 1 Issues Applicable to Onsite Land Use during the Renewal Term.............4-1 

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

33 Table 4-3. Groundwater Use and Quality Issues..........................................................................4-2 

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

35 Table 4-5. Aquatic Resource Issues.............................................................................................4-6 

36 Table 4-6. Terrestrial Resource Issues.........................................................................................4-7 

37 Table 4-7. Threatened or Endangered Species............................................................................4-7 

38 Table 4-8. Human Health Issues ..................................................................................................4-8 

39 Table 4-9. The Maximum Daily Discharge Temperatures, Reported in 

40 DAEC NPDES Reports for the 2001–2008 Period....................................................4-12 

41 Table 4-10. Category 1 Issues Applicable to Socioeconomics during the Renewal Term ..........4-15 

42 Table 4-11. Category 2 Issues Applicable to Socioeconomics and Environmental Justice 

43 during the Renewal Term ..........................................................................................4-16 

44 Table 4-12. Summary of Cumulative Impacts on Resource Areas...............................................4-39 

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

46 Table 5-2. Duane Arnold Energy Center Core Damage Frequency for Internal Events...............5-5 

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

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

February 2010 xiii Draft NUREG-1437, Supplement 42

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

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

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

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

5 Table 8-1. Summary of Environmental Impacts of Supercritical Coal-Fired Alternative 

6 Compared to Continued Operation of Duane Arnold Energy Center ..........................8-5 

7 Table 8-2. Summary of Environmental Impacts of the Natural Gas-Fired Combined-Cycle 

8 Generation Alternative Compared to Continued Operation of Duane Arnold 

9 Energy Center ...........................................................................................................8-17 

10 Table 8-3. Summary of Environmental Impacts of the Combination Alternative Compared to 

11 Continued Operation of Duane Arnold Energy Center ..............................................8-26 

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

13 Operation of Duane Arnold Energy Center................................................................8-41 

14 Table 8-5. Summary of Environmental Impacts of Proposed Action and Alternatives ...............8-45 

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

February 2010 xv Draft NUREG-1437, Supplement 42 

1 EXECUTIVE SUMMARY 

2 BACKGROUND 

3 By a letter dated September 30, 2008, FPL Energy Duane Arnold, LLC (FPL-DA) submitted an 

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

5 license for Duane Arnold Energy Center (DAEC) for an additional 20-year period. 

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

7 implementing Section 102 of the National Environmental Policy Act (NEPA) of 1969, of the 

8 United States Code (42 U.S.C. 4321), in Title 10 of the Code of Federal Regulations (CFR), Part 

9 51 (10 CFR Part 51). In 10 CFR 51.20(b)(2), the Commission indicates that issuing a renewed 

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

11 (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that the EIS 

12 prepared at the operating license renewal stage will be a supplement to the Generic 

13 Environmental Impact Statement (GEIS) for License Renewal of Nuclear Plants, NUREG-1437, 

14 Volumes 1 and 2 (NRC 1996, 1999). 

15 Upon acceptance of the FPL-DA application, the NRC staff began the environmental review 

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

17 conduct a public scoping process. The NRC staff held public scoping meetings on April 22, 

18 2009, in Hiawatha, Iowa, and conducted a site regulatory audit at the plant in June 2009. 

19 In preparing this supplemental environmental impact statement (SEIS) for the DAEC, the NRC 

20 staff performed the following: 

21 ● Reviewed FPL-DA’s environmental report (ER) and compared it to the 

22 GEIS 

23 ● Consulted with other agencies 

24 ● Conducted a review of the issues following the guidance set forth in 

25 NUREG-1555, Supplement 1, Standard Review Plans for Environmental 

26 Reviews for Nuclear Power Plants, Supplement 1: Operating License 

27 Renewal

28 ● Considered the public comments received during the scoping process. 

29 PROPOSED ACTION 

30 FPL-DA initiated the proposed Federal action—issuance of a renewed power reactor operating 

31 license—by submitting an application for license renewal of DAEC, for which the existing license 

32 (DPR-49) expires on February 21, 2014. NRC’s Federal action is the decision of whether or not 

33 to renew the license for an additional 20 years. 
Executive Summary 

Draft NUREG-1437, Supplement 42 xvi February 2010 

1 PURPOSE AND NEED FOR ACTION 

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

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

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

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

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

7 findings in the safety review required by the Atomic Energy Act of 1954 (AEA) or findings in the 

8 NEPA environmental analysis that would lead the NRC to not grant a license renewal, the NRC 

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

10 to whether a particular nuclear power plant should continue to operate. 

11 If the renewed license is issued, State regulatory agencies and FPL-DA will ultimately decide 

12 whether or not the plant will continue to operate based on factors such as the need for power or 

13 other matters within the State’s jurisdiction or the purview of the owners. If the operating license 

14 is not renewed, then the facility must be shut down on or before the expiration date of the 

15 current operating license, February 21, 2014. 

16 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL 

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

18 environmental impacts of the proposed action can be assigned values of SMALL, MODERATE, 

19 or LARGE. The NRC staff established a process for identifying and evaluating the significance 

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

21 DAEC. The NRC did not identify information that is both new and significant related to Category 

22 1 issues that would call into question the conclusions in the GEIS. Similarly, neither the scoping 

23 process nor the NRC staff’s review has identified any new issue applicable to DAEC that has a 

24 significant environmental impact. The NRC staff, therefore, relies upon the conclusions of the 

25 GEIS for all the Category 1 issues applicable to DAEC. 

26 LAND USE 

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

28 staff identify any new and significant information during the environmental review; therefore, 

29 there would be no impacts beyond those discussed in the GEIS. 

30 AIR QUALITY 

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

32 lines on air quality, nor did the staff identify any new or significant information during the 

33 environmental review; therefore, for plant operation during the license renewal term, there are 

34 no impacts beyond those discussed in the GEIS. 

35 GROUNDWATER USE AND QUALITY 

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

37 gallons per minute (gpm) and plants using cooling towers withdrawing makeup water from a 

38 small river—are Category 2 issues related to license renewal at DAEC. Information provided by 

39 FPL-DA, including groundwater level monitoring data and aquifer test data, shows that DAEC 

40 groundwater withdrawal has no significant effect on nearby groundwater wells and ground water 

41 supplies. 
Executive Summary 

February 2010 xvii Draft NUREG-1437, Supplement 42 

1 SURFACE WATER USE AND QUALITY 

2 SMALL to MODERATE. Water use conflicts—plants with cooling ponds or cooling towers using 

3 makeup water from a small river with low flow—are a Category 2 issue related to license 

4 renewal at DAEC. Withdrawals of Cedar River water by DAEC are approximately 0.6 percent of 

5 the average annual flow of the river. The impact is generally SMALL. During low-flow periods, 

6 however, the impact may be MODERATE, as the withdrawal rate and consumptive rate are 

7 higher proportions of the river flow. By permit, when river flow falls below 500 cubic feet per 

8 second (cfs), an upstream reservoir may discharge to the river at a rate equal to the 

9 consumptive use rate. At this low-flow threshold, flow in the river is only 13 percent of the 

10 average flow, the withdrawal rate is 5 percent of the low flow, and the return of blowdown to the 

11 river results in a net consumptive rate of over 3 percent of the low flow. 

12 AQUATIC RESOURCES 

13 SMALL. With regard to operation of DAEC during the license renewal term, the NRC did not 

14 identify any Category 2 issues for aquatic resources, nor did the staff identify any new and 

15 significant information during the environmental review; therefore, there are no impacts beyond 

16 those discussed in the GEIS. 

17 TERRESTRIAL RESOURCES 

18 SMALL. With regard to operation of DAEC during the license renewal term, the NRC did not 

19 identify any Category 2 issues for terrestrial resources, nor did the staff identify any new or 

20 significant information during the environmental review; therefore, there are no impacts beyond 

21 those discussed in the GEIS. 

22 THREATENED AND ENDANGERED SPECIES 

23 SMALL. Impacts to threatened and endangered species during the period of extended operation 

24 are Category 2 issues. No Federally listed threatened or endangered terrestrial species are 

25 known to occur on the DAEC site or within the in-scope transmission line right of ways (ROWs). 

26 Nor are any threatened or endangered aquatic species known to occur within the Cedar River 

27 near the vicinity of DAEC or within any streams crossed by in-scope transmission line ROWs. 

28 The NRC staff did not identify any new or significant information during the environmental 

29 review; therefore, there are no impacts beyond those discussed in the GEIS. 

30 HUMAN HEALTH 

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

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

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

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

35 there are no impacts beyond those discussed in the GEIS. The chronic effects of 

36 electromagnetic fields from power lines were not designated as Category 1 or 2 issues, and will 

37 not be until a scientific consensus is reached on the health implications of these fields. 

38 Microbiological organisms (public health) and electromagnetic fields–acute effects (electric 

39 shock) are Category 2 human health issues which are discussed below. 

40 The NRC staff considers the GEIS finding of “uncertain” for electromagnetic fields–chronic 

41 effects still appropriate and will continue to follow developments on this issue. 

42 The applicant has no plans to conduct refurbishment activities during the license renewal term, 

43 thus, no change to radiological conditions is expected to occur. Continued compliance with 
Executive Summary 

Draft NUREG-1437, Supplement 42 xviii February 2010 

1 regulatory requirements is expected during the license renewal term; therefore, the impacts 

2 from radioactive effluents are not expected to change during the license renewal term. 

3 The NRC staff concludes that thermophilic microbiological organisms are not likely to present a 

4 public health hazard as a result of DAEC discharges to the Cedar River. The NRC staff 

5 concludes that impacts on public health from thermophilic microbiological organisms from 

6 continued operation of DAEC in the license renewal period would be SMALL. 

7 NRC staff reviewed FPL-DA’s analysis of electromagnetic fields–acute shock resulting from 

8 induced charges in metallic structures, and verified that there are no locations under the 

9 transmission lines that have the capacity to induce more than 5 milliamps (mA) in a vehicle 

10 parked beneath the line. No induced shock hazard to the public should occur, since the lines are 

11 operating within original design specifications and meet current National Electric Safety Code 

12 (NESC) clearance standards. The NRC staff has reviewed the available information, including 

13 the applicant’s evaluation and computational results. Based on this information, the staff 

14 concludes that the potential impacts from electric shock during the renewal period would be 

15 SMALL. The NRC staff did not identify any cost benefit studies applicable to the mitigation 

16 measures. 

17 SOCIOECONOMICS 

18 SMALL to MODERATE. The NRC staff identified no Category 1 public services and aesthetic 

19 impacts, or new and significant information during the environmental review; therefore, there 

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

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

22 transportation), and historic and archaeological resources. Since FPL-DA has indicated that 

23 they have no plans to add non-outage employees during the license renewal period, there 

24 would be no impact on housing during the license renewal term beyond what has already been 

25 experienced. DAEC operations during the license renewal term would also not increase 

26 plant-related population growth demand for public water and sewer services. Since there are no 

27 planned refurbishment activities at DAEC, there would be no land use impacts related to 

28 population or tax revenues, and no transportation impacts. 

29 Based on the NRC staff’s review of past surveys conducted at DAEC, review of the procedures 

30 for considering historic and archaeological materials at DAEC, and review of the Iowa Historical 

31 Society and Iowa State Archaeologist files for the region, the NRC staff concludes that the 

32 potential impacts on historic and archaeological resources at DAEC could be MODERATE. 

33 However, if DAEC develops procedures that more effectively consider historic and 

34 archaeological resources and develops a cultural resource management plan, potential impacts 

35 could be minimized or avoided. 

36 With respect to environmental justice, an analysis of minority and low-income populations 

37 residing within a 50-mile (80-km) radius of DAEC indicated there would be no disproportionately 

38 high and adverse impacts to these populations from the continued operation of DAEC during the 

39 license renewal period. As a result of recent monitoring results, concentrations of contaminants 

40 in native vegetation, crops, soils and sediments, surface water, fish, and game animals in areas 

41 surrounding DAEC have been quite low (at or near the threshold of detection) and seldom 

42 above background levels. Consequently, no disproportionately high and adverse human health 

43 impacts would be expected in special pathway receptor populations in the region as a result of 

44 subsistence consumption of fish and wildlife. 
Executive Summary 

February 2010 xix Draft NUREG-1437, Supplement 42 

1 SEVERE ACCIDENT MITIGATION ALTERNATIVES 

2 Since DAEC had not previously considered alternatives to reduce the likelihood or potential 

3 consequences of a variety of highly uncommon but potentially serious accidents, NRC 

4 regulation 10 CFR 51.53(c)(3)(ii)(L) requires that DAEC evaluate Severe Accident Mitigation 

5 Alternatives (SAMAs) in the course of license renewal review. SAMAs are potential ways to 

6 reduce the risk or potential impacts of uncommon but potentially severe accidents, and may 

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

8 Based on the review of potential SAMAs, the staff concludes that DAEC made a reasonable, 

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

10 DAEC, and the plant improvements already made, the staff concludes that none of the 

11 potentially cost-beneficial SAMAs that relate to adequately managing the effects of aging are 

12 warranted during the period of extended operation; therefore, they need not be implemented as 

13 part of the license renewal pursuant to 10 CFR Part 54. 

14 ALTERNATIVES 

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

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

17 DAEC operating license (the No-Action alternative). Replacement power options considered 

18 were supercritical coal-fired generation, natural gas combined-cycle generation, and as part of 

19 the combination alternative, construction of wind turbines and a component of energy 

20 conservation/energy efficiency. Potential environmental impacts of these alternatives were 

21 considered at both the DAEC site and at some other unspecified alternate location for the wind 

22 power component of the combination alternative. Each alternative was evaluated using the 

23 same impact areas that were used in evaluating impacts from license renewal. The results of 

24 this evaluation are summarized in the table on the following page. 

25 COMPARISON OF ALTERNATIVES 

26 A comparison of the impacts of DAEC license renewal with its three reasonable alternatives is 

27 provided in Table I-1. In the staff’s best professional opinion, the coal-fired alternative is the 

28 least environmentally favorable alternative, due to: impacts to air quality from nitrogen oxides 

29 (NOx), sulfur oxides (SOx), particulate matter (PM), polycyclic aromatic hydrocarbons (PAHs), 

30 carbon monoxide (CO), carbon dioxide (CO2), and mercury—and the corresponding human 

31 health impacts. Construction impacts to aquatic, terrestrial, and potentially historic and 

32 archaeological resources are also factors that added to this conclusion. The gas-fired alternative 

33 would have lower air emissions, but construction-related impacts to aquatic, terrestrial, and 

34 historic and archaeological resources would be similar to the coal-fired alternative. The wind 

35 power component of the combination alternative would have relatively lower air emissions over 

36 its life-cycle, but construction, aesthetic, and land use impacts would likely be substantial larger 

37 because of the amount of land required. 

38 The NRC notes that the renewal of the DAEC license could have a MODERATE impact on two 

39 environmentally-related issues, and SMALL impacts on all other categories evaluated; 

40 therefore, in the staff’s professional opinion, renewal of the DAEC license is the environmentally 

41 preferred action. All other alternatives capable of meeting the needs currently served by DAEC 

42 entail potentially greater impacts than the proposed action involving license renewal of DAEC. 

43 The No-Action alternative does not meet the purpose and need of this draft SEIS. 
Executive Summary 

Draft NUREG-1437, Supplement 42 xx February 2010 

1 Table I-1. Comparison of the Impacts of the DAEC License Renewal and its Three 

2 Reasonable Alternatives 

Impact Area 

Alternative 

Land Use 

Air Quality 

Groundwater 

Surface Water 

Aquatic and Terrestrial 

Resources 

Human Health 

Socioeconomics 

Waste Management 

DAEC License 

Renewal S to M S S S to M S S S to M S(b)

Supercritical CoalFired Alternative at 

DAEC Site 

M M S S S to M S S to M M 

Natural Gas 

Combined-Cycle 

Alternative 

at DAEC site 

S to M S to M S S S S S to M S 

Combination 

Alternative 1(a) S to M S S S S to M S S to M S 

No-Action 

Alternative S S S S S S S to M S 

(a) Combination alternative consists of gas-fired generation, wind power, and conservation 

(b) For the DAEC license renewal alternative, waste management was evaluated in Chapter 6. Consistent with the findings 

in the generic environmental impact statement (GEIS), these impacts were determined to be SMALL with the 

exception of collective offsite radiological impacts from the fuel cycle and from high-level waste and spent fuel 

disposal. 

S – SMALL impact 

M – MODERATE impact 

L – LARGE impact

3 RECOMMENDATION 

4 Our preliminary recommendation is that the Commission determine that the adverse 

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

6 of license renewal for energy planning decision makers would be unreasonable. This 

7 recommendation is based on: 

8 (1) The analysis and findings in the GEIS 

9 (2) Information submitted in the FPL-DA’s ER 

10 (3) Consultation with other Federal, State, and local agencies 

11 (4) A review of other pertinent studies and reports 

12 (5) A consideration of public comments received during the scoping process. 
Executive Summary 

February 2010 xxi Draft NUREG-1437, Supplement 42 

1 REFERENCES 

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

3 License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, Washington, D.C., 1996. 

4 ADAMS Accession Nos. ML040690705 and ML040690738. 

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

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

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

8 NUREG-1437, Volume 1, Addendum 1, Washington, D.C., 1999.

February 2010 xxiii Draft NUREG-1437, Supplement 42 

1 ABBREVIATIONS AND ACRONYMS 

2 ac acre 

3 AEA Atomic Energy Act of 1954 

4 AEC U.S. Atomic Energy Commission 

5 ALARA as low as reasonably achievable 

6 AQCR Northeast Iowa Intrastate Air Quality Control Region 

7 BWR boiling water reactor 

8 cfs cubic feet per second 

9 cm centimeter 

10 CAA Clean Air Act 

11 CDC Center for Disease Control 

12 CDF core damage frequency 

13 CEQ Council on Environmental Quality 

14 CESQG conditionally exempt small quantity generators 

15 CFR Code of Federal Regulations 

16 CFS cubic feet per second 

17 CO carbon monoxide 

18 COPC chemicals of potential concern 

19 CRT cathode ray tube 

20 CWA Clean Water Act 

21 DAEC Duane Arnold Energy Center 

22 DBA design-basis accident 

23 DOE Department of Energy 

24 DPR demonstration power reactor 

25 DSEIS draft supplemental environmental impact statement 

26 DSM demand-side management 

27 EIA Energy Information Administration (of DOE) 

28 EIS environmental impact statement 

29 ELF-EMF extremely low frequency-electromagnetic field 
Abbreviations and Acronyms 

Draft NUREG-1437, Supplement 42 xxiv February 2010 

1 EMF electromagnetic force 

2 EMS environmental management system 

3 EOP emergency operating procedure 

4 ER environmental report 

5 EPA Environmental Protection Agency 

6 EPCRA Emergency Planning and Community Right-to-Know Act 

7 ESA Endangered Species Act of 1973 

8 ESW emergency service water 

9 ft/s feet per second 

ft3 10 /s cubic ft per second 

ft3 11 /year cubic ft per year 

12 FES final environmental statement 

13 FPL Florida Power and Light 

14 FPL-DA Florida Power and Light Energy Duane Arnold, LLC 

15 FSAR final safety analysis report 

16 ft feet 

17 GEIS generic environmental impact statement 

18 GHG greenhouse gas 

19 gpd gallons per day 

20 gpm gallons per minute 

21 ha hectare 

22 HAP hazardous air pollutants 

23 HLW high-level waste 

24 HVAC heating, ventilation, and air conditioning 

25 Hz hertz 

26 in inch 

27 IAC Iowa Administrative Code 

28 IBI Index of Biotic Integrity 

29 ICCAC Iowa Climate Change Advisory Council (ICCAC) 

30 IDNR Iowa Department of Natural Resources 
Abbreviations and Acronyms 

February 2010 xxv Draft NUREG-1437, Supplement 42 

1 Inc. incorporated 

2 IPA integrated plant assessment 

3 ISFSI independent spent fuel storage installation 

4 ISO International Standardization Organization 

5 ITC Information Technology Midwest LLC 

6 km kilometers 

km2 7 kilometers squared 

8 Kv kilovolts 

9 LCCO Linn County Code of Ordinances 

10 LCPH Linn County Public Health Department 

11 LLC limited liability corporation 

12 LLMW low-level mixed waste 

13 LLW low–level radioactive waste 

14 LOCA loss of coolant accident 

15 LOS level of service 

16 LQG large quantity generators 

17 LWR light-water reactor 

18 m meter 

19 mA milliamps 

20 mi miles 

21 mGy milligray 

mi2 22 miles squared 

m3 23 /s cubic meters per second 

24 m/s meters per second 

25 mrad millirad 

26 mrem millirem 

27 MRS Midcontinent Rift System 

28 MSL mean sea level 

29 mSv millisievert 

30 MTU metric ton uranium 
Abbreviations and Acronyms 

Draft NUREG-1437, Supplement 42 xxvi February 2010 

1 MW megawatt 

2 MWe megawatt-electric 

3 MWt megawatt-thermal 

ug/m3 4 micrograms per cubic meter 

5 N/A not applicable 

6 NAAQS National Ambient Air Quality Standards 

7 NEPA National Environmental Policy Act of 1969 

8 NESC National Electrical Safety Code 

9 NHPA National Historic Preservation Act 

10 NIEHS National Institute of Environmental Health Sciences 

11 NOx nitrogen oxide(s) 

12 NPDES National Pollutant Discharge Elimination System 

13 NRC U.S. Nuclear Regulatory Commission 

14 NRHP National Register of Historic Places 

15 NUREG NRC Regulatory Guide 

16 NWS National Weather Service 

17 PCB polychlorinated biphenol 

18 pCi/L picocuries per liter 

19 PDS plant damage state 

20 PM particulate matter 

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

22 PM10 particulate matter, 10 microns or less in diameter 

23 POE potential to emit 

24 PRA probabilistic risk assessment 

25 PSA probabilistic safety assessment 

26 Psig pound-force per square inch gauge 

27 R-12 dichlorodifluoromethane 

28 R-22 chlorodifluoromethane 

29 RBCCW reactor building closed cooling water 

30 RCRA Resource Conservation and Recovery Act 
Abbreviations and Acronyms 

February 2010 xxvii Draft NUREG-1437, Supplement 42 

1 REMP radiological environmental monitoring program 

2 RHRSW residual heat removal service water 

3 ROI region of influence 

4 ROW(s) right of way(s) 

5 SAMA Severe Accident Mitigation Alternative 

6 SAR safety analysis report 

7 SER safety evaluation report 

8 SHPO State Historic Preservation Office 

9 SO2 sulfur dioxide 

10 SQG small quantity generators 

11 STF stormwater and sewage treatment facility (STF) 

12 SPDS safety parameter display system 

13 TLD thermoluminescent dosimeters 

14 TSC technical support center 

15 TSS total suspended solids 

16 U Uranium 

17 UFSAR updated final safety analysis report 

18 USFWS U.S. Fish and Wildlife Service 

19 U.S. United States 

20 USGS U.S. Geological Survey 

21 USGCRP United States Global Change Research Program

February 2010 1-1 Draft NUREG-1437, Supplement 42 

1 1.0 PURPOSE AND NEED FOR ACTION 

2 Pursuant to the U.S. Nuclear Regulatory Commission’s (NRC’s) environmental protection 

3 regulations in Title 10, Part 51, of the U.S. Code of Federal Regulations (10 CFR 51), which 

4 implement the U.S. National Environmental Policy Act of 1969 (NEPA), an environmental impact 

5 statement (EIS) is required to be prepared for issuance of a new nuclear power plant operating 

6 license. 

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

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

9 40-year licensing period is based on economic and antitrust considerations rather than on 

10 technical limitations of the nuclear facility. 

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

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

13 meet NRC safety and environmental requirements. The NRC staff (Staff) makes the decision to 

14 grant or deny a license renewal, based on whether or not the applicant has demonstrated that 

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

16 period of extended operation. 

17 1.1 PROPOSED FEDERAL ACTION 

18 FPL Energy Duane Arnold, LLC (FPL-DA) initiated the proposed Federal action by submitting 

19 an application for license renewal of Duane Arnold Energy Center (DAEC), for which the 

20 existing license number DPR-49 currently expires on February 21, 2014. NRC’s Federal action 

21 is the decision of whether or not to renew the license 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, which may be determined by 

26 State, utility, and, where authorized, Federal (other than NRC) decision-makers. This definition 

27 of purpose and need reflects the Commission’s recognition that, unless there are findings in the 

28 safety review required by the AEA or findings in the NEPA environmental analysis that would 

29 lead the NRC to not grant a license renewal, the NRC does not have a role in the energy30 planning decisions of State regulators and utility officials as to whether or not a particular 

31 nuclear power plant should continue to operate. 

32 If the renewed license is issued, State regulatory agencies and FPL-DA will ultimately decide 

33 whether the plant will continue to operate or not based on factors such as the need for power, or 

34 other matters within the State’s jurisdiction, or the purview of the owners. If the operating license 

35 is not renewed, the facility must be shut down on or before the expiration date (February 21, 

36 2014) of the current operating license. 
Purpose and Need for Action 

Draft NUREG-1437, Supplement 42 1-2 February 2010 

1 1.3 MAJOR ENVIRONMENTAL REVIEW MILESTONES 

2 Figure 1-1. Environmental Review Process. The environmental review provides opportunities 

3 for public involvement. 

4 

5 As part of its license renewal application, DAEC submitted an environmental report (ER) dated 

6 September 30, 2008 (FPL-DA, 2008). After reviewing the application and the ER for sufficiency, 

7 the Staff published a notice of acceptance for docketing of the application on February 17, 2009, 

8 in the Federal Register (FR) (73 FR 7489). On March 24, 2009, the NRC published another 

9 notice in the FR (74 FR 12399) on its intent to conduct scoping, thereby beginning a 60-day 

10 public scoping period for the supplemental environmental impact statement (SEIS). 
Purpose and Need for Action 

February 2010 1-3 Draft NUREG-1437, Supplement 42 

1 NRC conducted two public scoping meetings on 

2 April 22, 2009, in Hiawatha, IA. The Staff prepared 

3 an SEIS scoping process summary report dated 

4 August 7, 2009, which presents the comments 

5 received during the scoping process (NRC, 

6 2009a). Appendix A to this SEIS presents 

7 comments considered to be within the scope of the 

8 environmental license renewal review and the 

9 associated NRC responses. 

10 To independently verify information provided in the 

11 ER, the Staff conducted a site audit at the DAEC 

12 site in June of 2009. During the site audit, the Staff met with plant personnel, reviewed specific 

13 documentation, toured the facility, and met with interested Federal, State, and local agencies. A 

14 summary of that site audit and the attendees is contained in the site audit summary report 

15 (NRC, 2009b). 

16 On completion of the scoping period and site audit, the Staff compiled its findings in this draft 

17 SEIS (Figure 1-1). This SEIS is being made publicly available for a period of 75 days during 

18 which the Staff will host public meetings and collect public comments. Based on the information 

19 gathered, the Staff will amend the draft SEIS findings as necessary, and then publish the final 

20 SEIS. 

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

22 period of time with clear requirements to assure safe plant operation for up to an additional 20 

23 years. The safety review, which documents its finding in a safety evaluation report (SER), is 

24 conducted simultaneously with the environmental review process. Both the findings in the SEIS 

25 and the SER are factors considered in the Commission’s decision to either grant or deny the 

26 issuance of a new license. 

27 1.4 GENERIC ENVIRONMENTAL IMPACT STATEMENT 

28 To improve the efficiency of the license renewal process, the Staff prepared a generic 

29 assessment of the environmental impacts associated with license renewal. Specifically, the 

30 agency prepared NUREG-1437, Generic Environmental Impact Statement (GEIS) for License 

31 Renewal of Nuclear Power Plants, which evaluates the environmental consequences of 

32 renewing the licenses of individual nuclear power plants and operating them for an additional 20 

years (NRC 1996, 1999).1 33 The Staff analyzed those environmental issues that could be resolved 

34 generically in the GEIS. 

35 The GEIS investigates 92 separate issues for Staff to consider. Of these, the Staff determined 

36 that 69 are generic to all plants (Category 1), while 21 issues do not lend themselves to generic 

37 consideration (Category 2). Two other issues remain uncategorized; environmental justice and 

38 the chronic effects of electromagnetic fields, which must be evaluated on a site-specific basis. 

39 Appendix B of this report lists all 92 issues. 

 

1

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

to the GEIS include the GEIS and Addendum 1. 

Significance indicates the 

importance of likely environmental 

impacts and is determined by 

considering two variables: context

and intensity. 

Context is the geographic, 

biophysical, and social context in 

which the effects will occur. 

Intensity refers to the severity of the 

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

Draft NUREG-1437, Supplement 42 1-4 February 2010 

1 For each environmental issue, the GEIS: (1) describes the activity that affects the environment; 

2 (2) identifies the population or resource that is affected; (3) assesses the nature and magnitude 

3 of the impact on the affected population or resource; (4) characterizes the significance of the 

4 effect for both beneficial and adverse effects; (5) determines whether the results of the analysis 

5 apply to all plants or not; and (6) considers whether additional mitigation measures are 

6 warranted or not for impacts that would have the same significance level for all plants. 

7 The GEIS assesses the significance of these issues, using the Council on Environmental 

8 Quality (CEQ) terminology for “significant.” The Staff established three levels of significance for 

9 potential impacts—SMALL, MODERATE, and LARGE. The three levels of significance are 

10 defined below: 

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

12 destabilize nor noticeably alter any important attribute of the resource. 

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

14 important attributes of the resource. 

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

16 attributes of the resource. 

17 The GEIS includes a determination of whether or not the analysis of the environmental issue 

18 could be applied to all plants and whether or not additional mitigation measures are warranted 

19 (Figure 1-2). Issues are assigned as a Category 1 or a Category 2 designation. As set forth in 

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

21 (1) The environmental impacts associated with the issue have been determined to apply 

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

23 or other specified plant or site characteristics. 

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

25 the impacts, except for collective offsite radiological impacts from the fuel cycle and from 

26 high-level waste and spent fuel disposal. 

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

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

29 are not likely to be sufficiently beneficial to warrant implementation. 

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

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

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

33 do not meet one or more of the criterion for Category 1 issues, and therefore, additional site34 specific review for these issues is required. The SEIS documents the results of that site-specific 

35 review. 
Purpose and Need for Action 

February 2010 1-5 Draft NUREG-1437, Supplement 42 

1 Figure 1-2. Environmental Issues Evaluated during License Renewal. Ninety-two issues 

2 were initially evaluated in the GEIS. A site-specific analysis is required for 23 of those 92 issues. 

3 

4 1.5 SUPPLEMENTAL ENVIRONMENTAL IMPACT STATEMENT 

5 This SEIS presents an analysis of the environmental effects of the continued operation of the 

6 DAEC, potential alternatives to license renewal, and potential mitigation measures for 

7 minimizing adverse environmental impacts. Chapter 8 contains analyses and comparisons of 

8 environmental impacts from alternatives. Chapter 9 presents the preliminary recommendation to 

9 the Commission as to whether or not the environmental impact of license renewal are so great 

10 that preserving the option of license renewal would be unreasonable. The recommendation will 

11 be made after consideration of comments received during the public scoping period and the 

12 public comment period for the draft SEIS. 
Purpose and Need for Action 

Draft NUREG-1437, Supplement 42 1-6 February 2010 

New and significant information 

either: 

(1) identifies a significant environmental 

issue not covered in the GEIS, or 

(2) was not considered in the analysis in 

the GEIS and leads to an impact finding 

that is different from the finding 

presented in the GEIS. 

1 In preparation of this SEIS, the Staff: 

2 ● reviewed the information provided in the FPL-DA ER 

3 ● consulted with other Federal, State, and local agencies 

4 ● conducted an independent review of the issues during site audit 

5 ● considered the public comments received during the scoping process and 

7 on the draft SEIS. 

9 New and significant information can be 

11 identified from a number of sources, including 

13 the Staff, the applicant, other agencies, and 

15 public comments. If a new issue is revealed, it is 

17 first analyzed to determine whether or not it is 

19 within the scope of the license renewal 

21 evaluation. If it is not addressed in the GEIS, 

23 then the NRC determines its significance and 

25 documents its analysis in the SEIS. 

26 1.6 COOPERATING AGENCIES 

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

28 agencies in the preparation of this SEIS. 

29 1.7 CONSULTATIONS 

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

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

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

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

34 fisheries, or historic and archaeological resources, respectively. 

35 Listed below are the agencies and groups with whom the NRC consulted; Appendix D of this 

36 report includes copies of consultation documents. 

37 ● Iowa Department of Natural Resources 

38 ● Region 3, U.S. Fish and Wildlife Service 

39 ● Iowa State Archaeologist, Office of the State Archaeologist 

40 ● Historic Preservation Officer, State Historical Society of Iowa 
Purpose and Need for Action 

February 2010 1-7 Draft NUREG-1437, Supplement 42 

1 1.8 CORRESPONDENCE 

2 Table 1-1 lists persons and organizations to which a copy of this draft SEIS is sent. 

3 Appendix E to this report contains a chronological list of all documents sent and received during 

4 the environmental review. During the course of the environmental review, the Staff 

5 corresponded or consulted with the following Federal, State, regional, local, or tribal agencies: 

6 Advisory Council on Historic Preservation 

7 National Oceanographic and Atmospheric Administration, National Marine 

8 Fisheries Service 

9 State Archaeologist, Office of the State Archaeologist 

10 Historic Preservation Officer State Historical Society of Iowa 

11 Iowa Department of Natural Resources 

12 Region 3, U.S. Fish and Wildlife Service 

13 Flandreau Santee Sioux Tribe 

14 Ho-Chunk Nation 

15 Iowa Tribe of Oklahoma 

16 Kickapoo Tribe in Kansas 

17 Prairie Band of Potawatomi Indians 

18 Prairie Island Indian Community 

19 Sac and Fox Nation of Missouri 

20 Sac and Fox Nation of Oklahoma 

21 Santee Sioux Nation 

22 Shakopee Mdewakanton Sioux Community of Minnesota 

23 Upper Sioux Community of Minnesota 

24 Winnebago Tribe of Nebraska 

25 The Sac and Fox Tribe of the Mississippi 

26 Lower Sioux Indian Community of Minnesota 

27 Omaha Tribal Council 

28 Kickapoo Tribe of Oklahoma 

29 Otoe-Missouria Tribe of Indians 

30 Iowa Tribe of Kansas and Nebraska 
Purpose and Need for Action 

Draft NUREG-1437, Supplement 42 1-8 February 2010 

1 Table 1-1. List of persons who are sent a copy of this draft SEIS 

Mr. M. S. Ross 

Florida Power & Light Company 

Ms. Marjan Mashhadi 

Florida Power & Light Company 

T. O. Jones, VPVice President 

Florida Power & Light Company 

Steven R. Catron, Manager 

Duane Arnold Energy Center 

U.S. Nuclear Regulatory 

Commission 

Resident Inspector’s Office 

Mano Nazar 

Sr. VP and Nuclear Chief 

Operating Officer, Florida Power 

& Light Company 

D. A. Curtland 

Duane Arnold Energy Center 

Abdy Khanpour, VP 

Florida Power & Light Company 

Melanie Rasmusson 

Iowa Department of Public Health 

Linn County 

Board of Supervisors 

Peter Wells, Acting VP 

Florida Power & Light Company 

U.S. Environmental Protection 

Agency 

Mark E. Warner, VP 

Florida Power & Light Company 

Fredia Perkins, Chairperson 

Sac and Fox Nation of Missouri 

Christie Modlin, Chairperson, 

Iowa Tribe of Oklahoma 

Steve Cadue, ChairmanKickapoo 

Tribe in Kansas 

Steve Ortiz, Chairman 

Prairie Band of Potawatomi 

Indians 

Joshua Weston, President, 

Flandreau Santee Sioux Tribe 

Roger Trudell, Chairman 

Santee Sioux Nation 

John Blackhawk 

Winnebago Tribe of Nebraska 

Ronald Johnson 

Prairie Island Indian Community 

Stanley R. Crooks 

Shakopee Mdewakanton Sioux 

Community of Minnesota 

Kevin Jensvold 

Upper Sioux Community of 

Minnesota 

Wilfred Cleveland 

Ho-Chunk Nation 

Dusky Terry 

Central Iowa Power Cooperative 

Bennett Brown 

member of the public 

Amir H. Moazzez 

member of the public 

Adrian Pushetonequa 

The Sac and Fox Tribe of the 

Mississippi 

Lori Nelson 

Lower Sioux Indian Community of 

Minnesota 

Amen Sheriden 

Omaha Tribal Council 

Marlon E. Frye 

Kickapoo Tribe of Oklahoma 

John Shotton 

Otoe-Missouria Tribe of Indians 

Leon Campbell 

Iowa Tribe of Kansas and 

Nebraska 

Dr. Roy Crabtree, NOAA 

National Marine Fisheries Service 

Wayne Gieselman, Administrator 

Iowa Department of Natural 

Resources 

Tom Melius, Regional 3 Director 

U.S. Fish and Wildlife Service 

Charlene Dwin Vaughn 

Assistant Director 

Advisory Council on Historic 

Preservation 

John Doershuck 

State Archaeologist 

Office of the State Archaeologist 

Jerome Thompson 

Interim State Historic Preservation 

Officer 

State Historical Society of Iowa 

George Thurman, Principal Chief 

Sac and Fox Nation of Oklahoma 

2 1.9 STATUS OF COMPLIANCE 

3 FPL-DA is responsible for complying with all NRC regulations and other applicable Federal, 

4 State, and local requirements; Appendix C describes some of the principle Federal statutes for 

5 which FPL-DA must comply. Table 1-2 lists the numerous permits and licenses issued by 

6 Federal, State, and local authorities for activities at DAEC. 
Purpose and Need for Action 

February 2010 1-9 Draft NUREG-1437, Supplement 42 

1 Table 1-2. Licenses and Permits. Existing environmental authorizations for Duane Arnold 

2 Energy Center Operations. 

Permit/License Number Date Responsible Agency 

License to operate 

DAEC DPR-49 Issued: 02/21/1974 

Expires: 02/21/2014 

U.S. Nuclear Regulatory 

Commission 

Hazardous materials 

shipment registration 

070908 550 

040QS 

Issued: 07/09/2008 

Expires: 06/30/2011 

U.S. Department of 

Transportation 

Hazardous waste 

generation/transport IAD984566133 N/A U.S. Environmental Protection Agency 

Permit for water intake 

and discharge structures 

and low head dam on 

Cedar River 

71-192 Issued: 08/06/1971 

Iowa Department of 

Natural Resources 

(DNR) 

Permit to store water in 

Pleasant Creek 

Reservoir and withdraw 

water from Cedar River 

3533-R3 Issued: 03/14/2004 

Expires:03/13/2014 Iowa DNR 

Dredging for 

constructing spur dikes 

and subsequent 

maintenance dredging 

05-I-113-08-02-S Issued: 08/26/2005 Iowa DNR 

Dredging for spur dikes 

and subsequent 

maintenance dredging 

CEMVR-OD-P-2005-

1016 

Issued: 09/20/2005 

Expires: 12/31/2010 

U.S. Army Corps of 

Engineers 

Flood Plain 

Development Permit PF07-015 Issued: 12/04/2007 

Expires: 12/04/2008 Linn County 

Sovereign Lands 

Construction Permit 06-141 Issued: 10/10/2006 

Expires: 12/31/2008 Iowa DNR 

Sovereign Lands 

Construction Permit 07-175 Issued: 11/07/2007 

Expires: 12/31/2009 Iowa DNR 

Drinking water system 

operation certification Operator ID# 6007 Issued: 08/29/2007 

Expires: 06/30/2009 Iowa DNR 

NPDES Permit 57-00-1-04 

IA0003727 

Issued: 07/06/2007 

Expires: 07/05/2009 Iowa DNR 

Air Operation Permit 

4863, 4864, 4865, 

4866, 4867, 

4868, 4869, 4870 

Expires 11/10/2008 Linn County 

Transportation service 

license N/A Issued: 06/25/2007 

Expires: 06/30/2009 

Iowa Department of 

Public Health 

Permit to operate public 

water system ID# IA5715150 Issued: 11/21/2006 

Expires: 12/31/2009 Iowa DNR 

Permit to operate 4-well 

system for potable water 

3046-MR5 

SDWIS Well ID#s: 

WL04, WL05, W06, 

WL07 

Issued: 07/01/2002 

Expires: 06/30/2012 Iowa DNR 

Underground storage 

tanks N/A N/A Iowa DNR 

License to ship 

radioactive material T-IA-001-L08 Expires: 12/31/2008 

Tennessee Department 

of Environment and 

Conservation 

License to ship 

radioactive material 0210001768 Expires: 10/27/2008 Utah Department of 

Environmental Quality 
Purpose and Need for Action 

Draft NUREG-1437, Supplement 42 1-10 February 2010 

1 1.10 REFERENCES 

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

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

4 Federal Register (FR). U.S. Nuclear Regulatory Commission (NRC) . Washington DC. “Notice 

5 of Acceptance for Docketing of the Application and Notice of Opportunity for Hearing Regarding 

6 Renewal of Facility Operating License No. DPR-49 for an Additional 20-Year Period for FPL 

7 Energy Duane Arnold, LLC Duane Arnold Energy Center,” Vol. 74, No. 30, Page 7489-7491. 

8 February 17, 2009. 

9 FPL Energy Duane Arnold LLC (FPL-DA). Duane Arnold Energy Center, License Renewal 

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

11 Stage, Duane Arnold Energy Center. September 2008. 

12 FR. NRC. Washington DC. “FPL Energy Duane Arnold, LLC; Duane Arnold Energy Center; 

13 Notice of Intent to Prepare an Environmental Impact Statement and Conduct Scoping Process,” 

14 Vol. 74, No. 55, Page 12399-12401. March 24, 2009. 

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

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

17 National Environmental Policy Act of 1969. §42 United States Code (U.S.C.) §4321, et seq. 

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

19 U.S. Code of Federal Regulations (CFR). “Environmental Protection Regulations for Domestic 

20 Licensing and Related Regulatory Functions,” Part 51, Title 10, “Energy.” 

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

22 License Renewal of Nuclear Plants. NUREG-1437, Vol. 1 and 2, Washington, DC, 1966. 

23 ADAMS Accession Nos. ML040690705 and ML040690738. 

24 NRC. Generic Environmental Impact Statement for License Renewal of Nuclear Plants, Main 

25 Report, “Section 6.3 – Transportation, Table 9.1, Summary of Findings on NEPA Issues for 

26 License Renewal of Nuclear Power Plants, Final Report.” NUREG-1437, Vol. 1, Add. 1, 

27 Washington, DC, 1999. 

28 NRC, 2009a. Issuance of the Environmental Scoping Summary Report for the Staff’s Review of 

29 the License Renewal Application for Duane Arnold Energy Center (Tac No. MD9770). August 7, 

30 2009. Adams Accession No. ML092030185. 

31 NRC, 2009b. Summary of Environmental Site Information Review (Site Audit), Related to 

32 Review of the License Renewal Application for Duane Arnold Energy Center (Tac No. MD9770). 

33 July 2, 2009. Adams Accession No. ML091750075. 
February 2010 2-1 Draft NUREG-1437, Supplement 42 

1 2.0 AFFECTED ENVIRONMENT 

2 Duane Arnold Energy Center (DAEC) is located in Linn County, Iowa, on the western bank of a 

3 north-south reach of the Cedar River, approximately two miles north-northeast of the town of 

4 Palo and approximately three miles east of the Benton County line. Figure 2-1 shows the 

5 location of DAEC within a six-mile radius. 

6 Because existing conditions are partially the result of past construction and operation at the 

7 plant, the impacts of these past and ongoing actions and how they have shaped the 

8 environment are presented in this chapter. Section 2.1 of this report describes the DAEC site, 

9 facility, and its operation; Section 2.2 discusses the affected environment; and Section 2.3 

10 describes related Federal and State activities near the DAEC site. 

11 

12 Figure 2-1. Location of Duane Arnold Energy Center, within a 6-Mile Radius 

13 (Source: (FPL-DA, 2008a, Figure 2.1-1) 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-2 February 2010 

1 2.1 FACILITY AND SITE DESCRIPTION AND PROPOSED PLANT OPERATION 

2 DURING THE RENEWAL TERM 

3 DAEC is located in a rural, sparsely populated area. The site encompasses approximately 500 

4 acres (Figure 2-2 shows an aerial photograph of the plant site, switchyard, and transmission 

5 lines). DAEC uses only a small portion of the acreage for power production; the remaining 

6 portion is leased to area farmers (FPL Energy Duane Arnold, LLC (FPL-DA), (FPL-DA, 2007a). 

7 The site's property boundary and facility layout are shown in Figure 2-3 (FPL-DA, 2005a). The 

8 site is located on a strip of land running northeast and parallel to the Cedar River, which is the 

9 largest tributary of the Iowa River. The site is a flat plain, approximately 750 feet above mean 

10 sea level. The general topographical features in this portion of the Cedar River consist of broad 

11 valleys and narrow flood plains. Across the Cedar River from the site, the land rises to an 

12 elevation of about 900 feet. The slopes are heavily wooded, but away from the immediate 

13 vicinity of the river, the land is gently rolling farmland (FPL-DA, 2005a). 

14 

15 Figure 2-2. Plant Site, Switchyard, and Transmission Lines (Source: FPL-DA, 2008a) 
Affected Environment 

February 2010 2-3 Draft NUREG-1437, Supplement 42 

1 

2 Figure 2-3. Duane Arnold Energy Center Property Boundaries and Facility Layout 

3 (Source: FPL-DA 2008a, Figure 2.1-3) 

4 Three metropolitan areas lie within 50 miles of the DAEC site: Waterloo, approximately 34 miles 

5 to the northwest; Iowa City, approximately 32 miles to the southeast; and Cedar Rapids, the 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-4 February 2010 

1 closest city, approximately 5.7 miles to the southeast (Figure 2-4 shows a map of DAEC within a 

2 50-mile radius). Industrial activities within 10 miles of the site are confined principally to the 

3 Cedar Rapids metropolitan area. There is no significant industrial activity near the site. 

4 Manufacturing is the single-most important industry to the Linn County economy (USCB, 2005). 

5 Smaller communities in the vicinity of the site consist of small retail businesses. 
Affected Environment 

February 2010 2-5 Draft NUREG-1437, Supplement 42 

1 

2 Figure 2-4. Location of Duane Arnold Energy Center, within a 50-Mile Radius 

3 (Source: FPL-DA, 2008a) 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-6 February 2010 

1 Located one mile northwest of the site is the Pleasant Creek State Recreation Area, a 1,927-

2 acre park. Included in this acreage is a 410-acre lake that was jointly developed by the Iowa 

3 Conservation Commission and the Iowa Electric Light and Power Company to provide a 

4 supplemental water supply for DAEC and, at the same time, regional recreation opportunities 

5 (IDNR, 2007a). 

6 Recreational activities at several park areas within 10 miles of the site consist of boating, 

7 fishing, hunting, camping, hiking, picnicking, and swimming. Palo Marsh Wildlife Refuge, located 

8 two miles south of DAEC, is a 144-acre site featuring a wetland trail and bottomland forest for 

9 wildlife observation. Wickiup Hill is a 563-acre natural area located across from Cedar River just 

10 east of DAEC, which includes the 240-acre Wickiup Hill Outdoor Learning Area and a 10,000-

11 square foot learning center (LCCD, 2007). Cedar Rapids offers many attractions that draw 

12 visitors from surrounding areas, including the annual Cedar Rapids Freedom Festival which is 

13 typically a 16-day event (Cedar Rapids, 2007). 

14 The DAEC employs more than 600 Iowans and is the only nuclear reactor in the State of Iowa 

15 (FPL-DA, 2007a). The nuclear reactor is a single General Electric (GE) boiling water reactor 

16 (BWR) of the standard BWR-4 design, with a generating capacity of 610 gross megawatts 

17 electric (MWe). Two mechanical draft cooling towers are used, drawing water from the Cedar 

18 River (Figure 2-2). Water used in the reactor and most other plant systems is piped in from the 

19 site’s well water supply (FPL-DA, 2007a). Other site structures include an administration 

20 building, control building, turbine building, radwaste building, low-level radwaste processing and 

21 storage building, pump house, intake structure, and off-gas stack. The independent spent fuel 

22 storage installation (ISFSI) is located on the northern part of the site’s property (Figure 2-3). The 

23 following sections describe key features of DAEC, including reactor and containment systems, 

24 cooling water system, and transmission system. Also included in the scope of this chapter are 

25 six transmission lines that connect the DAEC to the regional grid. 

26 2.1.1 Reactor and Containment Systems 

27 Conceptually, a BWR design is not difficult to understand. A BWR uses water, which acts as a 

28 coolant and neutron moderator (Figure 2-5). A neutron moderator is a substance (e.g., light 

29 water) that slows the speed of neutrons allowing them to strike uranium-235 atoms contained 

30 within the reactor vessel. As the uranium-235 atoms are struck by the slower moving neutrons, 

31 they fission, or split apart (Figure 2-6). When uranium atoms fission, they produce heat. This 

32 heat causes the cooling water to boil, producing steam. The steam is directed to a turbine, 

33 causing it to spin. The spinning turbine is connected to a generator, which generates electricity. 

34 This electricity is transmitted along electrical transmission lines to power homes, offices, 

35 businesses, and industries. The steam is directed to a condenser where it cools and converts 

36 back to liquid water. This cool water is then cycled back to the reactor core, completing the loop. 
Affected Environment 

February 2010 2-7 Draft NUREG-1437, Supplement 42 

1 

2 Figure 2-5. Simplified Design of a Boiling Water Reactor 

3 (http://www.nrc.gov/reading-rm/basic-ref/students/animated-bwr.html) 

4 

5 

6 Figure 2-6. The Process of Nuclear Fission. Figure illustrates how a slow neutron collides 

7 with a uranium-235 atom (target nucleus). This collision causes the uranium-235 atom to split 

8 into two lighter atoms (fission products). This collision also releases other neutrons that then go 

9 on to strike more uranium-235 atoms, producing a sustaining nuclear chain reaction. As the 

10 uranium-235 atom splits, it releases energy in the form of heat.

11 (http://www.cfo.doe.gov/me70/manhattan/images/FissionChainReaction.gif) 

12 

13 As indicated earlier, DAEC is a single unit plant with a BWR that uses a BWR-4 reactor design 

14 and a Mark I primary containment design. The nuclear steam supply system and the turbine15 generator were supplied by GE. The nuclear steam supply system at DAEC is typical of GE 

16 BWRs. The balance of the plant was designed and constructed by Bechtel Power Corporation 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-8 February 2010 

1 (BPC) as the architect-engineer and construction contractor. The primary containment for the 

2 unit consists of a drywell, a steel structure that encloses the reactor vessel and related piping; a 

3 pressure suppression chamber containing a large volume of water; and a vent system that 

4 connects the drywell to the suppression chamber. The concrete reactor building, which houses 

5 the primary containment, serves as a radiation shield and fulfills a secondary containment 

6 function (FPL-DA, 2008a). 

7 The reactor is fueled using slightly enriched (less than 5 weight percent) uranium dioxide pellets 

8 sealed in Zircoly-2 tubes with an average batch burnup between 33,000 and 60,000 megawatt 

9 days per metric ton uranium. DAEC was originally licensed for a thermal output of 

10 1,658 megawatts thermal (MWt) and a gross electrical output of 541 MWe. In 2001, the plant 

11 received a license amendment that increased the thermal output to 1,912 MWt. The generating 

12 capacity for the plant was increased to about 610 gross MWe power. 

13 DAEC-generated radioactive waste is addressed in Section 2.1.2. Section 2.1.3 describes 

14 DAEC nonradioactive waste streams. 

15 2.1.2 Radioactive Waste Management 

16 The DAEC facility includes a radioactive waste system, which collects, treats, and provides for 

17 disposal of radioactive and potentially radioactive wastes that are byproducts of plant 

18 operations. Byproducts are activation products resulting from the irradiation of reactor water and 

19 impurities therein (principally metallic corrosion products) and fission products resulting from 

20 defective fuel cladding or uranium contamination within the reactor coolant system. Radioactive 

21 waste system operating procedures ensure that radioactive wastes are safely processed and 

22 discharged from the plant within the limits set forth in the Code of Federal Regulations (CFR), 

23 10 CFR Part 20, “Standards for Protection against Radiation,” and 10 CFR Part 50, “Domestic 

24 Licensing of Production and Utilization Facilities.” 

25 The DAEC produces radioactive wastes in the form of liquid, gaseous, or solid waste 

26 streams. Radioactive liquid wastes are generated from liquids received directly from portions of 

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

28 system. Radioactive gaseous wastes are generated from gases or airborne particulates vented 

29 from reactor and turbine equipment containing radioactive material. Solid radioactive wastes are 

30 solids from the reactor coolant system, solids that contacted reactor coolant system liquids or 

31 gases, or solids used in the reactor coolant system or the power conversion system. 

32 When reactor fuel has been exhausted, a certain percentage of its fissile uranium content is 

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

34 with fresh fuel assemblies during routine refueling outages, typically every 24 months. Spent 

35 fuel assemblies are stored in the spent fuel pool. In addition to the spent fuel pool, spent nuclear 

36 fuel is stored in dry casks, located in a secure area onsite (FPL-DA, 2008a). 

37 2.1.2.1 Radioactive Liquid Waste 

38 A liquid radioactive waste system consists of subsystems that allow liquid wastes from various 

39 sources to be segregated and processed separately. Radioactive liquids are recycled within the 

40 plant to the extent practicable. Although allowed by U.S. Nuclear Regulatory Commission (NRC) 
Affected Environment 

February 2010 2-9 Draft NUREG-1437, Supplement 42 

1 regulations, the DAEC has not made batch release of liquid radioactive waste into the Cedar 

2 River since 1985. The liquid waste is processed, solidified, and shipped offsite for disposal. 

3 Cross connections between the subsystems provide flexibility to process the wastes by 

4 alternative methods. Liquid wastes are classified, collected, and treated as high purity, low 

5 purity, chemical, detergent, sludge, or spent resins. The terms high purity and low purity refer to 

6 the conductivity and not the radioactivity. The liquid waste system design provides for the 

7 filtration and demineralization of effluents. Organics in the radioactive liquids may be processed 

8 by an ultraviolet ozone treatment system (FPL-DA, 2008a). 

9 DAEC radioactive effluent release reports for 2004 through 2008 for liquid effluents were 

10 reviewed by the NRC Staff (Staff) (FPL-DA 2005b, 2006, 2007b, 2008b, 2009a). As reported by 

11 the applicant, there were no routine, periodic liquid batch discharges into the Cedar River. As 

12 indicated earlier, the liquid waste is processed and solidified for shipment to a disposal facility; 

13 however, there were small volume discharges from the sanitary sewage facility in 2007 and 

14 2008 that contained small amounts of tritium. Tritium in the sanitary sewage facility originated 

15 from radioactive gaseous effluents discharged from the plant. Tritium, in the form of tritiated 

16 water vapor, was condensed by building air conditioning units and air compressors. 

17 Condensation is routed to the sewage treatment facility and the transformer pit. This mechanism 

18 was validated by the applicant’s radiological environmental monitoring program 

19 (FPL-DA, 2008b, 2009a). All samples were within NRC standards. 

20 Based on the liquid waste processing system’s performance from 2004 through 2008, the liquid 

21 discharges from the sanitary sewage system for 2008 are consistent with the radioactive liquid 

22 effluents discharged from 2004 through 2007. The applicant is expected to maintain its zero 

23 radioactive liquid effluent policy during the license renewal term. The quantities of reported 

24 radioactive liquid wastes are reasonable and no unusual trends were noted. 

25 2.1.2.2 Radioactive Gaseous Waste 

26 The facility’s gaseous waste disposal system processes and disposes of radioactive gaseous 

27 effluent to the atmosphere. Gaseous wastes are processed through a recombiner-charcoal 

28 delay system to reduce radioactive materials in gaseous effluents before discharge to meet the 

29 dose limits in 10 CFR Part 20 and the dose design objectives in Appendix I to 10 CFR Part 50. 

30 Gaseous effluents are released to the atmosphere from the plant’s offgas stack. Gaseous 

31 effluents are continuously monitored and the discharges are terminated if the effluents exceed 

32 pre-set radioactivity levels (FPL-DA, 2008a). 

33 Radioactive effluent release reports for 2004 through 2008 for gaseous effluents were reviewed 

34 by the Staff (FPL-DA 2005b, 2006, 2007b, 2008b, 2009a). Based on the gaseous waste 

35 processing system’s performance from 2004 through 2008, the gaseous discharges for 2008 

36 are consistent with the effluents discharged from 2004 through 2007. Variations on the amount 

37 of radioactive effluents released from year to year are expected based on the overall 

38 performance of the plant and the number and scope of outages and maintenance activities. The 

39 radioactive gaseous wastes reported by DAEC are reasonable and no unusual trends were 

40 noted. 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-10 February 2010 

1 2.1.2.3 Radioactive Solid Waste 

2 The radioactive solid waste system processes wet and dry solid wastes. The wet solid wastes 

3 are composed of spent demineralizer resins and filter sludge that are byproducts of plant water 

4 treatment processes. The dry solid wastes consist of air filters, contaminated clothing, and used 

5 reactor equipment generated from operation and maintenance activities (FPL-DA, 2008a). 

6 Because of differences in radioactivity or contamination levels of the many wastes, various 

7 methods are employed for processing and packaging. The disposition of a particular item of 

8 waste is determined by its radiation level, type, presence of hazardous material, and the 

9 availability of disposal space. Compressible material is compacted into either 55-gallon drums 

10 by a hydraulic press or metal containers by a box trash compactor. 

11 DAEC also generates and temporarily stores small quantities of low-level mixed waste (LLMW). 

12 Low-level mixed waste is waste that exhibits hazardous characteristics and contains low levels 

13 of radioactivity. The mixed waste is stored in the Low–Level Radwaste Processing and Storage 

14 Facility per DAEC’s Treatment Storage and Disposal Permit. When sufficient quantities are 

15 amassed, the material is sent to a licensed processor who separates the hazardous material 

16 from the radioactive material. The hazardous material is sent to a waste processor for 

17 disposition while the radioactive component is sent for offsite burial at a licensed disposal facility 

18 (FPL-DA, 2008a). 

19 The State of South Carolina’s licensed low-level radioactive waste (LLW) disposal facility, 

20 located in Barnwell, has limited the access from radioactive waste generators located in states 

21 that are not part of the Atlantic Low-Level Waste Compact. Iowa is not a member of the Atlantic 

22 Low-Level Waste Compact. This has had a negligible affect on DAEC’s ability to handle its 

23 LLW. Radioactive wastes are shipped to offsite facilities for treatment, disposal, or both. In the 

24 past, DAEC has shipped waste to facilities in Pennsylvania and Tennessee for treatment prior to 

25 disposal at a permitted radioactive waste landfill in South Carolina or Utah. DAEC primarily uses 

26 the Utah facility for disposal. Shipments have been made in accordance with Department of 

27 Transportation (DOT) requirements by truck and by rail. 

28 DAEC LLW reports for 2004 through 2008 were reviewed by the Staff (FPL-DA 2005b, 2006, 

29 2007b, 2008b, 2009a). The solid waste volumes and radioactivity amounts generated in 2008 

30 are typical of previous annual waste shipments. Variations in the amount of solid radioactive 

31 waste generated and shipped from year to year are expected based on the overall performance 

32 of the plant and the number and scope of outages and maintenance activities. The volume and 

33 activity of solid radioactive wastes reported by DAEC are reasonable and no unusual trends 

34 were noted. 

35 No plant refurbishment activities were identified by the applicant as necessary for the continued 

36 operation of DAEC through the license renewal term. Routine plant operational and 

37 maintenance activities currently performed will continue during the license renewal term. Based 

38 on past performance of the radioactive waste system, and the lack of any planned 

39 refurbishment activities, similar amounts of radioactive solid waste are expected to be 

40 generated during the license renewal term. 
Affected Environment 

February 2010 2-11 Draft NUREG-1437, Supplement 42 

1 2.1.2.4 Nonradioactive Hazardous Waste Streams 

2 The Resources Conservation and Recovery Act (RCRA) governs the disposal of solid and 

3 hazardous waste. RCRA regulations are contained in Title 40, “Protection of the Environment,” 

4 Parts 239 through 299 (40 CFR 239, et seq.). Parts 239 through 259 of these regulations cover 

5 solid (nonhazardous) waste, and Parts 260 through 279 regulate hazardous waste. RCRA 

6 Subtitle C establishes a system for controlling hazardous waste from “cradle to grave,” and 

7 RCRA Subtitle D encourages States to develop comprehensive plans to manage nonhazardous 

8 solid waste and mandates minimum technological standards for municipal solid waste landfills. 

9 Solid waste, defined by RCRA, is generated by the facility as part of routine plant maintenance, 

10 cleaning activities, and plant operations. Iowa is a part of the Environmental Protection Agency 

11 (EPA) Region VII. The EPA authorized the State of Iowa to regulate and oversee most of the 

12 solid waste disposal programs, as recognized by Subtitle D of the RCRA. Compliance is 

13 assured through State-issued permits. The State of Iowa and local governments are the primary 

14 planning, permitting, regulating, implementing, and enforcement agencies for management and 

15 disposal of household and industrial or commercial nonhazardous solid wastes in the State. 

16 Some of the Federal waste regulations are incorporated by the Iowa Administrative Code (IAC) 

17 (IAC 567, Ch.100 - 121). 

18 The EPA classifies certain nonradioactive wastes as “hazardous” based on characteristics 

19 including ignitability, corrosivity, reactivity, or toxicity (identification and listing of hazardous 

20 waste is available in 40 CFR Part 261). State-level regulators may add wastes to the EPA’s list 

21 of hazardous wastes. RCRA provides standards for the treatment, storage, and disposal of 

22 hazardous waste for hazardous waste generators (40 CFR Part 262). The EPA recognizes 

23 three main types of hazardous waste generators (40 CFR 260.10) based on the quantity of the 

24 hazardous waste produced: 

25 ● Large quantity generators (LQGs) that generate 2,200 pounds 

26 (1,000 kilograms (kg)) per month or more of hazardous waste, more than 

27 2.2 pounds (1 kg) per month of acutely hazardous waste, or more than 220 

28 pounds (100 kg) per month of acute spill residue or soil. 

29 ● Small quantity generators (SQGs) that generate more than 220 pounds 

30 (100 kg), but less than 2,200 pounds (1,000 kg), of hazardous waste per 

31 month. 

32 ● Conditionally exempt small quantity generators (CESQGs) which generate 

33 220 pounds (100 kg) or less per month of hazardous waste, or 2.2 pounds 

34 (1 kg) or less per month of acutely hazardous waste, or less than 220 

35 pounds (100 kg) per month of acute spill residue or soil. DAEC is a small 

36 quantity generator of non-acute hazardous waste. 

37 Under the Emergency Planning and Community Right-to-Know Act (EPCRA), applicable 

38 facilities are required to provide information on hazardous and toxic chemicals to local 

39 emergency planning authorities and the EPA (Title 42, Section 11001, of the United States 

40 Code (U.S.C.) (42 U.S.C. 11001)). On October 17, 2008, the EPA finalized several changes to 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-12 February 2010 

1 the Emergency Planning (Section 302), Emergency Release Notification (Section 304), and 

2 Hazardous Chemical Reporting (Sections 311 and 312) regulations that were proposed on 

3 June 8, 1998 (63 Federal Register (FR) 31268). DAEC is subject to Federal EPCRA reporting 

4 requirements, and thus submits an annual Section 312 (TIER II) report on hazardous 

5 substances to local emergency agencies. 

6 Wastes that contain both low level radioactive waste and RCRA hazardous waste are referred 

7 to as LLMW (40 CFR 266.210). The EPA (or any authorized State agency) regulates the 

8 hazardous component of the mixed waste through RCRA, and NRC regulates radioactive waste 

9 subject to the Atomic Energy Act of 1954 (AEA). DAEC has not generated any LLMW during the 

10 last five years. 

11 The facility generates small amounts of hazardous wastes including spent and expired 

12 chemicals, laboratory chemical wastes, and occasional project-specific wastes. Used oil, 

13 produced during operation of DAEC, is sent offsite to the EPA-approved hazardous waste 

14 disposal facility (FPL-DA, 2008a). The EPA classifies several hazardous wastes as universal 

15 wastes; these include batteries, pesticides, mercury-containing items, and fluorescent lamps. In 

16 the State of Iowa, EPA Region VII administers Federal universal wastes regulations 

17 (EPA, 2009a). 

18 Biocide and chemical wastes are generated during normal operating processes at DAEC that 

19 control the pH of the coolant, control scale and erosion in the cooling system, and clean and 

20 mechanically remove biofouling microorganisms from water circulation piping. The periodic use 

21 of chlorine and bromine in the water circulating system and cooling water system is stipulated in 

22 DAEC National Pollutant Discharge Elimination System (NPDES) permit No. 5700104, issued 

23 by the Iowa Department of Natural Resources (IDNR) (FPL-DA, 2008a). 

24 2.1.2.5 Mixed Waste 

25 The term “mixed waste” refers to waste that contain both radioactive and hazardous 

26 constituents. Mixed wastes are stored in the Low Level Radwaste Processing and Storage 

27 Facility per DAEC’s Treatment Storage and Disposal Permit. When sufficient quantities are 

28 amassed the material is sent to a licensed processor who separates the hazardous material 

29 from the radioactive material. The former is dispositioned by the processor while the radioactive 

30 component is sent for offsite burial (DAEC 2005a) 

31 2.1.2.6 Pollution Prevention and Waste Minimization 

32 In 2008, FPL-DA initiated a recycling program at DAEC that focuses on pollution prevention, 

33 waste minimization, and education of personnel. As a result of the DAEC recycling efforts, 

34 14 tons (12.7 metric tons) of the office paper, 6 tons (5.4 metric tons) of cardboard, 

35 5,000 pounds (2.27 metric tons) of batteries, 6,800 pounds (3.08 metric tons) of electronic 

36 waste were recycled in the first four months of the implemented program. 

37 To promote nonradiological waste minimization efforts, the EPA’s Office of Pollution Prevention 

38 and Toxics has established a clearinghouse that provides information regarding waste 

39 management and technical and operational approaches to pollution prevention (EPA, 2009b). 

40 The EPA’s clearinghouse can be used as a source for additional opportunities for waste 

41 minimization and pollution prevention at DAEC, as appropriate. 
Affected Environment 

February 2010 2-13 Draft NUREG-1437, Supplement 42 

1 Additionally, the EPA encourages use of Environmental Management Systems (EMSs) for 

2 organizations to assess and manage the environmental impact associated with their activities, 

3 products, and services in an efficient and cost-effective manner. The EPA defines an EMS as “a 

4 set of processes and practices that enable an organization to reduce its environmental impact 

5 and increase its operating efficiency.” EMSs help organizations fully integrate a wide range of 

6 environmental initiatives, establish environmental goals, and create a continuous monitoring 

7 process to help meet those goals. The EPA Office of Solid Waste especially advocates the use 

8 of EMSs at RCRA-regulated facilities to improve environmental performance, compliance, and 

9 pollution prevention (EPA, 2009c). FPL-DA is taking the initial steps in adopting an International 

10 Organization for Standardization (ISO) 14001 EMS at the DAEC site. 

11 2.1.3 Facility Operation and Maintenance 

12 Various types of maintenance activities are performed at DAEC, including inspection, testing, 

13 and surveillance to maintain the current licensing basis of the facility and to ensure compliance 

14 with environmental and safety requirements. Various programs and activities currently exist at 

15 DAEC to maintain, inspect, test, and monitor the performance of facility equipment. These 

16 maintenance activities include inspection requirements for reactor vessel materials, boiler and 

17 pressure vessel in-service inspection and testing, a maintenance structures monitoring program, 

18 and maintenance of water chemistry. 

19 Other programs include those implemented in response to NRC generic communications, those 

20 implemented to meet technical specification surveillance requirements, and various periodic 

21 maintenance, testing, and inspection procedures. Certain program activities are performed 

22 during the operation of the unit, while others are performed during scheduled refueling outages. 

23 Nuclear power plants must periodically discontinue the production of electricity for refueling, 

24 periodic in-service inspection, and scheduled maintenance. 

25 2.1.4 Power Transmission System 

26 Six transmission lines connect DAEC to the regional electric grid, all of which are owned and 

27 maintained by Information Technology Council (ITC) Midwest LLC. Unless otherwise noted, the 

28 discussion of the power transmission system is adapted from the environmental report (ER) 

29 (FPL-DA, 2008a) or information gathered at NRC’s environmental site audit. 

30 Two 345 kV lines connect to an existing 345 kV line, and three 161 kV lines deliver power to 

31 three substations (i.e., Washburn, Bertram, and Hiawatha). One additional 161-kV line connects 

32 to the Sixth Street Generating Station substation; the additional 161-kV line is not described in 

33 the final environmental statement (FES) related to the operation of DAEC (AEC, 1973) because 

34 it was constructed in 1978, after publication of the FES. The transmission lines cross through 

35 Linn, Benton, and Black Hawk counties, Iowa. In total, the transmission lines associated with the 

36 operation of DAEC comprise approximately 1,370 acres (554 hectares (ha)) and span 101 miles 

37 (163 km) of transmission line rights-of-way (ROWs). Generally, the transmission line ROWs 

38 pass through regions of agriculture and forested land. 

39 Transmission lines considered in-scope for license renewal are those constructed specifically to 

40 connect the facility to the transmission system (10 CFR 51.53(c)(3)(ii)(H)); therefore, the Hills, 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-14 February 2010 

1 Hazelton, Washburn, Bertram, Hiawatha, and Sixth Street lines are considered in-scope for this 

2 supplemental environmental impact statement (SEIS) and are discussed in detail below. 

3 Figure 2-7 contains a map of the DAEC transmission system. The six transmission lines are as 

4 follows (see Table 2-1): 

5 ● Hills Line: This 345-kV line extends west for 2.7 miles (4.3 km), at which 

6 point it turns south and connects to the Hills substation feed. This line 

7 shares a 500-foot (153-m) wide ROW with the Hazelton, Washburn, and 

8 the Bertram lines for approximately 0.34 mile (0.55 km), at which point the 

9 Bertram line splits off. For the remainder of its length, the line shares a 

10 665-foot (203-m) wide ROW with the Hazelton and the Washburn lines. 

11 This line is contained within Linn County. 

12 ● Hazelton Line: This 345-kV line extends west for 2.7 miles (4.3 km) parallel 

13 to the Hills line and also connects to the Hills substation feed. This line 

14 shares a 500-foot (152-m) wide ROW with the Hills, Washburn, and the 

15 Bertram lines for approximately 0.34 mile (0.55 km), at which point the 

16 Bertram line splits off. For the remainder of its length, the line shares a 

17 665-foot (203-m) wide ROW with the Hills and the Washburn lines. This line 

18 is contained within Linn County. 

19 ● Washburn Line: This 161-kV line extends west for 16 miles (26 km) to the 

20 Garrison substation and then an additional 30 miles (48 km) to the 

21 Washburn substation. This line shares a 500- to 665-foott (152- to 203-m) 

22 ROW with the Hills and Hazelton lines, as described above, and the 

23 remainder of the ROW ranges from 60 to 120 feet (18 to 37 km) wide. This 

24 line spans Linn, Benton, and Black Hawk counties. 

25 ● Bertram Line: This 161-kV line extends west for 0.34 mile (0.55 km) and 

26 then continues southeast for a total distance of 28 miles (45 km) to the 

27 Bertram substation. This line shares a 665-foot (203-m) wide ROW, as 

28 described above, and then has a 100-foot (30-m) wide ROW for the 

29 remainder of the line. This line is contained within Linn County. 

30 ● Hiawatha Line: This 161-kV line extends east for 8 miles (13 km) to the 

31 Hiawatha substation. This line’s ROW varies from 60 to 120 feet (18 to 

32 37 km) in width. The line crosses the Cedar River and is contained within 

33 Linn County. 

34 ● Sixth Street Line: This 161-kV line extends southwest around the city of 

35 Palo and then continues southeast following a railroad corridor to the center 

36 of the city of Cedar Rapids. The total length of this line is 16 miles (26 km), 

37 and its ROW varies from 60 to 120 feet (18 to 37 km) in width. This line is 

38 contained within Linn County. 
Affected Environment 

February 2010 2-15 Draft NUREG-1437, Supplement 42 

1 

2 Figure 2-7. Duane Arnold Energy Center Transmission Line System 

3 (Source: FPL-DA, 2008a, Figure 3.1-1) 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-16 February 2010 

1 In addition to these six transmission lines, two substations were constructed for the operation of 

2 DAEC; the DAEC substation, located about 0.25 mile (0.4 km) west of the plant, and the 

3 Hiawatha substation, located approximately 8 miles (13 km) east of the plant. 

4 ITC employs an integrated vegetative management program, which utilizes a combination of 

5 manual, mechanical, biological, and chemical control techniques and is directed by certified 

6 foresters and planners. ITC conducts biannual aerial inspections of transmission lines to identify 

7 areas that require maintenance. A follow-up ground inspection is completed for any areas that 

8 have been marked as requiring maintenance, and a complete span-by-span inspection is 

9 completed once every three years. ITC maintains a 26-foot (8-m) clearance for 230-kV lines and 

10 a 30-foot (9-m) clearance for 345-kV lines on either side of the lines. The majority of the in11 scope transmission lines traverse agricultural land. Those areas that are not already cultivated 

12 or developed in some other way are maintained to promote herbaceous vegetation, which 

13 includes shrubs, bushes, and other low-growing groundcover. The EPA-approved herbicides 

14 may be used to prevent regrowth from tree stumps and to control incompatible woody 

15 vegetation. A minimum of a 50-foot (15-m) buffer is maintained in areas near streams and 

16 wetlands. ITC maintains a database that includes known threatened and endangered species 

17 locations, raptor nests, and natural heritage areas to ensure that workers are aware of areas for 

18 which special consideration is required. 

19 All transmission lines were designed and built in accordance with industry standards in place at 

20 the time of construction. All transmission lines will remain a permanent part of the transmission 

21 system and will be maintained by ITC regardless of DAEC continued operation (FPL-DA, 

22 2008a); however, the Hazelton and Hills lines, which tie into the Hills substation feed, would be 

23 deactivated if the DAEC switchyard were no longer in use and would need to be reconnected to 

24 the grid if they were to remain in service beyond the operation of DAEC. 

25 Table 2-1. Duane Arnold Energy Center Transmission Lines. Six transmission lines convey 

26 electricity from DAEC to the regional electric transmission system via four ROWs. 

Approximate Distance ROW Width(a) Approx. 

ROW Area(b)

Line Owner kV mi (km) ft (m) ac (ha) 

Hills ITC 345 2.7 (4.3) 665 (203) 218 (88) 

Hazelton ITC 345 2.7 4.3) 665 (203) 218 (88) 

Washburn ITC 161 46 (74) 60 to 120 (18 to 37) 502 (203) 

Bertram ITC 161 28 (45) 100 (30) 339 (137) 

Hiawatha ITC 161 8 (13) 60 to 120 (18 to 37) 87 (35) 

Sixth Street ITC 161 16 (26) 60 to 120 (18 to 37) 175 (71) 

(a)ROW widths for the Washburn, Hiawatha, and Sixth Street lines are approximations and vary along the length of 

each line. 

(b)ROW area for the Washburn, Hiawatha, and Sixth Street lines are approximated using 90 feet (27 m) as the 

average ROW width for these lines. 

Source: (FPL-DA, 2008a) 
Affected Environment 

February 2010 2-17 Draft NUREG-1437, Supplement 42 

1 2.1.5 Cooling and Auxiliary Water Systems 

2 DAEC uses a closed-cycle heat dissipation system that withdraws water from, and discharges 

3 cooling tower blowdown to, the Cedar River. DAEC employs two cross-flow mechanical forced 

4 draft cooling towers to dissipate heat from the plant’s steam cycle to the atmosphere. Unless 

5 otherwise noted, the discussion of the cooling water system is adapted from the ER (FLP-DA, 

6 2008a), or information gathered at the site audit. 

7 Water that is lost through cooling tower evaporation, wind, and as blowdown returned to the 

8 Cedar River is termed “makeup” water. Makeup is withdrawn from the Cedar River via a 

9 reinforced concrete intake structure located on the west bank of the river. During low flow, an 

10 overflow barrier located across the river intercepts the streambed flow and diverts it to the intake 

11 structure, thereby making available the entire flow of river water. 

12 Incoming water is directed into the underground portion of the intake structure and passes 

13 through vertical bar racks at a rate of 0.3 feet per second (ft/s) (0.09 meters per second (m/s)). 

14 Water then passes through trash racks, spaced 3 inches (8 cm) apart, which removes debris 

15 accumulated on the bar racks before the water enters two parallel intake channels. Once water 

16 enters the intake channels, it passes through automated wire mesh traveling screens to remove 

17 any impinged aquatic organisms or remaining debris. After passing through the traveling 

18 screens, the water flows into one of two pump wet pits containing vertical turbine pumps, which 

19 empty water into a pipe. Water from the two parallel pathways is then recombined into a single 

20 pipe, which discharges into the stilling basin in the pump house. This basin supplies water for 

21 the circulating water system, the general service water system, and the fire water system, as 

22 well as back-up for residual heat removal service water and emergency service water. 

23 Under normal operation, a maximum of 11,200 gallons per minute (gpm) (25 cubic feet per 

second (cfs) or 0.71 cubic meters per second (m3 24 /s)) of makeup water is withdrawn from the 

25 Cedar River. This water is circulated through the condenser to dissipate heat and then travels to 

the cooling towers at a rate of 155,000 gpm (345 cfs or 9.78 m3 26 /s) per tower, or 310,000 gpm 

(691 cfs or 19.6 m3 27 /s) overall. Of the water that is transferred to the cooling towers, 8,100 gpm 

(18 cfs or 0.51 m3

/s) is lost as evaporative dissipation and 3,100 gpm (6.9 cfs or 0.20 m3 28 /s) is 

29 lost as blowdown, which is returned to the Cedar River. The remaining water, approximately 

298,800 gpm (665.7 cfs or 18.85 m3 30 /s), is recirculated through the condenser for cooling. 

31 2.1.6 Facility Water Use and Quality 

32 The DAEC relies on the Cedar River as its source of makeup water for its cooling system, and it 

33 discharges various waste flows to the river. An onsite well system provides groundwater for 

34 other site needs. The following sections describe the water use. 

35 2.1.6.1 Groundwater Use 

36 Groundwater at the DAEC is present in river alluvium, unconsolidated glacial deposits, and 

37 deep sedimentary bedrock formations (FPL-DA 2007c). At the plant, the surficial material is 

38 roughly 20 feet (6 meters) of alluvium, comprised of fine to coarse sand with some silt and 

39 gravel. It is underlain by roughly 12 to 80 feet (3.7 to 24 m) of clayey glacial till with lenses of 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-18 February 2010 

1 sand and gravel. The uppermost bedrock is the carbonate Wapsipinicon and Gower 

2 Formations, of middle Devonian and Upper Silurian age, respectively.

3 The alluvial aquifer is recharged by precipitation and locally by periodic flooding or river 

4 recharge. Flow is southeasterly, toward the Cedar River (FPL-DA, 2007c). Groundwater in the 

5 bedrock is under confined conditions and also flows toward the river. Minor sand and gravel 

6 units may be present within the glacial drift. 

7 Facility production wells are finished in the Wapsipinicon and Gower Formations. During the 

8 2008 flood, the production wellheads are reported to have stayed above water. 

9 DAEC (FPL-DA, 2007d) provided a list of the closest residences to the power plant. All 16 of the 

10 residences rely on private well water. They range from 0.5 to 2.3 miles (0.8 to 3.7 km) from the 

11 site. The private wells located west and north of the DAEC are hydraulically upgradient of the 

12 plant (FPL-DA, 2007a). Some of these wells are within about one mile of the site boundary. 

13 Private wells south-southwest of the plant are cross-gradient. 

14 The four onsite production wells provide water for multiple purposes. Approximately 100 gpm is 

used for demineralizer makeup and less than 10 gpm (0.022 cfs or 0.00063 m3 15 /s) is used for 

16 potable supply (FPL-DA, 2008a). In addition, the largest usage, on the order of 1,400 to 1,500 

gpm (3.1 to 3.3 cfs or 0.088 to 0.094 m3 17 /s), is sent to an air cooling system (FPL-DA 2008A; 

18 FPL-DA undated #1). The wells also provide a backup water source for emergency reactor 

19 injection, the fire protection systems, and the reactor building closed cooling water (RBCCW) 

20 heat exchangers. 

21 The wells are named A, B, C, and D, and have total depths ranging from 285 to 380 feet (87 to 

22 116 m) (IDNR, 2005a). Well B is along the property’s west boundary. Wells A and C are in the 

23 southwest portion of the property. Well D is approximately 200 feet (61 m) north of the cooling 

24 towers and was installed in 1980. Wells A, B, and C were originally shallower, but were replaced 

25 by deeper bedrock wells in 2002, 1992, and 1999, respectively. Wells B and D are within their 

26 own buildings, while the wellheads for A and C are located outdoors. 

27 Normally, wells D and A run continuously, and wells B and C are used for backup (IDNR, 

28 2008a). The facility is permitted to pump a maximum annual quantity of 1,575 million gallons 

5.962 million m3 29 ) from the well system (IDNR, 2005a). Review of annual water use records (e.g., 

30 FPL-DA, 2009b) for calendar years 2001 to 2008 indicates an annual groundwater use of 612 to 

848 million gallons (2.32 to 3.21 million m3 31 ) . 

32 Water from Well D is chlorinated to allow use in plant systems (heating, ventilation, and air 

33 conditioning (HVAC), dry well coolers). The IDNR requires well water to meet drinking water 

34 standards if a chlorination system is used. 

35 2.1.6.2 Surface Water Use 

36 The DAEC is located in the Cedar River Basin and is built near the west bank of the Cedar 

37 River. At the DAEC site, the basin’s drainage area is approximately 6,250 square miles (16,200 

38 square km) (FPL-DA, 2007c). The Cedar River is a tributary of the Iowa River, 133 miles (214 

39 km) downstream from DAEC, and the combined flow is a tributary feeding into the Mississippi 

40 River. 
Affected Environment 

February 2010 2-19 Draft NUREG-1437, Supplement 42 

1 Between 1903 and 2008, flow in the Cedar River at Cedar Rapids, Iowa varied from a 

seven-day minimum of 224 cfs (6.34 m3 2 /s) in December 1989 to a maximum flow of 140,000 cfs 

(3,960 m3 3 /s) on June 13, 2008 during intense flooding (USGS, 2008). The average flow at the 

4 station is 3,878 cfs. Statistics for the station are presented in Table 2-2. Average flows are 

5 lowest in the winter and highest in the spring and early summer. 

6 Table 2-2. Monthly Flow Rates between 1903 and 2008 (Source: U.S. Geological Survey 

7 (USGS), 2008) 

Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 

Mean 

flow 

(cfs) 2,445 2,427 1,870 1,607 2,477 6,609 7,090 5,649 6,379 4,424 3,065 2,455 

Mean 

flow 

(m3

/s) 69 69 53 46 70 187 201 160 181 125 87 70 

 

Max 

flow 

(cfs) 12,100 9,327 8,675 8,529 12,230 17,420 35,320 24,500 46,450 33,910 28,700 13,990 

Max 

flow 

(m3

/s) 343 264 246 242 346 493 1000 694 1315 960 813 396 

Water 

Year 2008 1973 1983 1973 1984 1929 1993 1991 2008 1993 1993 1993 

 

Min 

flow 

(cfs) 463 410 290 299 304 664 1,045 527 350 533 377 466 

Min 

flow 

(m3

/s) 13 12 8 8 9 19 30 15 10 15 11 13 

Water 

Year 1990 1990 1990 1911 1940 1934 1957 1934 1934 1989 1934 1934 

8 

9 As was described in Section 2.1.6, the Cedar River is the water source for the DAEC circulating 

10 water and service water systems. The intake at the river water supply system provides makeup 

11 water to the circulating water system to offset the evaporation and blowdown losses at the 

12 cooling towers. This reinforced concrete intake also serves as intake for the residual heat 

13 removal service water (RHRSW) and the emergency service water (ESW). The intake is located 

14 on the west bank of the river; a series of wing dams on the east bank divert the flow toward the 

15 intake side. A permitted submerged dam was constructed across the Cedar River to maintain 

16 water depth near the intake (Iowa Natural Resources Council, 1971). 

The maximum river water requirements are 8,100 gpm (0.51 m3 17 /s) for evaporative losses and 

drift from the cooling towers and 3,100 gpm (0.20 m3 18 /s) for blowdown, for a total withdrawal rate 

of 11,200 gpm (0.71 m3 19 /s) (FPL-DA, 2007c). The facility is permitted to withdraw a maximum of 

12,575 million (47,602,000 m3 20 ) gallons per year from the Cedar River (IDNR, 2005a) for plant 

21 purposes. 

As part of DAEC construction, a reservoir was created about 2 miles (47,602,000 m3 22 ) northwest 

23 of the power plant, in a tributary to the Cedar River. The purpose of the 410-acre (166 hectare) 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-20 February 2010 

1 Pleasant Creek Recreational Reservoir is to supply water to the Cedar River during low-flow 

conditions. DAEC may withdraw up to 16,000 acre-feet/year (19,700,000 m3 2 /yr) from the Cedar 

3 River to replenish the Pleasant Creek Reservoir (IDNR, 2005a). The INDR (2005a) allows 

withdrawal of river water when flow in the Cedar River is greater than 937 cfs (26.5 m3 4 /s) as 

5 measured at a gage in Cedar Rapids. From April 1 to September 30, withdrawal is allowed if 

flow in Cedar Rapids is between 500 and 937 cfs (14.1 and 26.5 m3 6 /s), only if flow is increasing 

7 on a 24-hour basis. From October 1 to March 31, withdrawal is allowed if flow is greater than 

500 cfs (14.1 m3 8 /s). IDNR (2005a) allows DAEC to discharge water from the reservoir for 

9 low-flow augmentation at a rate equal to the DAEC consumptive use. 

10 2.2 AFFECTED ENVIRONMENT 

11 This section provides general descriptions of the environment near DAEC as background 

12 information and to support the analysis of potential environmental impacts in Chapter 4. 

13 2.2.1 Land Use 

14 As indicated earlier, DAEC is located on approximately 500 acres of land, 8 miles northwest of 

15 Cedar Rapids, Iowa, on the west bank of the Cedar River. The site is approximately 2.5 miles 

16 north-northeast of Palo, Iowa, in Linn County (AEC, 1973). The general topographical features 

17 in this portion of the Cedar River are broad valleys with relatively narrow flood plains. Across the 

18 river from the site, the land rises to an elevation of about 900 feet, and is heavily wooded with 

19 sporadic fields or pastures. Away from the immediate vicinity of the river, to the south and west 

20 of the site, the land is relatively flat agricultural land, while to the northwest of the site, the land 

21 rises and tends to be sparsely wooded farmland. 

22 Only a small portion of the site, consisting of a relatively flat plain approximately 750 feet above 

23 mean sea level (msl), is used by the power plant itself, with the remaining land leased for 

24 agricultural use (FPL-DA, 2008a). Power plant buildings include the turbine-generator building, 

25 control building, reactor building, administration building, pump house and low-level radioactive 

26 waste building, which are co-located to form the main plant complex (see Section 2.1). A 

27 switchyard, substation, and a large parking lot are located to the west of the main complex. A 

28 discharge canal runs from the cooling tower area to the river, where intake and pump house 

29 facilities are located. A small sanitary sewage treatment facility is located north of the complex, 

30 and an offgas stack is located to the south. 

31 Industrial activities within 10 miles of the site are primarily located in the Cedar Rapids 

32 metropolitan area; there is no significant industrial activity near the site (FPL-DA, 2008a). 

33 Manufacturing is the single most important industry in Linn County (see Section 2.2.8.6), while 

34 employment in smaller communities in the vicinity of DAEC is primarily in small retail 

35 establishments. 

36 The Pleasant Creek State Recreation Area, a 1,927-acre park, is located 1 mile northwest of the 

37 site. The park includes a 410-acre lake, jointly developed by the Iowa Conservation Commission 

38 and the Iowa Electric Light and Power Company to provide both a supplemental water supply 

39 for DAEC, and provide regional recreation opportunities (FPL-DA, 2008a). Recreational 

40 activities in the vicinity of the site include boating, fishing, hunting, camping, hiking, picnicking, 

41 and swimming. Palo Marsh Wildlife Refuge, located 2 miles south of DAEC, is a 144-acre site 
Affected Environment 

February 2010 2-21 Draft NUREG-1437, Supplement 42 

1 featuring a wetland trail and bottomland forest for wildlife observation. Wickiup Hill, located 

2 across the Cedar River to the east of the site, is a 563-acre natural area and includes the 

3 240-acre Wickiup Hill Outdoor Learning Area and 10,000-square foot Learning Center 

4 (FPL-DA, 2008a). 

5 2.2.2 Air and Meteorology 

6 The closest National Weather Service (NWS) station is located in nearby Cedar Rapids, IA 

7 (IDNR, 2008b). 

8 All of Iowa is in a humid, continental climate zone characterized by hot humid summers, cold, 

9 relatively dry winters, and wet springs. The Iowa Annual Weather Summary for 2008, issued by 

10 the Iowa State Climatologist, includes the following data which are representative of some of the 

11 weather extremes that are possible in Iowa (IDNR, 2009a). Temperatures averaged 45.8° F 

12 (7.67° C), which is about 2 degrees below normal. Precipitation totaled 43.79 inches (111 cm), 

which is about 9.71 inches (24.67 cm) above normal, making 2008 the 11th coolest and 4th 13 

14 wettest year among 136 years of state weather records. The statewide average rainfall of 9.03 

inches (22.93 cm) over the period May 29th to June 12th 15 resulted in widespread flooding over the 

16 southeastern two-thirds of Iowa with record flooding down the length of the Cedar River and 

17 along portions of the Des Moines, Iowa, and Mississippi Rivers. Cedar Rapids was the hardest 

18 hit with a June 13 flood crest 11 feet (3.35 m) higher than the previous record; however, despite 

19 record flooding and temporary flooding of site access roads, operations at the DAEC were 

20 unaffected. 

The State’s first F5 tornado since 1976 occurred on May 26, 2008.1 21 The NWS reported a total of 

22 105 tornados in the State in 2008, tying 2001 as the second highest annual total behind the 

120 tornados that occurred in 2004.2 23 Overall, there were 13 fatalities in Iowa in 2008 due to 

24 tornados (Iowa State Climatologist, 2009). 

25 Queries of the National Climate Data Center data base resulted in the following additional 

26 climate facts: over the period January 1, 1983 to December 31, 2008, Linn County, Iowa 

27 experienced 61 flood events, 14 funnel cloud sightings, 29 tornados ranging in intensity from F0 

28 to F4, inflicting property damage as high as $25 million, 235 thunderstorm and high wind events, 

29 and no wild fire or forest fire events (NOAA 2009a, 2009b, 2009c, 2009d, 2009e). 

 

1 The Fujita six-point scale (F0 to F5) is used to rate the intensity of a tornado based on the damage it inflicts to 

structures and vegetation. The lowest intensity is F0, the highest is F5. Fujita scale categories are based on 

estimated (not measured) sustained wind speeds compared against observed structural damage. The Enhanced 

Fujita Scale replaced the original Fujita Scale in February 2007. The Enhanced Fujita Scale still uses six categories 

of tornado intensity (EF0 to EF5) but defines those categories differently (NOAA, 2009). Overall, most tornados 

(around 77 percent) in the United States are EF0 or EF1 and about 95 percent are below EF3 intensity. 

Approximately 0.1 percent of all tornadoes reach EF5 status with sustained winds in excess of 200 miles per hour 

(mph) (NOAA, 2008). For additional information about the Fujita Scales, see the NOAA Web site and its hypertext 

links at: http://www.spc.noaa.gov/efscale/. 2 The annual average number of tornados in Iowa (since Doppler Radar was installed at NWS) is 56. The annual 

average for the United States is 1,200 (NOAA, 2009). 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-22 February 2010 

1 2.2.2.1 Air Quality 

2 Linn County is in the Northeast Iowa Intrastate Air Quality Control Region (AQCR) 

3 (40 CFR 81.256). All of Iowa, including Linn County, is currently in attainment for all National 

4 Ambient Air Quality Standards (NAASAQ) (40 CFR 81.316). Recent lowering of particulate 

5 matter (PM) at the 2.5 micrometer range (PM2.5) standard from 65 to 35 micrograms per cubic 

meter (ug/m3 6 ) in December 2006 has required a re-evaluation of the compliance status of 

7 certain areas of the State. Preliminary monitoring data, compiled by Air Quality Bureau of the 

8 IDNR monitoring program, has identified two counties bordering the Mississippi River that may 

be determined to be non-attainment for the PM2.5 standard;3 9 however, Linn County continues to 

10 be in attainment. 

11 IDNR Air Quality Bureau has primary responsibility for regulating air emission sources within the 

12 State of Iowa, and, with the assistance from EPA Region VII and the local programs in Polk and 

13 Linn counties, to develop a monitoring plan for the State. IDNR conducts ambient air monitoring 

14 in the State. The closest IDNR’s ambient air monitoring station to DAEC is located in Cedar 

15 Rapids, approximately 8 miles (13 km) northwest from DAEC. Three new monitors (PM2.5

16 standard, sulfur dioxide (SO2) and carbon monoxide (CO)) were added in 2008 to the Cedar 

17 Rapids monitoring site in Linn County (IDNR, 2009a). IDNR annually submits to the EPA, an 

18 Iowa Ambient Air Monitoring Network Plan that discusses in detail the establishment, 

19 maintenance, and updates of the air quality surveillance system for the criteria pollutants 

20 throughout the State of Iowa, as required in 40 CFR Part 58 (IDNR, 2008b). 

DAEC qualifies as a minor source4 21 under the Title V permit program and therefore is not 

22 required to obtain a Title V permit; however, eight stationary pollutant sources on DAEC operate 

23 under the auspices of permits issued by the Linn County Health Department: four emergency 

24 generators, one auxiliary boiler, one sulfuric acid tank, and two diesel fuel underground storage 

25 tanks. These permits establish limits for operation and require annual reports to the county. 

26 Sections 101(b)(1), 110, 169(a)(2) and 301(a) of the Clean Air Act (CAA) as amended 

27 (42 U.S.C. 7410, 7491(a)(2), 7601(a)) established 156 mandatory Class I Federal areas where 

28 visibility is an important value that cannot be compromised. There are no mandatory Class I 

29 Federal areas in the State of Iowa or within 62 miles (100 km) of DAEC. The closest Class I 

30 areas are the Boundary Waters National Wilderness Area and Voyageurs National Park in 

31 Minnesota, Badlands National Wilderness Area in North Dakota, and Hercules-Glades National 

Wilderness Area and Mingo National Wilderness Area in Missouri.5 32 Given the distances involved 

33 and the nature of the stationary air pollutant sources at DAEC, no adverse impacts on Class I 

34 areas are anticipated from continued DAEC operation. 

35 The primary meteorological tower is located approximately 1,700 feet (518 m) south-southeast 

36 of the reactor building and 1,125 feet (343 m) southeast of the offgas stack (FPL-DA 2005b). 

37 Land areas and topography immediately surrounding the tower, as well as the distance of the 

38 tower from the reactor building and other permanent structures suggest that no significant 

 

3 Near real-time ambient air quality data is available at: http://www.iowadnr.gov/air/current/current.html. 4 Under the Title V Operating Permit program, EPA defines a Major Source as a stationary source with the potential 

to emit (PTE) any criteria pollutant at a rate > 100 tons/year, or any single hazardous air pollutant (HAP) at a rate of > 

10 tons/year or a combination of HAPs at a rate > 25 tons/year. 5

 A complete listing of all Class I areas can be found at 40 CFR 81, Subpart D. 
Affected Environment 

February 2010 2-23 Draft NUREG-1437, Supplement 42 

1 interferences to air flow exist that would compromise the quality of recovered meteorological 

2 data; however, volunteer trees and shrubs that become established in proximity to the tower 

3 must be continuously eliminated to prevent interferences. Two clusters of instruments are 

4 mounted on the primary tower. A lower set of instruments, located at a height of 33 feet (10 m), 

5 records wind speed and direction, temperature, and dew point. The upper set of instruments, 

6 located at a height of 156 feet (48 m), also records wind speed and direction and temperature. 

7 Meteorological instruments record data digitally and also on strip recorders (used primarily as 

8 backup data capture). Digital data are displayed and recorded in the control room and on a 

9 backup computer disk, and input into a computerized safety parameter display system (SPDS) 

10 to serve as inputs to the emergency response plume dispersion models (if necessary) and for 

11 the purpose of establishing a historical record. To guarantee operational reliability, redundant 

12 power is supplied to the meteorological instruments and their respective data recorders. 

13 Meteorological instruments are calibrated semiannually, as well as being subjected to routine 

14 inspection and maintenance in accordance with the manufacturer’s specifications and DAEC 

15 internal procedures, which require visual inspections of the meteorological instruments, 

16 verification of the performance through measurements, and documenting the status of the key 

17 performance indicators. 

18 2.2.3 Groundwater Resources 

19 Installation of the current set of 12 monitoring wells began in 2006 (FPL-DA, 2007d). The wells 

20 are located in six nests (1 through 6), with an A and a B well at each location. The A series wells 

21 are about 14–30 feet (4.3–9.1 m) deep, while the B series wells are about 40–60+ (12.2–18.3+ 

22 m) feet deep. The wells currently lack a concrete pad at the surface. 

23 Annual radiological environmental monitoring program (REMP) reports document regular 

24 samplings of groundwater; reports for the years 2006 and 2007 (Environmental Inc. Midwest 

25 Laboratory, 2007, 2008a) were reviewed. These reports represent eight quarters of data, which 

26 reflect recent tritium concentration conditions. Quarterly sampling of the site water system and 

27 three nearby private wells during 2006–2007 yielded a maximum gross beta of 8.6±2.2 

28 picocuries per liter (pCi/L). Tritium results were all <193 pCi/L. Quarterly sampling of site 

29 monitoring wells began midway through 2006 at six well nests, with sampling at all six nests 

30 beginning in 2007. The maximum gross beta observed in the available 2006–2007 data was 

31 17.7±1.3 pCi/L in MW-06A. Tritium was consistently highest at MW-01A, with measurements of 

32 287±105 to 644±114 pCi/L. This well is located near the base of the stack, and the relatively 

33 high readings are attributed to washout of gaseous effluents (Environmental Inc. Midwest 

34 Laboratory, 2008b). These readings are much lower than the EPA threshold for tritium in 

35 drinking water of 20,000 pCi/L. Measurements at the other wells were all <198±98 pCi/L, with 

36 the exception of one quarter’s sample at MW-05A, which was 269±94 pCi/L. 

37 During the site audit, a representative of IDNR provided a copy of a recent inspection of the 

38 water supply system (IDNR, 2008a). The inspection noted a possible cross-connection to be 

39 eliminated and several minor deficiencies and recommendations regarding equipment and 

40 procedures. 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-24 February 2010 

The facility has a 20,000-gallon (76-m3 1 ) sulfuric acid tank with secondary containment, a 

50,000-gallon (189-m3

) diesel tank, and a 40,535-gallon (153-m3 2 ) diesel tank. The two diesel 

3 tanks are near the reactor. Their liquid level is monitored by a sensor and alarm system and by 

4 manual checks. Additional aboveground tanks for gasoline and diesel are located at the south 

5 warehouse; these were moved during the rising floodwaters in 2008 (FPL-DA, 2008c). 

6 2.2.4 Surface Water Resources 

7 Cedar River water quality is influenced by non-point source contaminants such as runoff of 

8 fertilizer and animal wastes, because most of the basin is agricultural. Point-source discharges 

9 from municipal wastewater treatment plants or industries may also affect water quality. 

10 Significant flooding in the Cedar River watershed and elsewhere in the Midwest took place in 

11 June 2008, breaching a levy in Cedar Rapids and resulting in evacuations and extensive 

12 damage (National Climatic Data Center, 2008). Aerial photos taken on June 11, 2008, and 

13 viewed during the site audit, show the key plant areas, including the cooling towers, to be above 

14 water. The river covered the ground at the intake structure. Operations continued during the 

15 flood; no internal flooding was present in the power block (FPL-DA, 2008c). Because the site 

16 ditch for stormwater and wastewater effluent was full, effluent could not flow as normal to its 

17 outfall. Instead, the treated effluent was pumped from the wastewater treatment plant over the 

18 road to the outfall’s receiving ditch, until the level in the ditch subsided (FPL-DA, 2008c). 

19 The U.S. Geological Survey (USGS, 2008) collected samples at Cedar Rapids on 

20 June 19, 2008 to assess the effect of the ongoing flood on water quality. Nutrients in the water 

21 included total nitrogen (unfiltered) at 8.76 milligrams per liter (mg/L), orthophosphorous as P 

22 (filtered) at 0.146 mg/L, and phosphorous as P (unfiltered) at 0.325 mg/L. Atrazine was 

23 measured as 0.92 micrograms per liter (ug/L). A variety of organics were found to be below 

24 detection levels. The USGS (2008) notes that prior water quality analyses from Cedar Rapids 

25 samples were performed in 1906–1907 and 1944–1954. 

26 New shoreline protection was emplaced in 2008 along the west bank of the Cedar River, 

27 downstream of the tributary ditch of stormwater and sewage treatment facility (STF) effluent. 

28 This action took place after the 2008 flood to counter erosion that took place during the flooding. 

29 The improvement consists of large pieces of limestone. 

30 The EPA granted the State of Iowa the authority to issue NPDES permits, and such a permit 

31 implies water quality certification under the Federal Clean Water Act (CWA) Section 401. The 

32 State has provided the DAEC with an NPDES permit for Outfalls 001 and 002, subject to 

33 effluent limitations, monitoring requirements, and other stipulations (operation is allowed to 

34 continue pending state action) as discussed below (IDNR, 2004a). The current permit expired 

35 July 5, 2009. An application has been made for a new NPDES permit (FPL-DA, 2008d). A 

36 currently valid permit must be in place prior to issuing a license renewal. 

37 Outfall 001 is the discharge point for cooling tower blowdown and stormwater runoff. It is located 

38 near the power block in a discharge canal. The outfall is a pipe entering the canal; stormwater 

39 enters via another pipe about 30 feet (9 m) away. Effluent limitations are focused on pH, 

40 chlorine, chromium, zinc, acute toxicity, and duration of chlorine discharge. At Outfall 001, 

41 monitoring requirements include the following parameters, at varying sample frequencies: flow, 
Affected Environment 

February 2010 2-25 Draft NUREG-1437, Supplement 42 

1 pH, total residual chlorine, chromium, temperature, zinc, duration of chlorine discharge, acute 

2 toxicity, and visual observation. Monthly reporting is required. 

3 For the cooling water system, the State (IDNR, 2003) has permitted the use of Spectrus CT 

4 1300 (Betz), Spectrus NX 1107 (Betz), Spectrus OX 1201 (Betz), or Macrotech, Inc.’s 

5 electrolytic copper technology. 

6 The effluent from Outfall 001, along with stormwater, flows in a narrow open ditch toward the 

7 Cedar River. At the riverbank, the flow enters an 18-inch (46-cm) diameter pipe with a reducer 

8 to 15-inch (38-cm) diameter, flows under a sheet pile structure, and is released in a diffuser 

9 along the bottom of the river. The pipe openings are oriented so that discharge is aimed 

10 downstream and upward at a 20 degree angle. The diffuser is cleaned out using suction 

equipment. When flow in the canal exceeds 4,000 gpm (9 cfs or 0.25 m3 11 /s), such as during 

12 heavy precipitation, flow goes over a weir at the discharge structure, into an open canal, and 

13 then into the river. 

14 IDNR (2005b) granted a Water Quality Certification pursuant to Section 401 of the Clean Water 

15 Act for the construction of four spur dikes (or wing dams) on the Cedar River and for dredging. 

16 The approval includes mechanical dredging of a 1,250-foot (381-m) long by 50-foot (15-m) wide 

17 channel, with future maintenance dredging as needed. Dredged materials were to be hauled to 

18 an upland disposal site on the DAEC property. These actions were also approved by the U.S. 

19 Army Corps of Engineers (USACE) (Department of the Army, 2005). 

20 Prior to the installation of wing dams, dredging near the intake is reported to have taken place 

21 annually. Dredged sediments were used to create the site firing range under permit of USACE 

22 (Department of the Army, 2005; IDNR, (2005b). Following the 2008 flood, river flow had lowered 

23 the river bottom near the intake to a level 12 feet (3.7 m) below the minimum level (IIHR, 2008). 

24 Therefore, no channel dredging is anticipated in the near future. 

25 Outfall 002 is the discharge point for a sequencing batch reactor wastewater treatment plant 

26 treating domestic wastewater and stormwater. It is located where the plant’s discharge pipe 

27 enters a ditch across the street from the plant. The DAEC STF began operating in 1988 and has 

a design capacity of 54,000 gallons (204 m3 28 ) per day based on a 30-day average. Wastewater 

29 passes through the comminutor (grinder) before entering the first of two sequenced batch 

30 aerobic digesters for processing. Sludge, which is sampled once per year, is transferred to the 

31 nearby aerobic digestion tank for stabilization, and the wastewater is disinfected by chlorination 

32 prior to discharge at Outfall 002 (FPL-DA, 1988). The STF is operated by a contractor. 

Approximately 9,500 gallons (36 m3 33 ) per day of water are discharged to the Cedar River. The 

34 discharge flows in a pipe under the road to the south, discharging to an open ditch. Flow then 

35 mixes with stormwater in the ditch and is conveyed to the river at a point approximately 0.4 

36 miles (0.6 km) upstream of the location of the intake and the discharge (blowdown) canal. 

37 Effluent limitations are focused on a 5-day carbonaceous biochemical oxygen demand 

38 (5CBOD), total suspended solids (TSS), hydrogen-ion concentration or pH, total residual 

39 chlorine, and fecal coliform. At Outfall 002, monitoring requirements include the following 

40 parameters, at varying sample frequencies: 5CBOD, TSS, hydrogen-ion concentration or pH, 

41 temperature, flow, chlorine, fecal coliform, settleable solids, visual observation, dissolved 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-26 February 2010 

1 oxygen, and mixed liquor suspended solids. Sampling stations for particular parameters may be 

2 in the raw wastewater, the final effluent, the aeration basins, or the digester. Monthly reporting is 

3 required. 

4 As described earlier, an application has been made for a new NPDES permit (FPL-DA, 2008d). 

5 The application’s attachment list includes a list of proposed chemical additives for the term of 

6 the new permit (Table 2-3). The application notes an additional discharge under discussion with 

7 the IDNR. It is located near Outfall 001. The discharge is approximately 15 to 25 gpm (56 to 96 

8 liter per minute) continuously, with an additional 100 gpm (378 liter per minute) for six minutes, 

9 three times per day. The source of water is outflow from an inline corrosion monitor, inline pH 

10 monitors, the pump house sump pumps, and periodic strainer backwash from the general 

11 service water system. 

12 Table 2-3. Chemical Additives Listed in National Pollutant Discharge Elimination System 

13 Application (Source: FPL-DA, 2008d) 

Outfall Manufacturer Product Usage Rate Purpose Injection 

Point 

 001 GE Betz Continuum AEC 3110 50 gal/day (189 liter 

per day) 

Corrosion 

Inhibitor Cooling Tower 

 001 GE Betz Spectrus BD1501E 10 gal/day (38 liter 

per day) 

Minimize 

Scaling Cooling Tower 

 001 GE Betz Inhibitor AZ8100 Currently not in use Corrosion 

Inhibitor Cooling Tower 

 001 K.A. Steel 

Chemicals Sodium Hypochlorite 200 gal/day (757 liter 

per day) Algaecide Cooling Tower 

 001 Koch Sulfur 

Products Sulfuric Acid 93% 1,000 gal/day (3,785 

liter per day) pH Balance Cooling Tower 

 001 GE Betz Spectrus NX1007 

5 gal/week (19 liter 

per week), summer 

only 

Biocide Cooling Tower 

 001 GE Betz Corrshield MD4100 <10 gal/year (<19 liter 

per year) 

Corrosion 

Inhibitor 

Closed Cooling 

Systems 

 001 GE Betz Spectrus NX1105 (<0.26 gal/year) <1 

liter/year Biocide Closed Cooling 

Systems 

 001 GE Betz Spectrus NX1106 (<0.26 gal/year) <1 

liter/year Biocide Closed Cooling 

Systems 

 002 FMC Soda Ash 50 lbs/week (23 

kg/week) pH Balance 

Sewage 

Treatment 

Basins 

14 DAEC has a stormwater pollution prevention plan (FPL-DA, undated #2). The plan includes a 

15 listing of potential sources of pollutants and associated best management practices. 

16 A clay-lined sluice pond is located outside and south of the reactor area. In case of an event at 

17 the low-level radwaste processing and storage buildings, the pond would receive and retain its 

18 stormwater runoff. The sluice pond has no sampling program. 
Affected Environment 

February 2010 2-27 Draft NUREG-1437, Supplement 42 

1 During the 2008 flood, effluent was pumped overland to the ditch because a high water level in 

2 the ditch was preventing normal gravity flow from the STF. Chlorination continued during this 

3 flood event. 

4 The STF is listed in a State Web site as having no health-based violations in the last ten years 

5 (IDNR, 2009b). The Web site does, however, describe monitoring violations since 2005. These 

6 include three violations for three parameters (coliform, total trihalomethanes, and total 

7 haloacetic acids), each taking place in 2007–2008. State compliance was later achieved for total 

8 trihalomethanes and total haloacetic acids. 

9 At the site audit conducted by NRC, an IDNR representative provided a recent STF inspection 

10 report (IDNR, 2007b) and a written response (FPL-DA, 2007e). The response showed adequate 

11 resolution regarding modification of equipment and procedures. 

12 The NPDES permit prohibits any discharge of polychlorinated biphenyl (PCB) compounds such 

13 as those used for transformer fluid. Cooling tower blowdown resulting from maintenance 

14 chemicals may not contain any of the 126 priority pollutants listed in Appendix “A” of 40 CFR 

15 Part 423 except for chromium and zinc, as limited in the permit requirements. Neither free 

16 available chlorine nor total residual chlorine may be discharged from any source for more than 

17 two hours in any one day and not more than one source may discharge free available or total 

18 residual chlorine at any one time. No chemicals may be added to the circulating water system 

19 during offline conditions. The permit also calls for periodic sampling of the blowdown; 

20 stipulations on the frequency, duration, and concentration of molluscide treatments for zebra 

21 mussels; sewage sludge disposal requirements; and adherence to a stormwater pollution 

22 prevention plan. 

23 The IDNR (2009c) maintains Web-based information tracking systems that include DAEC data. 

24 Listed are 21 inspection dates from 1977–2007. No enforcement actions are noted. Monthly 

25 reported data are available from July 2004 to December 2008. These include several 

26 exceedences for the 5CBOD, total residual chlorine, TSS, and pH. The EPA (2009d) maintains 

27 a similar database tool, which tracks the monitoring data for the past 12 quarters. In three 

28 quarters from first quarter 2006 to fourth quarter 2008, the exceedences for 5CBOD were 

29 determined by EPA to be significant. TSS were significantly high in one quarter. 

30 Annual REMP reports document regular sampling of surface water; reports for 2006 and 2007 

31 (Environmental Inc. Midwest Laboratory, 2007, 2008a) were reviewed. Monthly results for 13 or 

32 more radioisotopes at the plant intake, the plant discharge (Outfall 001), an upstream location, a 

33 downstream location, and the Pleasant Creek reservoir were all below the laboratory reporting 

34 limit; tritium for example was <193 pCi/L in each case. At the STF discharge (Outfall 002), 

35 however, measurable activity concentrations ranging up to 382±98 pCi/L of tritium were 

36 observed in 7 of the 24 monthly samples. For the other months, tritium was <193 pCi/L, and the 

37 other 12 radionuclides were all below laboratory reporting limits. Environmental Inc. Midwest 

38 Laboratory (2008b) attributes the relatively high tritium readings in the summer to condensation 

39 of tritiated water vapor by plant air conditioner systems. Several elevated wintertime readings 

40 were attributed to radiation workers breathing tritium water vapor in the work environment and 

41 releasing this tritium in their urine. 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-28 February 2010 

1 2.2.5 Description of Aquatic Resources 

2 DAEC is located within the Cedar River Valley in Linn County, Iowa, on the western bank of the 

3 Cedar River, which is the largest tributary of the Iowa River. The headwaters of the Cedar River 

4 are located in Dodge County, Minnesota, where its tributaries, the Little Cedar and the Shell 

5 Rock rivers merge. The Cedar River flows southeast for 329 miles (529 km) through Iowa to its 

6 confluence with the Iowa River in Columbus Junction, Louisa County, Iowa, about 30 mi (48 km) 

7 upstream of the mouth of the Iowa River (Sullivan, 2000). The combined Cedar River and Iowa 

River Basins account for 12,640 mi2

 (32,740 km2 8 ) and are generally characterized by fertile 

9 farmland (Sullivan, 2000). 

10 In June 2008, heavy rainfall from late May to early June across the Midwest region caused 

11 major flooding events. The Iowa Statewide average rainfall was 9.03 inches (22.9 cm), which is 

12 6.58 inches (16.7 cm) above the normal level for the time period (NWS, 2009). The city of Cedar 

13 Rapids, located approximately 5.7 miles (9.2 km) southeast of DAEC, underwent mandatory 

14 evacuation in anticipation of the Cedar River water level rising above the city’s levee. On 

June 12, 2008, the levee broke, and approximately 1300 city blocks, or 9.2 mi2

 (15 km2 15 ) were 

16 submerged (MCEER, 2009). The Cedar River at Cedar Rapids rose to 31.10 ft (9.48 m), 

17 representing a 500-year recurrence interval and setting a new record flow of 150,000 cfs 

(4250 m3 18 /s) (IWSC, 2009). The Cedar River rose to a level 11.44 feet (3.49 m) higher than the 

19 previous record of 19.66 feet (5.99 km) set on March 31, 1961 (IWSC, 2009). 

20 2.2.5.1 Benthic Macroinvertebrates 

21 Benthic macroinvertebrates were monitored at the DAEC site from 1971 through 1999. 

22 McDonald (2000) observed that a diverse community of macroinvertebrates was unlikely to 

23 inhabit the area due to the riverbed’s sandy substrate, which is easily transported; thus, 

24 preventing establishment of a macroinvertebrate community. Artificial substrates were placed 

25 upstream of, downstream of, and in the discharge canal, and larger and more diverse benthic 

26 communities readily developed on these surfaces within a five-week period than what had 

27 previously been observed. A total of 30 taxa (26 species of insects, 1 annelid, 1 isopod, 1 

28 nematode, and 1 flatworm) were identified during two sampling periods in September and 

29 October of 1999. Nematoceran flies (family Chironomidae) and a species of netspinner caddisfly 

30 (Hydropsyche bidens) dominated all four sampling areas. Generally, diversity of organisms was 

31 significantly lower in the discharge canal sampling areas than in the river. Development of a 

32 diverse benthic community on artificial substrate during the sampling period suggests that the 

33 Cedar River’s natural substrates, and not poor quality of water, prevent the development of a 

34 diverse macroinvertebrate community (McDonald, 2000). 

35 Similarly, in the Cedar River Baseline Ecological Study Annual Report (McDonald,1972) 

36 conducted between April 1971 and April 1972, bottom samples in the vicinity of the site only 

37 yielded three benthic organisms mentioned in the report— tubificid worms, some chironomid 

38 larvae, and a significant population of the mayfly Stenoma in rocky, unsilted areas. This study 

39 concluded that scarce habitat, rather than water quality, prevented the development of larger, 

40 more diverse benthic populations (McDonald, 1972). 
Affected Environment 

February 2010 2-29 Draft NUREG-1437, Supplement 42 

1 2.2.5.2 Freshwater Mussels 

2 Approximately 55 species of native freshwater mussels were recorded in Iowa during European 

3 settlement; today, about 44 native species and 2 exotic species can be found within Iowa and in 

4 the Mississippi and Missouri rivers along the State’s border (CVRC&D, 2002). Within Iowa, 

5 mussels are historically important sources of food for Native Americans, and in the late 1800s, 

6 mussels were harvested for their shells, which were manufactured into pearl buttons until the 

7 1940s (CVRC&D, 2002). Overharvesting for the button industry greatly reduced the numbers of 

8 many of the mussel species native to Iowa. Freshwater mussel numbers have also been 

9 harmed by river damming because large areas of flowing, oxygenated water becomes 

10 low-flowing or stagnant after damming and no longer provides adequate mussel habitat. 

11 Competition with exotic mussel species and contaminants also threaten freshwater mussel 

12 species. 

13 Helms & Associates (2003) conducted mussel surveys in December 2002 along the west shore 

14 of the Cedar River upstream of the DAEC intake canal and found 14 individuals representative 

15 of 4 species, all of which are native to Iowa. Samples were collected via timed dive searches 

16 and whole-substrate collections along specified transects. The majority (10) of the individuals 

17 collected were plain pocketbook (Lampsilis cardium) (Helms, 2003), a species common to Iowa 

18 waters and found in small creeks to large rivers in a variety of substrate types (CVRC&D, 2002). 

19 Additionally, two black sandshells (Ligumia recta), one pink papershell (Potamilus ohiensis), and 

20 one white heelsplitter (Lasmigona complanata) (Helms, 2003) were found. Black sandshells and 

21 white heelsplitters are classified as uncommon by the IDNR and are generally found in interior 

22 rivers and streams (IDNR, 2001a; IDNR, 2001b). Black sandshells prefer riffles with gravel or 

23 sand substrate, and white heelsplitters prefer pools with mud of sand substrate (IDNR, 2001a; 

24 IDNR, 2001b). Pink papershells are common to Iowa waters and are generally found in the 

25 lower reaches of larger tributaries in slower moving waters and silt, mud, or sand substrate 

26 (IDNR, 2001c). An additional dead individual, a squawfoot (Strophitus undulatus), was collected 

27 during the 2002 survey. This species is threatened at the Iowa State level and is found in 

28 interior rivers and streams in mud, sand, or gravel substrate (IDNR, 2001d). More information 

29 about this species is provided in Section 2.2.7 of this draft SEIS. The study concluded that the 

30 substrate within the Cedar River near DAEC provides poor to marginal habitat for mussels, 

31 though a small population exists within the area (Helms, 2003). 

32 2.2.5.3 Fish 

33 In 1996, the USGS collected data on fish communities in eastern Iowa across 12 sites as part of 

34 the National Water-Quality Assessment (NAWQA) Program from mid-September to early 

35 October. A total of 56 fish species in 13 families were collected across all sites. Two of the data 

36 collection sites were located on the Cedar River: one at Gilbertville, Black Hawk County 

37 (upstream of the DAEC site), representative of water quality near both row-crop agriculture and 

38 urban development, and one near Conesville, Muscatine County, at the mouth of the Cedar 

39 River Basin (downstream of the DAEC site). (Sullivan, 2000) 

40 Minnows (Cyprinids) and suckers (Catastomids) dominated all large river sites that were 

41 sampled, including both of the Cedar River sites. At the upstream Cedar River site, minnows 

42 accounted for 81 percent of fish collected, followed by suckers (16 percent), sunfish 

43 (Centrarchids; 2 percent), catfish (Ictalurids; less than 1 percent), and perch (Percids; less than 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-30 February 2010 

1 1 percent). The most abundant species at the upstream site were spotfin shiner (Cyprinella 

2 spiloptera; 749 individuals), bluntnose minnow (Pimephales notatus; 527 individuals), river 

3 carpsucker (Carpoides cyprinus; 293 individuals), and sand shiner (Notropis stramineus; 130 

4 individuals). At the downstream Cedar River site, suckers accounted for nearly 45 percent and 

5 minnows accounted for 43 percent of fish collected, followed by catfish (9 percent); sunfish (2 

6 percent); and herrings (Clupids), temperate bass (Percichthyids), drums (Sciaenids), and gars 

7 (Lepisosteids) (each less than 1 percent). The most abundant species at the downstream site 

8 were river carpsucker (665 individuals), bullhead minnow (Pimephales vigilax; 485 individuals), 

9 channel catfish (Ictalurus punctatus; 137 individuals), and spotfin shiner (127 individuals). 

10 (Sullivan, 2000) 

11 The fish community within the Cedar River sites was rated “fair” by Sullivan (2000) using the 

12 States of Ohio and Wisconsin’s Index of Biotic Integrity (IBI). The IBI system integrates 

13 information at multiple levels including individual, population, community, and ecosystem to 

14 produce a numerical rating of a fish community’s health. Of the six large-river sites, the 

15 upstream and downstream Cedar River sites received the second and third highest IBI score, 

16 though fish communities at all sites were considered to be somewhat degraded compared to 

17 reference conditions. The report concluded that conversion of prairie for agricultural use and the 

18 increasing population along the Iowa and southern Minnesota rivers account for the majority of 

19 this trend. Eutrophication (excessive nutrients in a body of water caused by runoff of nutrients 

20 such as animal waste, fertilizers, sewage from the land) from agricultural and urban runoff; 

21 contamination from pesticides and other chemicals; soil erosion; and sedimentation were also 

22 cited as factors that have degraded the aquatic environment in eastern Iowa. (Sullivan, 2000) 

23 From 1979 through 1983, Ecological Analysts, Inc. conducted operational ecological studies for 

24 Iowa Electric Light and Power Company in the vicinity of the DAEC site. During the 5-year 

25 period, a total of 1347 fish representing 41 species and 8 families were collected. River 

26 carpsucker (Carpiodes carpio), spotfin shiner (Cyprinella spiloptera), and carp (Cyprinus carpio) 

27 were among the most prevalent fish collected each year, and generally, few differences were 

28 observed in species composition over the five years of sampling. During the 1983 sampling 

29 year, minnows (Cyprinids) accounted for 79.7 percent of fish collected, followed by suckers 

30 (Catastomids; 12 percent), sunfish (Centrarchids; 3.6 percent), catfish (Ictalurids; 2.8 percent), 

31 perch (Percids; 0.6 percent), and then herrings, pikes, and silversides (Clupids, Esocidae, and 

32 Atherinidae; each 0.1 percent). When compared, these sampling results are similar in species 

33 composition and density to the Sullivan (2000) study discussed above. (Ecological Analysts, 

34 1984) 

35 2.2.6 Description of Terrestrial Resources 

36 DAEC is located on the western bank of the Cedar River, a tributary of the Iowa River and, 

37 geologically, within the Midcontinent Rift System (MRS). The MRS began to form about 1100 

38 million years ago when tensional stresses, suggested to be the result of a mantle plume, caused 

39 a large fracture across the North American continent stretching in an arc from Kansas 

40 northeasterly through Lake Superior, and then southeasterly through lower Michigan (Anderson 

41 1997; Bornhorst et al. Undated). Subsequently, compressive stresses forced sedimentary rock 

42 upwards, redepositing older rock over new rock (Anderson 1997). Overall, the central portions 

43 of Iowa were uplifted as much as 30,000 ft (9,100 m) (Anderson 1997). A unique characteristic 

44 of this rift system is that it cuts across a number of Precambrian basement terranes, each of 
Affected Environment 

February 2010 2-31 Draft NUREG-1437, Supplement 42 

1 which have different age, structure, and composition (Schmus and Hinze 1985). The rift system 

encompasses nearly 42,000 mi2

 (67,600 km2 2 ) and is characterized by a central horst bounded 

3 by fault zones and bordered by basins (Anderson 1997). DAEC is located just east of the 

4 Williamsburg Basin, which is characterized by clastics, or rocks composed of pre-exisiting 

5 sedimentary rock, that was formed from the MRS. Black Hawk County, through which the 

6 Washburn transmission line passes, contains MRS clastics that reach thicknesses of up to 8000 

7 ft (2400 m) (IDNR 2006). 

8 The portion of the Cedar River on which the DAEC site is located generally consists of broad 

9 valleys and narrow floodplains and has an elevation of 750 ft (230 m) above msl. The DAEC site 

10 encompasses approximately 500 ac (200 ha), of which about 140 ac (57 ha) contain the 

11 generating facility, associated buildings, switchyard, parking lots, and mowed areas (FPL-DA, 

12 2008). Of the remaining 360 ac (143 ha), about 126 ac (51 ha) is leased for agricultural use, and 

13 the remaining land is composed of oak-hickory forest, marsh, and riparian and floodplain habitat 

14 (FPL-DA, 2008a). 

15 Predominating floodplain and riparian vegetation include silver maple (Acer saccharinum), 

16 green ash (Fraxinus pennsylvanica), box elder (A. negunde), and hawthorn (Crataegus mollis) 

17 (Neimann and McDonald, 1972). Understory species are less common within the vicinity of the 

18 DAEC site due to periodic flooding of the river floodplain. 

19 A variety of wildlife is known to inhabit the DAEC site, including white-tailed deer (Odocoileus 

20 virginianus), raccoon (Procyon lotor), muskrat (Ondatra zibethica), opossum (Didelphis 

21 virginiana), spotted skunk (Spilogale putorius), and striped skunk (Mephitis mephitis) (FLP-DA, 

22 2008a; Collins and MacDonald, 1972). Commonly observed birds include meadowlark 

23 (Sturnella spp.), barn swallows (Hirundo rustica), red-wing blackbirds (Agelaius phoeniceus), 

24 blue jays (Cyanocitta cristata), and wood duck (Aix sponsa) (FLP, 2008a). Bird surveys 

25 conducted for the FES, related to the operation of DAEC (AEC, 1973) also included pheasants 

26 and quail in the wooded areas as well as doves and crows. 

27 The U.S. osprey (Pandion haliaeetus) population declined significantly between 1950 and 1970 

28 due to the species’ sensitivity to the insecticide dichlorodiphenyltrichloroethane (DDT) and other 

29 chemicals (Cornell, 2003). After DDT was banned from use in 1972, the species’ numbers 

30 began to increase, but migration to new breeding areas remains low. The species is not 

31 endangered nor threatened at the Federal or State level; however, State agencies have been 

32 working together to expand the bird’s breeding range because ospreys experience suppressed 

33 reproductive ability as the population becomes more dense, as has been observed in the Great 

34 Lakes population. In July of 2004, the IDNR released 24 42-day-old ospreys at five sites around 

35 the state in an effort to expand the species’ distribution (IDNR, 2004b). The young ospreys were 

36 relocated from areas in Minnesota and Wisconsin so that surviving mature birds will return to 

37 Iowa to nest within three to four years of release. During this effort, five ospreys were released 

38 at Wickiup Hill, which is located just east of the site and across the river (IDNR, 2004b). As of 

39 2005, IDNR has recorded an active osprey nest at Hartman Reserve in Black Hawk County, and 

40 as of 2007, an active osprey nest at Wickiup Hill in Linn County (IDNR, 2008c). The pair that 

41 returned to Wickiup Hill is believed to be a pair that was released in 2006 (Fritzell, 2008). The 

42 pair incubated eggs in 2007, though none hatched (Fritzell, 2008). In 2008, three young 

43 hatched, but did not survive a storm in June (Fritzell, 2008). In July 2007, a nest site on the 280-
Affected Environment 

Draft NUREG-1437, Supplement 42 2-32 February 2010 

1 ft (85-m) DAEC meteorological tower was discovered (Fritzell, 2008). The pair is believed to be 

2 a separate nesting pair from the one recorded at nearby Wickiup Hill, though specific banding of 

3 the pair is unknown (Fritzell, 2008). The pair returned in 2008, however neither year resulted in 

4 successful hatching (Fritzell, 2008). DAEC staff has consulted with IDNR concerning the 

5 potential construction of artificial nesting platforms for the birds (FPL-DA, 2008a). 

6 DAEC maintains a U.S. Fish and Wildlife Service (FWS) Permit (FWS, 2009a) for depredation 

7 of turkey vultures. In the past, turkey vultures have nested on and caused interference with the 

8 communication towers on the site. This permit allows specified DAEC staff members to take 

9 four turkey vultures per year in the threatened area, which is defined as “private property or real 

10 property in danger of harm to its commercial value or recreational use” (FWS, 2009a). DAEC 

11 must submit an annual report to USFWS on January 31 of each year as a requirement of the 

12 permit. The 2008 Depredation Annual Report (FPL-DA, 2009c) specified that three turkey 

13 vultures had been killed in the 2008 calendar year. DAEC first sought this permit in 2008 and 

14 has since renewed it once. The current permit expires on March 31, 2010. 

15 Four parks or designated wildlife areas are located near the DAEC site: 

16 ● Pleasant Creek State Recreation Area is a 1927-ac (780-ha) park that is 

17 located 1 mi (0.6 km) northwest of the site (FPL-DA, 2008a). The park 

18 contains a 410-ac (166-ha) lake and is designated as an Important Bird 

19 Area in Iowa (IDNR, 2009d). Over 200 bird species have been recorded 

20 within the park, including the threatened Henslow’s sparrow (Ammodramus 

21 henslowii), which is known to nest on the south end of the lake (IDNR, 

22 2009d). 

23 ● Lewis Preserve is located about 2 mi (2.4 km) north of the site and just east 

24 of the Pleasant Creek State Recreation Area. 

25 ● The Palo Marsh Natural Area covers 144 ac (58 ha) and is located 2 mi (1.2 

26 km) southwest of the DAEC site and just north of the town of Palo (FLP-DA, 

27 2008). 

28 ● Wickiup Hill encompasses 563 ac (228 ha) across the Cedar River and just 

29 east of the DAEC site. This area includes the Wickiup Hill Outdoor Learning 

30 Center, which hosts educational, historical, and cultural events. 

31 2.2.7 Protected Species 

32 Tables 2-4 and 2-5 list threatened, endangered, or candidate species known to occur in Linn 

33 County (in which DAEC is located) or Benton or Black Hawk counties (through which 

34 transmission line ROWs are associated with DAEC traverse). 

35 2.2.7.1 Aquatic Species 

36 No Federally or State-listed aquatic species are known to occur on or within the vicinity of the 

37 DAEC site (FWS, 2009b; IDNR, 2009e). However, one previously dead squawfoot mussel 

38 (Strophitus undulatus) was recovered during a 2002 mussel survey (Helms, 2003) that was 
Affected Environment 

February 2010 2-33 Draft NUREG-1437, Supplement 42 

1 conducted on the west bank of the Cedar River upstream of the DAEC intake canal, which 

2 indicates that this species has the potential to occur within the vicinity of the site. Additionally, 

3 the USFWS and IDNR are taking action to restore the Higgins eye pearly mussel (Lampsilis 

4 higginsii) to the Cedar River downstream of DAEC (FWS, 2009b). Historic records (pre-1965) 

5 indicate that the species’ natural range included 14 Mississippi River tributaries, including the 

6 Cedar River (Miller and Payne, 2007). Recovery efforts are located downstream of DAEC. 

7 Impingement and entrainment into the DAEC cooling system is not expected to be a threat, nor 

8 is this species Federally or State-listed within Linn, Benton, or Black Hawk counties; therefore, 

9 the species is not discussed below in detail. 

10 Squawfoot

11 The squawfoot (also known as creeper or strange floater) is Iowa State-listed as threatened. 

12 The species’ range extends throughout the eastern and central United States and parts of 

13 Canada. The freshwater mussel species has an oval, moderately compressed, chestnut to dark 

14 brown shell with green rays (CVRC&D, 2002). The shell is smooth and shiny with a rounded 

15 anterior edge and bluntly pointed posterior edge and total length of up to 4 inches (10 cm) 

16 (Cummings and Mayer, 1992). The squawfoot is a habitat generalist and can be found in small17 to medium-size interior rivers and streams with mud, sand, or gravel substrate (Cummings and 

18 Mayer, 1992). Increasing water temperatures in the spring induce males to release sperm into 

19 the water column (Mulcrone, Undated). As females siphon water for food, they also take in the 

20 sperm to fertilize eggs in gill sacs (referred to as marsupia) where the fertilized eggs mature into 

21 a larval stage (referred to as glochoidia). Squawfoot eggs are fertilized in the summer, and the 

22 female carries the eggs through the following spring, at which point the glochidia are released 

23 into the water column (NatureServe, 2009). Glochoidia then attach themselves to a host fish 

24 parasitically and remain attached until they develop into juveniles. Juveniles then detach from 

25 the host and drop to the bottom of the water column (IDNR, 2001d). Squawfoot glochidia have 

26 been observed to have a wide range of possible host species, including numerous species of 

27 Cyprinids and Ictalurids (NatureServe, 2009). Juveniles and adults are filter feeders and prefer 

28 oxygenated, flowing water (CVRC&D, 2002). Squawfoot are preyed upon by muskrat (Ondatra 

29 zibethicus), raccoons (Procyon lotor), mink (Mustela vison), Canadian otter (Lontra canadensis), 

30 as well as some species of birds. The main causes of this species’ decline are pollution from 

31 agricultural runoff, pesticides, and other chemicals; damming of rivers; over-harvesting; and 

32 competition with exotic mussel species. The species is not known to occur within the vicinity of 

33 the DAEC site (IDNR, 2009e). 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-34 February 2010 

1 Table 2-4. Listed Aquatic Species. The species below are Federally listed and/or Iowa-listed 

2 as threatened or endangered species. These species may occur on the DAEC site or within the 

3 Cedar River near the DAEC site or along in-scope transmission line ROWs. 

Scientific Name Common Name Federal 

Status(a)

State 

Status(b) County(ies) 

Fish 

Ammocrypta clara western sand darter - IT Black Hawk, 

Linn 

Esox americanus grass pickerel - IT Linn 

Etheostoma spectabile orangethroat darter - IT Linn 

Lampetra appendix American brook lamprey - IT Benton, Black 

Hawk, Linn 

Moxostoma duquesnei black redhorse - IT Benton, Black 

Hawk, Linn 

Notropis heterolepis blacknose shiner - IT Benton, Linn 

Notropis texanus weed shiner - IE Benton, Linn 

Freshwater Mussels 

Alasmidonta viridis slippershell - IE Linn 

Anodontoides ferussacianus cylindrical papershell - IT Black Hawk, 

Linn 

Lampsilis teres yellow sandshell - IE Black Hawk, 

Linn 

Lasmigona compressa creek heelsplitter - IT Black Hawk, 

Linn 

Strophitus undulates squawfoot - IT Black Hawk, 

Linn 

Tritogonia verrucosa pistolgrip - IE Linn 

Venustaconcha ellipsiformis ellipse - IE Linn 

(a) DL = Delisted; E = Federally endangered; T = Federally threatened; - = No listing 

(b) IE = Iowa endangered; IT = Iowa threatened 

Sources: IDNR, 2009f; IDNR, 2009g; IDNR, 2009h 

4 2.2.7.2 Terrestrial Species 

5 Two Federally-listed species, the prairie bush clover (Lespedeza leptostachya) and the western 

6 prairie fringed orchid (Platanthera praeclara), have been recorded within Linn, Benton, and 

7 Black Hawk counties (USFWS, 2009b); however, neither of these species is known to occur on 

8 the DAEC site (FLP-DA, 2008a). The State-listed species, the peregrine falcon (Falco 

9 peregrinus), is discussed below because the species was introduced to the site as part of Iowa’s 
Affected Environment 

February 2010 2-35 Draft NUREG-1437, Supplement 42 

1 Peregrine Falcon Restoration Project in 2002. The State-listed bald eagle (Haliaeetus 

2 leucocephalus) is also discussed because the USFWS lists the species as breeding in Linn 

3 County as well as wintering along rivers and larger bodies of water in the area (USFWS, 

4 2007a). 

5 Prairie Bush Clover

6 The prairie bush clover is Federally and Iowa State-listed as threatened. The species is a 

7 slender-leaved legume in the pea family with pink to cream flowers that bloom in July 

8 (Sather, 1990). The prairie bush clover is endemic to the Midwest and only occurs in Minnesota, 

9 Wisconsin, Iowa, and Illinois tall-grass prairie habitat within the upper Mississippi River Valley 

10 (USFWS, 2000). In 1990, about 100 known prairie bush clover sites existed, and by 2000, fewer 

11 than 40 known sites remained (USFWS, 2000; Sather, 1990). Loss of prairie habitat is attributed 

12 to this species’ decline (USFWS, 2000). According to the IDNR Natural Areas Inventory 

13 Database, the species occurs in all three counties associated with DAEC and its in-scope 

14 transmission lines (IDNR, 2009b; IDNR, 2009c; IDNR, 2009d); however, the species is not 

15 known to occur on the DAEC site. No critical habitat has been designated for this species 

16 (USFWS, 2007a; USFWS 2009). 

17 Western Prairie Fringed Orchid

18 The western prairie fringed orchid is Federally and Iowa State-listed as threatened. The species 

19 is characterized by a single 2.5- to 4-foot (0.8- to 1.2-m) stalk with up to 40 large white flowers 

20 and 2 to 5 elongate leaves originating at the base of the plant (Sather 1991). The species only 

21 occurs west of the Mississippi River in Iowa, Kansas, Minnesota, Nebraska, North Dakota, and 

22 in Manitona, Canada (USFWS, 2004). Historic records indicated the existence of over 160 sites 

23 in nine States, whereas today, only 55 sites in 7 States are known to exist (Sather, 1991). 

24 Western prairie fringed orchids occur in mesic to wet tallgrass prairie, wet meadows, and 

25 remnant native prairie (USFWS, 2004; Sather, 1991). Conversion of prairie for agricultural use, 

26 filling in of wetlands, and use of pesticides and insecticides in and near the species’ habitat, 

27 which reduce numbers of available pollinators, are the major threats to the species (USFWS, 

28 2004). According to the IDNR Natural Areas Inventory Database, the species occurs in all three 

29 counties associated with DAEC and its in-scope transmission lines (IDNR, 2009b; IDNR, 2009c; 

30 IDNR, 2009d); however, the species is not known to occur on the DAEC site. No critical habitat 

31 has been designated for this species (USFWS, 2007a; USFWS, 2009). 

32 Peregrine Falcon

33 The peregrine falcon is endangered at the Iowa State level. The USFWS formally removed the 

34 peregrine falcon from the Federal List of Endangered and Threatened Wildlife effective August 

35 25, 1999, though the species continues to be protected under the Migratory Bird Treaty Act 

36 (64 FR 46541). Post-delisting monitoring results for the species published in 71 FR 60563 in 

37 2006 estimated the number of breeding pairs across the United States, Canada, and Mexico to 

38 be 3005, an increase of 1255 pairs when compared to the 1999 estimate of 1750 pairs at the 

39 time of delisting. The monitoring results concluded that the peregrine falcon population is 

40 “secure and vital” (71 FR 60563). 

41 Adult peregrine falcons have a bluish-black head and wings, are 14 to 19 inches (36 to 48 cm) 

42 tall, and have a wingspan of 39 to 43 inches (99 to 109 cm) (Cornell, 2003). Adults nest from 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-36 February 2010 

1 April to July on high cliffs and bluffs along the Mississippi River. Females lay two to five eggs, 

2 which hatch in 28 to 29 days, and young leave the nest within six to nine weeks of hatching 

3 (MNDNR, 2008a). Peregrine falcons prey on ducks, pigeons, and other birds, as well as small 

4 mammals and insects (MNDNR, 2008a). 

5 Peregrine falcons have been recorded to nest in nine Iowa counties, including Linn and Black 

6 Hawk counties; however, prior to current ongoing reintroduction efforts, the last recorded nest in 

7 Iowa was in 1956 (IDNR, 2009i). Between 1989 and 1992, Iowa, in coordination with the 

8 Peregrine Fund, the Raptor Center at the University of Minnesota, and the Iowa Peregrine 

9 Falcon Recovery Team, released 50 peregrine falcons in Cedar Rapids, Des Moines, and 

10 Muscatine as part of the Eastern Peregrine Recovery Program (IDNR, 2009i). By 2000, over 

11 900 peregrine falcons had been released across the Midwest region (IDNR, 2009i). Five nesting 

12 pairs have been recorded in Iowa (IDNR, 2009i). In 2002, representatives of the Iowa Peregrine 

13 Falcon Restoration Project released eight peregrine falcons at a hacking station on the offgas 

14 stack on the DAEC site; however, the birds did not return to the site to nest (FLP, 2008a). 

15 Bald Eagle

16 The bald eagle is threatened at the Iowa State level. The USFWS formally removed the bald 

17 eagle from the Federal List of Endangered and Threatened Wildlife effective August 8, 2007, 

18 though the species continues to be protected under the Bald and Golden Eagle Protection Act 

19 and the Migratory Bird Treaty Act (72 FR 37346). Each of these acts protects the species by 

20 prohibiting killing, selling, or otherwise harming eagles, nests, or eggs. On June 4, 2007, the 

21 USFWS published National Bald Eagle Management Guidelines (USFWS, 2007b) to ensure the 

22 continued protection of the species under the applicable acts. 

23 Bald eagles mature at 4 to 5 years of age and average 8 to 9 lbs (3.6 to 4.1 kg) for males and 

24 10 to 14 lbs (4.5 to 6.4 kg) for females with a 6 to 7.5 feet (1.8 to 2.3 m) wingspan 

25 (MNDNR, 2008b). Juveniles have speckled white and brown plumage, which gradually changes 

26 to dark brown on the body and white on the head by the time adulthood is reached at about 

27 5 years of age (USFWS, 2007b). Adults usually nest near coasts, rivers, or large bodies of 

28 water in old-growth trees, dead trees, or on cliffs (USFWS, 2007b). Females lay eggs between 

29 late April and early May in the northern United States, and eggs hatch in 33 to 35 days 

30 (USFWS, 2007b). Eaglets generally leave the nest within six weeks of hatching. Bald eagles 

31 prey primarily on fish, but also eat waterfowl, small mammals, and carrion. 

32 As part of the USFWS bald eagle regional recovery plan, the State of Iowa aimed to establish 

33 10 active bald eagle nests between 1981 and 2000 (Fritzell, 2008). This goal was more than 

34 surpassed; by 1991, 13 active nests were recorded, and, in 1998, the State reported 84 active 

35 nests across 42 counties (Fritzell, 2008). The population continued to expand, and by 2008, an 

36 estimated 210 active nests in 83 of the 99 Iowa counties have been recorded (Fritzell, 2008). 

37 According to the IDNR, bald eagles were recorded as first nesting in Benton, Black Hawk, and 

38 Linn counties in 1992, 1993, and 1994, respectively (Fritzell, 2008). No active nests have been 

39 observed on or near the DAEC site (FPL-DA, 2008a). 
Affected Environment 

February 2010 2-37 Draft NUREG-1437, Supplement 42 

1 Table 2-5. Listed Terrestrial Species. This table shows the status of Federally listed and/or 

2 Iowa-listed as threatened, endangered, or special concern species (note: none of these species 

3 are Federally listed species). These species may occur on the DAEC site or within the in-scope 

4 transmission line ROWs. 

Scientific Name Common 

Name 

Federal 

Status(a)

State 

Status(b) County(ies) Habitat 

Reptiles and Amphibians 

Ambystoma laterale blue-spotted 

salamander 

- IE Black Hawk, 

Linn 

moist woodlands 

with small ponds 

Clemmys insculpta wood turtle - IE Benton, Black 

Hawk 

large rivers with 

sandy substrate 

Crotalus viridis prairie rattle 

snake 

- IE Benton prairie; 

grasslands; 

pastures 

Emydoidea blandingii Blanding’s 

turtle 

- IT Black Hawk, 

Linn 

shallow ponds; 

marshes; 

swamps 

Liochlorophis vernalis smooth green 

snake 

- SSC Benton fields and 

meadows; 

grassy areas 

Necturus maculosus mudpuppy - IT Black Hawk rivers; streams; 

canals; lakes 

Notophthalmus viridescens central newt - IT Black Hawk, 

Linn 

temperate 

forests with 

semi-permanent 

ponds 

Terrapene ornate ornate box 

turtle 

- IT Benton, Black 

Hawk, Linn 

dry prairie; oak 

savannahs 

Insects 

Euphydryas phaeton Baltimore 

butterfly 

- IT Linn wet meadows; 

bogs; marshes 

Problema byssus byssus skipper - IT Linn tall-grass prairie; 

coastal marshes 

Birds 

Ammodramus henslowii Henslow’s 

sparrow 

- IT Linn grasslands 

Buteo lineatus red-shouldered 

hawk 

- IE Benton, Black 

Hawk 

deciduous and 

deciduousconifer forest; 

swamps 

Falco peregrinus peregrine 

falcon 

- IE Linn grasslands; 

meadowlands 

Haliaeetus leucocephalus bald eagle DL IE Benton, Black 

Hawk, Linn 

forested areas 

near open water 

Mammals 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-38 February 2010 

Scientific Name Common 

Name 

Federal 

Status(a)

State 

Status(b) County(ies) Habitat 

Perognathus flavenscens plains pocket 

mouse 

- IE Benton, Black 

Hawk, Linn 

sparsely 

vegetated areas 

Spilogale putorius spotted skunk - IE Black Hawk rocky bluffs; 

canyon stream 

beds 

Plants 

Adoxa moschatellina muskroot - SSC Benton damp cliffs and 

slopes 

Astragalus distortus bent milk-vetch - SSC Benton sparsely 

vegetated slopes 

Besseya bullii kitten-tail - IT Benton, Black 

Hawk, Linn 

prairie 

Betula pumila bog birch - IT Black Hawk bogs; calcareous 

fens; swamps; 

lakeshores 

Botrychium simplex little grape fern - IT Black Hawk, 

Linn 

dry fields; 

marshes; bogs; 

swamps 

Cacalia suaveolens sweet Indian 

plantain 

- IT Benton nutrient rich 

wooded areas; 

shaded, wet 

streamsides 

Carex leptalea slender sage - SSC Benton fens; wet 

meadows 

Chimaphilla umbellate prince’s pine - IT Linn coniferous 

woodlands 

Cirsium muticum swamp thistle - SSC Benton wet meadows; 

moist wooded 

areas 

Cornus canadensis bunchberry - IT Linn woodland edges; 

bogs 

Cypripedium candidum small white 

lady’s slipper 

- SSC Benton fens; wet prairies 

Cypripedium reginae showy lady’s 

slipper 

- IT Black Hawk bogs; swamps; 

wet meadows 

and prairie 

Dalea villosa silky prairie 

clover 

- IE Black Hawk prairie 

Decodon verticillata swamp 

loosestrife 

- IE Black Hawk swamps; shallow 

water 

Dichanthelium borealis northern panic 

grass 

- IE Linn open woods; 

fields; shorelines 

Eriophorum angustifolium tall cotton 

grass 

- SSC Benton 

Equisetum sylvaticum woodland 

horsetail 

- IT Black Hawk, 

Linn 

moist, open 

woods; 

meadows; 

thickets 
Affected Environment 

February 2010 2-39 Draft NUREG-1437, Supplement 42 

Scientific Name Common 

Name 

Federal 

Status(a)

State 

Status(b) County(ies) Habitat 

Gaylussacia baccata black 

huckleberry 

- IT Linn open woodlands; 

clearings with 

dry, sandy soils 

Hypericum boreale northern St. 

John’s wort 

- IE Linn sunny, welldrained soils in 

agricultural areas 

and clearings 

Ilex verticillata winterberry - IE Linn swamps; 

marshes 

Juncus greenei Green’s rush - SSC Benton wet meadows; 

pond and marsh 

margins 

Lechea intermedia narrowleaf 

pinweed 

- IT Benton dry, sandy soils 

on hillsides; 

open woodlands 

Lespedeza leptostachya prairie bush 

clover 

T IT Benton, Black 

Hawk, Linn 

prairie 

Menyanthes trifoliate buckbean - IT Linn shallow ponds; 

bogs 

Mimulus glabratus yellow monkey 

flower 

- IT Linn streamsides; 

shorelines; 

swamps 

Oenothera perennis small sundrops - IT Linn fields; open 

woodlands 

Ophioglossum pusillum northern 

Adder’stongue 

- SSC Benton open fens; bogs; 

marsh edges; 

pastures 

Opuntia macrorhiza prickly-pear - IE Linn open, sandy, 

rocky areas 

Phlox bifida cleft phlox - SSC Benton rocky, open 

wooded areas; 

ravines 

Platanthera flava tubercled 

orchid 

- IE Linn wet prairies; 

sedge meadows 

Platanthera praeclara western prairie 

fringed orchid 

T IT Benton, Black 

Hawk, Linn 

tallgrass prairie; 

sedge meadows 

Platanthera psycoides purple fringed 

orchid 

- IT Linn swamps; wet 

meadows 

Polygala incarnate pink milkwort - IT Black Hawk, 

Linn 

prairie; 

lakeshores; 

meadows 

Polygala polygama purple milkwort - IE Linn pine-oak 

woodlands; 

mountain 

ridgetops 

Salix candida sage willow - SSC Benton bogs; fens; 

willow thickets 

Salix pedicellaris bog willow - IT Benton, Black 

Hawk 

bogs; sedge 

meadows 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-40 February 2010 

Scientific Name Common 

Name 

Federal 

Status(a)

State 

Status(b) County(ies) Habitat 

Selaginella rupestris ledge 

spikemoss 

- SSC Benton cliffs; rocky 

outcrops 

Spiranthes ovalis oval ladiestresses 

- IT Linn moist, shady 

upland forests 

Biola lanceolata lance-leaved 

violet 

- SSC Benton bogs; swamps; 

wet meadows 

Xyris torta yellow-eyed 

grass 

- IE Benton, Linn bogs; pond 

margins; fields; 

dtiches 

Snails 

Vertigo meramecensis bluff vertigo - IT Linn wooded bluffs; 

caves 

(a) DL = Delisted; E = Federally endangered; T = Federally threatened; - = No listing 

(b) IE = Iowa endangered; IT = Iowa threatened; SSC = Iowa species of special concern 

Sources: FWS, 2008; IDNR, 2009f; IDNR, 2009g; IDNR, 2009h 

1 2.2.8 Socioeconomic Factors 

2 This section describes current socioeconomic factors that have the potential to be directly or 

3 indirectly affected by changes in operations at DAEC. DAEC and the communities that support it 

4 can be described as a dynamic socioeconomic system. The communities provide the people, 

5 goods, and services required by DAEC operations. DAEC operations, in turn, create the 

6 demand and pay for the people, goods, and services in the form of wages, salaries, and 

7 benefits for jobs and dollar expenditures for goods and services. The measure of the 

8 communities’ ability to support the demands of DAEC depends on their ability to respond to 

9 changing environmental, social, economic, and demographic conditions. 

10 The socioeconomics region of influence (ROI) is defined by the areas where DAEC employees 

11 and their families reside, spend their income, and use their benefits, thereby affecting the 

12 economic conditions of the region. The DAEC ROI consists of a two-county area (Linn and 

13 Benton counties) where approximately 90 percent of DAEC employees reside, and includes the 

14 city of Cedar Rapids. The following sections describe the housing, public services, offsite land 

15 use, visual aesthetics and noise, population demography, and the economy in the ROI 

16 surrounding the DAEC site. 

17 DAEC employs a permanent workforce of approximately 661 employees (FPL-DA, 2008a). 

18 Approximately 90 percent live in Linn, Benton, Johnson and Black Hawk counties, Iowa 

19 (Table 2–6). The remaining 11 percent of the workforce are divided among 14 counties in Iowa, 

20 with numbers ranging from one to five employees per county, and elsewhere in the United 

21 States. Given the residential locations of DAEC employees, the most significant impacts of plant 

22 operations are likely to occur in Linn and Benton counties. The focus of the analysis in this SEIS 

23 is therefore on the impacts of DAEC in these two counties. 
Affected Environment 

February 2010 2-41 Draft NUREG-1437, Supplement 42 

1 Table 2-6. Duane Arnold Energy Center Permanent Employee Residence by County in 

2 2006 

County Number of DAEC Personnel Percentage of Total 

Linn 504 76 

Benton 86 13 

Johnson 28 4 

Black Hawk 6 1 

Others 37 6 

Total 661 100 

Source: (FPL-DA, 2008a) 

3 DAEC schedules refueling outages at 24-month intervals. During refueling outages, site 

4 employment increases by 1,000 workers for approximately 25 to 30 days (FPL-DA, 2008a). 

5 Most of these workers are assumed to be located in the same geographic areas as the 

6 permanent DAEC staff. 

7 2.2.8.1 Housing 

8 Table 2-7 lists the total number of occupied housing units, vacancy rates, and median value in 

9 the ROI. According to the 2000 Census, there were almost 91,000 housing units in the ROI, of 

10 which approximately 86,500 were occupied. The median value of owner-occupied units was 

11 almost $99,500 in Linn County, higher than in Benton County. The vacancy rate was lower in 

12 Linn County (4.7 percent) and higher in Benton County (6.1 percent) than in the ROI as a whole 

13 (4.8 percent). 

14 By 2007, the total number of housing units in Linn County had grown by almost 12,000 units to 

15 102,748 while the total number of occupied units grew by 8,146 units to 94,645. As a result, the 

16 number of available vacant housing units increased by more than 3,700 units to 8,103, or 

17 7.9 percent of total housing units. 

18 Table 2-7. Housing in Linn and Benton Counties, Iowa 

Linn Benton ROI 

Year 2000 

Total 80,551 10,377 90,928 

Occupied housing units 76,753 9,746 86,499 

Vacant units 3,758 631 4,389 

Vacancy rate (percent) 4.7 6.1 4.8 

Median value (dollars) 99,400 82,700 97,494 

Year 2007 

Total 91,733 11,015 102,748 

Occupied housing units 84,535 10,110 94,645 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-42 February 2010 

Vacant units 7,198 905 8,103 

Vacancy rate (percent) 7.8 8.2 7.9 

Source: USCB, (2009a, b, c) 

1 2.2.8.2 Public Services 

2 This section presents a discussion of public services including water supply, education, and 

3 transportation. 

4 Water Supply

5 Water systems in Linn and Benton counties use groundwater sources. The largest water supply 

6 system in the two counties is the Cedar Rapids Water Department, which also operates a well 

7 system of shallow vertical and collector wells constructed in the sand and gravel deposits along 

8 the Cedar River. Because of continuous pumping of the city’s wells, most of the water in the 

9 aquifer is pulled from the river. The well system consists of four well fields with a total of four 

10 collector wells and 45 vertical wells. Local industries use 75 percent of the water and the 

11 remaining 25 percent is used by residential, commercial, and municipal customers 

12 (CRWD 2005, undated). Table 2-8 lists the largest municipal water suppliers in Linn and Benton 

13 counties. 

14 Table 2-8. Major Public Water Supply Systems in Linn and Benton Counties. Average 

15 Daily and Maximum Daily Production and System Design Capacity (gallons per day.)

Water Supplier a Water Source Average Daily 

Production Design Capacity

Linn County 

Cedar Rapids Water Department GW 39.4 45.0 

Marion Municipal Water Department GW 2.6 6.5 

Benton County 

Vinton Municipal Water Department GW 0.5 1.2 

GW = Groundwater 

a Source: EPA, (2007a, b) 

16 Education

17 DAEC is located in the Cedar Rapids Community School District, Linn County. The school 

18 district had 35 schools and an enrollment of approximately 17,263 students in 2007. Including 

19 the Cedar Rapids Community School District, Linn County had 11 school districts (NCES, 

20 2009), with 34,492 students enrolled in public schools in the county in 2007. Benton County has 

21 a total of 3 school districts with an enrollment of 3,988 students in 2007 (NCES, 2009). 

22 Transportation

23 DAEC is accessed by DAEC Road, which intersects with McClintock Road/Power Plant Road 

24 and terminates at Palo Marsh Road/County Road W36, which in turn links Interstate 380 to the 

25 north and continues southeast of Palo and terminates at an intersection with Interstate 380 in 
Affected Environment 

February 2010 2-43 Draft NUREG-1437, Supplement 42 

1 Cedar Rapids. Employees commuting from Cedar Rapids could take County Road W36 or take 

2 County Road E36 (also known as Blairs Ferry Road) (FPL-DA, 2008a), which has an 

3 interchange with Interstate 380 north of Cedar Rapids. Employees commuting from the north 

4 would also travel south on County Road W36. Employees from the west or southwest would 

5 travel to County Road E36 which intersects with County Road W36 in Palo. Those traveling 

6 from the northwest would travel to Interstate 380 and exit at the County Road W36 interchange 

7 (FPL-DA, 2008a). 

8 Of the road segments identified, traffic counts are only available for Interstate 380 at County 

9 Road E36 (Blairs Ferry Road), (28,800 annual average daily traffic trips) and County Road W36 

10 (F Avenue) (24,100 trips), both in Cedar Rapids (IDOT, 2006). Level of Service (LOS) data, 

11 which describes operating conditions within a traffic stream and their perception by motorists, is 

12 available only for Interstate 380 in the northern Cedar Rapids metropolitan area (LOS C - stable 

13 flow, marking the beginning of the range of flow in which individual vehicle traffic is significantly 

14 affected by interaction with the traffic stream) and at the Blairs Ferry Road interchange (LOS D -

15 high-density, stable flow in which speed and freedom to maneuver are severely restricted, 

16 where small increases in traffic will generally cause operational problems). 

17 The Linn County Regional Planning Commission’s (LCRPC) long-range transportation plan 

18 includes improvements to Interstate 380 and Blairs Ferry Road, although the planning area 

19 does not include DAEC (LCRPC, 2005). Benton County does not have a transportation plan. 

20 2.2.8.3 Offsite Land Use 

21 This section focuses on Linn and Benton counties because the majority of the permanent DAEC 

22 workforce (approximately 83.7 percent) live in these counties, and because DAEC pays 

23 property taxes in Linn County. 

Linn County is 717 mi2 24 (458,180 ac) (Linn County, 2003) and is primarily rural outside the Cedar 

25 Rapids metropolitan area. Urban area in Linn County comprises approximately 61,000 acres, or 

26 13 percent of the total acreage; the remaining 397,180 acres are unincorporated. Of the 

27 acreage located in the unincorporated areas, approximately 16 percent is either developed, 

28 considered public lands, or located in critical natural resource areas. The remaining 

29 303,958 acres are in agricultural use or woodlands (Linn County, 2003). 

30 The LCRPC coordinates land use planning, zoning, transportation improvements, water and 

31 sewer systems, and other issues among the municipalities and in the Cedar Rapids 

32 metropolitan area (LCRPC, 2007). In addition, the City of Cedar Rapids has a comprehensive 

33 plan that addresses land use and other issues (Cedar Rapids, 1999). Linn County has a rural 

34 land use plan and map that provides the land use policy for the rural portions of the county. The 

35 plan is reviewed annually and is intended to serve as a guide for land use decision-making 

36 through the year 2020. 

Benton County covers 716 mi2 37 . Farm acreage totals approximately 400,000 acres (FPL-DA, 

38 2008a), about 87 percent of the total land area of the county. 

39 Benton County has a land preservation and use plan that provides the land use policy for the 

40 unincorporated areas of the county, ensuring the protection and preservation of agricultural land 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-44 February 2010 

1 and other limited natural resources, while providing for growth in those areas that would be 

2 compatible with existing land uses and public facilities and services that are available (Benton 

3 County, 1986). The objectives of the plan are met through administration of the Benton County 

4 Agricultural Land Preservation Ordinance. The plan and ordinance are reviewed and amended 

5 from time-to-time by the Benton County Board of Supervisors (Benton County, 1994). 

6 2.2.8.4 Aesthetics and Noise 

7 The DAEC site is bordered on the east by the Cedar River and an associated series of low 

8 bluffs, and by hills to the north and west of the plant. The access road to the site runs in a north9 south direction; at the southern site boundary the road turns west for a distance of 1 1⁄2 miles 

10 before it turns south toward the town of Palo. 

11 A low-profile switchyard and substation are located to the west of the road to Palo, located 

12 approximately 700 feet from the outer edge of a large parking lot and about 2,000 feet from the 

13 turbine/generator building. The center of the plant building complex is about 1,700 feet from the 

14 western side of the north-south reach of the Cedar River, while the center of the switchyard is 

15 about 2,500 feet from the river. A discharge canal runs approximately 1,700 feet from the 

16 cooling tower area to the river, and an intake and pump house is located a short distance to the 

17 north. The turbine-generator building, control building, reactor building, administration building, 

18 pump house and low-level radioactive waste building are co-located to form the main plant 

19 complex. A small sanitary STF is located a few hundred feet north of the complex, and an offgas 

20 stack is located a few hundred feet south of the complex. Dimensions of the main buildings on 

21 the 500-acre plant site are 420 x 475 feet (4.6 ac) for the power plant, 500 x 600 feet (6.9 ac) for 

22 the cooling towers, and 600 x 1000 feet (13.7 ac) for the switchyard and substation. Except for 

23 the offgas stack which rises to a height of 328 feet above ground, the 153-foot reactor building 

24 is the tallest onsite structure (AEC, 1973). 

25 Outer walls of all plant buildings consist of light buff-colored concrete. The upper area of the 

26 walls of the reactor and turbine-generator buildings are covered with light brown metal siding 

27 which has dark brown vertical stripes. The cooling towers are constructed with cedar and fir. All 

28 substation and switchyard equipment and supporting structures are painted light gray, and 

29 overhead aluminum conductors have a nonreflecting finish. Other areas of the site, which were 

30 disturbed during development and construction, have been largely restored and planted with 

31 grasses, shrubs, and trees. 

32 The three most significant noise sources associated with the plant are the cooling towers, 

33 transformers, and circuit breakers. The impacts of plant operation on outdoor and indoor noise 

34 levels were assessed in the FES conducted at the time of plant construction (AEC, 1973). 

35 The cooling towers have a source noise level of 138 decibels (dB). Outdoor noise levels at the 

36 nearest farm house and indoor noise levels, assuming typical wall construction with some open 

37 windows, would mean that these noise levels would transform the rural environment into an 

38 urban environment, and this may prove annoying to the occupants of local buildings, particularly 

39 at night. In addition, persons visiting the Wickiup Conservation Area east of the plant, less than 

40 1 mile across the river, would be subjected to an overall sound pressure level of about 55 dB 

41 from the cooling towers. This may be annoying to persons visiting the area. The FES concluded 

42 that in no case will offsite sound levels from cooling tower operation be of such a magnitude as 

43 to cause actual hearing damage (AEC, 1973). 
Affected Environment 

February 2010 2-45 Draft NUREG-1437, Supplement 42 

1 A noise level of 89 db was associated with the transformers located in the turbine building and 

2 in the electrical power distribution substation located west of the plant. This noise level is much 

3 lower than the noise level at the cooling towers. The sound level at the nearest offsite occupied 

4 dwelling closest to the transformers was assumed in the FES to be below the threshold of 

5 hearing. Circuit breakers associated with the plant are air-operated and have a source noise 

6 level of 181 db. At the nearest occupied dwelling, this would result in momentary sound 

7 pressure levels of about 110 db. Exposures to ambient levels of 110 db are of sufficient 

8 magnitude to cause possible hearing damage if they are constantly repeated at the rate of one 

9 hour per day. At the time of the FES, the applicant estimated that the breakers would operate 

10 approximately once per year, meaning that, although sound levels associated with circuit 

11 breaker operation are high, they would not result in a serious noise impact (AEC, 1973). 

12 2.2.8.5 Demography 

13 In 2000, approximately 210,081 persons lived within a 20-mile (32-km) radius of DAEC, which 

equates to a population density of 167 persons/mi2 14 . This density translates to a Category 4 

(greater than or equal to 120 persons/mi2 15 within 20 miles) using the generic environmental 

16 impact statement (GEIS) measure of sparseness (FPL-DA 2008a). At the same time, there were 

17 approximately 621,461 persons living within a 50-mile radius of the plant, for a density of 

79 persons/mi2 18 , meaning that DAEC falls into Category 3 (one or more cities with 100,000 or 

more persons and less than 190 persons/mi2 19 within 50 miles (80 km)) on the NRC proximity 

20 scale. A Category 4 value for sparseness and a Category 3 value for proximity indicate that 

21 DAEC is in a high density population area. 

22 Table 2-9 shows population projections and growth rates from 1970 to 2050 in Linn and Benton 

23 counties. The growth rate in Linn County showed a decline of 0.6 percent for the period of 1980 

24 to 1990, but has grown, and is projected to grow, throughout the remainder of the period. A 

25 similar pattern of growth can be observed in Benton County, with a decline in population 

26 between 1980 and 1990, with population growth expected through 2040. 

27 Table 2-9. Population and Percent Growth in Linn and Benton Counties, Iowa, from 1970 

28 to 2000 and Projected for 2010 and 2040 

Linn County Benton County 

Year Population Percent Growth(a) Population Percent Growth(a)

1970 163,213 — 22,885 — 

1980 169,775 4.0 23,649 3.3 

1990 168,767 -0.6 22,429 -5.2 

2000 191,701 13.6 25,308 12.8 

2010 211,489 10.3 26,815 6.0 

2020 231,345 9.4 27,846 3.8 

2030 252,057 9.0 28,980 4.1 

2040 273,054 8.3 30,142 4.0 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-46 February 2010 

— = No data available. 

(a) Percent growth rate is calculated over the previous decade. 

Sources: Population data for 1970 through 1990 (USCB, 2009d); data for 2000 (USCB, 2009e); projected population 

data for 2010 to 2040 (State Library of Iowa, 2008) 

1 The 2000 demographic profile of the ROI population is included in Table 2-10. Persons 

2 self-designated as minority individuals comprise 5.5 percent of the total population. This minority 

3 population is composed largely of Black or African American and Asian residents. 

4 Table 2-10. Demographic Profile of the Population in the Duane Arnold Energy Center 

5 Region of Influence in 2000 

Linn 

County 

Percent of 

Total 

Population 

Benton 

County 

Percent of 

Total 

Population 

Region of 

Influence 

Percent of 

Total 

Population 

Total Population 191,701 100 25,308 100 217,009 100 

Race (2000) (percent of total population, Not-Hispanic or Latino) 

White 179,999 93.9 25,015 98.8 205,014 94.5 

Black or African American 4,919 2.6 51 0.2 4,970 2.3 

American Indian and 

Alaska Native 

418 0.2 37 0.1 455 0.2 

Asian 2,634 1.4 43 0.2 2,677 1.2 

Native Hawaiian and Other 

Pacific Islander 

91 0.0 4 0.0 95 0.0 

Some other race 881 1.5 27 0.1 908 0.4 

Two or more races 2,759 1.4 131 0.5 2,890 1.3 

Ethnicity 

Hispanic or Latino 2,722 1.4 156 0.6 2,878 1.3 

Minority Population (including Hispanic or Latino ethnicity) 

Total minority population 11,702 6.1 293 1.2 11,995 5.5 

Source: USCB, (2009f) 

6 Transient Population

7 Within 50 miles (80 km) of DAEC, colleges and recreational opportunities attract daily and 

8 seasonal visitors who create demand for temporary housing and services in some counties 

9 within 50 miles of the plant (Table 2-11). In 2000 in Linn County, 0.6 percent of all housing units 

10 were considered temporary housing for seasonal, recreational, or occasional use, while 

11 temporary housing accounted for only 1.2 percent of total housing units in Benton County. In 

12 2007, there were 18,480 students attending colleges and universities within 50 miles (80 km) of 

13 DAEC. 

14 Table 2-11. Seasonal Housing within 50 Miles of Duane Arnold Energy Center, 2000 

County a Number of Housing Units

Vacant Housing Units for 

Seasonal, Recreational or 

Occasional Use Percent 

Clayton 8,619 717 8.3 

Poweshiek 8,556 637 7.4 
Affected Environment 

February 2010 2-47 Draft NUREG-1437, Supplement 42 

Delaware 7,682 465 6.0 

Jackson 8,949 415 4.6 

Louisa 5,133 284 1.7 

Others 338,617 2,020 0.6 

Total 377,556 4,538 1.2 

Source: USCB 2009c 

a

 Counties within 50 miles of DAEC with at least one block group located within the 50-mile radius 

1 Migrant Farm Workers

2 Migrant farm workers are individuals whose employment requires travel to harvest agricultural 

3 crops. These workers may or may not have a permanent residence. Some migrant workers may 

4 follow the harvesting of crops, particularly fruit, throughout the northeastern U.S. rural areas. 

5 Others may be permanent residents near DAEC who travel from farm to farm harvesting crops. 

6 Migrant workers may be members of minority or low-income populations. Because they travel 

7 and can spend a significant amount of time in an area without being actual residents, migrant 

8 workers may be unavailable for counting by census takers. If uncounted, these workers would 

9 be “underrepresented” in U.S. Census Bureau (USCB) minority and low-income population 

10 counts. 

11 The 2007 Census of Agriculture collected information on migrant farm and temporary labor. 

12 Table 2-12 provides information on migrant farm workers and temporary (less than 150 days) 

13 farm labor within 50 miles of DAEC. According to 2007 Census of Agriculture estimates, Linn 

14 County hosts relatively small numbers of migrant workers, with 482 temporary farm laborers 

15 employed on 211 farms in the county (USDA, 2009). The county with the most temporary farm 

16 workers within 50 miles of DAEC was Johnson County with 1,240 workers on 253 farms. 

17 Table 2-12. Migrant Farm Worker and Temporary Farm Labor within 50 Miles of Duane 

18 Arnold Energy Center 

County a

Number of Farm 

Workers Working for 

Less that 150 Days 

Number of Farms 

Hiring Workers for 

Less than 150 Days 

Number of Farms 

Reporting Migrant 

Farm Labor 

Number of Farms 

with Hired Farm 

Labor 

Johnson 1,240 253 4 319 

Fayette 1,101 359 4 420 

Clinton 1,021 341 1 411 

Dubuque 865 295 4 395 

Delaware 855 327 6 444 

Others 7,249 4,106 23 4,321 

Total 12,331 5,681 42 6,310 

Source: USDA (2009) 

a

 Counties within 50 miles of DAEC with at least one block group located within the 50-mile radius 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-48 February 2010 

1 2.2.8.6 Economy 

2 This section contains a discussion of the economy, including employment and income, 

3 unemployment, and taxes. 

4 Employment and Income

5 Between 2000 and 2008, the civilian labor force in the Linn County area grew at an annual 

6 average rate of 0.9 percent to 120,241 (USDOL, 2009). The civilian labor force in the Benton 

7 County area grew at an annual rate of 0.7 percent to the 2008 level of 14,501. 

8 In 2006, manufacturing, retail, health care, and social assistance employment represented the 

9 largest sector of employment in both counties followed by accommodation and food services 

10 (USCB, 2009g). The largest employer in Linn County in 2006 was Rockwell Collins with 7,300 

11 employees (Table 2-13). The majority of employment in Linn County is located in the city of 

12 Cedar Rapids. 

13 Table 2-13. Major Employers in Linn County in 2006 

Firm Number of Employees 

Rockwell Collins 7,300 

Cedar Rapids Community School District 2,800 

AEGON USA 2,600 

St. Luke’s Hospital 2,400 

Maytag Appliances 2,200 

Mercy Medical Center 2,060 

Hy-Vee Food Stores 2,044 

MCI 1,528 

City of Cedar Rapids 1,493 

Kirkwood Community College 1,443 

McLeod USA 1,361 

Alliant Energy-Interstate Power and Light 1,100 

Quaker Foods 1,100 

Source: Cedar Rapids Area Chamber of Commerce (undated) 

14 Income information for the DAEC ROI is included in Table 2-14. There are slight differences in 

15 the income levels between the two counties. The median household and per capita incomes in 

16 Linn and Benton counties were higher than the Iowa average. Only 9.9 percent of the population 

17 in Linn County was living below the official poverty level, while in Benton County, 7.2 percent of 

18 the population was below the poverty level. 

19 Table 2-14. Income Information for the Duane Arnold Energy Center Region of Influence, 

20 2007 

Linn County Benton County Iowa 

Median household income (dollars) 53,076 54,417 47,324 
Affected Environment 

February 2010 2-49 Draft NUREG-1437, Supplement 42 

Per capita income (dollars) 38,419 32,419 34,916 

Percent of persons below the poverty line 9.9 7.2 11.0 

1 Source: USCB (2009g, h) 

2 Unemployment

3 In 2008, the annual unemployment average in Linn and Benton counties was 4.0 and 

4 4.1 percent, respectively, which was similar to the annual unemployment average of 4.1 percent 

5 for Iowa (USDOL, 2009). 

6 Taxes

7 The owners of DAEC pay annual property taxes to Linn County. A portion of the total is retained 

8 for county operations, including public safety and legal services, physical health and social 

9 services, mental health services, roads and transportation, administration, and other expenses. 

10 Linn County forwards the remainder of the collected tax revenue to the townships, school 

11 districts, cities, and other taxing authorities in the county. 

12 During 2005 through 2008, Linn County collected approximately $236 to $262 million annually in 

13 property taxes (Table 2-15). DAEC’s property tax payments during this period represented 0.3 

14 to 0.4 percent of the total property tax revenues collected in the county. The sale of DAEC by 

15 Alliant Energy to Nextera Energy in 2006 resulted in a reassessment of the valuation of the 

16 plant, and consequently the amount of property tax paid by the plant to the county. Linn County 

17 retained $35 to $41 million dollars each year for its operations over the period 2002 to 2006, 

18 with tax payments made by DAEC constituting less than 1 percent of Linn County’s total 

19 operational costs. More than 50 percent of DAEC tax payments go to Cedar Rapids Community 

20 School District, which had expenditures of $159.1 million during 2006–2007 (NCES, 2009). 

21 Table 2-15. Property Tax Revenues in Linn County, 2005 to 2008; Florida Power and Light 

22 Property Tax, 2005 to 2008; and Florida Power and Light Property Tax as a Percentage of 

23 Total Property Tax Revenues in Linn County 

Year 

Total Property Tax Revenues in Linn 

County 

(in millions of dollars, 2006) 

Property Tax Paid by FPL 

(in millions of dollars, 

2006)1

FPL Property Tax as 

Percentage of Total Property 

Tax Revenues in Linn County1

2005 236.0 603.2 0.3 

2006 245.3 1,049.2 0.4 

2007 259.3 1,135.5 0.4 

2008 261.6 844.9 0.3 

1 24 Includes property taxes paid to all jurisdictions in Linn County 

25 Source: FPL-DA, 2008a 

26 In 1998, the Iowa Legislature established the “Deregulation and Restructuring of the Electric 

27 Utility Industry Study Committee” to review restructuring activities and experiences in other 

28 States, and at that time, the Committee did not make any formal recommendations. In 1999, the 

29 Iowa Utilities Board undertook an extensive study of electricity restructuring and issued a 

30 number of reports. In 2000, bills related to the restructuring of the electric utility industry were 

31 introduced to the Iowa General Assembly in the legislative session, although the legislative 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-50 February 2010 

1 session ended with no further action on the bills. Currently, there has been no new action on the 

2 status of deregulating the electric power industry in Iowa (FEMP, 2006). Should deregulation 

3 ever be enacted in Iowa, this could affect utilities’ tax payments to counties; however, any 

4 changes to DAEC property tax rates due to deregulation would be independent of license 

5 renewal. 

6 The continued availability of DAEC and the associated tax base is an important feature in the 

7 ability of Linn County communities to continue to invest in infrastructure and to draw industry 

8 and new residents. 

9 2.2.9 Historic and Archaeological Resources 

10 This section discusses the cultural background and the known historic and archaeological 

11 resources at the DAEC and surrounding areas. 

12 2.2.9.1 Cultural Background 

13 As indicated earlier, DAEC is located in eastern Iowa along the Cedar River. Archaeological 

14 evidence from all major prehistoric periods and the historic period has been found in the vicinity 

15 of the plant. There are 74 properties listed on the National Register of Historic Places in Linn 

16 County, Iowa. Three of the National Register sites are within 10 miles of DAEC. Two of the sites 

17 are bridges and the third is the Taylor Van Note Building in Cedar Rapids. The Wickiup Hill 

18 Outdoor Learning Area located across the Cedar River from the DAEC has several Native 

19 American mounds on the property. There are more than 40 known archaeological sites located 

20 within 1 mile of DAEC (Louis Berger Group, Inc. 2008). 

21 The earliest evidence for people in Iowa dates to the Paleo Indian period (11,500 B.C. to 

22 8500 B.C.). The Paleo Indian period occurred as the ice sheets that once covered North 

23 America were retreating. Climate during the Paleo Indian period was much cooler and wetter 

24 than today. Paleo Indians lived a nomadic lifestyle focused on hunting large game. Fluted spear 

25 points are the most common artifact found associated with the Paleo Indian cultures such as 

26 Clovis or Folsom. Most Paleo Indian finds in Iowa consist of surface finds of isolated projectile 

27 points (Alex, 2000). 

28 The Archaic Period (8500 B.C. to 800 B.C.) is defined by changes in technology from primarily 

29 large fluted points to smaller spear and dart points and grinding stones for processing plants. 

30 The intensification of resource use is seen as the result of increased population. During the 

31 Archaic period the land cover transformed from wooded to the tall grass prairie of today. The 

32 transformation took most of the 7,700 years encompassed by the period and spread from west 

33 to east. The very long Archaic Period is commonly divided into an Early (8500 B.C to 

34 5500 B.C.), Middle (5500 B.C. to 3000 B.C.) and Late Period (3000 B.C. to 800 B.C.). Climate 

35 during the Archaic Period underwent significant alterations with the Middle Period being 

36 extremely dry. Changes in technology accelerated during the Archaic Period. Projectile point 

37 types proliferate during the Archaic Period. The atlatl, a notched wood stick which increases the 

38 throwing velocity of a spear, became widespread and the first evidence of dogs being kept also 

39 comes from the Archaic Period. 

40 The Woodland Period is often divided into an Early (800 B.C. to 200 B.C.), Middle (200 B.C. to 

41 A.D. 300), and Late (A.D. 300 to A.D. 1250). Hallmarks of the Woodland Period are pottery, the 
Affected Environment 

February 2010 2-51 Draft NUREG-1437, Supplement 42 

1 burial mound, and horticulture mainly involving corn. The change to horticulture in the Late 

2 Woodland Period resulted in several changes to Native American societies. A horticultural 

3 tradition allows for a more predictable food supply but ties a population to specific locations. 

4 Burial mounds are a visible remnant of the Woodland Period. There are two types of mounds: 

5 burial and effigy. Large numbers of mounds and mound groups are found throughout the 

6 Midwest. 

7 The final prehistoric period known near the project area is the Oneota (c. A. D. 1250 to 1700s). 

8 The Oneota relied on an agriculture based on corn, beans, and squash as well as seasonal 

9 hunting of small and large game and seasonal plant harvesting. Pottery styles and distinctive 

10 stone tools are hallmarks of the culture. Oneota sites usually contain numerous storage pits, 

11 multiple structures which can be of various construction types, and show evidence of 

12 reoccupation over time. Carved catlinite pipes and tablets are also indicative of Oneota culture. 

13 When the first Europeans entered Iowa, there were roughly 18 distinct groups living in the state. 

14 These groups were the Ioway, Oto, Winnebago, Omaha, Ottawa, Huron, Miami, Kitchigami, 

15 Mascouten, Chippewa, Sauk, Mequaki, Potowatomi, Pawnee, Santee, Yankton, Moingwena, 

16 and Peoria (Alex, 2000). Many of these groups were originally from the eastern states and 

17 Canada but had been removed to the West in the face of European expansion. Through a 

18 series of treaties and constant Euro-American settlement, most Native Americans were 

removed from Iowa by the middle of the 19th 19 century. The only group that retains any land in the 

20 State is the Meskwakie. It is recognized by the Federal government as the Sac and Fox Tribe of 

21 the Mississippi in Iowa. 

22 The first historic contact between Native Americans and Europeans within modern Iowa was 

23 when Father Jacques Marquette and Louis Joliet traveled down the Mississippi in 1673 

24 (Schweider, 2009). In 1832, a group of Sauk Indians under Black Hawk resisted removal from 

25 northern Illinois. The group was eventually removed by mid-1832 in what was called the Black 

26 Hawk War. The Black Hawk Treaty of 1832, which ended the resistance, ceded the eastern 

27 portion of Iowa to Euro-American settlement. Linn County was created in 1837 as part of the 

28 Territory of Wisconsin. The county seat for Linn County is Marion. The first settler in Linn county 

29 arrived in 1839 (Brewer and Wick, 1911). Iowa became a State in December 1846, and 

30 railroads began crossing the State in the 1850s. With the coming of the railroads, Iowa became 

31 connected to the markets in Chicago. The primary products produced in Linn County were cattle 

32 and dairy products. By 1870 there were five railroad lines that crossed Iowa. 

33 The area near the DAEC was originally settled as farmland. The first farmers grew corn and 

34 wheat and conducted subsistence farming. Some pigs and sheep were raised. Maple sugaring 

35 was also common, following the practices established by Native Americans. The town of Palo 

36 was established in 1854 (Rogers and Page, 1993). The town contained a blacksmith and 

37 sawmill. The economy of the region changed to cattle and dairying by the 1870s. During the 

38 twentieth century many of the farms were consolidated under large landowners. The 

39 consolidation of farm land continues to present. Another industry occurring in the vicinity of Palo 

40 was limestone quarrying. There were eight quarries operating near Palo in the 1960s. 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-52 February 2010 

1 2.2.9.2 Historic and Archaeological Resources 

2 Four archaeological sites are known to exist on the DAEC property. The sites 13LN362, 

3 13LN363, 13LN365, and 13LN366 were first identified in 1993 during a survey of the region 

(Rogers and Page, 1993). All four sites date to the late 19th 4 century and are the remains of 

5 farmsteads. All but 13LN362 were recommended eligible for listing on the National Register of 

6 Historic Places. A 2008 archival study of the DAEC property identified 5 locations that have the 

7 potential to contain archaeological remains. The locations are associated with historic era 

8 farmsteads and a platted town site that appear on historic maps of the area (Louis Berger 

9 Group, Inc. 2008). The locations identified in the report have not been investigated; therefore, it 

10 remains unknown if subsurface remains exist. 

11 Site 13LN362 is an artifact scatter associated with J. Craya who was reported as living in the 

12 location in 1859. There is some discrepancy in the location of the artifacts and the reported farm 

13 location (Louis Berger Group, Inc. 2008). 

14 Site 13LN363 is the remains of a farmstead originally belonging to a John H. Ray. The 

15 farmstead first appears on an 1875 map of Linn County. The farm also appears on maps from 

16 1907 and 1921 but was then associated with a Jonathon McClintock. The site does not appear 

17 on 1934 aerial photographs. A limestone foundation is still visible at the site. 

18 Site 13LN365 is a farmstead that is first associated with a Sarah McClintock in 1895. The 

19 farmstead appears on later maps (1907, 1914, and 1921) associated with Jonathan McClintock. 

20 The site, consisting of nine structures, appears in aerial photographs from 1934 and 1939. The 

21 nine structures also appear in a 1970 aerial photograph. The structures had been removed by 

22 the 1980s. No surface features were noted at the site in 1993. 

23 The final known site on the DAEC property is 13LN366. The site consists of a historic artifact 

24 scatter. No farms or structures appear in this location on any historic maps or aerial 

25 photographs of the region. 

26 Transmission Lines

27 There are roughly 101 miles of transmission line associated with the DAEC (FPL-DA, 2008a) 

28 (see Figure 2-7). A review of files at the Iowa Office of the State Archaeologist identified that 

29 there are 12 archaeological sites located in the ROW of the transmission lines associated with 

30 DAEC. The archaeological sites are listed in Table 2-16. Because the transmission lines were 

31 constructed prior to passage of the National Historic Preservation Act (NHPA), no historic and 

32 archaeological surveys were undertaken for the transmission lines. The resources listed were 

33 identified through surveys conducted for various highway projects and Section 106 compliance 

34 projects. The transmission lines are owned and maintained by ITC Midwest, LLC. 
Affected Environment 

February 2010 2-53 Draft NUREG-1437, Supplement 42 

1 Table 2-16. Historic and Archaeological Sites in the Duane Arnold Energy Center 

2 Associated Transmission Lines 

Site Name Cultural Affiliation NRHP Status 

13LN81 Prehistoric Unevaluated 

13LN88 Woodland Unevaluated 

13LN139 Prehistoric/Historic Unevaluated 

13LN141 Prehistoric Unevaluated 

13LN167 Prehistoric Unevaluated 

13LN173 Prehistoric Unevaluated 

13LN183 Prehistoric Unevaluated 

13LN228 Prehistoric Unevaluated 

13LN362 Historic Unevaluated 

13LN380 Historic Unevaluated 

13LN465 Prehistoric Unevaluated 

13LN810 Historic Unevaluated 

3 2.3 RELATED FEDERAL AND STATE ACTIVITIES 

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

5 renewal of the operating license for DAEC. Any such activity could result in cumulative 

6 environmental impacts and the possible need for a Federal agency to become a cooperating 

7 agency in the preparation of the DAEC SEIS. 

8 There are no known Federal facilities within 50 miles of DAEC. The staff has determined that 

9 there are no Federal projects that would make it desirable for another Federal agency to 

10 become a cooperating agency in the preparation of the SEIS. Parks and wilderness areas 

11 located near the DAEC are listed below: 

12 ● Pleasant Creek State Recreation Area 

13 ● Palo Marsh Wildlife Refuge 

14 ● Wickiup Hill Outdoor Learning Area 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-54 February 2010 

1 NRC is required under Section 102(2)(c) of the NEPA to consult with and obtain the comments 

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

3 environmental impact involved. NRC has consulted with the American Council on Historic 

4 Preservation and the USFWS. Federal Agency consultation correspondence and comments on 

5 the SEIS are presented in Appendix D. 

6 2.4 REFERENCES 

7 CFR (U.S. Code of Federal Regulations), “Standards for Protection Against Radiation,” Part 20, 

8 Title 10, “Energy.” 

9 CFR. “Domestic Licensing of Production and Utilization Facilities,” Part 50, Title 10, “Energy.” 

10 CFR. “Licensing Requirements for Land Disposal of Radioactive Waste,” Part 61, Title 10, 

11 “Energy.” 

12 CFR. “Packaging and Transportation of Radioactive Material,” Part 71, Title 10, “Energy.” 

13 CFR. “Environmental Radiation Protection Standards for Nuclear Power Operations,” Part 190, 

14 Title 40, “Energy.” 

15 64 FR 46541. U.S. Fish and Wildlife Service (USFWS). Endangered and threatened wildlife and 

16 plants; final rule to remove the American peregrine falcon from the federal list of endangered 

17 and threatened wildlife, and to remove the similarity of appearance provision for free-flying 

18 peregrines in the conterminous United States. August 25, 1999. 

19 71 FR 60563. USFWS. Endangered and threatened wildlife and plants; post-delisting monitoring 

20 results for the American peregrine falcon (Falco peregrinus anatum), 2003. October 13, 2006. 

21 72 FR 37346. USFWS. Endangered and threatened wildlife and plants; removing the Bald 

22 Eagle in the lower 48 states from the list of endangered and threatened wildlife. July 9, 2007. 

23 AEC (Atomic Energy Commission). Final Environmental Statement Related to the Operation of 

24 Duane Arnold Energy Center. Iowa Electric Light and Power Company, et al. Docket No. 50-

25 331. Directorate of Licensing. March. Washington, D.C., 1973. ADAMS Accession No. 

26 ML091200609. 

27 Alex, Lynn M., 2000, Iowa’s Archaeological Past, University of Iowa Press, Iowa City, 2002. 

28 Benton County. Land Preservation and Use Plan for Benton County, Iowa (Unincorporated 

29 Areas). July 1986. 

30 Benton County. Benton County, Iowa, Agricultural Land Preservation Ordinance. November 

31 1994. 

32 Brewer, Luther A. and Barthinius L. Wick. History of Linn County, Iowa: From Its Earliest 

33 Settlement to the Present Time, Vol. 1, The Pioneer Publishing Company, Chicago, Illinois, 

34 1911. 

35 Cedar Rapids. Community - List of Local Attractions. 2007. http://www.cedar36 rapids.org/community/NewsDetail.asp?NewsID=208 (accessed June, 2007). 

37 Cedar Rapids. Comprehensive Plan for Cedar Rapids. 1999. http://www.cedar38 rapids.org/development/documents/comp_plan/comp_plan.pdf
Affected Environment 

February 2010 2-55 Draft NUREG-1437, Supplement 42 

1 Collins, F.W. and D.B. MacDonald. 1972. Terrestrial Fauna Determination for the Duane Arnold 

2 Energy Center Site Environs. Prepared for Iowa Electric Light and Power Company, Cedar 

3 Rapids, Iowa. October. 

4 Cornell (Cornell Lab of Ornithology). “Peregrine Falcon.” 2003. 

5 http://www.allaboutbirds.org/guide/Peregrine_Falcon/lifehistory (accessed April 22, 2009). 

6 CRWD (Cedar Rapids Water Department). Cedar Rapids Utility Energy Efficiency Management 

7 Program. Meeting the Demands of Industrial and Residential/Commercial Customers. Undated. 

8 http://www.iamu.org/services/electric/resources/appa_deed/CR_Water_Department.pdf 

9 CRWD. 2005 Water Quality Report. 2005. http://www.cedar10 rapids.org/water/documents/waterquality2005.pdf

11 Cummings, K.S., and C.A. Mayer. Field Guide to Freshwater Mussels of the Midwest. Illinois 

12 Natural History Survey Manual 5, 1992. 

13 http://www.inhs.uiuc.edu/cbd/collections/mollusk/fieldguide.html (accessed April 29, 2009). 

14 CVRC&D (Cedar Valley Resource Conservation & Development, Inc.). The Freshwater Mussels 

15 of Iowa. Prepared by the Iowa Mussel Team in cooperation with Iowa Department of Natural 

16 Resources and the U.S. Environmental Protection Agency. Charles City, IA, 2002. 

17 http://www.fws.gov/midwest/mussel/documents/freshwater_mussels_of_iowa.pdf (accessed 

18 April 27, 2009). 

19 Department of the Army. Letter re CEMVR-OD-P-2005-1016, from J.G. Betker, Project 

20 Manager, Regulatory Branch, Corps of Engineers, to J. Hogan Duane Arnold Energy Center, 

21 September 20, 2005. 

22 Ecological Analysts, Inc. Operational Ecological Study in the Cedar River near Duane Arnold 

23 Energy Center, January through December 1983. Prepared for Iowa Electric Light and Power 

24 Company, Cedar Rapids, Iowa. May 1984. 

25 Environmental Inc. Midwest Laboratory. Annual Radiological Environmental Operating Report, 

26 January 1 to December 31, 2006. Radiological Environmental Monitoring Program (REMP), 

27 Annual Report – Part II: Data Tabulations and Analyses. Docket 50-331, 2007. 

28 2008a. Annual Radiological Environmental Operating Report, January 1 to December 31, 2007. 

29 Radiological Environmental Monitoring Program (REMP), Annual Report – Part II: Data 

30 Tabulations and Analyses. Docket 50-331, 2008. 

31 2008b. Annual Radiological Environmental Operating Report, January 1 to December 31, 2007. 

32 Report to the U.S. Nuclear Regulatory Commission. Docket 50-331, 2008. 

33 EPA (US Environmental Protection Agency) 2007a. Safe Drinking Water Information System, 

34 Query Results for Linn County, Iowa, 2007. 

35 http://www.epa.gov/enviro/html/sdwis/sdwis_query.html

36 EPA 2007b. Safe Drinking Water Information System, Query Results for Benton County Iowa, 

37 2007. http://www.epa.gov/enviro/html/sdwis/sdwis_query.html 

38 EPA 2009a. “Universal Wastes: State-Specific Universal Waste Regulations.” 2009. 

39 http://www.epa.gov/osw/hazard/wastetypes/universal/statespf.htm (accessed May, 2009). 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-56 February 2010 

1 EPA 2009b. “Waste minimization.” 2009. 

2 http://www.epa.gov/osw/hazard/wastemin/minimize/faqs.htm#wastemin (accessed May, 2009). 

3 EPA 2009c. “Office of Solid Waste.” 2009. http://www.epa.gov/osw/ (accessed May, 2009). 

4 EPA 2009d, Enforcement & Compliance History Online (ECHO). 2009. http://www.epa5 echo.gov/cgi-bin/get1cReport.cgi?tool=echo&IDNumber=110000612052 (accessed June 4, 

6 2009). 

7 FEMP (Federal Energy Management Program). Restructuring Status of Electric Markets, Iowa. 

8 U.S. Department of Energy. December 2006. 

9 http://www1.eere.energy.gov/femp/program/utility/utilityman_elec_ia.html

10 FPL-DA (Florida Power and Light-Duane Arnold Energy, LLC). Cooling Water and Circulating 

11 Water System, SD-442, Revision 5, 29 pages, undated #1. 

12 FPL-DA. Storm Water Pollution Prevention Plan (SWPPP), revision 5.3, 26 pages, undated #2. 

13 FPL-DA . Operations Guidelines – Wastewater Treatment System. October 1988. 

14 FPL-DA 2005a. Updated Final Safety Analysis Report, Revision 18. October 2005. 

15 FPL-DA 2005b. Duane Arnold Energy Center. 2004 Annual Radioactive Material Release 

16 Report. Palo, Iowa, 2005. 

17 FPL-DA. Duane Arnold Energy Center. 2005 Annual Radioactive Material Release Report. Palo, 

18 Iowa, 2006. 

19 FPL-DA 2007a. FPL - About Duane Arnold Energy Center, 2007. 

20 http://www.fpl.com/environment/nuclear/about_duane_arnold.shtml (accessed June, 2007). 

21 FPL-DA 2007b. Duane Arnold Energy Center. 2006 Annual Radioactive Material Release 

22 Report. Palo, Iowa, 2007. 

23 FPL-DA 2007c, Updated Final Safety Analysis Report, Duane Arnold Energy Center, Section 

24 9.2, Revision 19, September 2007. 

25 FPL-DA 2007d, Protection Initiative Site Conceptual Model, prepared by S. Funk, 19 pages plus 

26 attachments, December 19, 2007. 

27 FPL-DA 2007e, Letter re Response to State of Iowa Inspection of the Duane Arnold Energy 

28 Center Wastewater Treatment Facility, from G. Van Middlesworth, Site Vice President, to M. 

29 Wade, IDNR, July 13, 2007. 

30 FPL-DA 2008a. Duane Arnold Energy Center, License Renewal Application, Appendix E – 

31 Applicant’s Environmental Report – Operating License Renewal Stage, Duane Arnold Energy 

32 Center. September 2008. ADAMS Accession No. ML082980483. 

33 FPL-DA 2008b. Duane Arnold Energy Center. 2007 Annual Radioactive Material Release 

34 Report. Palo, Iowa, 2008. 

35 FPL-DA 2008c. Recovery Phase Plan Outline EPIP 5.2, updated June 18, 2008. 

36 FPL-DA 2008d. Set of aerial photographs of Duane Arnold Energy Center, dated June 11, 2008. 

37 FPL-DA 2008e. Letter re Waste Water Discharge NPDES Renewal, from R.L. Anderson, Vice 

38 President, to W. Hieb, NPDES Section, IDNR, December 31, 2008. 
Affected Environment 

February 2010 2-57 Draft NUREG-1437, Supplement 42 

1 FPL-DA 2009a. Duane Arnold Energy Center. 2008 Annual Radioactive Material Release 

2 Report. Palo, Iowa, 2009. 

3 FPL-DA 2009b. Letter re Annual Water Use Report Form for Water Use Permits #3046-MR5 

4 and 3533-R3, from D. Curtland, Plant Manager-Nuclear, to M. Anderson, IDNR, Water Supply 

5 Engineering, January 27, 2009. 

6 FPL-DA 2009c. Letter from R. Anderson, Vice President, Duane Arnold Energy Center, to U.S. 

7 Fish and Wildlife Service. Subject: Bird Control Activities Request. March 23, 2009. 

8 Fritzell, R. Trends in Iowa Wildlife Populations and Harvest 2007. Iowa Department of Natural 

9 Resources, September 2008. 

10 http://www.iowadnr.gov/wildlife/pdfs/status_of_iowa_wildlife_populations_and_harvest_2007.pdf

11 (accessed May 12, 2009). 

12 Helms (Helms & Associates). Mussel Survey near the Duane Arnold Energy Center Intake in 

13 the Cedar River near Palo, Iowa. Prepared for Nuclear Management Company, Duane Arnold 

14 Energy Center. Palo, Iowa. January 2003. 

15 IDNR (Iowa Department of Natural Resources) 2001a. Black Sandshell (Ligumia recta) Fact 

16 Sheet. 2001. http://www.iowadnr.gov/education/files/blksdshl.pdf (accessed April 27, 2009). 

17 IDNR 2001b. White Heelsplitter (Lasmigona complanata) Fact Sheet. 2001. 

18 http://www.iowadnr.gov/education/files/whlspltr.pdf (accessed April 27, 2009). 

19 IDNR 2001c. Pink Papershell (Potamilus ohiensis) Fact Sheet. 2001. 

20 http://www.iowadnr.gov/education/files/pkpprshl.pdf (accessed April 27, 2009). 

21 IDNR 2001d. Squawfoot (Strophitus undulatus) Fact Sheet. 2001. 

22 http://www.iowadnr.gov/education/files/squawft.pdf (accessed April 27, 2009). 

23 IDNR. Letter from S.N. Williams, Environmental Scientist, Wastewater Section, to J. Bjorseth, 

24 Plant Manager, Duane Arnold Energy Center, July 21, 2003. 

25 IDNR 2004a, National Pollutant Discharge Elimination System (NPDES) Permit, by W. Farrand, 

26 Wastewater Section, Environmental Services Division, issued July 6, 2004. 

27 IDNR 2004b. “Iowa Outdoors – July 13, 2004.” http://www.iowadnr.gov/news/io/04july13io.pdf

28 (accessed April 21, 2009). 

29 IDNR 2005a, letter re Water Use Permits 3533-R3 and 3046-MR5, from M.T. Moeller, Water 

30 Supply Engineering, to D. Siegfried, Duane Arnold Energy Center, October 31, 2005. 

31 IDNR 2005b, letter re 401 Water Quality Certification, from C.M. Schwake, Environmental 

32 Specialist, to J. Hogan, Duane Arnold Energy Center, August 26, 2005. 

33 IDNR 2007a. Pleasant Creek State Recreational Area. 2007. 

34 http://iowadnr.com/parks/pleasant_creek/index.html (accessed June 8, 2007). 

35 IDNR 2007b, letter re Duane Arnold Energy Center Wastewater Treatment Facility Inspection, 

36 NPDES Permit 5700104, from M. Wade, Environmental Specialist, to D. Curtland, Plant 

37 Manager-Nuclear, June 8, 2007. 

38 IDNR 2008a, letter re Duane Arnold Energy Center Water Supply Sanitary Survey, from J. 

39 Sanfilippo, Environmental Program Supervisor, to D. Curtland, Plant Manager, March 4, 2008. 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-58 February 2010 

1 IDNR 2008b. “Iowa Ambient Air Monitoring Annual Report: 2008 Air Quality Bureau.” 2008. 

2 http://www.iowadnr.gov/air/prof/monitor/files/08ambient.pdf (accessed August, 2009). 

3 ML092150501. 

4 IDNR 2008c. Map of Ospreys in Iowa. 2008. 

5 http://www.iowadnr.gov/wildlife/files/files/osprey_map.pdf (accessed April 21, 2009). 

6 IDNR 2009a. Air Quality Monitoring Program Description, Des Moines, IA. 2009. 

7 http://www.iowadnr.gov/air/prof/monitor/monitor.html (accessed June, 2009). 

8 IDNR 2009b. Safe Drinking Water Information System (SDWIS) Violation Report. 2009. 

9 http://oaspub.epa.gov/enviro/sdw_report_v2.first_table?pws_id=IA5715150&state=IA&source=

10 Groundwater&population=500&sys_num=1 (accessed June 4, 2009). 

11 IDNR 2009c. Detailed Reports for NPDES permit IA0003727 (Duane Arnold Energy Center), 

12 Water Discharge Permits, Permit Compliance System. 2009. 

13 http://iaspub.epa.gov/enviro/pcs_det_reports.pcs_tst?npdesid=IA0003727&npvalue=1&npvalue

14 =2&npvalue=3&npvalue=4&npvalue=5&rvalue=12&npvalue=6&npvalue=7&npvalue=9&npvalue

15 =10&npvalue=11 (accessed June 4, 2009). 

16 IDNR 2009d. “Pleasant Creek Recreational Area.” 2009. 

17 http://www.iowadnr.gov/parks/pleasant_creek/index.html (accessed April 21, 2009). 

18 IDNR 2009e. Letter from I. Foster, Environmental Specialist, Iowa Department of Natural 

19 Resources, to D. Pelton, Branch Chief, Division of License Renewal. Subject: Environmental 

20 Review for Natural Resources for Duane Arnold Energy Center License Renewal Application 

21 Review. May 18, 2009. ADAMS Accession No. ML092020069. 

22 IDNR 2009f. Natural Areas Inventory Interactive Map: Summary by Species Report for Benton 

23 County, IA. 2009. 

24 https://programs.iowadnr.gov/naturalareasinventory/pages/RepDistinctSpeciesByCounty.aspx?

25 CountyID=6 (accessed April 3, 2009). 

26 IDNR 2009g. Natural Areas Inventory Interactive Map: Summary by Species Report for Black 

27 Hawk County, IA. 2009. 

28 https://programs.iowadnr.gov/naturalareasinventory/pages/RepDistinctSpeciesByCounty.aspx?

29 CountyID=7 (accessed April 3, 2009). 

30 IDNR 2009h. Natural Areas Inventory Interactive Map: Summary by Species Report for Linn 

31 County, IA. 2009. 

32 https://programs.iowadnr.gov/naturalareasinventory/pages/RepDistinctSpeciesByCounty.aspx?

33 CountyID=57 (accessed April 3, 2009). 

34 IDNR 2009i. “The Peregrine Falcon Restoration Effort: Iowa’s Restoration Plan.” 2009. 

35 http://www.iowadnr.gov/wildlife/files/falconrestr.html (accessed April 22, 2009). 

36 IDOT (Iowa Department of Transportation). 2006 Traffic Book: Volume of Traffic on the Primary 

37 Road System, Linn County. 2006. 

38 http://www.transdata.dot.state.ia.us/transdataapps/b1530140/routes_frame.asp?year=2006. 

39 IIHR (Hydroscience and Engineering, University of Iowa), Bathymetric and Topographic Survey 

40 near Duane Arnold Energy Center: August 2008 Survey. Prepared by P.E. Haug and J.A. 

41 Odgaard, IIHR Hydroscience and Engineering, University of Iowa, November 2008. 
Affected Environment 

February 2010 2-59 Draft NUREG-1437, Supplement 42 

1 Iowa Natural Resources Council. Letter Re control weir, wall and intake structure, from O.R. 

2 McMurry, Director, to Duane Arnold, August 9, 1971. 

3 Iowa State Climatologist, Iowa Annual Weather Summary 2008. 2009. Available electronically 

4 by following the link to the “Iowa Annual Weather Summary 2008” at: 

5 http://www.iowaagriculture.gov/climatology.asp (accessed June, 2009). 

6 IWSC (Iowa Water Sciences Center). “High Flow Statistics – Flood 2008.” 2009. 

7 http://ia.water.usgs.gov/flood08/high_flow_stats.htm (accessed May 6, 2009). 

8 LCCD (Linn County Conservation Department). Parks and Outdoor Recreation. 2007. 

9 http://www.linncountyparks.com/parksDirectory.asp. (accessed June 8, 2007). 

10 LCRPC (Linn County Regional Planning Commission). Linn County, Iowa Rural Land Use Plan. 

11 Cedar Rapids, IA. May 2003. http://www.co.linn.ia.us/content.asp?Page_Id=783&Dept_Id=25. 

12 LCRPC. 2040 Transportation Plan for the Cedar Rapids Iowa Metropolitan Area. Cedar Rapids, 

13 IA. July 2005. http://www.cedar-rapids.org/rpc/lrtp.pdf. 

14 LCRPC. Linn County Regional Planning Commission. 2007. 

15 http://www.cedarrapids.org/rpc/history.html 

16 Louis Berger Group, Inc. Cultural Resource Assessment of the Duane Arnold Energy Center 

17 Property, Near Palo, Linn County, Iowa. Prepared for Florida Power and Light Energy, LLC, 

18 DAEC, Palo, Iowa. June 2008. 

19 McDonald, D.B. Cedar River Baseline Ecological Study Annual Report, April 1971 to April 1972. 

20 Prepared for Iowa Electric Light and Power Company, Cedar Rapids, Iowa. June 1972. 

21 McDonald, D.B. Cedar River Operational Ecological Study Annual Report, January 1999 to 

22 December 1999. Prepared for Iowa Electric Light and Power Company, Cedar Rapids, Iowa. 

23 April 2000. 

24 MCEER (Multidisciplinary Center for Earthquake Engineering Research). “Iowa – Midwest Flood 

25 News & Statistics.” State University of New York at Buffalo, 2009 

26 http://mceer.buffalo.edu/infoservice/disasters/iowa-flood-news-statistics.asp (accessed May 6, 

27 2009). 

28 Miller, A.C., and B.S. Payne. A Re-examination of the Endangered Higgins Eye Pearlymussel 

29 Lampsilis higginsii in the Upper Mississippi River, USA. Endangered Species Research, Vol. 

30 3:229-237. October 2007. http://www.int-res.com/articles/esr2007/3/n003p229.pdf (accessed 

31 June 29, 2009). 

32 MNDNR (Minnesota Department of Natural Resources). 2008a. “Peregrine Falcon (Falco 

33 peregrinus).” 2008. http://www.dnr.state.mn.us/snapshots/birds/peregrinefalcon.html (accessed 

34 April 22, 2009). 

35 MNDNR 2008b. “Bald Eagle (Haliaeetus leucocephalus). 2008. 

36 http://www.dnr.state.mn.us/birds/eagles/index.html (accessed May 12, 2009). 

37 Mulcrone, R.S. “Strophitus undulatus (Say, 1817).” Encyclopedia of Life, undated. 

38 https://eol.org/pages/449435 (accessed April 29, 2009). 

39 National Climatic Data Center. Climate of 2008 Midwestern U.S. Flood Overview, July 9, 2008. 

40 www.ncdc.noaa.gov/oa/climate/research/2008/flood08.html (accessed May 8, 2009) 
Affected Environment 

Draft NUREG-1437, Supplement 42 2-60 February 2010 

1 NCES (National Center for Education Statistics). Search for Public School Districts. U.S. 

2 Department of Education, 2009. http://www.nces.ed.gov/ccd/districtsearch/ 

3 NatureServe. Strophitus undulatus on NatureServe Explorer: An online encyclopedia of life. 

4 Version 7.1. NatureServe, Arlington, Virginia, 2009. http://www.natureserve.org/explorer

5 (accessed June 10, 2009). 

6 Niemann, M.S. and D.B. MacDonald. An Ecological Study of the Terrestrial Plant Communities 

7 in the Vicinity of the Duane Arnold Energy Center. Prepared for Iowa Electric Light and Power 

8 Company, Cedar Rapids, Iowa. August 1972. 

9 NOAA (National Oceanographic and Atmospheric Administration). 2009a. NOAA Satellite and 

10 Information Service Query Results, Linn County, Iowa, Flood Events, 2009. 

11 http://www.ncdc.noaa.gov/oa/climate/severeweather/extremes.html (accessed May, 2009). 

12 NOAA 2009b. NOAA Satellite and Information Service Query Results, Linn County, Iowa, 

13 Funnel Cloud Events. 2009. http://www.ncdc.noaa.gov/oa/climate/severeweather/extremes.html

14 (accessed May, 2009). 

15 NOAA 2009c. NOAA Satellite and Information Service Query Results, Linn County, Iowa, 

16 Tornado Events. 2009. http://www.ncdc.noaa.gov/oa/climate/severeweather/extremes.html

17 (accessed May, 2009). 

18 NOAA 2009d. NOAA Satellite and Information Service Query Results, Linn County, Iowa, 

19 Thunderstorm and High Wind Events. 2009. 

20 http://www.ncdc.noaa.gov/oa/climate/severeweather/extremes.html (accessed May, 2009). 

21 NOAA 2009e. NOAA Satellite and Information Service Query Results, Linn County, Iowa, Wild 

22 and Forest Fire Events. 2009. 

23 http://www.ncdc.noaa.gov/oa/climate/severeweather/extremes.html.(accessed May, 2009). 

24 NWS (National Weather Service). “2008 Iowa Weather in Review.” 2009. 

25 http://www.crh.noaa.gov/images/dmx/2008YearReview.pdf (accessed May 6, 2009). 

26 Rogers, Leah D. and William C. Page. Linn County Comprehensive Planning Project Phase 

27 Two: Archaeological, Historical, and Architectural Survey Subsection E (Fayette Township), 

28 prepared for the Linn County Historic Preservation Commission and the State Historical Society 

29 of Iowa, Historic Preservation Bureau. September 1993. 

30 Sather, N. “Prairie Bush Clover: A Threatened Midwestern Prairie Plant.” Minnesota 

31 Department of Natural Resources, 1990. 

32 http://files.dnr.state.mn.us/natural_resources/ets/prairie_bush_clover.pdf (accessed April 22, 

33 2009). 

34 Sather, N. “Western Prairie Fringed Orchid: A Threatened Midwestern Prairie Plant.” Minnesota 

35 Department of Natural Resources. 1991. 

36 http://files.dnr.state.mn.us/natural_resources/ets/fringed_orchid.pdf (accessed April 22, 2009). 

37 Schweider, Dorothy. History of Iowa. 2009. http://publications.iowa.gov/135/1/history/7-1.html

38 (accessed July 1, 2009). 

39 State Library of Iowa. Projections of Total Population for U.S., Iowa, and its Counties: 2010-

40 2040. State Data Center Program. December 2008. 

41 http://data.iowadatacenter.org/datatables/CountyAll/co2008populationprojections20002040.xls
Affected Environment 

February 2010 2-61 Draft NUREG-1437, Supplement 42 

1 Sullivan, D. J. Fish Communities and Their Relation to Environmental Factors in the Eastern 

2 Iowa Basins in Iowa and Minnesota, 1996. Water-Resources Investigations Report 00-4194. 

3 2000. http://pubs.usgs.gov/wri/2000/wri004194/pdf/wri00_4194.pdf (accessed April 24, 2009). 

4 USCB (U.S. Bureau of the Census). Economic Characteristics: 2005. For Linn County, Iowa. 

5 U.S. Census Bureau. Washington D.C., 2005. 

6 http://factfinder.census.gov/servlet/AdvSearchByPlacenameServlet?_lang=en (accessed 

7 August 2007). 

8 USCB 2009a. QT-H1 General Housing Characteristics: 2000. 2009. 

9 http://factfinder.census.gov/servlet/QTTable?_bm=y&-context=qt&-

10 qr_name=DEC_2000_SF1_U_QTH1&-ds_name=DEC_2000_SF1_U&-tree_id=4001&-

11 redoLog=true&-all_geo_types=N&-_caller=geoselect&-geo_id=05000US12017&-

12 search_results=01000US&-format=&-_lang=en

13 USCB 2009b. QT-H14: Value, Mortgage Status and Selected Conditions: 2000. 2009 

14 http://factfinder.census.gov/servlet/QTTable?_bm=y&-context=qt&-

15 qr_name=DEC_2000_SF3_U_QTH14&-ds_name=DEC_2000_SF3_U&-tree_id=403&-

16 redoLog=true&-all_geo_types=N&-_caller=geoselect&-geo_id=05000US12017&-

17 search_results=01000US&-format=&-_lang=en

18 USCB 2009c. 2007 American Community Survey. 2009. 

19 http://factfinder.census.gov/servlet/STTable?_bm=y&-context=st&-

20 qr_name=ACS_2007_3YR_G00_S2504&-ds_name=ACS_2007_3YR_G00_&-tree_id=3307&-

21 redoLog=true&-_caller=geoselect&-geo_id=05000US12017&-format=&-_lang=en 

22 USCB 2009d. IOWA: Population of Counties by Decennial Census: 1900 to 1990. 2009. 

23 http://www.census.gov/population/www/censusdata/cencounts/files/ia190090.txt

24 USCB 2008e. American Fact Finder. 2008. http://factfinder.census.gov/

25 USCB 2009f. QT-P3 Race and Hispanic or Latino: 2000. 2009. 

26 http://factfinder.census.gov/servlet/QT,.?_bm=y&-context=qt&-

27 qr_name=DEC_2000_SF1_U_QTP3&-ds_name=DEC_2000_SF1_U&-tree_id=4001&-

28 redoLog=true&-all_geo_types=N&-_caller=geoselect&-geo_id=05000US12017&-

29 search_results=01000US&-format=&-_lang=en

30 USCB 2009g. State and County Quickfacts – Linn County, Iowa, 2009. 

31 http://quickfacts.census.gov/qfd/states/12/12017.html

32 USCB 2009h. State and County Quickfacts – Benton County, Iowa, 2009. 

33 http://quickfacts.census.gov/qfd/states/12/12017.html

34 USDA (U.S. Department of Agriculture). 2007 Census of Agriculture. Hired Farm Labor - 

35 Workers and Payroll: 2007. 2009. 

36 http://www.agcensus.usda.gov/Publications/2007/Full_Report/Volume_1,_Chapter_2_County_L

37 evel/Florida/st12_2_007_007.pdf

38 USDOL (U.S. Department of Labor). Local Area Unemployment Statistics. 2009. 

39 http://www.bls.gov/lau/#tables
Affected Environment 

Draft NUREG-1437, Supplement 42 2-62 February 2010 

1 USFWS (U.S. Fish and Wildlife Service). “Threatened and Endangered Species: Prairie Bush 

2 Clover (Lespedeza leptostachya).” 2000. 

3 http://www.fws.gov/midwest/endangered/plants/pdf/lelefctsht.pdf (accessed April 22, 2009). 

4 USFWS. “Prairie Fringed Orchids Fact Sheet.” 2004. 

5 http://www.fws.gov/midwest/endangered/plants/prairief.html (accessed April 22, 2009). 

6 USFWS 2007a. Letter from R. Nelson, Field Supervisor, U.S. Fish and Wildlife Service, to G. 

7 Middlesworth, Vice President, FPL Energy Duane Arnold, LLC. Subject: Response to request 

8 for information about impacts to species from license renewal project. July 3, 2007. ADAMS 

9 Accession No. ML082980483. 

10 USFWS 2007b. National Bald Eagle Management Guidelines. 2007. 

11 http://www.fws.gov/pacific/eagle/NationalBaldEagleManagementGuidelines.pdf (accessed May 

12 12, 2009). 

13 USFWS. “Iowa County Distribution of Federally Threatened, Endangered, Proposed, and 

14 Candidate Species.” 2008. http://www.fws.gov/Midwest/Endangered/LISTS/iowa_cty.html

15 (accessed April 3, 2009). 

16 USFWS 2009a. Federal Fish and Wildlife Permit No. MB160836-0 for Depredation of Turkey 

17 Vultures. April 1, 2009. 

18 USFWS 2009b. Letter from R. Nelson, Field Supervisor, Rock Island Field Office, to D. Pelton, 

19 Branch Chief, Division of License Renewal. Subject: Response to letter requesting a list of 

20 protected species within the area under evaluation for the Duane Arnold Energy Center license 

21 renewal application. May 29, 2009. ADAMS Accession No. ML092020070. 

22 USGS (U.S. Geological Survey). Water-Data Report 2008 for 05464500 Cedar River at Cedar 

23 Rapids, IA, 2008. http://wdr.water.usgs.gov/wy2008/pdfs/05464500.2008.pdf (accessed June 3, 

24 2009
February 2010 3-1 Draft NUREG-1437, Supplement 42 

1 3.0 ENVIRONMENTAL IMPACTS OF REFURBISHMENT 

2 License renewal actions include refurbishment actions for the extended plant life. These actions 

3 may have an impact on the environment that requires evaluation, depending on the type of 

4 action and the plant-specific design. If such actions were planned, the potential environmental 

5 effects of refurbishment actions would be identified and the analysis would be summarized 

6 within this section. 

7 Environmental issues associated with refurbishment activities are discussed in the “Generic 

8 Environmental Impact Statement (GEIS) for License Renewal of Nuclear Plants”, NUREG-1437, 

Vol. 1 and 2 (U.S. Nuclear Regulatory Commission (NRC) 1996, 1999).1 9 The GEIS includes a 

10 determination of whether or not the analysis of the environmental issues can be applied to all 

11 plants and whether or not additional mitigation measures are warranted. Issues are then 

12 assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, Category1 issues 

13 are those that meet all of the following criteria: 

14 (1) The environmental impacts associated with the issue have been determined to apply 

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

16 or other specified plant or site characteristics. 

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

18 the impacts (except for collective offsite radiological impacts from the fuel cycle and from 

19 high-level waste and spent fuel disposal). 

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

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

22 are not likely to be sufficiently beneficial to warrant implementation. 

23 For issues that meet the three Category 1 criteria, no additional plant-specific analysis is 

24 required in this supplemental environmental impact statement (SEIS) unless new and significant 

25 information is identified. Category 2 issues are those that do not meet one or more of the criteria 

26 for Category 1 and, therefore, an additional plant-specific review of these issues is required. 

27 Environmental issues associated with refurbishment, which were determined to be Category 1 

28 and Category 2 issues, are listed in Tables 3-1 and 3-2, respectively. 

29 Requirements for the renewal of operating licenses for nuclear power plants include the 

30 preparation of an integrated plant assessment (IPA) pursuant to Section 54.21 of Title 10 of the 

31 Code of Federal Regulations (CFR). The IPA must identify and list systems, structures, and 

32 components subject to an aging management review. The GEIS (NRC, 1996) provides helpful 

33 information on the scope and preparation of refurbishment activities to be evaluated. 

34 Environmental resource categories to be evaluated for impacts of refurbishment include 

35 terrestrial resources, threatened and endangered species, air quality, housing, public utilities 

36 and water supply, education, land use, transportation, and historic and archaeological 

37 resources. Items that are subject to aging and might require refurbishment include, for example, 

 

1 The GEIS was originally issued in 1996. Addendum 1 to the GEIS was issued in 1999. Hereafter, all references 

to the GEIS include the GEIS and its Addendum 1. 
Environmental Impacts of Refurbishment 

Draft NUREG-1437, Supplement 42 3-2 February 2010 

1 the reactor vessel piping, supports, and pump casings (see 10 CFR 54.21 for details), as well as 

2 items that are not subject to periodic replacement. 

3 FPL Energy Duane Arnold, LLC (FPL-DA) performed an IPA on Duane Arnold Energy Center 

4 (DAEC) pursuant to 10 CFR 54.21. This assessment did not identify the need to undertake any 

5 major refurbishment or replacement actions to maintain the functionality of important systems, 

6 structures, and components during the DAEC license renewal period or other facility 

7 modifications associated with license renewal that would affect the environment or plant 

8 effluents (FPL-DA, 2008); therefore, an assessment of refurbishment activities is not considered 

9 in this SEIS. 

10 Table 3-1. Category 1 Issues for Refurbishment Evaluation 

ISSUE—10 CFR Part 51, Subpart A, Appendix B, Table B-1 GEIS Sections 

Surface Water Quality, Hydrology, and Use (for all plants) 

Impacts of refurbishment on surface water quality 3.4.1 

Impacts of refurbishment on surface water use 3.4.1 

Aquatic Ecology (for all plants) 

Refurbishment 3.5 

Groundwater Use and Quality 

Impacts of refurbishment on groundwater use and quality 3.4.2 

Land Use 

Onsite land use 3.2 

Human Health 

Radiation exposures to the public during refurbishment 3.8.1 

Occupational radiation exposures during refurbishment 3.8.2 

Socioeconomics 

Public services: public safety, social services, and tourism and recreation 3.7.4; 3.7.4.3; 

3.7.4.4; 3.7.4.6 

Aesthetic impacts (refurbishment) 3.7.8 

11 
Environmental Impacts of Refurbishment 

February 2010 3-3 Draft NUREG-1437, Supplement 42 

1 Table 3-2. Category 2 Issues for Refurbishment Evaluation 

ISSUE—10 CFR Part 51, Subpart A, Appendix B, Table B-1 GEIS Sections 

10 CFR 51.53 

(c)(3)(ii) 

Subparagraph 

Terrestrial Resources 

Refurbishment impacts 3.6 E 

Threatened or Endangered Species (for all plants) 

Threatened or endangered species 3.9 E 

Air Quality 

Air quality during refurbishment (nonattainment and maintenance areas) 3.3 F 

Socioeconomics 

Housing impacts 3.7.2 I 

Public services: public utilities 3.7.4.5 I 

Public services: education (refurbishment) 3.7.4.1 I 

Offsite land use (refurbishment) 3.7.5 I 

Public services, transportation 3.7.4.2 J 

Historic and archaeological resources 3.7.7 K 

Environmental Justice 

Environmental justice Not addresseda Not addresseda

a

 Guidance related to environmental justice was not in place at the time the NRC prepared the GEIS and the 

associated revision to 10 CFR Part 51. If an applicant plans to undertake refurbishment activities for license renewal, 

the applicant’s ER and NRC staff’s environmental impact statement must address environmental justice. 

2 3.1 REFERENCES 

3 CFR (U.S. Code of Federal Regulations). “Environmental Protection Regulations for Domestic 

4 Licensing and Related Regulatory Functions,” Part 51, Title 10, “Energy.” NUREG-1437, 

5 Supplement 33 3-4 August 2008. 

6 CFR. “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 

7 Title 10, “Energy.” 

8 FPL-DA (Florida Power and Light Energy Duane Arnold). Duane Arnold Energy Center, License 

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

10 Renewal Stage, Duane Arnold Energy Center, September 2008. 

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

12 License Renewal of Nuclear Plants, NUREG-1437, Vol., 1 and 2. Office of Nuclear Regulatory 

13 Research, Washington, DC, 1996. 

14 NRC. Generic Environmental Impact Statement for License Renewal of Nuclear Plant. NUREG15 1437, Vol. 1, Add. 1, Office of Nuclear Reactor Regulation, Washington, DC, 1999.

February 2010 4-1 Draft NUREG-1437, Supplement 42 

1 4.0 ENVIRONMENTAL IMPACTS OF OPERATION 

2 Chapter 4 investigates potential environmental impacts related to the period of extended 

3 operation of Duane Arnold Energy Center (DAEC). These impacts are grouped and presented 

4 according to resource. Generic issues (Category 1) rely on the analysis provided in the Generic 

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

6 prepared by the U.S. Nuclear Regulatory Commission (NRC) and are discussed briefly (NRC 

7 1996, 1999a). The NRC staff (Staff) has also analyzed site-specific issues (Category 2) for 

8 DAEC and assigned them a significance level (e.g., SMALL, MODERATE, or LARGE). Some 

9 remaining site characteristics or plant feature issues are not applicable to DAEC. Section 1.4 of 

10 this report explains the criteria for Category 1 and Category 2 issues and defines the impact 

11 designations of SMALL, MODERATE, and LARGE. The issue of waste management is dealt 

12 with in Chapter 6. 

13 4.1 LAND USE 

14 Land use issues are listed in Table 4-1. The Staff did not identify any Category 2 issues for 

15 onsite land use and did not identify any new and significant information during the review of the 

16 environmental report (ER) (FPL Energy Duane Arnold, LLC (FPL-DA), 2008a), the site audit, or 

17 the public scoping process; therefore, there are no impacts related to these issues beyond 

18 those discussed in the GEIS. For these Category 2 issues, the GEIS concludes that the impacts 

19 are designated as SMALL, and additional site-specific mitigation measures are unlikely to be 

20 warranted. 

21 Table 4-1. Category 1 Issues Applicable to Onsite Land Use during the Renewal Term 

ISSUE—10 CFR Part 51, Subpart A, Appendix B, Table B-1 GEIS Section 

Onsite land use 

Onsite land use 4.5.3.1 

Power line right-of-way 4.5.3.1 

22 4.2 AIR QUALITY 

23 Table 4-2 lists the air quality issue applicable to DAEC. The Staff did not identify any Category 2 

24 issues for air quality. The Staff also did not identify any new and significant information during 

25 the review of the applicant’s ER (FPL-DA, 2008a), the site audit, or the scoping process; 

26 therefore, there are no impacts related to this issue beyond those discussed in the GEIS. 

27 Consistent with the GEIS, the staff therefore concludes that the impacts are SMALL, and 

28 additional site-specific mitigation measures are unlikely to be warranted. 

29 Table 4-2. Air Quality Issue. Section 2.2.2 of this report describes air quality in the 

30 vicinity of DAEC. 

Issue GEIS Section Category 

Air quality effects of transmission lines 4.5.2 1 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-2 February 2010 

1 4.3 GROUNDWATER 

2 The Category 2 groundwater issues applicable to the DAEC are discussed below and listed in 

3 Table 4-3. No Category 1 issues relate to the site. 

4 Table 4-3. Groundwater Use and Quality Issues. Groundwater use and quality at the DAEC 

5 are discussed in Section 2.2.3. 

Issues GEIS Sections Category 

Groundwater use conflicts (potable and service water, and dewatering 

plants that use >100 gpm) 4.8.1.1, 4.8.2.1 2 

Groundwater use conflicts (plants using cooling towers withdrawing 

makeup water from a small river) 4.8.1.3, 4.4.2.1 2 

6 4.3.1 Generic Groundwater Issues 

7 Discussions during the site audit included description of various incidents, including a diesel line 

8 break and cleanup and several sulphuric acid tank leaks, which were contained. During the 

9 most recent dredging, a few gallons of diesel fuel were spilled into the Cedar River. Cleanup 

10 was directed toward removing the sheen at the surface of a backwater (water backed up in its 

11 course by an obstruction). In 1983, a barrel of 30 gal (114 L) of condensate water was spilled 

12 and flowed into the storm sewer (FPL-DA, 2006c). The site maintains that “there have been no 

13 identified instances of radioactivity released from the DAEC that resulted in groundwater 

14 concentrations exceeding the allowable Environmental Protection Agency (EPA) maximum 

15 contaminant levels for drinking water” (FPL-DA, 2006c). 

16 The National Pollutant Discharge Elimination System (NPDES) application (FPL-DA, 2008c) 

17 describes several releases in the prior three years. These include a July 2006 sulphuric acid 

18 tank leak of approximately 1,000 gal (3,800 L) into a concrete containment berm. Only a few 

19 gallons were not contained. In September 2007, some petroleum-contaminated soil was 

20 discovered beneath a concrete structure. The soil was excavated and disposed of. 

21 The potential impact to groundwater from the incidents described above is considered low 

22 because of the volume and type of contaminants and the mitigation measures taken in each 

23 instance. The Staff did not identify any new and significant information regarding Category 1 

24 issues during the review of DAEC’s ER (FPL-DA, 2008a), the site audit, or during the public 

25 scoping process. The Staff also evaluated and reviewed various permits, assorted applicant 

26 files, radiological environmental monitoring program (REMP) reports, and other sources of 

27 information; therefore, there are no impacts related to these issues beyond those discussed in 

28 the GEIS. For these issues, the GEIS concluded that the impacts are SMALL, and additional 

29 site-specific mitigation measures are unlikely to be sufficiently beneficial to be warranted. 
Environmental Impacts of Operation 

February 2010 4-3 Draft NUREG-1437, Supplement 42 

1 4.3.2 Groundwater Use Conflicts (Plants That Use More Than 100 Gallons [378 Liter] 

2 Per Minute) 

3 NRC specifies as issue #33 in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, that, “if the 

4 applicant’s plant...pumps more than 100 gallons (total onsite) of groundwater per minute (gpm), 

5 an assessment of the impact of the proposed action on groundwater use must be provided.” 

6 NRC further states that “plants that use more than 100 gpm (378 L) of groundwater may cause 

7 groundwater use conflicts with nearby groundwater users,” (10 CFR 51.53[c][3][ii][C]). This 

8 applies to DAEC because, as discussed in Section 2.1.7.1 of this report, DAEC uses over 1,500 

9 gpm (5,700 liter per minute) of groundwater. 

10 The DAEC pumps groundwater from four production wells on a schedule that normally involves 

11 one or two wells pumping at a time. Approximately 100 gpm (378 liter per minute) of 

12 groundwater are used for demineralizer makeup, less than 10 gpm (38 liter per minute) are 

13 used for potable supply, and about 1,400 gpm (5,300 liter per minute) are sent to an air cooling 

14 system. 

15 A drawdown test was performed in 1972 (Bechtel Corp., 1972), which involved increasing the 

16 pumping rate at well No. 1, turning on well No. 2, and measuring drawdown at five observation 

17 wells. Although drawdown was minimal at most of the observation well locations, the locations 

18 and depths of the various pumping wells and observation wells are not described in Bechtel's 

19 test results, so the Staff cannot evaluate the results. 

20 In 2001, an aquifer test at Well A showed a stable water level in the well after five hours of 

21 pumping at 930 gpm (3,500 liter per minute) (Northway Well and Pump Co., 2001). More 

22 importantly, recent water level data from a set of six monitoring well nests (FPL-DA, 2007b) do 

23 not show a cone of depression at the site. Concerns about water supply are not known from 

24 nearby private well owners. Annual withdrawal volumes have remained fairly steady and are 

25 approximately one-half of the permitted amount (IDNR, 2005). Therefore, the Staff concludes 

26 the impact on groundwater from pumping more than 100 gpm is SMALL. 

27 4.3.3 Groundwater Use Conflicts (Makeup from a Small River) 

28 NRC specifies that, “if the applicant’s plant utilizes cooling towers or cooling ponds and 

withdraws makeup water from a river whose annual flow rate is less than 3.15 x 1012 29 cubic feet 

per year (ft3 30 /year) (99,885 cubic feet per second (cfs))...[t]he applicant shall also provide an 

31 assessment of the impacts of the withdrawal of water from the river on alluvial aquifers during 

32 low flow,” (10 CFR 51.53[c][3][ii][A]). For water use conflicts, NRC further states, as issue #34 in 

33 Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 that, “water use conflicts may result 

34 from surface water withdrawals from small water bodies during low flow conditions which may 

35 affect aquifer recharge, especially if other groundwater or upstream surface water users come 

36 online before the time of license renewal....” This issue is applicable to DAEC because the 

37 water used for the plant cooling towers is withdrawn from the Cedar River, which has an annual 

mean flow of approximately 1.2 x 1011 ft3

/yr (3,878 cfs or 110 m3 38 /s), thus meeting NRC’s 

39 definition of a small river. Flow is monitored in Cedar Rapids, IA, about 15 miles (24 km) 

40 downstream of DAEC. 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-4 February 2010 

The Cedar River has an average flow of 3,878 cfs (110 m3 1 /s) at Cedar Rapids. Flow at DAEC is 

2 expected to be similar because no major tributaries enter the river between the facility and 

3 Cedar Rapids. The design rate for water withdrawal under operating conditions is 11,200 gpm 

(25 cfs or 0.71 m3 4 /s), or approximately 0.6 percent of the average river flow. Maximum 

consumptive use is 8,100 (18 cfs or 0.51 m3 5 /s), or approximately 0.46 percent of the average 

6 river flow. 

7 During low-flow periods, the withdrawal rate and consumptive rate are higher proportions of the 

river flow. By permit, when river flow falls below 500 cfs (14 m3 8 /s), the Pleasant Creek 

9 Recreational Reservoir may discharge to the Cedar River at a rate equal to the consumptive 

10 use rate (IDNR, 2005). At this low-flow threshold, flow in the river is only 13 percent of the 

11 average flow, the withdrawal rate is 5 percent of the low flow, and the return of blowdown to the 

12 river results in a net consumptive rate of over 3 percent of the low flow. Discharge from the 

13 reservoir is not a requirement of the permit. 

14 In summary, the withdrawal is typically less than 1 percent of river flow and the release of water 

15 from a reservoir is possible during drought. In the vicinity of the plant, private wells do not pump 

16 from the alluvium layer. The Staff concludes that the impact on groundwater due to the use of a 

17 small river for makeup water purposes is SMALL. 

18 4.4 SURFACE WATER 

19 Surface water quality issues applicable to DAEC are discussed below and listed in Table 4-4. 

20 The Staff did not identify any new and significant information during the review of DAEC’s ER 

21 (FPL-DA, 2008a), the site audit, or during the public scoping process. The Staff reviewed other 

22 sources of information such as various permits, a permit application, assorted applicant files, 

23 and REMP reports, and concludes there are no impacts related to these issues beyond those 

24 discussed in the GEIS. For surface water issues, the GEIS concluded that the Category 1 

25 issues were SMALL, and additional site-specific mitigation measures are unlikely to be 

26 sufficiently beneficial to be warranted. 

27 Table 4-4. Surface Water Quality Issues. A description of the surface water quality conditions 

28 at DAEC is provided in Section 2.2.4. 

Issues GEIS Sections Category 

Altered current patterns at intake and discharge structures 4.2.1.2.1 1 

Altered salinity gradient 4.2.1.2.2 1 

Temperature effects on sediment transport capacity 4.2.1.2.3 1 

Scouring caused by discharged cooling water 4.2.1.2.3 1 

Eutrophication 4.2.1.2.3 1 

Discharge of chlorine or other biocides 4.2.1.2.4 1 

Discharge of sanitary wastes and minor chemical spills 4.2.1.2.4 1 

Discharge of other metals in wastewater 4.2.1.2.4 1 

Water use conflicts (plants with cooling ponds or cooling towers using 

makeup water from a small river with low flow) 4.3.2.1, 4.4.2.1 2 
Environmental Impacts of Operation 

February 2010 4-5 Draft NUREG-1437, Supplement 42 

1 4.4.1 Water Use Conflicts 

2 Section 4.3.3 describes NRC’s requirements for assessing water use conflicts on a “small river” 

3 Specifically. NRC specifies that, “if the applicant’s plant uses cooling towers or cooling ponds 

and withdraws makeup water from a river whose annual flow rate is less than 3.15 x 1012 4 

ft3

/year (99,885 cfs or 2,828 m3 5 /s), an assessment of the impact of the proposed action on the 

6 flow of the river and related impacts on instream and riparian ecological communities must be 

7 provided” (10 CFR 51.53(c)(3)(ii)(A)). For water use conflicts, NRC further states as issue #13 in 

8 Table B-1 of Appendix B to Subpart A of 10 CFR Part 51, that “[t]he issue has been a concern 

9 at nuclear power plants with cooling ponds and at plants with cooling towers. Impacts on 

10 instream and riparian communities near these plants could be of MODERATE significance in 

11 some situations.” 

12 This issue is applicable to DAEC because the plant uses a cooling-tower-based heat dissipation 

13 system, and water to replace that lost to evaporation in the cooling system is withdrawn from the 

Cedar River (which has an annual mean flow of approximately 1.2 x 1011 ft3 14 /yr (3,878 cfs or 110 

m3 15 /s), meeting NRC’s definition of a small river). Flow is monitored in Cedar Rapids, IA, about 

16 15 mi (24 km) downstream of DAEC. The GEIS considered surface water use conflicts to be a 

17 Category 2 issue for two reasons: 

18 (1) Consumptive water use can adversely affect riparian vegetation and instream aquatic 

19 communities. Reducing the amount of water available to either the riparian zones or 

20 instream communities could result in impacts on threatened and endangered species, 

21 wildlife, and recreational uses of the water body. In addition, riparian vegetation performs 

22 several important ecological functions, including stabilizing channels and floodplains, 

23 influencing water temperature and quality, and providing habitat for aquatic and 

24 terrestrial wildlife. 

25 (2) Continuing operation of these facilities depends on the availability of water within the 

26 river from which they are withdrawing water. For facilities that are located on small 

27 bodies of water, the volume of available water is expected to be susceptible to droughts 

28 and to competing water uses within the basin. In cases of extreme drought, these 

29 facilities may be required to curtail operations if the volume of water available is not 

30 sufficient. 

31 An additional effect of the withdrawal of water from a small river is that the withdrawal may have 

32 an impact on groundwater levels, which would result in groundwater use conflicts (NRC, 1996). 

33 The Staff considers this to be a separate Category 2 issue, which is evaluated in Section 4.3.3 

34 of this draft SEIS. 

35 As discussed in Section 2.1.7.2, flow in the Cedar River at Cedar Rapids averages 3,878 cfs 

(110 m3 36 /s). Flow at DAEC is expected to be similar because no major tributaries enter the river 

37 between the facility and Cedar Rapids. The design rate for water withdrawal under operating 

conditions is 11,200 gpm (25 cfs or 0.71 m3 38 /s), or approximately 0.6 percent of the average river 

39 flow. Maximum consumptive use is 8,100 gpm (18 cfs), or approximately 0.46 percent of the 

40 average river flow. 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-6 February 2010 

1 During low-flow periods, the withdrawal rate and consumptive rate are higher proportions of the 

2 river flow. By permit, when river flow falls below 500 cfs, the Pleasant Creek Recreational 

3 Reservoir may discharge to the Cedar River at a rate equal to the consumptive use rate (IDNR, 

4 2005). At this low-flow threshold, flow in the river is only 13 percent of the average flow, the 

5 withdrawal rate is 5 percent of the low flow, and the return of blowdown to the river results in a 

6 net consumptive rate of over 3 percent of the low flow. Discharge from the reservoir is not a 

7 requirement of the permit. During low-flow conditions, the effect would be magnified and could 

8 contribute to a cumulative impact. 

9 In summary, the withdrawal is typically less than 1 percent of mean river flow and the release of 

10 water from a reservoir is possible during drought. However, during a period of low river flow 

11 associated with a drought, the withdrawal rate may be significant. The Staff concludes the 

12 impact on groundwater due to the use of a small amount of river makeup water is SMALL to 

13 MODERATE. 

14 4.5 AQUATIC RESOURCES 

15 Table 4-5 lists issues related to aquatic resources applicable to DAEC. No Category 2 issues 

16 are related to aquatic resources. The Staff did not find any new and significant information 

17 during the review of the applicant’s ER, the site audit, the scoping process, or the evaluation of 

18 other available information; therefore, the Staff concludes that there are no impacts related to 

19 aquatic resource issues beyond those discussed in the GEIS (NRC, 1996). Consistent with the 

20 GEIS, the Staff concludes that the impacts are SMALL, and additional site-specific mitigation 

21 measures are unikely to be sufficiently beneficial to warrant implementation. 

22 Table 4-5. Aquatic Resource Issues. Section 2.1.6 of this report describes the DAEC 

23 cooling water system; Section 2.2.5 describes aquatic resources. 

Issues GEIS Section Category 

For All Plants 

Accumulation of contaminants in sediments or biota 4.2.1.2.4 1 

Entrainment of phytoplankton and zooplankton 4.2.2.1.1 1 

Cold shock 4.2.2.1.5 1 

Thermal plume barrier to migrating fish 4.2.2.1.6 1 

Distribution of aquatic organisms 4.2.2.1.6 1 

Premature emergence of aquatic insects 4.2.2.1.7 1 

Gas supersaturation (gas bubble disease) 4.2.2.1.8 1 

Low dissolved oxygen in the discharge 4.2.2.1.9 1 

Losses from predation, parasitism, and disease among organisms 

exposed to sublethal stresses 4.2.2.1.10 1 

For Plants with Cooling Tower-Based Heat Dissipation Systems 

Entrainment of fish and shellfish in early life stages 4.3.3 1 

Impingement of fish and shellfish 4.3.3 1 

Heat shock 4.3.3 1 
Environmental Impacts of Operation 

February 2010 4-7 Draft NUREG-1437, Supplement 42 

1 4.6 TERRESTRIAL RESOURCES 

2 The issues related to terrestrial resources applicable to DAEC are listed in Table 4-6. There are 

3 no Category 2 issues related to terrestrial resources. NRC did not identify any new and 

4 significant information during the review of the applicant’s ER, the Staff’s site audit, the scoping 

5 process, or the evaluation of other available information. Therefore, there are no impacts related 

6 to these issues beyond those discussed in the GEIS. Consistent with the GEIS, the Staff 

7 concludes that the impacts are SMALL, and additional site-specific mitigation measures are not 

8 likely to be sufficiently beneficial to warrant implementation. 

9 Table 4-6. Terrestrial Resources Issues. Section 2.2.6 provides a description of the 

10 terrestrial resources at DAEC and in the surrounding area. 

Issues GEIS Section Category 

Cooling tower impacts on crops and ornamental vegetation 4.3.4 1 

Cooling tower impacts on native plants 4.3.5.1 1 

Bird collisions with cooling towers 4.3.5.2 1 

Power line right-of-way management (cutting herbicide application) 4.5.6.1 1 

Bird collisions with power lines 4.5.6.1 1 

Impacts of electromagnetic fields on flora and fauna (plants, 

agricultural crops, honeybees, wildlife, livestock) 4.5.6.3 1 

Floodplains and wetlands on power line right-of-way 4.5.7 1 

11 4.7 THREATENED AND ENDANGERED SPECIES 

12 The issues related to terrestrial resources applicable to DAEC are listed in Table 4-7. 

13 Table 4-7. Threatened or Endangered Species. Section 2.2.7 describes the 

14 threatened or endangered species on or near DAEC.

Issue GEIS Section Category 

Threatened or endangered species 4.1 2 

15 This site-specific, or Category 2 issue, requires consultation with the appropriate agencies to 

16 determine whether or not threatened or endangered species are present and whether or not 

17 they would be adversely affected by continued operation of DAEC during the license renewal 

18 term. The characteristics and habitats of threatened and endangered species in the vicinity of 

19 the DAEC site are discussed in Sections 2.2.5 through 2.2.7 of this draft SEIS. 

20 NRC contacted the U.S. Fish and Wildlife Service (USFWS) on May 6, 2009, regarding 

21 threatened and endangered species at the DAEC site (NRC, 2009a). A description of the site 

22 and the in-scope transmission lines and a preliminary assessment of the Federal threatened, 

23 endangered, and candidate species potentially occurring on or near the DAEC site was 

24 provided in this letter. In response, on May 29, 2009, the USFWS indicated that the prairie bush 

25 clover (Lespedeza leptostachya) and the western prairie fringed orchid (Platanthera praeclara), 

26 both listed as threatened on Federal and Iowa State lists have the potential to occur in Linn 
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Draft NUREG-1437, Supplement 42 4-8 February 2010 

1 County (USFWS, 2009). Neither species was identified during the pre-operational terrestrial 

2 flora study (Neimann and McDonald, 1972), nor have they been identified on the DAEC site 

3 since this time (FPL-DA, 2008a). 

4 NRC contacted the Iowa Department of Natural Resources (IDNR) on May 6, 2009, to request 

5 data to aid in determining which State-listed species may be affected by continued operations 

6 and maintenance procedures at the DAEC site and associated transmission line right of ways 

7 (ROWs) (NRC, 2009b). The IDNR provided responses on May 18, 2009, indicating that its 

8 record search for rare species and significant natural habitats or communities yielded “no site9 specific records that would be impacted by the use of existing plant facilities and transmission 

10 lines” (IDNR, 2009a). 

11 4.7.1 Aquatic Species 

12 The Staff has reviewed information provided by the applicant and information publicly available 

13 and has contacted the USFWS and IDNR (NRC 2009a, 2009b). Currently, no threatened or 

14 endangered aquatic species are known to occur within the Cedar River near the vicinity of 

15 DAEC or within any streams crossed by in-scope transmission line ROWs. Therefore, license 

16 renewal of DAEC would have no effect on any Federally or State-listed aquatic species, and 

17 mitigation measures do not need to be considered. 

18 4.7.2 Terrestrial Species 

19 Currently, no known sightings of Federally listed threatened or endangered terrestrial species 

20 have occurred on the DAEC site or within the in-scope transmission line ROWs. Operation of 

21 DAEC and its associated transmission lines are not expected to adversely affect any threatened 

22 or endangered terrestrial species during the license renewal term. 

23 The Staff encourages FPL-DA and Information Technology Council (ITC) Midwest LLC to 

24 identify and report the existence of any Federally or State-listed endangered or threatened 

25 species within or near the transmission line ROWs to the IDNR and/or USFWS if any such 

26 species are identified during the renewal term. In particular, if any evidence of injury or mortality 

27 of migratory birds or threatened or endangered species is observed within transmission line 

28 ROWs during the renewal period, FPL-DA or ITC is encouraged to report this information 

29 promptly to the appropriate wildlife management agencies. 

30 4.8 HUMAN HEALTH 

31 The human health issues applicable to DAEC are discussed below and listed in Table 4-8 for 

32 Category 1, Category 2, and uncategorized issues. 

33 Table 4-8. Human Health Issues. Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 

34 contains additional information on human health issues applicable to DAEC. 

Issues GEIS Section Category 

Microbiological organisms (occupational health) 4.3.6 1 
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February 2010 4-9 Draft NUREG-1437, Supplement 42 

Issues GEIS Section Category 

Microbiological organisms (public health, for plants using small 

rivers) 4.3.6 2 

Noise 4.3.7 1 

Radiation exposures to public (license renewal term) 4.6.1, 4.6.2 1 

Occupation radiation exposures (license renewal term) 4.6.3 1 

Electromagnetic fields – acute effects (electric shock) 4.5.4.1 2 

Electromagnetic fields – chronic effects 4.5.4.2 Uncategorized 

1 4.8.1 Generic Human Health Issues 

2 The Staff did not identify any new and significant information during its review of the FPL-DA 

3 ER, the site audit, or the public scoping process; therefore, there are no impacts related to 

4 generic human health issues beyond those discussed in the GEIS. For these issues, the GEIS 

5 concluded that the impacts are SMALL, and additional site-specific mitigation measures are 

6 unlikely to be sufficiently beneficial to be warranted. The information presented below discusses 

7 selected radiological programs conducted at DAEC. 

8 DAEC conducts a REMP to assess the radiological impact, if any, to its employees, the public, 

9 and environs around the plant site. An annual radiological environmental operating report is 

10 issued with a discussion of the results of the monitoring program. The report contains data on 

11 the monitoring performed for the most recent year and graphs, which show data trends from 

12 prior years, and in some cases, provide a comparison to pre-plant operation baseline data. The 

13 objectives of the REMP include the following: 

14 ● To measure and evaluate the levels of radiation and radioactive material in 

15 the environs around the DAEC site to assess the radiological impacts, if 

16 any, of plant operation on the environment. 

17 ● To supplement the results of the radiological effluent monitoring program by 

18 verifying that the measurable concentrations of radioactive material and 

19 levels of radiation are not higher than expected based on the measurement 

20 of radioactive effluents and modeling for the applicable exposure pathways. 

21 ● To demonstrate compliance with the requirements of applicable Federal 

22 regulatory agencies. 

23 The DAEC REMP collects samples of environmental media in the environs around the site to 

24 analyze and measure the radioactivity levels that may be present. The media samples are 

25 representative of radiation exposure pathways to the public from all plant radioactive effluents. 

26 The REMP measures the aquatic, terrestrial, and atmospheric environment, as well as ambient 

27 gamma radiation, for radioactivity. Ambient gamma radiation pathways include radiation from 

28 buildings and plant structures and airborne material that may be released from the plant. In 

29 addition, the REMP also measures background radiation (i.e., cosmic sources, global fallout, 

30 and naturally occurring radioactive material, including radon). Thermoluminescent dosimeters 
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Draft NUREG-1437, Supplement 42 4-10 February 2010 

1 (TLDs) are used to measure direct radiation. Atmospheric environmental monitoring consists of 

2 sampling the air for particulates and radioiodine. Terrestrial environmental monitoring consists 

3 of analyzing samples of milk and food products. Aquatic environmental monitoring consists of 

4 analyzing samples of surface water, drinking water, groundwater, fish, and sediment from the 

5 Cedar River. There is also an onsite groundwater protection program designed to monitor the 

6 onsite plant environment for early detection of leaks from plant systems and pipes which convey 

7 radioactive liquids. 

8 The Staff reviewed the DAEC annual radiological environmental operating reports for 2004 

9 through 2008 to identify any significant impacts to the environment or any unusual trends in the 

10 data (FPL-DA 2005c, 2006d, 2007c, 2008d, 2009d). The Staff’s review of the REMP reports 

11 revealed no unusual trends in the data and showed no measurable impact from the operations 

12 at DAEC on the environment. Further, NRC inspection reports were also reviewed supporting 

13 this conclusion. 

14 Historical data on radioactive releases from DAEC and the resultant dose calculations 

15 demonstrate that the amount of radiation received to a hypothetical maximally exposed 

16 individual in the vicinity of DAEC is a small fraction of the dose limits specified in 10 CFR Part 

17 20–the “as low as is reasonably achievable” (ALARA) dose design objectives in Appendix I to 

18 10 CFR Part 50, and EPA’s radiation standards in 40 CFR Part 190, “Environmental Radiation 

19 Protection Standards for Nuclear Power Operations.” Dose estimates for members of the public 

20 are calculated based on liquid and gaseous effluent release data and atmospheric and aquatic 

21 transport models. The DAEC 2008 annual radioactive material release report (FPL-DA, 2009c) 

22 contains a detailed presentation of the radioactive discharges and the resultant calculated 

23 doses. The following conclusion summarizes the calculated hypothetical maximum dose to an 

24 individual located outside the DAEC site boundary from radioactive liquid and gaseous effluents 

25 released during 2007: 

26 ● The maximum whole-body dose to an offsite member of the public from 

27 liquid effluents discharged from the sanitary waste treatment facility was 

28 3.23 E-05 milliroentgen equivalent man (mrem) (3.23 E-07 millisievert 

29 (mSv)), which is well below the 3 mrem (0.03 mSv) dose criterion in 

30 Appendix I to 10 CFR Part 50. 

31 ● The maximum organ (child liver) dose to an offsite member of the public 

32 from liquid effluents discharged from the sanitary waste treatment facility 

33 effluents was 3.23 E-05 mrem (3.23 E-07 mSv), which is well below the 

34 10 mrem (0.1 mSv) dose criterion in Appendix I to 10 CFR Part 50. 

35 ● The maximum air dose at the site boundary from gamma radiation in 

36 gaseous effluents was 4.96 E-04 milliradiation absorbed dose (mrad) 

37 (4.96 E-06 milligray (mGy)), which is well below the 10 mrad (0.1 mGy) 

38 dose criterion in Appendix I to 10 CFR Part 50. 
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February 2010 4-11 Draft NUREG-1437, Supplement 42 

1 ● The maximum air dose at the site boundary from beta radiation in gaseous 

2 effluents was 1.01 E-04 mrad (1.01 E-06 mGy), which is well below the 

3 20 mrad (0.2 mGy) dose criterion in Appendix I to 10 CFR Part 50. 

4 ● The maximum organ (child liver) dose to an offsite member of the public 

5 from radioactive iodine and radioactive material in particulate form was 

6 1.13 E-02 mrem (1.13 E-04 mSv), which is well below the 15 mrem 

7 (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50. 

8 Based on the Staff’s review and assessment of the DAEC radioactive waste system 

9 performance in controlling radioactive effluents and the resultant doses to members of the 

10 public in conformance with the ALARA criteria, the Staff found that the 2008 radiological effluent 

11 data for DAEC are consistent, with reasonable variation attributable to operating conditions and 

12 outages, with the five-year historical radiological effluent releases and resultant doses (FPL-DA 

13 2005d, 2006e, 2007d, 2008e, 2009e). These results demonstrate that DAEC is operating in 

14 compliance with Federal radiation protection standards contained in Appendix I to 10 CFR Part 

15 50 and 10 CFR Part 20. 

16 The applicant has no plans to conduct refurbishment activities during the license renewal term, 

17 thus, no significant change to radiological conditions is expected to occur. Continued 

18 compliance with regulatory requirements is expected during the license renewal term; therefore, 

19 the impacts from radioactive effluents are not expected to change during the license renewal 

20 term. 

21 4.8.2 Microbiological Organisms – Public Health 

22 The effects of thermophilic microbiological organisms on human health, listed in Table B-1 of 

23 Appendix to Subpart A of 10 CFR Part 51, are categorized as a Category 2 issue and require a 

24 plant-specific evaluation during the license renewal process for the plants located on the small 

25 river that use closed-cycle cooling. The average annual flow of the Cedar River nearest the 

DAEC measuring station is approximately 1.05 x 1011 ft3

/yr (2.97 x 109 m3/yr) to 1.19 x 1011 ft3 26 /yr 

(3.37 x 109

 m3/yr), which is less than the threshold value of 3.15 x 1012 ft3 27 /yr 

(9 x 1010 m3 28 /yr) in 10 CFR 51.53(c)(3)(ii)(G) for thermal discharge to a small river (FPL-DA, 

29 2008a). Therefore, the effects of the DAEC cooling water discharge on microbiological 

30 organisms must be addressed for DAEC license renewal. 

31 The Category 2 designation is based on the magnitude of the potential public health impacts 

32 associated with thermal enhancement of enteric pathogens such as Salmonella spp. and 

33 Shigella spp., the Pseudomonas aeruginosa bacterium, the pathogenic strain of the free-living 

34 amoebae Naegleria spp., and Legionella spp. bacteria (NRC, 1996). Thermophilic 

35 microorganisms generally occur at temperatures of 77°F to 176°F (25°C to 80°C) with optimal 

36 growth temperature range of 122°F to 150°F (50° to 66°C), and minimum and maximum 

37 temperature tolerances of 68°F (20°C) and 158°F (70°C), respectively; however, thermal 

38 preferences and tolerances vary across bacterial groups. Pathogenic thermophilic 

39 microbiological organisms of concern during nuclear reactor operation typically have optimal 

40 growing temperatures of approximately 99°F (37°C) (Joklik and Smith, 1972). 
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Draft NUREG-1437, Supplement 42 4-12 February 2010 

1 Pseudomonas aeruginosa is an opportunistic pathogen that causes serious and sometimes fatal 

2 infections in immunocompromised individuals. The organism produces toxins harmful to 

3 humans and animals. It has an optimal growth temperature of 99°F (37°C) (Todar, 2007). 

4 Legionella spp. consists of at least 46 species and 70 serogroups. It is responsible for 

5 Legionnaires’ disease, with the onset of pneumonia in the first two weeks of exposure. Risk 

6 groups for Legionella spp. include elderly, cigarette smokers, persons with chronic lung or 

7 immunocompromising disease, and persons receiving immunosuppressive drugs. 

8 The ambient temperatures of the Cedar River near DAEC varies from freezing (32°F (0°C)) in 

9 the winter to 76°F–78°F (24.4°C–25.6°C) in the summer. Therefore, ambient river conditions are 

10 not likely to support the proliferation of the pathogenic organisms of concern. Table 4-9 

11 represents the maximum daily discharge temperatures at outfall 001, reported in DAEC NPDES 

12 monthly reports for the 2001–2008 period. 

13 Table 4-9. The Maximum Daily Discharge Temperatures, Reported in DAEC NPDES 

14 Reports for the 2001-2008 Period 

Date (month/year) Maximum Daily Discharge Temperature 

July, August 2001 89°F (31.7°C) 

June, July 2002 90°F (32.2°C) 

July 2003 89°F (31.7°C) 

July, August 2004 89°F (31.7°C) 

June, August 2005 88°F (31.1°C) 

July 2006 80°F (26.7°C) 

July, August 2007 78°F (25.6°C) 

August 2008 79°F (26.1°C) 

15 The highest daily discharge temperature reported at DAEC in the 2001–2008 period is 90°F 

16 (32.2°C) during June and July of 2002, which is below the optimal growing temperature of 

17 approximately 99°F (37°C) for the pathogenic thermophilic microbiological organisms that are of 

18 concern during nuclear power reactor operation. DAEC implements additional measures 

19 (disinfection and chlorination of water discharged from DAEC) to control and inhibit the 

20 proliferation of the pathogenic thermophilic microbiological organisms (FPL-DA, 2008a). 

21 Ambient temperatures within the Cedar River are below 77°F (25°C) from October to April. 

22 Based on this data, ambient river conditions are not likely to support the proliferation of the 

23 pathogenic organisms of concern. 

24 FPL-DA consulted the Bureau of Water Supply Management of the Iowa Department of Public 

25 Health (IDPH) to determine whether or not there was any concern about the possible 

26 occurrence of thermophilic microbiological organisms in the Cedar River at the DAEC location. 

27 IDPH stated that no occurrences of infections caused by Naegleria fowleri and Legionella from 

28 the Cedar River in the DAEC vicinity had been documented (FPL-DA, 2008a). 

29 Available data assembled into biannual reports by the U.S. Centers for Disease Control (CDC) 

30 and Prevention for the years 1999 to 2006 (CDC 2000, 2002, 2004, 2006) indicates no 
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February 2010 4-13 Draft NUREG-1437, Supplement 42 

1 occurrence of waterborne disease outbreaks in the State of Iowa resulting from exposure to the 

2 thermophilic microbiological organisms Naegleria fowleri and Pseudomonas aeruginosa. 

3 The Staff reviewed all documents applicable to this Category 2 issue including the FPL-DA 

4 Environmental Report, the DAEC NPDES permit, and CDC reports. The Staff concludes that 

5 thermophilic microbiological organisms are unlikely to present a public health hazard as a result 

6 of DAEC discharges to the Cedar River. The Staff concludes that impacts on public health from 

7 thermophilic microbiological organisms from continued operation of DAEC in the license 

8 renewal period would be SMALL. 

9 The Staff identified measures that could mitigate the potential impacts of thermophilic 

10 microbiological organisms resulting from continued operation of DAEC. These mitigation 

11 measures include periodically monitoring for thermophilic microbiological organisms in water 

12 and sediments near the discharge, as well as prohibiting recreational use near the discharge 

13 plume. These mitigation measures could reduce human health impacts by minimizing public 

14 exposure to thermophilic microbiological organisms. The Staff did not identify any cost-benefit 

15 studies applicable to the mitigation measures mentioned above. 

16 4.8.3 Electromagnetic Fields – Acute Shock 

17 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

18 energized conductors or from induced charges in metallic structures have not been a problem at 

19 most operating plants and generally are not expected to be a problem during the period of 

20 extended operation. However, a site-specific review is required to determine the significance of 

21 electric shock potential along the portions of the transmission lines within the scope of this draft 

22 SEIS. 

23 The GEIS states that it is not possible to determine the significance of the electric shock 

24 potential without a review of the conformance of each nuclear plant’s transmission lines with 

25 National Electrical Safety Code (NESC) (IEEE, 2007) criteria. An evaluation of individual plant 

26 transmission lines is necessary because the issue of electric shock safety was not addressed in 

27 the licensing process for some plants. For other plants, land use in the vicinity of transmission 

28 lines may have changed, or power distribution companies may have chosen to upgrade line 

29 voltage. To comply with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an assessment of 

30 the potential shock hazard if the transmission lines that were constructed for the specific 

31 purpose of connecting the plant to the transmission system do not meet the recommendations 

32 of the NESC for preventing electric shock from induced currents. 

33 All transmission lines associated with DAEC were constructed in accordance with NESC and 

34 industry guidance in effect at that time (AEC, 1973). Transmission lines and facilities are 

35 maintained to ensure continued compliance with current standards. A transmission line 

36 assessment program implemented at DAEC ensures for continued monitoring and documenting 

37 of the transmission line conditions, maintenance and compliance with existing standards. 

38 Routine aerial inspections are conducted every six months to identify any ground clearance 

39 problems and ensure integrity of the transmission line structures. Ground inspections are 

40 conducted biannually by transmission line technicians (FPL-DA, 2008a). 
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Draft NUREG-1437, Supplement 42 4-14 February 2010 

1 Since the lines were constructed, a new criterion has been added to the NESC for power lines 

2 with voltages exceeding 98 kilovolts (kV). FPL-DA has reviewed the transmission lines for 

3 compliance with this criterion (FPL-DA, 2008a). FPL-DA indicated that all transmission lines 

4 within the scope of this review have been restudied, and the results show there are no locations 

5 under the transmission lines that have capacity to induce more than 5 milliamperes (mA) in a 

6 vehicle parked beneath the line. No induced shock hazard to the public should occur since the 

7 lines are operating within original design specifications and meet current NESC clearance 

8 standards. 

9 The Staff has reviewed the available information, including the applicant’s evaluation and 

10 computational results. Based on this information, the Staff evaluated potential impacts for 

11 electric shock resulting from operation of DAEC and its associated transmission lines. The Staff 

12 concludes that the potential impacts from electric shock during the renewal period are SMALL. 

13 The Staff identified measures that could mitigate potential acute electromagnetic force (EMF) 

14 impacts resulting from continued operation of the DAEC’s transmission lines. These mitigation 

15 measures include erecting barriers along the length of the transmission lines to prevent 

16 unauthorized access to the ground beneath the conductors, and installing road signs at road 

17 crossings. These mitigation measures could reduce human health impacts by minimizing public 

18 exposures to electric shock hazards. The Staff did not identify any cost benefit studies 

19 applicable to the mitigation measures mentioned above. 

20 4.8.4 Electromagnetic Fields – Chronic Effects 

21 In the GEIS, the chronic effects of 60-herz (Hz) electromagnetic fields from power lines are not 

22 designated as Category 1 or 2, and will not be, until a scientific consensus is reached on the 

23 health implications of these fields. 

24 The potential for chronic effects from these fields continues to be studied and is not known at 

25 this time. A 1999 report by the National Institute of Environmental Health Sciences (NIEHS) 

26 directs related research through the U.S. Department of Energy (DOE). The report by NIEHS 

27 contains the following conclusion, which is supported by recently published Environmental 

28 Health Criteria Monograph No.238 (WHO, 2007): 

29 ELF-EMF (extremely low frequency-electromagnetic field) exposure cannot be 

30 recognized as entirely safe because of weak scientific evidence that exposure 

31 may pose a leukemia hazard. In our opinion, this finding is insufficient to warrant 

32 aggressive regulatory concern. However, because virtually everyone in the 

33 United States uses electricity and therefore is routinely exposed to ELF-EMF, 

34 passive regulatory action is warranted such as a continued emphasis on 

35 educating both the public and the regulated community on means aimed at 

36 reducing exposures. The NIEHS does not believe that other cancers or non37 cancer health outcomes provide sufficient evidence of a risk to currently warrant 

38 concern. 

39 This statement is not sufficient to cause the Staff to change its position with respect to the 

40 chronic effects of electromagnetic fields (10 CFR 51 Footnote 5 to Table B-1): 
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February 2010 4-15 Draft NUREG-1437, Supplement 42 

1 If in the future, the Commission finds that, contrary to current indications, a 

2 consensus has been reached by appropriate Federal health agencies that there 

3 are adverse health effects from electromagnetic fields, the Commission will 

4 require applicants to submit plant-specific reviews of these health effects as part 

5 of their license renewal applications. Until such time, applicants for license 

6 renewal are not required to submit information on this issue. 

7 The Staff considers a GEIS finding of an “uncertain” hazard appropriate and will continue to 

8 follow developments on this issue. 

9 4.9 SOCIOECONOMICS 

10 Category 1 issues depicted in 10 CFR Part 51, Subpart A, Appendix B, Table B-1, which are 

11 applicable to socioeconomic impacts during the renewal term are listed in Table 4-10. As stated 

12 in the GEIS, the impacts associated with these Category 1 issues are determined to be SMALL, 

13 and plant-specific mitigation measures would not be sufficiently beneficial to be warranted. 

14 The Staff reviewed and evaluated the DAEC ER, public scoping comments, other available 

15 information, and visited DAEC in search of new and significant information that could change 

16 the conclusions presented in the GEIS. No new and significant information was identified during 

17 this review. Therefore, it is expected that there would be no impacts related to these Category 1 

18 issues during the renewal term beyond those discussed in the GEIS. 

19 Table 4-10. Category 1 Issues Applicable to Socioeconomics during the Renewal Term 

ISSUE—10 CFR Part 51, Subpart A, Appendix B, Table B-1 GEIS Section 

Socioeconomics 

Public services: public safety, social services, and tourism and recreation 4.7.3; 4.7.3.3; 4.7.3.4; 

4.7.3.6 

Public services: education (license renewal term) 4.7.3.1 

Aesthetic impacts (license renewal term) 4.7.6 

Aesthetic impacts of transmission lines (license renewal term) 4.5.8 

20 4.9.1 Generic Socioeconomic Issues 

21 The results of the NRC review and brief statement of GEIS conclusions, as codified in Table B-1 

22 of 10 CFR Part 51, Subpart A, Appendix B, for each of the socioeconomic Category 1 issues 

23 over the license renewal term are provided below: 

24 Public services: public safety, social services, and tourism and recreation. Based on 

25 information in the GEIS, the Commission found that: Impacts to public safety, social services, 

26 and tourism and recreation are expected to be of a significance level of SMALL at all sites. 
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Draft NUREG-1437, Supplement 42 4-16 February 2010 

1 Public services: education. Based on information in the GEIS, the Commission found that: 

2 Only impacts of a significance level of SMALL are expected. 

3 Aesthetic impacts. Based on information in the GEIS, the Commission found that: No 

4 significant impacts are expected during the license renewal term 

5 Aesthetic impacts of transmission lines. Based on information in the GEIS, the Commission 

6 found that: No significant impacts are expected during the license renewal term 

7 No new and significant information was identified for these issues during the review. Therefore, 

8 no impacts are expected during the renewal term beyond those discussed in the GEIS. 

9 Table 4-11 lists the Category 2 socioeconomic issues that require plant-specific analysis and an 

10 environmental justice impact assessment, which was not addressed in the GEIS. 

11 Table 4-11. Category 2 Issues Applicable to Socioeconomics and Environmental Justice 

12 during the Renewal Term 

ISSUE—10 CFR Part 51, Subpart A, 

Appendix B, Table B-1 GEIS Section 

10 CFR 51.53(c)(3)(ii) 

Subparagraph SEIS Section

Socioeconomics 

Housing impacts 4.7.1 I 4.4.1 

Public services: public utilities 4.7.3.5 I 4.4.2 

Offsite land use (license renewal term) 4.7.4 I 4.4.3 

Public services: transportation 4.7.3.2 J 4.4.4 

Historic and archaeological resources 4.7.7 K 4.4.5 

Environmental justice Not addressed(a) Not addressed(a) 4.4.6 

(a) Guidance related to environmental justice was not in place at the time the GEIS and the associated revision to 

10 CFR Part 51 were prepared; therefore, environmental justice must be addressed in plant-specific reviews. 

13 4.9.2 Housing Impacts 

14 Appendix C of the GEIS presents a population characterization method based on two factors: 

15 sparseness and proximity (NRC, Section C.1.4, 1996). Sparseness measures population 

16 density within 20 miles of the site, and proximity measures population density and city size 

17 within 50 miles of the site. Each factor has categories of density and size (NRC, Table C.1, 

18 1996). A matrix is used to rank the population category as low, medium, or high (NRC, Figure 

19 C.1, 1996). 

20 In 2000, approximately 210,081 persons lived within a 32-km (20-mi) radius of DAEC, which 

equates to a population density of 167 persons per mi2 21 . This density translates to a Category 4 

(greater than or equal to 120 persons per mi2 22 within 20miles) using the GEIS measure of 

23 sparseness (FPL-DA, 2008a). At the same time, there were approximately 621,461 persons 

living within a 50-mi radius of the plant, for a density of 79 persons per mi2 24 , meaning that DAEC 
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February 2010 4-17 Draft NUREG-1437, Supplement 42 

1 falls into Category 3 (one or more cities with 100,000 or more persons and less than 190 

persons per mi2 2 within 50miles (80 km) on the NRC proximity scale. A Category 4 value for 

3 sparseness and a Category 3 value for proximity indicate that DAEC is in a high density 

4 population area. 

5 Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, states that impacts on housing availability 

6 are expected to be of SMALL significance in medium-density population areas where 

7 growth-control measures are not in effect. Although DAEC is located in a high population area, 

8 Linn and Benton Counties are not subject to growth-control measures that would limit housing 

9 development, therefore, any DAEC employment-related impact on housing availability would 

10 likely be SMALL. FPL-DA has indicated that employment levels at DAEC would remain 

11 relatively constant with no additional demand for housing during the license renewal term. In 

12 addition, the number of available housing units has kept pace with growth in the area 

13 population. Based on this information, there would be no impact on housing during the license 

14 renewal term beyond what has already been experienced. 

15 4.9.3 Public Services: Public Utility Impacts 

16 Impacts on public utility services are considered SMALL if there is little or no change in the 

17 ability of the system to respond to demand and thus there is no need to add capital facilities. 

18 Impacts are considered MODERATE if service capabilities are overtaxed during periods of peak 

19 demand. Impacts are considered LARGE if services (e.g., water, sewer) are substantially 

20 degraded and additional capacity is needed to meet ongoing demand. The GEIS indicated that, 

21 in the absence of new and significant information to the contrary, the only impacts on public 

22 utilities that could be significant are impacts on public water supplies. 

23 The Staff’s analysis of impacts on the public water and sewer systems considered both plant 

24 demand and plant-related population growth. Section 2.1.7 of this DSEIS describes the DAEC 

25 permitted withdrawal rate and actual use of water. 

26 As discussed in Chapter 2, DAEC provides potable water for drinking, pump seal cooling, 

27 sanitation, and fire protection through the onsite groundwater well system. DAEC does not use 

28 water from a municipal system and plant groundwater usage during the renewed license period 

29 of operations would be considered SMALL. Further, no increase in plant demand is projected. 

30 DAEC operations during the license renewal term would also not increase plant-related 

31 population growth demand for public water and sewer services. Since FPL-DA has indicated 

32 that overall employment levels at DAEC would remain relatively constant with no additional 

33 demand for public services, both public and private water systems in the region would be 

34 adequate to provide the capacity and to meet the demand of residential and industrial 

35 customers in the area. Therefore, there would be no additional impact to public water services 

36 during the license renewal term beyond what is currently being experienced. 
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Draft NUREG-1437, Supplement 42 4-18 February 2010 

1 4.9.4 Offsite Land Use 

2 Offsite land use during the license renewal term is a Category 2 issue (10 CFR Part 51, 4 

3 Subpart A, Appendix B, Table B-1). Table B-1 notes that “significant changes in land use may 

4 be associated with population and tax revenue changes resulting from license renewal.” Section 

5 4.7.4 of the GEIS defines the magnitude of land use changes as a result of plant operation 

6 during the license renewal term as follows: 

7 ● SMALL—little new development and minimal changes to an area’s land 

8 use pattern 

9 ● MODERATE—considerable new development and some changes to the 

10 land use pattern 

11 ● LARGE—large-scale new development and major changes in the land use 

12 pattern 

13 Tax revenue can affect land use because it enables local jurisdictions to provide the public 

14 services (e.g., transportation and utilities) necessary to support development. Section 4.7.4.1 of 

15 the GEIS states that the assessment of tax-driven land use impacts during the license renewal 

16 term should consider (1) the size of the plant’s payments relative to the community’s total 

17 revenues, (2) the nature of the community’s existing land use pattern, and (3) the extent to 

18 which the community already has public services in place to support and guide development. If 

19 the plant’s tax payments are projected to be small, relative to the community’s total revenue, tax 

20 driven land use changes during the plant’s license renewal term would be SMALL, especially 

21 where the community has pre-established patterns of development and has provided adequate 

22 public services to support and guide development. Section 4.7.2.1 of the GEIS states that if tax 

23 payments by the plant owner are less than 10 percent of the taxing jurisdiction’s revenue, the 

24 significance level would be SMALL. If the plant’s tax payments are projected to be MODERATE 

25 to LARGE relative to the community’s total revenue, new tax-driven land use changes would be 

26 MODERATE. If the plant’s tax payments are projected to be a dominant source of the 

27 community’s total revenue, new tax-driven land use changes would be LARGE. This would be 

28 especially true if the community has no pre-established pattern of development or has not 

29 provided adequate public services to support and guide development. 

30 4.9.4.1 Population-Related Impacts 

31 Since FPL-DA has indicated that they have no plans to add non-outage employees during the 

32 license renewal period, there would be no noticeable change in land use conditions in the 

33 vicinity of DAEC. Therefore, there would be no population-related land use impacts during the 

34 license renewal term beyond those already being experienced. 

35 4.9.4.2 Tax-Revenue-Related Impacts 

36 As discussed in Chapter 2, FPL-DA pays annual real estate taxes to Linn County. For the four37 year period from 2005 through 2008, tax payments to Linn County represented between 0.3 and 
Environmental Impacts of Operation 

February 2010 4-19 Draft NUREG-1437, Supplement 42 

1 0.4 percent of the county’s total property tax revenue collections. Since FPL-DA started making 

2 payments to local jurisdictions, population levels and land use conditions in Linn County have 

3 not changed significantly, which may indicate that these tax revenues have had little or no effect 

4 on land use activities within the county. 

5 FPL-DA has indicated that it plans no construction refurbishment activities to support the 

6 continued operation of DAEC during the license renewal period. Accordingly, there would be no 

7 increase in the assessed value of DAEC, and annual property tax payments to Linn County 

8 would be expected to remain relatively unchanged throughout the license renewal period. 

9 Based on this information, there would be no land use impacts related to tax revenue during the 

10 license renewal term beyond those already being experienced. 

11 4.9.5 Public Services: Transportation Impacts 

12 Table B-1 in 10 CFR Part 51 states the following: 

13 Transportation impacts (level of service) of highway traffic generated during the 

14 term of the renewed license are generally expected to be of SMALL significance. 

15 However, the increase in traffic associated with additional workers and the local 

16 road and traffic control conditions may lead to impacts of MODERATE or LARGE 

17 significance at some sites. 

18 The regulation in 10 CFR 51.53(c)(3)(ii)(J) requires all applicants to assess the impacts of 

19 highway traffic generated by the proposed project on the level of service of local highways 

20 during the term of the renewed license. Since FPL-DA has no plans to add non-outage 

21 employees during the license renewal period, traffic volume and levels of service would remain 

22 unchanged. Therefore, there would be no transportation impacts during the license renewal 

23 term beyond those already being experienced. 

24 4.9.6 Historic and Archaeological Resources 

25 The National Historic Preservation Act (NHPA) requires Federal agencies to take into account 

26 the potential effects of their undertakings on historic properties. Historic properties are defined 

27 as resources that are eligible for listing on the National Register of Historic Places (NRHP). The 

28 criteria for eligibility include: (1) association with significant events in history; (2) association with 

29 the lives of persons significant in the past; (3) embodiment of distinctive characteristics of type, 

30 period, or construction; and (4) association with or potential to yield important information on 

31 history or prehistory. The historic preservation review process mandated by Section 106 of the 

32 NHPA is outlined in regulations issued by the Advisory Council on Historic Preservation in Title 

33 36, “Parks, Forests, and Public Property,” Part 800, “Protection of Historic Properties,” of the 

34 Code of Federal Regulations (36 CFR Part 800). The issuance of a renewed operating license 

35 for a nuclear power plant is a Federal undertaking that could possibly affect either known or 

36 potential historic properties located on or near the plant and its associated transmission lines. In 

37 accordance with the provisions of the NHPA, NRC is required to make a reasonable effort to 

38 identify historic properties in the areas of potential effect. If no historic properties are present or 

39 affected, NRC is required to notify the State Historic Preservation Office (SHPO) before 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-20 February 2010 

1 proceeding. If it is determined that historic properties are present, NRC is required to assess 

2 and resolve possible adverse effects of the undertaking. 

3 In April 2007, DAEC contacted the State Historical Society of Iowa concerning the relicense 

4 application being submitted by DAEC to the NRC. The State Historical Society of Iowa did not 

5 respond to the letter. NRC contacted the Iowa SHPO by letter on May 7, 2009 concerning the 

6 proposed relicensing of DAEC. NRC also contacted the Iowa State Archaeologist and the 

7 Advisory Council on Historic Preservation by letter dated May 7, 2009. NRC contacted 

8 seventeen Native American tribes in association with the relicensing action (see Appendix E). 

9 Five archaeological investigations have taken place on the DAEC property. Surveys have 

10 examined roughly 16.1 ac of the 900-ac property. The ER conducted for the initial construction 

11 of the DAEC in 1973 did not identify any historic or archaeological resources. However, the final 

12 environmental statement (FES) acknowledged that surveys were being conducted for the 

13 Pleasant Creek Reservoir to the northwest of the DAEC (AEC, 1973). The Pleasant Creek 

14 Reservoir surveys were the first systematic surveys conducted in the vicinity of the plant. 

15 Fifty-five archaeological sites were identified during the Pleasant Creek survey (Benn, 1974). 

16 In 1993, an archaeological survey sponsored by Linn County titled the Archaeological, 

17 Historical, and Architectural Survey of Fayette Township in Linn County, Iowa, examined 

18 several areas near and at the DAEC. The survey, which focused on historic era properties, 

19 identified the remains of four historic era sites on the DAEC property. The first site 13LN362 is 

an artifact scatter associated with a mid-19th 20 century farmstead. Rogers and Page 

21 recommended that site 13LN362 not be deemed eligible for listing on the NRHP (Rogers and 

Page, 1993). The second site, 13LN363, is the remains of a late 19th 22 century farmstead; it was 

23 recommended as potentially eligible for listing on the NRHP (Rogers and Page, 1993). A 

limestone well is visible at the site. The third site, 13LN365, is a late 19th 24 century farmstead that 

25 Rogers and Page recommended as potentially eligible for the NRHP. The final site, 13LN366, is 

an artifact scatter dating to the late 19th 26 century; this site was recommended as potentially 

27 eligible by Rogers and Page. 

28 The next three surveys conducted at DAEC occurred between 2000 and 2006. An 8.5-acre 

29 survey of an independent spent fuel storage facility conducted in 2001 by the University of Iowa 

30 did not identify any archaeological remains (UI, 2001). In 2005, the Louis Berger Group, Inc. 

31 conducted an archaeological survey of 7 acres for a cellular communications tower. No 

32 archaeological material was identified (Higginbottom 2005). The final field survey conducted on 

33 DAEC property examined a 1.9 acre area of shoreline along the Cedar River. The survey, 

34 conducted by the Louis Berger Group, did not identify any archaeological remains (Louis Berger 

35 Group, Inc. 2006). 

36 In 2008, DAEC contracted with Louis Berger Group, Inc. to perform a historic document review 

37 for the entire 900-acre property in anticipation of license renewal. The archival research 

38 identified five locations on the DAEC property that could contain historic and archaeological 

39 remains in addition to the four known archaeological sites (Louis Berger Group, Inc., 2008). The 

40 records indicate the potential presence of four residences or farmsteads and a platted townsite 

41 on the DAEC site. The report does not agree with the 1993 recommendation by Rogers and 
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February 2010 4-21 Draft NUREG-1437, Supplement 42 

1 Page that site 13LN362 is not eligible for listing on the NRHP. It recommends that 13LN362 be 

2 considered potentially eligible until further testing can be undertaken. Several of the landforms 

3 on the DAEC property contain the potential for archaeological remains (Louis Berger Group Inc., 

4 2008). As of July 2009, the SHPO review of the 2008 Louis Berger report had not occurred. 

5 Most impacts to historic and archaeological resources occur during ground disturbing activities. 

6 DAEC maintains excavation and trenching procedures. An Staff review of the procedures found 

7 that known resources are considered in the excavation and trenching procedures; however, 

8 undiscovered historic and archaeological sites could be affected by plant activities. The large 

9 numbers of historic and archaeological resources previously found in the vicinity of the DAEC 

10 indicate a potential for undiscovered resources to be present on the DAEC. Revised procedures 

11 and development of a cultural resources management plan would address potential impacts to 

12 both known and undiscovered resources. 

13 The transmission assets connecting DAEC to the grid are owned by ITC Midwest LLC. There 

14 are twelve historic and archaeological resources within the DAEC transmission line corridors. 

15 Information concerning the resources was provided to ITC. ITC indicated that they would 

16 coordinate management of the resources with the SHPO. 

17 DAEC has not proposed any new facilities, service roads, or transmission lines associated with 

18 license renewal or refurbishment, therefore, no impacts are expected to historic and 

19 archaeological resources from license renewal. However, limitations in the procedures for 

20 considering unknown historic and archaeological remains during plant operations and the 

21 potential for the presence of unidentified remains on the DAEC property makes the potential for 

22 impacts resulting from future operations possible. 

23 Based on the Staff’s review of past surveys conducted at the DAEC, procedures for reviewing 

24 historic and archaeological materials, and review of the Iowa Historical Society and Iowa State 

25 Archaeologist files for the region, the Staff concludes that the potential impacts on historic and 

26 archaeological resources at DAEC could be MODERATE. Potential impacts could be minimized 

27 or avoided if DAEC develops procedures that more effectively consider historic and 

28 archaeological resources, and develops a cultural resource management plan. 

29 Most impacts to historic and archaeological resources occur during ground disturbing activities. 

30 DAEC maintains excavation and trenching procedures. A Staff review of the procedures found 

31 that known resources are considered in the excavation and trenching procedures however, 

32 undiscovered historic and archaeological sites could be affected by plant activities. The large 

33 numbers of historic and archaeological resources previously found in the vicinity of the DAEC 

34 indicate a potential for undiscovered resources to be present on the DAEC. Revised procedures 

35 and development of a cultural resources management plan would address potential impacts to 

36 both known and undiscovered resources. DAEC in coordination with the SHPO has revised its 

37 excavation and trenching procedures and developed a cultural resource management plan for 

38 the plant property. The revised procedures and cultural resource management plan will be 

39 implemented once all consulting parties have reviewed and agree that the procedures 

40 effectively consider historic and archaeological resources. 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-22 February 2010 

1 DAEC has not proposed any new facilities, service roads, or transmission lines associated with 

2 license renewal or refurbishment, therefore, no impacts are expected to historic and 

3 archaeological resources from license renewal. However, limitations in the procedures for 

4 considering unknown historic and archaeological remains during plant operations and the 

5 potential for the presence of unidentified remains on the DAEC property makes the potential for 

6 impacts resulting from future operations possible.

7 Based on the Staff’s review of past surveys conducted at the DAEC, review of the procedures 

8 for considering historic and archaeological materials at DAEC, and review of the Iowa Historical 

9 Society and Iowa State Archaeologist files for the region, the Staff concludes that the potential 

10 impacts on historic and archaeological resources at DAEC would be MODERATE. As 

11 mentioned, the DAEC is in the process of finalizing its revised procedures and cultural resource 

12 management plan. This MODERATE impact could be mitigated (i.e., potential impacts could be 

13 reduced) once the revised procedures and cultural resources management plan are 

14 implemented. 

15 4.9.7 Environmental Justice 

16 Under Executive Order (E.O.) 12898 (59 FR 7629), Federal agencies are responsible for 

17 identifying and addressing potential disproportionately high and adverse human health and 

18 environmental impacts on minority and low-income populations. Although the E.O. is not 

19 mandatory for independent agencies such as the NRC, the NRC has voluntarily committed to 

20 undertake environmental justice reviews. In 2004, the Commission issued a Policy Statement 

21 on the Treatment of Environmental Justice Matters in NRC Regulatory and Licensing Actions

22 (69 FR 52040), which states that “[t]he Commission is committed to the general goals set forth 

23 in E.O. 12898, and strives to meet those goals as part of its National Environmental Policy Act 

24 (NEPA) review process.” 

25 The Council of Environmental Quality (CEQ) provides the following information in Environmental 

26 Justice: Guidance Under the National Environmental Policy Act (CEQ, 1997). This guidance 

27 states: 

28 Disproportionately High and Adverse Human Health Effects. Adverse health 

29 effects are measured in risks and rates that could result in latent cancer fatalities, 

30 as well as other fatal or nonfatal adverse impacts on human health. Adverse 

31 health effects may include bodily impairment, infirmity, illness, or death. 

32 Disproportionately high and adverse human health effects occur when the risk or 

33 rate of exposure to an environmental hazard for a minority or low-income 

34 population is significant (as defined by NEPA) and appreciably exceeds the risk 

35 or exposure rate for the general population or for another appropriate comparison 

36 group (CEQ, 1997). 
Environmental Impacts of Operation 

February 2010 4-23 Draft NUREG-1437, Supplement 42 

1 Disproportionately High and Adverse Environmental Effects. A 

2 disproportionately high environmental impact that is significant (as defined by 

3 NEPA) refers to an impact or risk of an impact on the natural or physical 

4 environment in a low-income or minority community that appreciably exceeds the 

5 environmental impact on the larger community. Such effects may include 

6 ecological, cultural, human health, economic, or social impacts. An adverse 

7 environmental impact is an impact that is determined to be both harmful and 

8 significant (as defined by NEPA). In assessing cultural and aesthetic 

9 environmental impacts, impacts that uniquely affect geographically dislocated or 

10 dispersed minority or low-income populations or American Indian tribes are 

11 considered (CEQ, 1997). 

12 The environmental justice analysis assesses the potential for disproportionately high and 

13 adverse human health or environmental effects on minority and low-income populations that 

14 could result from the operation of DAEC during the renewal term. In assessing the impacts, the 

15 following CEQ definitions of minority individuals and populations, and low-income population 

16 were used (CEQ, 1997): 

17 Minority individuals. Individuals who identify themselves as members of the 

18 following population groups: Hispanic or Latino, American Indian or Alaska 

19 Native, Asian, Black or African American, Native Hawaiian or Other Pacific 

20 Islander, or two or more races, meaning individuals who identified themselves on 

21 a Census form as being a member of two or more races, for example, Hispanic 

22 and Asian. 

23 Minority populations. Minority populations are identified when (1) the minority 

24 population of an affected area exceeds 50 percent or (2) the minority population 

25 percentage of the affected area is meaningfully greater than the minority 

26 population percentage in the general population or other appropriate unit of 

27 geographic analysis. 

28 Low-income population. Low-income populations in an affected area are 

29 identified with the annual statistical poverty thresholds from the U.S. Census 

30 Bureau’s (USCB) Current Population Reports, Series PB60, on Income and 

31 Poverty. 

32 4.9.7.1 Minority Population in 2000 

33 According to 2000 census data, 7.6 percent of the population (approximately 49,296 individuals) 

34 residing within a 50-mile radius of DAEC were minority individuals. The largest minority group 

35 was Black or African American (18,883 individuals, or 2.9 percent), followed by Hispanic 

36 (11,772 individuals, or about 1.8 percent). Approximately 6 percent of the Linn County 

37 population are minorities, with Black or African American (2.5 percent) the largest minority 

38 group, followed by Hispanic (1.4 percent). In Benton County, 1.2 percent of the population are 

39 minorities, with Hispanic (0.6 percent) the largest minority group, followed by Black or African 

40 American (0.2 percent). 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-24 February 2010 

1 The 50-mile radius around DAEC consists of each county with at least one census block group 

2 located within the 50-mile radius. The population demographic data from these counties were 

3 added together to derive average regional percentages. Of the 512 census block groups located 

4 wholly or partly within the 50-mile radius of DAEC, 23 block groups were determined to have 

5 minority population percentages that exceeded the regional percentages by 20 percentage 

6 points or more, or that were more than 50 percent minority. The largest number of minority block 

7 groups was Black or African American, with 14 block groups that exceed the regional 

8 percentage of 20 percent or more, or that were more than 50 percent Black or African American. 

9 These block groups are concentrated in urban areas with high population densities in Black 

10 Hawk County and Linn County. The closest high density minority population to DAEC is located 

11 in the city of Cedar Rapids, IA. Based on 2000 census data, Figure 4-1 shows minority block 

12 groups within a 50-mile radius of DAEC. 
Environmental Impacts of Operation 

February 2010 4-25 Draft NUREG-1437, Supplement 42 

1 

2 Figure 4-1. Aggregate Minority Population within a 50-Mile Radius of Duane Arnold 

3 Energy Center (USCB, 2009). (Source: FPL-DA 2008a, Figure 2.6-3) 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-26 February 2010 

1 4.9.7.2 Low-Income Population in 2000 

2 According to 2000 census data, 59,848 individuals (approximately 9.2 percent) residing within a 

3 50-mi radius of DAEC were identified as living below the Federal poverty threshold. The 1999 

4 Federal poverty threshold was $17,029 for a family of four. According to USCB data, the median 

5 household income for Iowa in 2007 was $47,324, while 11.0 percent of the State population was 

6 determined to be living below the 1999 Federal poverty threshold. Linn County had one of the 

7 higher median household incomes ($53,076) in the state, and a lower percentage (9.9 percent) 

8 of individuals living below the poverty level, when compared to the State. 

9 Census block groups were considered low-income block groups if the percentage of households 

10 below the Federal poverty threshold exceeded the State average by 20 percent or more. Based 

11 on 2000 census data, there were 15 block groups within the 50-mile radius of DAEC that 

12 exceeded the state average for low income households by 20 percent or more, or that were 

13 more than 50 percent low-income. The majority of census block groups with low-income 

14 populations were located in Black Hawk County. The nearest high density low-income 

15 population to DAEC is located in Cedar Rapids, IA. Based on 2000 census data, Figure 4-2 

16 shows low-income block groups within a 50-mi radius of DAEC. 
Environmental Impacts of Operation 

February 2010 4-27 Draft NUREG-1437, Supplement 42 

1 

2 Figure 4-2. Low-Income Population within a 50-Mile Radius of Duane Arnold Energy 

3 Center (USCB, 2009). (Source: FPL-DA, 2008a, Figure 2.6-5) 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-28 February 2010 

1 4.9.7.3 Analysis of Impacts 

2 Consistent with the impact analysis for public and occupational health and safety, the affected 

3 populations are defined as minority and low-income populations who reside within a 50-mi 

4 radius of DAEC. Presidential Executive Order (E.O.) 12898 provides direction for assessing 

5 high and adverse impacts upon minority and low income populations. Based on the analysis of 

6 impacts for other resource areas, there would be no high and adverse impacts from the 

7 operation of DAEC during the license renewal period. Because there are no high or adverse 

8 impacts, by definition there is also no disproportionate impact upon low income or minority 

9 populations. 

10 NRC also analyzed the risk of radiological exposure through the consumption patterns of 

11 special pathway receptors, including subsistence consumption of fish, native vegetation, surface 

12 waters, sediments, and local produce; absorption of contaminants in sediments through the 

13 skin; and inhalation of plant materials. The special pathway receptors analysis is important to 

14 the environmental justice analysis because consumption patterns may reflect the traditional or 

15 cultural practices of minority and low-income populations in the area. 

16 4.9.7.4 Subsistence Consumption of Fish and Wildlife 

17 Section 4-4 of E.O. 12898 (E.O. 12898 1994) directs Federal agencies, whenever practical and 

18 appropriate, to collect and analyze information on the consumption patterns of populations who 

19 rely principally on fish or wildlife or both for subsistence, and to communicate the risks of these 

20 consumption patterns to the public. In this draft SEIS, NRC considered whether or not there 

21 were any means for minority or low-income populations to be disproportionately affected by 

22 examining impacts to American Indian, Hispanic, and other traditional lifestyle special pathway 

23 receptors. Special pathways that took into account the levels of contaminants in native 

24 vegetation, crops, soils and sediments, surface water, fish, and game animals on or near the 

25 DAEC site were considered. 

26 FPL-DA has a comprehensive REMP at DAEC to assess the impact of site operations on the 

27 environment. Samples are collected from the aquatic and terrestrial pathways applicable to the 

28 site. The aquatic pathways include fish, surface waters, and sediment. The terrestrial pathways 

29 include airborne particulates and radioiodine, milk, food products, and direct radiation. During 

30 2007, analyses were performed on collected samples of environmental media as part of the 

31 required REMP, which showed no significant or measurable radiological impact from DAEC 

32 operations (FPL-DA, 2008d). 

33 No effects of plant operation were found in air quality or precipitation data. Gross radioactive 

34 beta concentrations in airborne particulates were identical at the indicator and control locations, 

35 and similar to levels observed from 1992 through 2006. Gamma spectroscopic analysis of 

36 quarterly composites of air particulate filters yielded similar results for indicator and control 

37 locations. Weekly levels of airborne iodine-131 were below the lower limit of detection in all 

38 samples. Precipitation from an onsite location was analyzed for tritium and gamma-emitting 

39 isotopes. No tritium activity was measured and no gamma-emitting isotopes were detected. 

40 Downwind rain-water samples measured small concentrations of tritium, with no tritium detected 

41 in the upwind samples. 
Environmental Impacts of Operation 

February 2010 4-29 Draft NUREG-1437, Supplement 42 

1 Milk data for 2007 show no radiological effects of plant operation. Iodine-131 results were below 

2 detection limits in all samples, and no gamma-emitting isotopes, except naturally occurring 

3 potassium-40, were detected in any milk samples. 

4 For potable groundwater, the annual mean gross beta activity was similar to levels observed 

5 from 1991 through 2006, with the highest reading found at a farm one mile from the plant. 

6 Tritium activity in all samples indicated no effects from plant operation. Twelve onsite 

7 groundwater monitoring wells sampled for gross beta and tritium, and analyses for gamma 

8 emitting isotopes, strontium-89 and strontium-90 were performed. Although higher beta activity 

9 was found, this was most likely from naturally-occurring isotopes. Tritium was identified in one of 

10 twenty-four samples taken from the intermediate depth wells. No plant operational effects were 

11 indicated in any of the samples. Tritium was identified in five of twenty-four samples taken from 

12 the shallow wells; these tritium levels are attributed to gaseous effluents releases. 

13 With the exception of potassium-40, all other gamma-emitting isotopes were below detection 

14 limits in vegetation samples (broadleaf, grain, and forage). Measurable strontium-90 and 

15 cesium-137 activity was found in soil samples of one out of the two onsite locations; these 

16 activity levels are similar to, or lower levels, than those observed from 1991 through 2006, and 

17 are primarily attributable to deposition of Chernobyl fallout. With the exception of naturally18 occurring potassium-40, no gamma-emitting isotopes were identified in edible portions of fish. 

19 River sediments were analyzed for gamma-emitting isotopes. Potassium-40 activity was found, 

20 together with Trace Cs-137 activity. All other gamma-emitting isotopes were below detection 

21 limits. 

22 The results of the 2007 REMP demonstrate that the routine operation at the DAEC site had no 

23 significant or measurable radiological impact on the environment. No elevated radiation levels 

24 were detected in the offsite environment as a result of plant operations and the storage of 

25 radioactive waste. The results of the REMP continue to demonstrate that the operation of the 

26 plant did not result in a significant measurable dose to a member of the general population or 

27 adversely impact the environment as a result of radiological effluents (FPL-DA, 2008d). REMP 

28 continues to demonstrate that the dose to a member of the public from the operation of DAEC 

29 remains significantly below the federally required dose limits specified in 10 CFR Part 20, 

30 “Standards for Protection against Radiation,” and Title 40, “Protection of Environment,” 

31 Part 190, “Environmental Radiation Protection Requirements for Normal Operations of Activities 

32 in the Uranium Fuel Cycle” (40 CFR Part 190). 

33 Based on recent monitoring results, concentrations of contaminants in native vegetation, crops, 

34 soils and sediments, surface water, fish, and game animals in areas surrounding DAEC have 

35 been quite low (at or near the threshold of detection) and seldom above background levels 

36 (FPL-DA, 2009d). Consequently, no disproportionately high and adverse human health impacts 

37 would be expected in special pathway receptor populations in the region as a result of 

38 subsistence consumption of fish and wildlife. 
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Draft NUREG-1437, Supplement 42 4-30 February 2010 

1 4.10 EVALUATION OF NEW AND POTENTIALLY SIGNIFICANT INFORMATION 

2 New and significant information is: (1) information that identifies a significant environmental 

3 issue not covered in the GEIS and codified in Table B-1 of 10 CFR Part 51, Subpart A, 

4 Appendix B, or (2) information that was not considered in the analyses summarized in the GEIS 

5 and that leads to an impact finding that is different from the finding presented in the GEIS and 

6 codified in 10 CFR Part 51. 

7 In preparing to submit its application to renew the DAEC operating license, FPL-DA developed a 

8 process to ensure that information not addressed in nor available during, the GEIS evaluation 

9 regarding the environmental impacts of license renewal for DAEC, would be properly reviewed 

10 before submitting the ER, and to ensure that such new and potentially significant information 

11 related to renewal of the operating license for DAEC would be identified, reviewed, and 

12 assessed during the period of NRC review. FPL-DA staff reviewed the Category 1 issues that 

13 appear in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, to verify that the conclusions of 

14 the GEIS remained valid with respect to DAEC. This review was performed by personnel from 

15 DAEC and its support organization who were familiar with NEPA issues and the scientific 

16 disciplines involved in the preparation of a license renewal ER. 

17 The Staff also has a process for identifying new and significant information. That process is 

18 described in detail in NUREG-1555, Supplement 1, Standard Review Plans for Environmental 

19 Reviews for Nuclear Power Plants, Supplement 1: Operating License Renewal (NRC, 1999b). 

20 The search for new information includes: (1) review of an applicant’s ER and the process for 

21 discovering and evaluating the significance of new information; (2) review of records of public 

22 comments; (3) review of environmental quality standards and regulations; (4) coordination with 

23 Federal, State, and local environmental protection and resource agencies, and (5) review of the 

24 technical literature. New information discovered by the Staff is evaluated for significance using 

25 the criteria set forth in the GEIS. For Category 1 issues where new and significant information is 

26 identified, reconsideration of the conclusions for those issues is limited in scope to the 

27 assessment of the relevant new and significant information; the scope of the assessment does 

28 not include other facets of an issue that are not affected by the new information. 

29 The Staff has not identified any new and significant information on environmental issues listed in 

30 Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, related to the operation of DAEC during 

31 the period of license renewal. The Staff also determined that information provided during the 

32 public comment period did not identify any new issues that require site-specific assessment. 

33 The Staff reviewed the discussion of environmental impacts in the GEIS (NRC, 1996) and 

34 conducted its own independent review (including two public scoping meetings held in April 

35 2008) to identify new and significant information. 

36 4.11 CUMULATIVE IMPACTS 

37 The Staff considered potential cumulative impacts in the environmental analysis of continued 

38 operation of DAEC. For the purposes of this analysis, past actions are those related to the 

39 resources at the time of the power plant licensing and construction; present actions are those 

40 related to the resources at the time of current operation of the power plant; and future actions 
Environmental Impacts of Operation 

February 2010 4-31 Draft NUREG-1437, Supplement 42 

1 are considered to be those that are reasonably foreseeable through the end of plant operation 

2 including the period of extended operation. Therefore, the analysis considers potential impacts 

3 through the end of the current license term as well as the 20-year renewal license term. The 

4 geographic area over which past, present, and future actions would occur is dependent on the 

5 type of action considered and is described below for each impact area. 

6 4.11.1 Land Use 

7 Consistent with the findings in the GEIS, the Staff concludes that the impacts from continued 

8 operation of the DAEC on land use are SMALL. For the purposes of this cumulative impact 

9 assessment, the spatial bounds of consideration include the region within a 50-mi radius of the 

10 site and the transmission line corridors. The Staff concludes that when combined with other 

11 past, present, and reasonably foreseeable future actions, the cumulative impact of DAEC12 related actions during the term of license renewal on land use would be SMALL. 

13 4.11.2 Cumulative Air Quality Impacts 

14 DAEC is located in Linn County, Iowa, which belongs to the EPA Region VII. Linn County is a 

15 part of the Northeast Iowa Intrastate Air Quality Control Region as codified in 40 CFR §81.256. 

16 All counties in the State of Iowa are currently in attainment for all NAAQS. 

17 In the “2008 FPL Group Sustainability Report,” Florida Power and Light (FPL) highlighted the 

18 environmental goals of the company with the emphasis on lowering greenhouse gas (GHG) 

19 emissions by at least 50 percent below 2000 levels by 2050 and implementing energy efficiency 

20 measures along with the use of the renewable resources (FPL, 2009). 

21 The Iowa Climate Change Advisory Council (ICCAC) was created after the Iowa General 

22 Assembly enacted Senate File 485 related to GHG emissions in 2007 and House File 2571 in 

23 2008. ICCAC, with the technical assistance of the U.S. Center for Climate Strategies, evaluated 

24 and addressed policies, cost-effective strategies, and multiple scenarios designed to reduce 

25 statewide GHG emissions. The developed proposals were compiled into the 2008 ICCAC final 

26 report and submitted to the Governor of Iowa and General Assembly (ICCAC, 2008). 

27 Potential cumulative effects of climate change on the area of eastern Iowa, which is part of the 

28 midwestern region, whether or not from natural cycles or anthropogenic (man-induced) 

29 activities, could result in a variety of changes to the air quality of the area. As projected in the 

30 “Global Climate Change Impacts in the United States” report by United States Global Change 

31 Research Program (USGCRP, 2009), the temperatures in the Midwest are expected to rise, 

32 causing more frequent extreme weather events. Increases in average annual temperatures, 

33 higher probability of extreme heat events, higher occurrences of extreme rainfall (intense rainfall 

34 or drought) and changes in the wind patterns could affect concentrations of the air pollutants 

35 and their long-range transport, because their formation partially depends on the temperature 

36 and humidity and is a result of the interactions between hourly changes in the physical and 

37 dynamic properties of the atmosphere, atmospheric circulation features, wind, topography and 

38 energy use (IPCC, 2009). 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-32 February 2010 

1 Consistent with the findings in the GEIS, the Staff concludes that the impacts from continued 

2 operation of the DAEC on air quality are SMALL. As no refurbishment is planned at DAEC 

3 during license renewal period, no additional air emissions would result from refurbishment 

4 activities (FPL-DA 2008a). In comparison with construction and operation of a comparable 

5 fossil-fueled power plant, license renewal would result in a net cumulative deferral of GHG 

6 emissions, which would otherwise be produced if a new gas or coal-fired plant were instead 

7 constructed. When compared with the alternative of a new fossil-fuel power plant, the option of 

8 license renewal also results in a substantial net cumulative deferral in toxic air emissions. 

9 For the purpose of this cumulative air impact assessment, the spatial bounds includes the 

10 Northeast Iowa Intrastate Air Quality Control Region. The Staff concludes that combined with 

11 the emissions from other past, present, and reasonably foreseeable future actions, cumulative 

12 hazardous and criteria air pollutants emissions on air quality from DAEC-related actions would 

13 be SMALL. When considered with respect to an alternative of building a fossil-fuel powered 

14 plant, continuing the operation of the DAEC could constitute a net cumulative beneficial 

15 environmental impact in terms of emissions offsets (i.e., reducing hazardous, criteria, and GHG 

16 air emissions) that would otherwise be generated by a fossil-fuel plant; only the Combined 

17 Alternative (described in Chapter 6) would be equivalent to or would contribute less cumulative 

18 emissions than the option of license renewal. 

19 4.11.3 Cumulative Impact on Water Resources 

20 For the purposes of this cumulative impact assessment, the spatial bounds of the groundwater 

21 system is the alluvial aquifer and Wapsipinicon and Gower aquifer formations; and the surface 

22 water boundary is the Cedar River Basin. Cedar Rapids, IA, is about 15 miles (24 km) 

23 downstream of the DAEC. The Cedar Rapids Water Department draws its water supply from the 

24 alluvium along the river, relying on four well fields with four collector wells and 45 vertical wells. 

25 The average supply rate to residential and industrial customers is 35 million gal/day (130,000 

m3 26 /day). 

27 Actions that can impact groundwater and surface water resources in the region include overuse 

28 of groundwater and surface water resources, unregulated use of water resources, drought 

29 impacts, and the need for flow compensation for consumptive water users. Similar impacts from 

30 future activities are likely to continue in the future. 

31 Within the DAEC local area, private well users are not known to have experienced issues with 

32 declining water levels in their wells. Therefore, it appears reasonable that the use of 

33 groundwater by the plant is not contributing to a significant cumulative effect on local 

34 groundwater users or larger regional users. Based on this reasoning, the Staff concludes that 

35 when added to the groundwater usage from other past, present, and reasonably foreseeable 

36 future actions, the cumulative impact on groundwater use is SMALL. 

37 During a drought, the effect of low-flow river conditions on the Cedar River would be magnified 

38 and could constitute a cumulative impact. As discussed in Section 2.1.7.2, flow in the Cedar 

39 River at Cedar Rapids averages 3,878 cfs. Flow at DAEC is expected to be similar because no 

40 major tributaries enter the river between the facility and Cedar Rapids. The design rate for water 
Environmental Impacts of Operation 

February 2010 4-33 Draft NUREG-1437, Supplement 42 

withdrawal under operating conditions is 11,200 gpm (25 cfs or 0.71 m3 1 /s), or approximately 0.6 

2 percent of the average river flow. 

3 Section 4.3.3 describes NRC’s requirements for assessing water use conflicts on a “small river” 

4 Specifically. During Cedar River low-flow periods, the withdrawal rate and consumptive rate are 

higher proportions of the river flow. By permit, when river flow falls below 500 cfs (14 m3 5 /s), the 

6 Pleasant Creek Recreational Reservoir may discharge to the Cedar River at a rate equal to the 

consumptive use rate of 18 cfs (0.51 m3 7 /s) (IDNR, 2005). At this low-flow threshold, flow in the 

8 river is only 13 percent of the average flow, the withdrawal rate is 5 percent of the low flow, and 

9 the return of blowdown to the river results in a net consumptive rate of over 3 percent of the low 

10 flow. Discharge from the reservoir is not a requirement of the permit. The cumulative effect on 

11 users of the river for water supply, for recreation, and for aquatic habitat could become 

12 significant. For this reason, the Staff concludes that when added to the surface water usage 

13 from other past, present, and reasonably foreseeable future actions, the cumulative impact on 

14 surface water use is SMALL to MODERATE. 

15 4.11.4 Cumulative Impacts on Aquatic Resources 

16 This section addresses past, present, and future actions that could result in adverse cumulative 

17 impacts to aquatic resources within the Cedar River. The headwaters of the Cedar River are 

18 located in Dodge County, Minnesota, where its tributaries, the Little Cedar and the Shell Rock 

19 Rivers merge. The Cedar River flows southeast for 329 miles (529 km) through Iowa to its 

20 confluence with the Iowa River in Columbus Junction, Louisa County, Iowa, about 30 miles (48 

21 km) upstream of the mouth of the Iowa River (Sullivan, 2000). For purposes of this analysis, the 

22 geographic area considered for cumulative impacts on aquatic resources is the Cedar River 

23 Basin. 

24 Water quality is of concern in the Cedar River and multiple stretches of the river are on the 

25 Clean Water Act (CWA) Section 303(d) 2008 list of impaired waters for high levels of bacteria, 

26 algae, polychlorinated biphenyls (PCBs) in fish, and mercury in fish (IDNR, 2008). Eight total 

27 areas have been identified as “impaired,” none of which currently have a water quality 

28 improvement plan in place (IDNR, 2008). “Impaired,” as defined by IDNR does not necessarily 

29 mean that the water body is highly polluted. Many waters on the 2008 303(d) list are considered 

30 “impaired” rather than “fully supported” due to the absence of only a few key aquatic species, 

31 but these waters can continue to support a moderate level of aquatic diversity (IDNR 2009b). 

32 However, for those waters with high levels of bacteria, the designation of “impaired” may 

33 indicate potential risks to recreational use (IDNR, 2009b). Because of the high percentage of 

34 agricultural land along the Cedar River, the majority of the pollution originates from nonpoint 

35 sources including pesticide and other chemical runoff, soil erosion, and nutrient loading from 

36 fertilizers and other organic sources. The IDNR has a Nonpoint Source Management Program 

37 to address some of these issues across the State. 

38 Current municipal and industrial effluents to the Cedar River in the vicinity of DAEC are, and will 

39 continue to be, regulated through NPDES permits by the IDNR. For facilities using the Cedar 

40 River as a source of cooling water, the NPDES permit will also contain regulations pertaining to 

41 the impingement and entrainment of fish and shellfish and temperature limits on heated 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-34 February 2010 

1 effluents to the river. The IDNR periodically reviews and renews NPDES permits, thus 

2 regulating the flow of industrial effluents to the river in a manner that preserves water quality 

3 and protects aquatic resources from impingement and entrainment through implementation of 

4 the best technology available and other mitigative measures. 

5 Because the Cedar River is not a major navigational travel route, channelization and dredging is 

6 not an issue at this time. Erosion from severe weather and flooding has likely affected 

7 sedimentation and clarity of the Cedar River, which may affect fish habitat locally, though this 

8 impact is not expected to significantly alter any fish populations. 

9 As no protected terrestrial species are known to occur on or in the vicinity of the DAEC site, 

10 protected species, discussed in Section 2.2.7, are not expected to be adversely affected due to 

11 future actions during the renewal term. 

12 The Staff examined the cumulative effects of effluents on Cedar River water quality, impacts to 

13 protected species, and effects of neighboring facilities. The Staff concludes that the minimal 

14 aquatic impacts on the continued DAEC operations would not contribute to the overall decline to 

15 the condition of aquatic resources. The Staff believes that the cumulative impacts of DAEC16 related actions during the term of license renewal on aquatic habitat and associated species, 

17 when added to past, present, and reasonably foreseeable future actions would be SMALL. 

18 4.11.5 Cumulative Impacts on Terrestrial Resources 

19 This section addresses past, present, and future actions that could result in adverse cumulative 

20 impacts to terrestrial resources, including wildlife populations, prairie and woodlands, riparian 

21 zones, invasive species, protected species, and land use. For purposes of this analysis, the 

22 geographic area considered in this evaluation includes the DAEC site and in-scope transmission 

23 line ROWs. 

24 Approximately 100 ac (40 ha) of the 500-ac (200-ha) site was originally disturbed for plant 

25 construction and associated machinery (AEC, 1973). In total, 140 ac (57 ha) contain the 

26 generating facility, associated buildings, switchyard, parking lots, and mowed areas (FPL-DA 

27 2008a). The site is situated on the western bank of the Cedar River. Before DAEC was 

28 constructed, the majority of the site’s land was cultivated with some grassland and woodland 

29 areas on and near the site (FPL-DA, 2008a). Because the land was previously farmed, no trees 

30 were removed during construction of DAEC (AEC, 1973). Removal of vegetation on the bank of 

31 the Cedar River for intake and discharge construction resulted in some erosion of the river bank; 

32 however the FES (AEC, 1973) states that the applicant replanted these areas after construction 

33 to mitigate the effects of clearing the area. 

34 Construction of the transmission lines required 1,155 ac (467 ha) to be disturbed for the 85 

35 miles (137 km) of lines constructed for plant operation (AEC, 1973). About 21 percent, or 18 

36 miles (29 km), of the constructed lines were routed along public roads or railroads and utilized 

37 existing ROWs, which minimized the impact of land disturbance associated with line 

38 construction and ROW clearance. The remaining 67 miles (108 km) of constructed lines were 

39 constructed over private property, of which 85.9 percent was previously cultivated, 6.5 percent 
Environmental Impacts of Operation 

February 2010 4-35 Draft NUREG-1437, Supplement 42 

1 was pasture, 3.6 percent was wooded, and 4.0 percent was marshland (AEC, 1973). Some 

2 minor habitat fragmentation may have occurred as a result of line construction and ROW 

3 clearance through forested and marsh areas, which may have resulted in edge effects such as 

4 changes in light, wind, and temperature, changes in abundance and distribution of interior 

5 species, and reduced habitat ranges for certain species. ROW maintenance has likely had past 

6 impacts and is likely to have present and future impacts on the terrestrial habitat, which may 

7 include bioaccumulation of chemicals, prevention of the natural successional stages of the 

8 surrounding vegetative communities in the ROWs, an increase in abundance of edge species, a 

9 decrease in abundance of interior species, and an increase in invasive species populations. 

10 As no protected terrestrial species are known to occur on or in the vicinity of the DAEC site, 

11 protected species, discussed in Section 2.2.7, are not expected to be adversely affected due to 

12 future actions during the renewal term. Numerous parks and natural areas are located in the 

13 vicinity of the DAEC site, which will continue to provide habitat for protected species and other 

14 wildlife. 

15 The Prairie Creek Generating Station, owned by Interstate Power and Light Company and 

16 operated by Alliant Energy, is located along the Cedar River approximately 20miles (32 km) 

17 downstream of DAEC in Cedar Rapids, IA. The 245-megawatt (MW) coal-fired plant began 

18 operation in 1951 and has a total of four units, the latest of which began operating in 1997. In 

19 addition to the Prairie Creek Generating Station, five other fossil-fuel fired generating facilities 

20 are located within a 50-mi (80-km) radius of DAEC. These facilities are the 6th Street 

21 Generating Station and the Archer Daniels Midland Cedar Rapids Plant, both in Cedar Rapids, 

22 IA; and the Streeter Station, the Electrifarm Generating Station, and the Cedar Falls Gas 

23 Turbine Station, which are in Black Hawk County, Iowa (FPL-DA, 2008a). Coal-fired plants are a 

24 major source of air pollution in the United States because they release sulfur dioxide, nitrogen 

25 oxides, mercury, carbon dioxide, and particulates. Nitrous oxides and sulfur dioxides combine 

26 with water to form acid rain, which can lead to erosion and changes in soil pH levels. Mercury 

27 deposits onto soil and surface water, which may then be taken up by terrestrial and aquatic 

28 plant or animal species and pose the risk of bioaccumulation. For these reasons, the Prairie 

29 Creek Generating Station is likely to have current and future adverse effects to the environment 

30 in the Cedar River Basin. 

31 The majority of land surrounding the DAEC site is rural and used for agricultural purposes. 

32 Pesticide and herbicide runoff is a primary contributor of water pollutants in the Cedar River and 

33 its tributaries. Additionally, the cities of Waterloo, Iowa City, and Cedar Rapids lie 34 miles (55 

34 km) to the northwest, 32 miles (52 km) to the northeast, and 5.7 miles (9.2 km) to the southeast 

35 of DAEC, respectively. Continued development of these areas may result in additional runoff 

36 from roads and impervious surfaces, development adjacent to wetlands and riparian zones, and 

37 an increase in waste releases, all of which could have adverse impacts on terrestrial habitat. 

38 The Staff examined the cumulative effects of initial construction of the site and transmission 

39 lines, impacts to protected species, effects of neighboring facilities, and continued land 

40 development in the Cedar Rapids area. The Staff concludes that the minimal terrestrial impacts 

41 on the continued DAEC operations would not contribute to the overall decline in the condition of 

42 terrestrial resources. The Staff believes that the expected cumulative impacts of other and 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-36 February 2010 

1 future actions during the term of license renewal on terrestrial habitat and associated species, 

2 when added to past, present, and reasonably foreseeable future actions, are SMALL. 

3 4.11.6 Cumulative Human Health Impacts 

4 The NRC and the EPA established radiological dose limits for protection of the public and 

5 workers from both acute and long-term exposure to radiation and radioactive materials. These 

6 dose limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.8.1, 

7 the doses resulting from operation of DAEC are below regulatory limits and the impacts of these 

8 exposures are SMALL. For the purposes of this cumulative impact analysis, the geographical 

9 area involves a 50-mile (80-km) radius around the DAEC site. 

10 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 

11 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 

12 facilities, and transportation of fuel and waste. In addition, as discussed in Section 4.8.1, DAEC 

13 conducts a radiological environmental monitoring program around its site, which was initiated 

14 before commercial operation began in 1975. This program measures radiation and radioactive 

15 materials from DAEC and all other sources. 

16 As discussed in Section 4.8.1 of this report, the Staff reviewed the radiological environmental 

17 monitoring results for DAEC over the five-year period from 2004–2008 as part of this cumulative 

18 impacts assessment. Cumulative radiological impacts from all uranium fuel cycle facilities within 

19 a 50-mi (80-km) radius of the DAEC site are limited by the dose limits in 10 CFR Part 20 and 40 

20 CFR Part 190. There are no other uranium fuel-cycle facilities within a 50-mi (80-km) radius of 

21 DAEC. 

22 Based on the Staff’s review of DAEC’s radiological environmental monitoring results, the 

23 radioactive effluent release data, and the expected continued compliance with Federal radiation 

24 protection standards, the cumulative radiological impacts to human health when combined with 

25 all past, present, and reasonably foreseeable future actions would be SMALL. The NRC and the 

26 State of Iowa will regulate any future development or actions in the vicinity of the DAEC site that 

27 could contribute to cumulative radiological impacts. 

28 As discussed in Section 4.8.2, the continued operation of DAEC has a low risk of causing 

29 outbreaks from thermophilic microbiological organisms associated with thermal discharges. 

30 Available data compiled into biannual reports by the CDC for the years 1999 to 2006 (CDC 

31 2000, 2002, 2004, 2006) indicates no occurrence of waterborne disease outbreaks in the State 

32 of Nebraska resulting from exposure to the thermophilic microbiological organisms Naegleria 

33 fowleri and Pseudomonas aeruginosa. 

34 As part of its evaluation of cumulative impacts, the Staff also considered the effects of thermal 

35 discharges from other facilities on the Cedar River located within one mile upstream of DAEC 

36 that are also producing thermal effluents. Such facilities could promote the growth of 

37 thermophilic microbiological organisms. The Staff did not identify any such facilities. The Staff 

38 concludes that, thermophilic microbiological organisms are not likely to present a public health 

39 hazard as a result of DAEC discharges to the Cedar River. The Staff concludes that when 
Environmental Impacts of Operation 

February 2010 4-37 Draft NUREG-1437, Supplement 42 

1 combined with other past, present, and reasonably foreseeable future actions, the cumulative 

2 impact on public health from thermophilic microbiological organisms would be SMALL. 

3 The Staff determined that the DAEC transmission lines are operating within original design 

4 specifications and meet current NESC clearance standards. The DAEC transmission lines, 

5 when combined with other past, present, and reasonably foreseeable future electrical sources, 

6 contribute only a SMALL cumulative potential for electric shock. 

7 With respect to the chronic effects of EMF, although the GEIS finding of “uncertain” is 

8 appropriate to DAEC, the transmission lines associated with DAEC are not likely to detectably 

9 contribute to the regional exposure of extremely low frequency electromagnetic fields. 

10 Therefore, the Staff has determined that when combined with other past, present, and 

11 reasonably foreseeable future actions, the continued operation of the DAEC transmission lines 

12 on cumulative chronic EMF impacts would be SMALL. 

13 4.11.7 Cumulative Socioeconomic Impacts 

14 For the purposes of this cumulative impact assessment, the geographical bounds of the 

15 analysis are Lynn and Benton Counties. As discussed in Section 4.9 of this DSEIS, the 

16 continued operation of DAEC during the license renewal term would have no measurable 

17 impact on socioeconomic conditions in the region beyond those already being experienced. 

18 Since FPL-DA has indicated that there would be no major plant refurbishment, and overall 

19 expenditures and employment levels at DAEC would remain relatively constant with no 

20 additional demand for housing, public utilities, and public services. In addition, since 

21 employment levels and the value of DAEC would not change, there would be no population and 

22 tax revenue-related land-use impacts. There would also be no disproportionately high or 

23 adverse health or environmental impacts on minority and low-income populations in the region. 

24 Based on this and other information presented in the DSEIS, the cumulative socioeconomic 

25 impact from continued operation of the DAEC, when combined with other past, present, and 

26 reasonably foreseeable future actions would be SMALL. 

27 4.11.8 Historic and Archaeological Resources Cumulative Impacts 

28 As discussed in Section 4.9.6, continued operation of DAEC during the license renewal term 

29 has the potential to impact both known and undiscovered historic and archaeological resources. 

30 Revised procedures and development of a cultural resources management plan would address 

31 potential impacts to both known and undiscovered resources. NRC has concluded that the 

32 impacts of continued operation could have a MODERATE impact on historic and archaeological 

33 resources. 

34 Past activities have included site clearing, and construction of facilities, parking lots, security 

35 trenches, roads, and other ancillary structures, as well as clearing, construction, and 

36 maintenance of the transmission line corridors. 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-38 February 2010 

1 For the purposes of this cumulative impact assessment, the spatial bounds includes the DAEC 

2 site and transmission lines corridors. Cumulative impacts to historic and archaeological 

3 resources can result from the incremental loss of unique site types. DAEC has no plans to alter 

4 the DAEC site for license renewal. Any land disturbing activities would be considered through 

5 the DAEC excavation and trenching procedures. Given that DAEC plant property has the 

6 potential for unknown resources, the Staff concludes that when combined with other past, 

7 present, and reasonably foreseeable future land disturbing activities, the potential cumulative 

8 impacts on historic and archaeological resources could be MODERATE. Cumulative impacts 

9 could be partly mitigated through application of the mitigation measures discussed in Section 

10 4.9.6. 

11 4.11.9 Summary of Cumulative Impacts 

12 The Staff considered the potential impacts resulting from operation of DAEC during the period of 

13 extended operation and other past, present, and reasonably foreseeable future actions in the 

14 vicinity of DAEC. The preliminary determination is that the potential cumulative impacts resulting 

15 from DAEC operation during the period of extended operation would range from SMALL to 

16 MODERATE. Table 4-12 summarizes the cumulative impact by resource area. 
Environmental Impacts of Operation 

February 2010 4-39 Draft NUREG-1437, Supplement 42 

1 Table 4-12. Summary of Cumulative Impacts on Resource Areas 

Resource Area Impact Summary 

Land use SMALL With respect to the DAEC facility, no measurable changes in 

land use would occur over the proposed license renewal term. 

When combined with other past, present, and reasonably 

foreseeable future activities, impacts from continued operation 

of DAEC would constitute a SMALL cumulative impact on 

land use. 

Air quality resources SMALL Impacts of air emissions over the proposed license renewal 

term would be SMALL. When combined with other past, 

present, and reasonably foreseeable future activities, impacts 

to air resources from the DAEC would constitute a SMALL 

cumulative impact on air quality. In comparison with the 

alterative of constructing and operating a comparable gas or 

coal-fired power plant, license renewal would result in a net 

cumulative deferral in both GHG and other toxic air emissions, 

which would otherwise be produced by a fossil-fueled plant. 

Water resources SMALL to 

MODERATE 

Water taken from the Cedar river to support DAEC operations 

constitutes a SMALL effect upon water usage and conflicts, 

When this DAEC water consumption is added to other past, 

present, and reasonably foreseeable future withdraws, 

cumulative impact upon the Cedar River is SMALL. 

Similarly, the Staff concludes that DAEC groundwater 

consumption, when added to groundwater usage from other 

past, present, and reasonably foreseeable future withdraws 

also constitutes a SMALL cumulative impact on groundwater 

on the resource. However, when combined with surface water 

usage from other past, present, and reasonably foreseeable 

future Cedar River withdraws, the cumulative consumption 

impact is SMALL to MODERATE. 

Aquatic resources SMALL Past and present impacts have impacted aquatic resources; 

and, continued impacts from agricultural and other 

development activities have impacted aquatic resources, with 

such effects likely to continue in the future. When combined 

with other past, present, and reasonably foreseeable future 

activities, impacts from continued operation of DAEC would 

constitute a SMALL cumulative impact on aquatic resources. 

Terrestrial resources SMALL Past and present impacts have impacted terrestrial habitat 

and species in the vicinity of DAEC, and would likely continue 

in the future. When combined with other past, present, and 

reasonably foreseeable future activities, impacts from 

continued operation of DAEC would constitute a SMALL 

cumulative impact on aquatic resources. 

Human Health SMALL When combined with the other past, present, and reasonably 

foreseeable future activities, the cumulative human health 

impacts of continued operation of DAEC from radiation 

exposure to the public, microbiological organisms from 

thermal discharge to the Cedar River, and electric-fieldinduced currents from the DAEC transmission lines would all 

be negligible to SMALL. 

Socioeconomics SMALL to When combined with the other past, present, and reasonably 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-40 February 2010 

Resource Area Impact Summary 

MODERATE foreseeable future activities, impacts to socioeconomic 

resources (with the exception of historic and archaeological) 

from continued operation of DAEC have no measurable 

cumulative impact. However, the potential cumulative land 

disturbance impact on historic and archaeological resources 

could be MODERATE. 

1 4.12 REFERENCES 

2 AEC (U.S. Atomic Energy Commission). 1973. Final Environmental Statement Related to 

3 Operation of Duane Arnold Energy Center. Iowa Electric Light and Power Company Docket No. 

4 50-331. Facility Operating License DPR-49. Directorate of Licensing. Directorate of Licensing. 

5 March. Washington, D.C. ADAMS No. ML091200609. 

6 Bechtel Corporation. Letter re: Duane Arnold Energy Center Unit #1, Results of Well Water 

7 Drawdown Test, from R.W. Cote, Supervising Startup Engineer, to G.G. Hunt, Chief Engineer, 

8 Iowa Electric Light & Power Company, December 14, 1972. 

9 Benn, David W., Pleasant Creek Testing I, 1974 Preliminary Report and Recommendations, 

10 Luther College Archaeological Research Center, Decorah, IA, 1974. 

11 CDC (Center for Disease Control and Prevention). Surveillance for Waterborne Disease and 

12 Outbreaks Associated with Recreational Water Use and Other Aquatic Facility-Associated 

13 Health Events --- United States, 1999–2000. Atlanta, GA, 2000. 

14 http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5108a1.htm#tab6 (accessed May, 2009). 

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16 Use and Other Aquatic Facility-Associated Health Events --- United States, 2001–2002. Atlanta, 

17 GA, 2002. http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5308a1.htm#tab3 (accessed May, 

18 2009). 

19 CDC. Surveillance for Waterborne Disease and Outbreaks Associated with Recreational Water 

20 Use and Other Aquatic Facility-Associated Health Events --- United States, 2003–2004. Atlanta, 

21 GA, 2004. http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5512a1.htm (accessed May, 2009). 

22 CDC. Surveillance for Waterborne Disease and Outbreaks Associated with Recreational Water 

23 Use and Other Aquatic Facility-Associated Health Events --- United States, 2005–2006. Atlanta, 

24 GA, 2006. http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5709a1.htm#fig2 (accessed May, 

25 2009). 

26 CEQ (Council on Environmental Quality). Environmental Justice: Guidance Under the National 

27 Environmental Policy Act, December 10, 1997. http://www.whitehouse.gov/CEQ/ 

28 CFR. (U.S. Code of Federal Regulations), “Standards for Protection Against Radiation,” Part 20, 

29 Title 10, “Energy.” 

30 CFR. “Domestic Licensing of Production and Utilization Facilities,” Part 50, Title 10, “Energy.” 

31 CFR. “Environmental Radiation Protection Standards for Nuclear Power Operations,” Part 190, 

32 Title 40, “Energy.” 
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February 2010 4-41 Draft NUREG-1437, Supplement 42 

1 CFR. “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 

2 Title 10, “Energy.” 

3 E.O. (Executive Order) 12898. Federal Actions to Address Environmental Justice in Minority 

4 Populations and Low-Income Populations, 59 FR 7629, February 11, 1994. 

5 FPL (Florida Power & Light Company). “FPL Group 2008 Sustainability Report,” 2009. 

6 http://www.fplgroup.com/pdf/sustain-report.pdf (accessed August, 2009). 

7 FPL- DA 2007d. Duane Arnold Energy Center. 2006 Annual Radioactive Material Release 

8 Report. Palo, IA. 

9 FPL- DA, 2008e. Duane Arnold Energy Center. 2007 Annual Radioactive Material Release 

10 Report. Palo, IA. 

11 FPL-DA (FPL Energy Duane Arnold, LLC) 2005a. Letter Report from D. Curtland, DAEC Plant 

12 Manager – Nuclear to A. Daughtherty, Linn County Health Department, Cedar Rapids, IA, Re: 

13 Annual Emission Point Recap Report for the Duane Arnold Energy Center (DAEC) for 2004, 

14 January 27, 2005. 

15 FPL-DA, 2005b. Updated Final Safety Analysis Report (UFSAR/DAEC-1) Section 1.8 Revision 

16 18 and Section 2.3 Revision 19. 

17 FPL-DA, 2005c. Duane Arnold Energy Center, 2004 Annual Radiological Environmental 

18 Operating Report. Palo, IA. 

19 FPL-DA, 2005d. Duane Arnold Energy Center, 2004 Annual Radioactive Material Release 

20 Report. Palo, IA. 

21 FPL-DA, 2006a. Letter from D. Cleary, FPL Energy, Juno Beach, FL to A. Daugherty, Linn 

22 County Health Department, Cedar Rapids, IA, Re: Notification of Facility Transfer and 

23 Ownership changes for Air Permits. January 27, 2006. 

24 FPL-DA, 2006b. Letter Report from D. Curtland, DAEC Plant Manager – Nuclear to A. 

25 Daughtherty, Linn County Health Department, Cedar Rapids, IA Re: Annual Emission Point 

26 Recap Report for the Duane Arnold Energy Center (DAEC) for 2005. January 12, 2006. 

27 FPL-DA, 2006c. Letter Re: Groundwater Protection – Data Collection Questionnaire, from J.A. 

28 Stall, Senior Vice President Nuclear and Chief Nuclear Officer, to S.A. Richards, Division of 

29 Inspection and Regional Support, Office of Nuclear Reactor Regulation, U.S. Nuclear 

30 Regulatory Commission. July 31, 2006. 

31 FPL-DA, 2006d. Duane Arnold Energy Center. 2005 Annual Radiological Environmental 

32 Operating Report. Palo, IA. 

33 FPL-DA, 2006e. Duane Arnold Energy Center. 2005 Annual Radioactive Material Release 

34 Report. Palo, IA. 

35 FPL-DA, 2007a. Letter Report from D. Curtland, DAEC Plant Manager – Nuclear to A. 

36 Daughtherty, Linn County Health Department, Cedar Rapids, IA, Re: Annual Emission Point 

37 Recap Report for the Duane Arnold Energy Center (DAEC) for 2006, NG-07-0059, January 19, 

38 2007. 
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Draft NUREG-1437, Supplement 42 4-42 February 2010 

1 FPL-DA, 2007b. Protection Initiative Site Conceptual Model, prepared by S. Funk, 

2 19 pages plus attachments, December 19, 2007. 

3 FPL-DA, 2007c. Duane Arnold Energy Center. 2006 Annual Radiological Environmental 

4 Operating Report. Palo, IA. 

5 FPL-DA, 2008a. Applicant’s Environmental Report, Operating License Renewal Stage, Duane 

6 Arnold Energy Center, FPL Energy Duane Arnold LLC, Unit 1, Docket 05000331, License No. 

7 DPR-49, September 2008, ADAMS Accession No. ML08298. 

8 FPL-DA, 2008b. Letter Report from D. Curtland, DAEC Plant Manager – Nuclear to A. 

9 Daughtherty, Linn County Health Department, Cedar Rapids, IA Re: Annual Emission Point 

10 Recap Report for the Duane Arnold Energy Center (DAEC) for 2007, NG-08-0060. January 22, 

11 2008. 

12 FPL-DA, 2008c. Letter re Waste Water Discharge NPDES Renewal, from R.L. Anderson, Vice 

13 President, to W. Hieb, NPDES Section, IDNR. December 31, 2008. 

14 FPL-DA, 2008d. Duane Arnold Energy Center. 2007 Annual Radiological Environmental 

15 Operating Report. Palo, IA. 

16 FPL-DA, 2009a. Letter Report from D. Curtland, DAEC Plant Manager – Nuclear to A. 

17 Daughtherty, Linn County Health Department, Cedar Rapids, IA, Re: Annual Emission Point 

18 Recap Report for the Duane Arnold Energy Center (DAEC) for 2008, NG-09-0080, January 28, 

19 2009. 

20 FPL-DA, 2009b. Emergency Generators and Other Internal Combustion Engine Pre-Planned 

21 Task List, June 2. 

22 FPL-DA, 2009c. Equipment-Specified Maintenance Procedure I-MIT-C012-01, Climatronics 

23 Meteorological Equipment, April 30, 2009. 

24 FPL-DA, 2009d. Duane Arnold Energy Center. 2008 Annual Radiological Environmental 

25 Operating Report. Palo, IA. 

26 FPL-DA, 2009e. Duane Arnold Energy Center. 2008 Annual Radioactive Material Release 

27 Report. Palo, IA. 

28 Higginbottom, D. K. “FCC-Linn County-City of Palo-Interstate Power and Light o.-Construction 

29 of a New Communication Facility-3200 Block DAEC Road-Sec. 9, 84N-R8W-Phase IA Cultural 

30 Resources Investigation [LBG Letter Report].” Letter to J. Archie, (Alliant Energy). Iowa State 

31 Historic Preservation Office. Des Moines, IA, June 24, 2005. 

32 ICCAC (Iowa Climate Change Advisory Council). “Iowa Climate Change Advisory Council Final 

33 Report.” 2008. http://www.iaclimatechange.us/capag.cfm (accessed August, 2009). 

34 IDNR (Iowa Department of Natural Resources). Letter Re: Water Use Permits 3533-R3 and 

35 3046-MR5, from M.T. Moeller, Water Supply Engineering, to D. Siegfried, Duane Arnold Energy 

36 Center, October 31, 2005. 

37 IDNR, 2009a. Letter from I. Foster, Environmental Specialist, Iowa Department of Natural 

38 Resources, to D. Pelton, Branch Chief, Division of License Renewal. Subject: Environmental 
Environmental Impacts of Operation 

February 2010 4-43 Draft NUREG-1437, Supplement 42 

1 Review for Natural Resources for Duane Arnold Energy Center License Renewal Application 

2 Review. May 18, 2009. ADAMS Accession No. ML092020069. 

3 IDNR, 2009b. “The Final 2008 List of Section 303(d) Impaired Waters Fact Sheet.” 

4 http://wqm.igsb.uiowa.edu/WQA/303d/2008/2008FinalListFactSheet.pdf (accessed July 16, 

5 2009). 

6 IDNR. “Iowa’s Final 2008 Integrated Report – Category 5: Water is Threatened or Impaired and 

7 a TDML is Needed.” 2008. http://wqm.igsb.uiowa.edu/WQA/303d/2008/2008IowaIR5-303d.pdf

8 (accessed July 16, 2009). 

9 IEEE (Institute of Electrical and Electronics Safety Code). National Electric Safety Code, 2007. 

10 IPCC (Intergovernmental Panel on Climate Change). “IPCC Fourth Assessment Report: 

11 Working Group II Report "Impacts, Adaptation and Vulnerability.” 

12 http://www.ipcc.ch/ipccreports/ar4-wg2.htm (accessed June, 2009). 

13 Joklik, W.K. and D.T. Smith. Zinsser Microbiology. Addleton-Century-Croft, NY. 1972. 

14 LCPH (Linn County Public Health) 2005a. Air Quality Construction Permit for Auxiliary Boiler, 

15 Permit 4912, November 17, 2005. 

16 LCPH, 2005b. Air Quality Construction Permit for Emergency Generator Diesel Engine 1G-21 

17 SBDG #1, Permit 4913, November 17, 2005. 

18 LCPH, 2005c. Air Quality Construction Permit for Emergency Generator Diesel Engine 1G-31 

19 SBDG #2, Permit 4912, November 17, 2005. 

20 LCPH, 2005d. Air Quality Construction Permit for Pump House Diesel Engine, Permit 4904, 

21 November 17, 2005. 

22 LCPH, 2005e. Air Quality Construction Permit for TSC Diesel Engine, Permit 4915, November 

23 17, 2005. 

24 LCPH, 2005f. Air Quality Construction Permit for Sulfuric Acid Tank, Permit 4916, November 17, 

25 2005. 

26 LCPH, 2005g. Air Quality Construction Permit for 1T-34 Diesel UST, Permit 4917, November 

27 17, 2005. 

28 LCPH, 2005h. Air Quality Construction Permit for 1T-35 Diesel UST, Permit 4918, November 

29 17, 2005. 

30 LCPH, 2005i. Letter from A. Daugherty, LCPH, Cedar Rapids, IA to A. Gould, FPL Energy, Juno 

31 Beach, FL, Re: Air Construction Permits – Ownership Changes, November 28, 2005. 

32 LCPH. Letter from J. Hodina, LCPH, Cedar Rapids, IA, to R. Anderson, DAEC, Palo, IA, Re: 

33 Approval of Variance Request, September 9, 2008. 

34 Louis Berger Group, 2006, Phase I Archaeological Survey for Cedar River Rip-Rap, Linn 

35 County, Iowa, Archaeological Survey Short Report Form, State Historical Society of Iowa, 

36 prepared for United States Army Corps of Engineers, October; Cultural Resource Assessment 

37 of the Duane Arnold Energy Center Property, Near Palo, Linn County, Iowa, prepared for 

38 Florida Power and Light Energy, LLC, DAEC, Palo, IA, June 2008. 
Environmental Impacts of Operation 

Draft NUREG-1437, Supplement 42 4-44 February 2010 

1 Niemann, M.S. and D.B. MacDonald. An Ecological Study of the Terrestrial Plant Communities 

2 in the Vicinity of the Duane Arnold Energy Center. Prepared for Iowa Electric Light and Power 

3 Company, Cedar Rapids, IA, August 1972. ADAMS Accession No. 

4 Northway Well and Pump Co. Data sheets from aquifer test performed November 13, 2001 at 

5 Well A. 

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

7 License Renewal of Nuclear Plants. NUREG-1437, Vols. 1 and 2, Washington, D.C. 1996. 

8 ADAMS Accession Nos. ML040690705 and ML040690738. 

9 NRC 1999a. Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 

10 Main Report, “Section 6.3 – Transportation, Table 9.1, Summary of findings on NEPA issues for 

11 license renewal of nuclear power plants, Final Report.” NUREG-1437, Volume 1, Addendum 1, 

12 Washington, DC. 

13 NRC 1999b. Environmental Standard Review Plan: Standard Review Plans for Environmental 

14 Reviews for Nuclear Power Plants. NUREG-1555, October 1999. 

15 NRC 2009a. Letter from D. Pelton, Branch Chief, Division of License Renewal, to T. Melius, 

16 Regional Director, Region 3, U.S. Fish and Wildlife Service. Subject: Request for List of 

17 Protected Species Within the Area Under Evaluation for the Duane Arnold Energy Center 

18 License Renewal Application Review, May 6, 2009. ADAMS Accession No. ML091210033. 

19 NRC 2009b. Letter from D. Pelton, Branch Chief, Division of License Renewal, to W. 

20 Gieselman, Administrator, Iowa Department of Natural Resources. Subject: Request for List of 

21 Protected Species within the Area Under Evaluation for the Duane Arnold Energy Center 

22 License Renewal Application Review, May 6, 2009. ADAMS Accession No. ML091200651. 

23 Rogers, Leah D. and William C. Page. Linn County Comprehensive Planning Project Phase 

24 Two: Archaeological, Historical, and Architectural Survey Subsection E (Fayette Township), 

25 prepared for the Linn County Historic Preservation Commission and the State Historical Society 

26 of Iowa, Historic Preservation Bureau, September 1993. 

27 Sullivan, D. J. Fish Communities and Their Relation to Environmental Factors in the Eastern 

28 Iowa Basins in Iowa and Minnesota, 1996. Water-Resources Investigations Report 00-4194. 

29 2000. http://pubs.usgs.gov/wri/2000/wri004194/pdf/wri00_4194.pdf (accessed April 24, 2009). 

30 Todar, K. “Todar’s online textbook of bacteriology,” 2007. http://www.textbookofbacteriology.net

31 UI (University of Iowa). Phase I Intensive Archaeological Survey of a Proposed Dry Spent Fuel 

32 Storage Facility, Alliant Energy Corporation, Section 9, T83N-R8W, Linn County, Iowa. Office of 

33 the State Archaeologist, Iowa City, IA, December 4, 2001. 

34 USCB (U.S. Bureau of the Census). American Fact Finder, 2009. http://factfinder.census.gov/

35 USFWS (U.S. Fish and Wildlife Service). Letter from R. Nelson, Field Supervisor, Rock Island 

36 Field Office, to D. Pelton, Branch Chief, Division of License Renewal. Subject: Response to 

37 letter requesting a list of protected species within the area under evaluation for the Duane 

38 Arnold Energy Center license renewal application. May 29, 2009. ADAMS Accession No. 

39 ML092020070. 
Environmental Impacts of Operation 

February 2010 4-45 Draft NUREG-1437, Supplement 42 

1 USGCRP (U.S. Global Change Research Program). “Global Climate Change Impacts in the 

2 United States,” Cambridge University Press, 2009. 

3 WHO (World Health Organization). “Extremely Low Frequency Fields Environmental Health 

4 Criteria Monograph No.238”, World Health Organization, Geneva, Switzerland, 2007. 

5 http://www.who.int/pehemf/publications/elf_ehc/en/index.html (accessed August, 2008). 

February 2010 5-1 Draft NUREG-1437, Supplement 42 

1 5.0 ENVIRONMENTAL IMPACTS OF POSTULATED ACCIDENTS 

2 This chapter describes the environmental impacts from postulated accidents that the Duane 

3 Arnold Energy Center (DAEC) might experience during the period of extended operation. For a 

4 more detailed discussion of this assessment, the reader is referred to Appendix G. The term 

5 “accident” refers to any unintentional event outside the normal plant operational envelope that 

6 results in a release or the potential for release of radioactive materials into the environment. 

7 Two classes of postulated accidents are evaluated in the Generic Environmental Impact 

8 Statements (GEIS) for License Renewal of Nuclear Power Plants prepared by the U.S. Nuclear 

9 Regulatory Commission (NRC), as listed in Table 5-1. These two classes include: 

10 ● design-basis accidents (DBAs) 

11 ● severe accidents 

12 Table 5-1. Issues Related to Postulated Accidents. Two issues related to postulated 

13 accidents are evaluated under the National Environmental Policy Act (NEPA) in the license 

14 renewal review: design-basis accidents and severe accidents.

Issues GEIS Section Category 

Design-basis accidents 5.3.2; 5.5.1 1 

Severe accidents 5.3.3; 5.3.3.2; 5.3.3.3; 5.3.3.4; 5.3.3.5; 5.4; 5.5.2 2 

15 Generic issues (Category 1 issues, see Chapter 1) rely on the analysis provided in the GEIS and are discussed 

16 briefly (NRC 1996,1999a). 

17 5.1 DESIGN BASIS ACCIDENTS 

18 As part of the process for receiving NRC approval to operate a nuclear power facility, an 

19 applicant for an initial operating license must submit a safety analysis report (SAR) as part of its 

20 application. The SAR presents the design criteria and design information for the proposed 

21 reactor and comprehensive data on the proposed site. The SAR also discusses various 

22 hypothetical accident situations and the safety features that are provided to prevent and mitigate 

23 accidents. The NRC staff (Staff) reviews the application to determine whether or not the plant 

24 design meets the NRC’s regulations and requirements and includes, in part, the nuclear plant 

25 design and its anticipated response to an accident. 

26 DBAs are those accidents that both the licensee and the Staff evaluate to ensure that the plant 

27 can withstand normal and abnormal transients, and a broad spectrum of postulated accidents, 

28 without undue hazard to the health and safety of the public. A number of these postulated 

29 accidents are not expected to occur during the life of the plant, but are evaluated to establish 

30 the design basis for the preventive and mitigative safety systems of the facility. The acceptance 

31 criteria for DBAs are described in Title 10 of the Code of Federal Regulations (CFR) Parts 50 

32 and 100. 

33 The environmental impacts of DBAs are evaluated during the initial licensing process. Before a 

34 license renewal is issued, the DBA assessment must demonstrate that the plant can withstand 
Environmental Impacts of Postulated Accidents 

Draft NUREG-1437, Supplement 42 5-2 February 2010 

1 these accidents. The results of these evaluations are found in license documentation such as 

2 the applicant’s final safety analysis report (FSAR), the safety evaluation report (SER), the final 

3 environmental statement (FES), and Section 5.1 of this draft supplemental environmental 

4 impact statement (SEIS). A licensee is required to maintain the acceptable design and 

5 performance criteria throughout the life of the plant, including any extended-life operation. The 

6 consequences for these events are evaluated for the hypothetical maximum exposed individual; 

7 as such, changes in the plant environment will not affect these evaluations. Because of the 

8 requirements that continuous acceptability of the consequences and aging management 

9 programs be in effect for the period of extended operation, the environmental impacts, as 

10 calculated for DBAs, should not differ significantly from initial licensing assessments over the life 

11 of the plant, including the period of extended operation. Accordingly, the design of the plant 

12 relative to DBAs during the period of extended operation is considered to remain acceptable 

13 and the environmental impacts of those accidents were not examined further in the GEIS. 

14 The Commission has determined that the significance level of the environmental impacts of 

15 DBAs are SMALL for all plants because the plants were designed to successfully withstand 

16 these accidents. For the purposes of license renewal, DBAs have been designated as a 

17 Category 1 issue. The early resolution of the DBAs makes them a part of the current licensing 

18 basis of the plant; the current licensing basis of the plant is to be maintained by the licensee 

19 under its current license and, therefore, under the provisions of 10 CFR 54.30, is not subject to 

20 review under license renewal. 

21 No new and significant information related to DBAs was identified during the review of FPL 

22 Energy Duane Arnold, LLC’s (FPL-DA) environmental report (ER) (FPL-DA, 2008), site audit, 

23 scoping process, or evaluation of other available information. Therefore, there are no impacts 

24 related to these issues beyond those discussed in the GEIS. 

25 5.2 SEVERE ACCIDENTS 

26 Severe nuclear accidents are those that are more severe than DBAs because they could result 

27 in substantial damage to the reactor core, whether or not there are serious offsite 

28 consequences. In the GEIS, the Staff assessed the impacts of severe accidents during the 

29 period of extended operation, using the results of existing analyses and site-specific information 

30 to conservatively predict the environmental impacts of severe accidents for each plant during 

31 the period of extended operation. 

32 Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, 

33 fires, and sabotage have not traditionally been discussed in quantitative terms in FESs and 

34 were not specifically considered for the DAEC site in the GEIS (NRC, 1996). However, the GEIS 

35 did evaluate existing impact assessments performed by the Staff and by the industry at 44 

36 nuclear plants in the United States and concluded that the risk from beyond design-basis 

37 earthquakes at existing nuclear power plants is SMALL. The GEIS for license renewal 

38 performed a discretionary analysis of sabotage in connection with license renewal, and 

39 concluded that the core damage and radiological release from such acts would be no worse 

40 than the damage and release expected from internally initiated events. In the GEIS, the NRC 

41 concludes that the risk from sabotage and beyond design-basis earthquakes at existing nuclear 
Environmental Impacts of Postulated Accidents 

February 2010 5-3 Draft NUREG-1437, Supplement 42 

1 power plants is small, and additionally, that the risks from other external events are adequately 

2 addressed by a generic consideration of internally initiated severe accidents (NRC, 1996). 

3 Based on information in the GEIS, the NRC found that: 

4 The probability weighted consequences of atmospheric releases, fallout onto 

5 open bodies of water, releases to ground water, and societal and economic 

6 impacts from severe accidents are small for all plants. However, alternatives to 

7 mitigate severe accidents must be considered for all plants that have not 

8 considered such alternatives. 

9 The Staff identified no new and significant information related to postulated accidents during the 

10 review of FPL-DA’s ER (FPL Energy, 2008), the site audit, the scoping process, or evaluation of 

11 other available information. Therefore, there are no impacts related to these issues beyond 

12 those discussed in the GEIS. However, in accordance with Title 10 CFR 51.53(c)(3)(ii)(L), the 

13 Staff reviewed severe accident mitigation alternatives (SAMAs) for the DAEC. The results of the 

14 review are discussed in Section 5.3. 

15 5.3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 

16 The Federal regulation 10 CFR 51.53(c)(3)(ii)(L) requires that license renewal applicants 

17 consider alternatives to mitigate severe accidents if the Staff has not previously evaluated 

18 SAMAs for the applicant’s plant in an environmental impact statement (EIS), related 

19 supplement, or in an environmental assessment. The purpose of this consideration is to ensure 

20 that plant changes (i.e., hardware, procedures, and training) with the potential for improving 

21 severe accident safety performance, are identified and evaluated. SAMAs have not been 

22 previously considered for DAEC, therefore, the remainder of Chapter 5 addresses those 

23 alternatives. 

24 5.3.1 Introduction 

25 This section presents a summary of the SAMA evaluation for DAEC conducted by FPL-DA and 

26 the Staff's review of that evaluation. The Staff performed its review with contract assistance from 

27 Information Systems Laboratories. The Staff’s review is available in full in Appendix G; the 

28 SAMA evaluation is available in full in FPL-DA’s ER. 

29 The SAMA evaluation for DAEC was conducted with a four-step approach. In the first step, 

30 FPL-DA quantified the level of risk associated with potential reactor accidents using the 

31 plant-specific probabilistic risk assessment (PRA) and other risk models. 

32 In the second step, FPL-DA examined the major risk contributors and identified possible ways 

33 (i.e., SAMAs) of reducing that risk. Common ways of reducing risk are changes to components, 

34 systems, procedures, and training. FPL-DA identified 166 potential SAMAs for DAEC. FPL-DA 

35 performed an initial screening to determine if any SAMAs could be eliminated because they are 

36 not applicable to DAEC due to design differences, have already been implemented at DAEC, 

37 are similar in nature and could be combined with another SAMA candidate, or have excessive 

38 implementation cost. This screening reduced the list of potential SAMAs to 24. 
Environmental Impacts of Postulated Accidents 

Draft NUREG-1437, Supplement 42 5-4 February 2010 

1 In the third step, FPL-DA estimated the benefits and costs associated with each of the 

2 remaining SAMAs. Estimates were made of how much each SAMA could reduce risk. Those 

3 estimates were developed in terms of dollars in accordance with NRC guidance for performing 

4 regulatory analyses (NRC, 1997). The cost of implementing the proposed SAMAs was also 

5 estimated. 

6 Finally, in the fourth step, the costs and benefits of each of the remaining SAMAs were 

7 compared to determine whether the SAMA was cost-beneficial, meaning the benefits of the 

8 SAMA were greater than the cost (a positive cost benefit). FPL-DA concluded in its ER that 

9 several of the SAMAs evaluated are potentially cost-beneficial (FPL-DA, 2008). 

10 FPL-DA’s SAMA analyses and the Staff’s review are discussed in more detail below. 

11 5.3.2 Estimate of Risk 

12 FPL-DA submitted an assessment of SAMAs for DAEC as part of the ER (FPL-DA, 2008). This 

13 assessment was based on the most recent DAEC PRA available at that time; a plant-specific 

14 offsite consequence analysis performed using the MELCOR Accident Consequence Code 

15 System 2 (MACCS2) computer program, and insights from the DAEC Individual Plant 

16 Examination (IPE) (IELP, 1992) and Individual Plant Examination of External Events (IPEEE) 

17 (IES, 1995). 

18 The baseline core damage frequency (CDF) for the purpose of the SAMA evaluation is 

approximately 1.08 x 10-5 19 per year (see Appendix G for details). The CDF value is based on the 

20 risk assessment for internally-initiated events. FPL-DA did not include the contributions from 

21 external events within the DAEC risk estimates; however, it did account for the potential risk 

22 reduction benefits associated with external events by multiplying the estimated benefits for 

23 internal events by a factor of 1.57. The breakdown of CDF by initiating event is provided in 

24 Table 5-2 (see Appendix G.2 for details). 
Environmental Impacts of Postulated Accidents 

February 2010 5-5 Draft NUREG-1437, Supplement 42 

1 Table 5-2. Duane Arnold Energy Center Core Damage Frequency for Internal Events 

Initiating Event 

CDF 

(per year) 

% Contribution to 

CDF 

Loss of Offsite Power 4.0  10–6 37 

Turbine Trip with Bypass 1.6  10–6 15 

Main Steam Isolation Valve (MSIV) Closure 1.4  10–6 13 

Inadvertent Open Relief Valve 1.2  10–6 11 

Loss of Condenser Vacuum 5.9  10–7 6 

Div 2 125 Volt DC Bus Failure 3.2  10–7 3 

Manual shutdown 2.8  10–7 3 

Loss of River Water Supply 2.8  10–7 3 

Small loss of coolant accident (LOCA) 2.7  10–7 3 

Loss of Feedwater 2.5  10–7 2 

Medium LOCA 1.9  10–7 2 

Div 1 125 Volt DC Bus Failure 1.3  10–7 1 

Others (less than 1 percent each) 2.8  10–7 3 

Total CDF (internal events) 1.08  10–5 100 

2 As shown in this table, events initiated by loss of offsite power and other transients (e.g., turbine 

3 trip, MSIV closure, and inadvertent open of relief valve) are the dominant contributors to the 

4 CDF. 

5 FPL-DA estimated the dose to the population within 50 miles (80 km) of the DAEC site to be 

6 approximately 0.198 person-sievert (Sv) (19.8 person-rem) per year. The breakdown of the total 

7 population dose by containment release mode is summarized in Table 5-3. Releases from the 

8 containment within the early timeframe (0 to less than 6 hours following event initiation) 

9 dominate the population dose risk at DAEC. 

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

Containment Release Mode Population Dose 

(Person-Rem1 Per Year) % Contribution 

Early Releases (< 6 hrs) 14.1 71 

Intermediate Releases (6 to <24 hrs) 4.2 21 
Environmental Impacts of Postulated Accidents 

Draft NUREG-1437, Supplement 42 5-6 February 2010 

Late Releases (≥ 24 hrs) 1.5 8 

Total 19.8 100 

1

One person-rem = 0.01 person-Sv

1 The Staff reviewed FPL-DA’s data and evaluation methods and concludes that the quality of the 

2 risk analyses is adequate to support an assessment of the risk reduction potential for candidate 

3 SAMAs. Accordingly, the Staff based its assessment of offsite risk on the CDFs and offsite 

4 doses reported by FPL-DA. 

5 5.3.3 Potential Plant Improvements 

6 Once the dominant contributors to plant risk were identified, FPL-DA searched for ways to 

7 reduce that risk. In identifying and evaluating potential SAMAs, FPL-DA considered insights 

8 from the plant-specific PRA, and SAMA analyses performed for other operating plants that have 

9 submitted license renewal applications. FPL-DA identified 166 potential risk-reducing 

10 improvements (i.e., SAMAs) to plant components, systems, procedures, and training. 

11 FPL-DA removed all but 24 of the SAMAs from further consideration because they are not 

12 applicable at DAEC due to design differences, have already been implemented at DAEC, are 

13 similar in nature and could be combined with another SAMA candidate, or have excessive 

14 implementation cost. A detailed cost-benefit analysis was performed for each of the remaining 

15 SAMAs. 

16 The Staff concludes that FPL-DA used a systematic and comprehensive process for identifying 

17 potential plant improvements for DAEC, and that the set of potential plant improvements 

18 identified by FPL-DA is reasonably comprehensive and, therefore, acceptable. 

19 5.3.4 Evaluation of Risk Reduction and Costs of Improvements 

20 FPL-DA evaluated the risk-reduction potential of the remaining 24 SAMAs. The majority of the 

21 SAMA evaluations were performed in a bounding fashion in that the SAMA was assumed to 

22 completely eliminate the risk associated with the proposed enhancement. 

23 FPL-DA estimated the costs of implementing the candidate SAMAs through the application of 

24 engineering judgment, use of other licensee’s estimates for similar improvements, and the use 

25 of DAEC actual experience for similar improvements. The cost estimates conservatively did not 

26 include the cost of replacement power during extended outages required to implement the 

27 modifications, nor did they include contingency costs associated with unforeseen 

28 implementation obstacles. 

29 The Staff reviewed FPL-DA’s bases for calculating the risk reduction for the various plant 

30 improvements and concludes that the rationale and assumptions for estimating risk reduction 

31 are reasonable and generally conservative (i.e., the estimated risk reduction is higher than what 

32 would actually be realized). Accordingly, the Staff based its estimates of averted risk for the 

33 various SAMAs on FPL-DA’s risk reduction estimates. 
Environmental Impacts of Postulated Accidents 

February 2010 5-7 Draft NUREG-1437, Supplement 42 

1 The Staff reviewed the bases for the applicant’s cost estimates. For certain improvements, the 

2 Staff also compared the cost estimates to estimates developed elsewhere for similar 

3 improvements, including estimates developed as part of other licensee’s analyses of SAMAs for 

4 operating reactors and advanced light-water reactors. The Staff found the cost estimates to be 

5 reasonable, and generally consistent with estimates provided in support of other plants’ 

6 analyses. 

7 The Staff concludes that the risk reduction and the cost estimates provided by FPL-DA are 

8 sufficient and appropriate for use in the SAMA evaluation. 

9 5.3.5 Cost-Benefit Comparison 

10 The cost-benefit analysis performed by FPL-DA was based primarily on NUREG/BR-0184 

11 (NRC, 1997) and was executed consistent with this guidance. NUREG/BR-0058 has recently 

12 been revised to reflect the agency’s revised policy on discount rates. Revision 4 of 

13 NUREG/BR-0058 states that two sets of estimates should be developed: one at 3 percent and 

14 the other at 7 percent (NRC, 2004). FPL-DA provided both sets of estimates (FPL-DA, 2008). 

15 FPL-DA identified two potentially cost-beneficial SAMAs in the baseline analysis contained in 

16 the ER. The potentially cost-beneficial SAMAs are: 

17 ● SAMA 156 – Provide an alternate source of water for the residual heat 

18 removal service water (RHRSW)/emergency service water (ESW) pit. 

19 ● SAMA 166 – Increase the reliability of the low pressure emergency core 

20 cooling system (ECCS) reactor pressure vessel (RPV) low pressure 

21 permissive circuitry. Install manual bypass of low pressure permissive. 

22 FPL-DA performed additional analyses to evaluate the impact of parameter choices and 

23 uncertainties on the results of the SAMA assessment (FPL-DA, 2008; NextEra, 2009). If the 

24 benefits are increased by an additional factor of 2.5 to account for uncertainties, one additional 

25 SAMA candidate was determined to be potentially cost-beneficial: 

26 ● SAMA 117 – Increase boron concentration in the boron storage tank. 

27 FPL-DA indicated that they plan to further evaluate these SAMAs for possible implementation, 

28 and have included these items in FPL-DA’s corrective action program (FPL-DA, 2008; 

29 NextEra, 2009). 

30 The Staff concludes that, with the exception of the potentially cost-beneficial SAMAs discussed 

31 above, the costs of the SAMAs evaluated would be higher than the associated benefits. 
Environmental Impacts of Postulated Accidents 

Draft NUREG-1437, Supplement 42 5-8 February 2010 

1 5.3.6 Conclusions 

2 The Staff reviewed FPL-DA’s analysis and concluded that the methods used and the 

3 implementation of those methods are sound. The treatment of SAMA benefits and costs support 

4 the general conclusion that the SAMA evaluations performed by FPL-DA are reasonable and 

5 sufficient for the license renewal submittal. 

6 Based on its review of the SAMA analysis, the Staff concurs with FPL-DA’s identification of 

7 areas in which risk can be further reduced in a cost-beneficial manner through the 

8 implementation of all, or a subset, of potentially cost-beneficial SAMAs. Given the potential for 

9 cost-beneficial risk reduction, the Staff considers that further evaluation of these SAMAs by 

10 FPL-DA is warranted. The staff considered the mitigating benefits of implementing the SAMAs. 

11 However, none of the SAMAs listed above are specifically related to an aging management 

12 review conducted under the license renewal safety review pursuant to 10 CFR Part 54. The 

13 applicant has not made a final determination to implement these SAMAs. 

14 5.4 REFERENCES 

15 FPL Energy Duane Arnold, LLC (FPL-DA). 2008. “Duane Arnold Energy Center – License 

16 Renewal Application, Applicant’s Environmental Report, Operating License Renewal Stage.” 

17 September 2008. ADAMS Accession No. ML082980480. 

18 IES Utilities, Inc. (IES). 1995. “Duane Arnold Energy Center Individual Plant Examination for 

19 External Events.” November 1995. 

20 Iowa Electric Light and Power Co. (IELP). 1992. “Duane Arnold Energy Center Individual Plant 

21 Examination.” November 1992. 

22 NextEra (NextEra). 2009. Letter from C. R. Costanzo, NextEra to U.S. Nuclear Regulatory 

23 Commission Document Control Desk, Subject: Clarification of Response to Request for 

24 Additional Information Regarding Severe Accident Mitigation Alternatives for Duane Arnold 

25 Energy Center. September 23. 

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

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

28 Accession Nos. ML040690705 and ML040690738. 

29 U.S. Nuclear Regulatory Commission (NRC). 1997. Regulatory Analysis Technical Evaluation 

30 Handbook. NUREG/BR-0184, Washington, D.C., January 1997. 

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

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

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

34 NUREG-1437, Vol. 1, Add. 1, Washington, D.C. 

35 U.S. Nuclear Regulatory Commission (NRC). 2004. Regulatory Analysis Guidelines of the U.S. 

36 Nuclear Regulatory Commission. NUREG/BR-0058, Rev. 4, Washington, D.C., 

37 September 2004. 
February 2010 6-1 Draft NUREG-1437, Supplement 42 

1 6.0 ENVIRONMENTAL IMPACTS OF THE URANIUM FUEL CYCLE, 

2 SOLID WASTE MANAGEMENT, AND GREENHOUSE EMISSIONS 

3 6.1 THE URANIUM FUEL CYCLE 

4 This section addresses issues related to the uranium fuel cycle and solid waste 

5 management during the period of extended operation. The uranium cycle includes uranium 

6 mining and milling, the production of uranium hexafluoride, isotopic enrichment, fuel 

7 fabrication, reprocessing of irradiated fuel, transportation of radioactive materials, and 

8 management of low-level wastes and high-level wastes related to uranium fuel cycle 

9 activities. The Generic Environmental Impact Statement (GEIS) (NRC 1996, 1999) details 

10 the potential generic impacts of the radiological and nonradiological environmental impacts 

11 of the uranium fuel cycle including transportation of nuclear fuel and wastes. The GEIS is 

12 based, in part, on the generic impacts provided in Table S-3, “Table of Uranium Fuel Cycle 

13 Environmental Data,” in Title 10 of the Code of Federal Regulations (CFR), Section 

14 51.51(a), and in Table S-4, “Environmental Impact of Transportation of Fuel and Waste to 

15 and from One Light-Water-Cooled Nuclear Power Reactor,” in 10 CFR 51.52(b). The GEIS 

16 also addresses the impacts from radon-222 and technetium-99. 

17 For these Category 1 issues, the GEIS concludes that the impacts are designated as 

18 SMALL, except for the collective offsite radiological impacts from the fuel cycle and from 

19 high-level waste and spent fuel disposal where no significance level was assigned to these 

20 two impacts. For the collective offsite radiological impacts, the Commission concludes that 

21 these impacts are acceptable in that these impacts would not be sufficiently large to require 

22 the NEPA conclusion, for any plant, that the option of extended operation under 10 CFR 

23 Part 54 should be eliminated. The staff of the U.S. Nuclear Regulatory Commission (NRC) 

24 did not identify any new and significant information related to the uranium fuel cycle during 

25 the review of Nebraska Public Power District’s (NPPD) environmental report (ER) (NPPD, 

26 2008), the site audit, and the scoping process. Therefore, there are no impacts related to 

27 these issues beyond those discussed in the GEIS. 

28 Nine generic issues are related to the fuel cycle and solid waste management. These are 

29 shown in Table 6-1. There are no site-specific issues. 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

Draft NUREG-1437, Supplement 42 6-2 February 2010 

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

Issues GEIS Section Category 

Offsite radiological impacts (individual effects from other than the 

disposal of spent fuel and high-level waste) 

6.1, 6.2.1, 6.2.2.1, 

6.2.2.3, 6.2.3, 6.2.4, 

6.6 

1 

Offsite radiological impacts (collective effects) 6.1, 6.2.2.1, 6.2.3, 

6.2.4, 6.6 

1 

Offsite radiological impacts (spent fuel and high-level waste 

disposal) 

6.1, 6.2.2.1, 6.2.3, 

6.2.4, 6.6 

1 

Nonradiological impacts of the uranium fuel cycle 6.1, 6.2.2.6, 6.2.2.7, 

6.2.2.8, 6.2.2.9, 6.2.3, 

6.2.4, 6.6 

1 

Low-level waste storage and disposal 6.1, 6.2.2.2, 6.4.2, 

6.4.3, 6.4.3.1, 6.4.3.2, 

6.4.3.3, 6.4.4, 6.4.4.1, 

6.4.4.2, 6.4.4.3, 

6.4.4.4, 6.4.4.5, 

6.4.4.5.1, 6.4.4.5.2, 

6.4.4.5.3, 6.4.4.5.4, 

6.4.4.6, 6.6 

1 

Mixed waste storage and disposal 6.4.5.1, 6.4.5.2, 

6.4.5.3, 6.4.5.4, 

6.4.5.5, 6.4.5.6, 

6.4.5.6.1, 6.4.5.6.2, 

6.4.5.6.3, 6.4.5.6.4, 

6.6 

1 

Onsite spent fuel 6.1, 6.4.6, 6.4.6.1, 

6.4.6.2, 6.4.6.3, 

6.4.6.4, 6.4.6.5, 

6.4.6.6, 6.4.6.7, 6.6 

1 

Nonradiological waste 6.1, 6.5, 6.5.1, 6.5.2, 

6.5.3, 6.6 

1 

Transportation 6.1, 6.3.1, 6.3.2.3, 

6.3.3, 6.3.4, 6.6, 

Addendum 1 

1 

2 6.2 GREENHOUSE GAS EMISSIONS 

3 This section provides a discussion of potential impacts from greenhouse gases (GHGs) 

4 emitted from the nuclear fuel cycle. The GEIS does not directly address these emissions, 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

February 2010 6-3 Draft NUREG-1437, Supplement 42 

1 and its discussion is limited to an inference that substantial carbon dioxide (CO2) emissions 

2 may occur if coal- or oil-fired alternatives to license renewal are implemented. 

3 6.2.1 Existing Studies 

4 Since the development of the GEIS, the relative volumes of GHGs emitted by nuclear and 

5 other electricity generating methods have been widely studied. However, estimates and 

6 projections of the carbon footprint of the nuclear power lifecycle vary depending on the type 

7 of study conducted. Additionally, considerable debate also exists among researchers 

8 regarding the relative impacts of nuclear and other forms of electricity generation on GHG 

9 emissions. Existing studies on GHG emissions from nuclear power plants generally take two 

10 different forms: 

11 (1) Qualitative discussions of the potential to use nuclear power to reduce GHG 

12 emissions and mitigate global warming; and 

13 (2) Technical analyses and quantitative estimates of the actual amount of GHGs 

14 generated by the nuclear fuel cycle or entire nuclear power plant life cycle and 

15 comparisons to the operational or life cycle emissions from other energy generation 

16 alternatives. 

17 Some of these studies are summarized below to give the reader an overview of the current 

18 state of these assessments. 

19 

20 6.2.1.1 Qualitative Studies 

21 The qualitative studies consist primarily of broad, large-scale public policy or investment 

22 evaluations of whether an expansion of nuclear power is likely to be a technically, 

23 economically, and/or politically feasible means of achieving global GHG reductions. 

24 Examples of the studies include: 

25 ● Evaluations to determine whether investments in nuclear power in developing 

26 countries should be accepted as a flexibility mechanism to assist industrialized 

27 nations in achieving their GHG reduction goals under the Kyoto Protocols 

28 (Schneider, 2000; IAEA, 2000; NEA, 2002; NIRS/WISE, 2005). Ultimately, the 

29 parties to the Kyoto Protocol did not approve nuclear power as a component 

30 under the Clean Development Mechanism (CDM) due to safety and waste 

31 disposal concerns (NEA, 2002). 

32 ● Analyses developed to assist governments, including the United States, in 

33 making long-term investment and public policy decisions in nuclear power 

34 (Keepin, 1988; Hagen et al., 2001; MIT, 2003). 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

Draft NUREG-1437, Supplement 42 6-4 February 2010 

1 Although the qualitative studies sometimes reference and critique the existing quantitative 

2 estimates of GHGs produced by the nuclear fuel cycle or life cycle, their conclusions 

3 generally rely heavily on discussions of other aspects of nuclear policy decisions and 

4 investment such as safety, cost, waste generation, and political acceptability. Therefore, 

5 these studies are typically not directly applicable to an evaluation of GHG emissions 

6 associated with the proposed license renewal for a given nuclear power plant. 

7 6.2.1.2 Quantitative Studies 

8 A large number of technical studies, including calculations and estimates of the amount of 

9 GHGs emitted by nuclear and other power generation options, are available in the literature 

10 and were useful to the NRC staff’s efforts in addressing relative GHG emission levels. 

11 Examples of these studies include – but are not limited to – Mortimer (1990), Andseta et al. 

12 (1998), Spadaro (2000), Storm van Leeuwen and Smith (2005), Fritsche (2006), 

13 Parliamentary Office of Science and Technology (POST) (2006), Atomic Energy Authority 

14 (AEA) (2006), Weisser (2006), Fthenakis and Kim (2007), and Dones (2007). 

15 Comparing these studies and others like them is difficult because the assumptions and 

16 components of the lifecycles the authors evaluate vary widely. Examples of areas in which 

17 differing assumptions make comparing the studies difficult include: 

18  Energy sources that may be used to mine uranium deposits in the future; 

19  Reprocessing or disposal of spent nuclear fuel; 

20  Current and potential future processes to enrich uranium and the energy 

21 sources that will power them; 

22  Estimated grades and quantities of recoverable uranium resources; 

23  Estimated grades and quantities of recoverable fossil fuel resources; 

24  Estimated GHG emissions other than CO2, including the conversion to CO2

25 equivalents per unit of electric energy produced; 

26  Performance of future fossil fuel power systems; 

27  Projected capacity factors for alternatives means of generation; and 

28  Current and potential future reactor technologies. 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

February 2010 6-5 Draft NUREG-1437, Supplement 42 

1 In addition, studies may vary with respect to whether all or parts of a power plant’s lifecycle 

2 are analyzed, i.e., a full lifecycle analysis will typically address plant construction, 

3 operations, resource extraction (for fuel and construction materials), and decommissioning, 

4 whereas, a partial lifecycle analysis primarily focus on operational differences. 

5 In the case of license renewal a GHG analysis for that portion of the plant’s lifecycle 

6 (operation for an additional 20 years) would not involve GHG emissions associated with 

7 construction because construction activities have already been completed at the time of 

8 relicensing. In addition, the proposed action of license renewal would also not involve 

9 additional GHG emissions associated with facility decommissioning, because that 

10 decommissioning must occur whether the facility is relicensed or not. However, in some of 

11 the aforementioned studies, the specific contribution of GHG emissions from construction, 

12 decommissioning, or other portions of a plant’s lifecycle cannot be clearly separated from 

13 one another. In such cases, an analysis of GHG emissions would overestimate the GHG 

14 emissions attributed to a specific portion of a plant’s lifecycle. Nonetheless, these studies 

15 provide some meaningful information with respect to the relative magnitude of the emissions 

16 among nuclear power plants and other forms of electric generation, as discussed in the 

17 following sections. 

18 In Tables 6-2, 6-3, and 6-4 the NRC staff presents the results of the aforementioned 

19 quantitative studies to provide a weight-of-evidence evaluation of the relative GHG 

20 emissions that may result from the proposed license renewal as compared to the potential 

21 alternative use of coal-fired, natural gas-fired, and renewable generation. Most studies from 

22 Mortimer (1990) onward suggest that uranium ore grades and uranium enrichment 

23 processes are leading determinants in the ultimate GHG emissions attributable to nuclear 

24 power generation. These studies indicate that the relatively lower order of magnitude of 

25 GHG emissions from nuclear power when compared to fossil-fueled alternatives (especially 

26 natural gas) could potentially disappear if available uranium ore grades drop sufficiently 

27 while enrichment processes continued to rely on the same technologies. 

28 Summary of Nuclear Greenhouse Gas Emissions Compared to Coal 

29 Considering that coal fuels the largest share of electricity generation in the United States 

30 and that its burning results in the largest emissions of GHGs for any of the likely alternatives 

31 to nuclear power generation, including Duane Arnold Energy Center (DAEC), most of the 

32 available quantitative studies focused on comparisons of the relative GHG emissions of 

33 nuclear to coal-fired generation. The quantitative estimates of the GHG emissions 

34 associated with the nuclear fuel cycle (and, in some cases, the nuclear lifecycle), as 

35 compared to an equivalent coal-fired plant, are presented in Table 6-2. The following chart 

36 does not include all existing studies, but provides an illustrative range of estimates 

37 developed by various sources. 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

Draft NUREG-1437, Supplement 42 6-6 February 2010 

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

Source GHG Emission Results 

Nuclear—230,000 tons CO2 

Coal—5,912,000 tons CO2

Mortimer (1990) 

Note: Future GHG emissions from nuclear to increase because of declining ore 

grade. 

Andseta et al. (1998) Nuclear energy produces 1.4 percent of the GHG emissions compared to coal. 

Note: Future reprocessing and use of nuclear-generated electrical power in the 

mining and enrichment steps are likely to change the projections of earlier 

authors, such as Mortimer (1990). 

Spadaro (2000) Nuclear—2.5 to 5.7 g Ceq/kWh 

Coal—264 to 357 g Ceq/kWh 

Storm van Leeuwen 

and Smith (2005) 

Authors did not evaluate nuclear versus coal. 

Fritsche (2006) (Values Nuclear—33 g Ceq/kWh 

estimated from graph 

in Figure 4) Coal—950 g Ceq/kWh 

Nuclear—5 g Ceq/kWh 

Coal—>1000 g Ceq/kWh 

POST (2006) (Nuclear 

calculations from AEA, 

2006) 

Note: Decrease of uranium ore grade to 0.03 percent would raise nuclear to 6.8 g 

Ceq /kWh. Future improved technology and carbon capture and storage could 

reduce coal-fired GHG emissions by 90 percent. 

Weisser (2006) Nuclear—2.8 to 24 g Ceq/kWh 

(Compilation of results 

from other studies) Coal—950 to 1250 g Ceq/kWh 

Fthenakis and Kim 

(2007) 

Authors did not evaluate nuclear versus coal. 

Dones (2007) Author did not evaluate nuclear versus coal. 

2 

3 Summary of Nuclear Greenhouse Gas Emissions Compared to Natural Gas 

4 The quantitative estimates of the GHG emissions associated with the nuclear fuel cycle 

5 (and, in some cases, the nuclear lifecycle), as compared to an equivalent natural gas-fired 

6 plant, are presented in Table 6-3. The following chart does not include all existing studies, 

7 but provides an illustrative range of estimates developed by various sources. 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

February 2010 6-7 Draft NUREG-1437, Supplement 42 

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

Source GHG Emission Results 

Mortimer (1990) Author did not evaluate nuclear versus natural gas. 

Andseta (1998) Author did not evaluate nuclear versus natural gas. 

Spadaro (2000) Nuclear—2.5 to 5.7 g Ceq/kWh 

Natural Gas—120 to 188 g Ceq/kWh 

Nuclear fuel cycle produces 20 to 33 percent of the GHG emissions compared to 

natural gas (at high ore grades). 

Storm van Leeuwen 

and Smith (2005) 

Note: Future nuclear GHG emissions to increase because of declining ore grade. 

Fritsche (2006) Nuclear—33 g Ceq/kWh 

(Values estimated 

from graph in Figure 4) Cogeneration Combined Cycle Natural Gas—150 g Ceq/kWh 

Nuclear—5 g Ceq/kWh 

Natural Gas—500 g Ceq/kWh 

POST (2006) (Nuclear 

calculations from AEA, 

2006) 

Note: Decrease of uranium ore grade to 0.03 percent would raise nuclear to 

6.8 g Ceq/kWh. Future improved technology and carbon capture and storage could 

reduce natural gas GHG emissions by 90 percent. 

Weisser (2006) Nuclear—2.8 to 24 g Ceq/kWh 

(Compilation of results 

from other studies) Natural Gas—440 to 780 g Ceq/kWh 

Fthenakis and Kim 

(2007) 

Authors did not evaluate nuclear versus natural gas. 

Dones (2007) Author critiqued methods and assumptions of Storm van Leeuwen and Smith 

(2005), and concluded that the nuclear fuel cycle produces 15 to 27 percent of the 

GHG emissions of natural gas. 

2 

3 Summary of Nuclear Greenhouse Gas Emissions Compared to Renewable Energy Sources 

4 The quantitative estimates of the GHG emissions associated with the nuclear fuel cycle, as 

5 compared to equivalent renewable energy sources, are presented in Table 6-4. Calculation 

6 of GHG emissions associated with these sources is more difficult than the calculations for 

7 nuclear energy and fossil fuels because of the large variation in efficiencies due to their 

8 different sources and locations. For example, the efficiency of solar and wind energy is 

9 highly dependent on the location in which the power generation facility is installed. Similarly, 

10 the range of GHG emissions estimates for hydropower varies greatly depending on the type 

11 of dam or reservoir involved (if used at all). Therefore, the GHG emissions estimates for 

12 these energy sources have a greater range of variability than the estimates for nuclear and 

13 fossil fuel sources. The following chart does not include all existing studies, but provides an 

14 illustrative range of estimates developed by various sources. 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

Draft NUREG-1437, Supplement 42 6-8 February 2010 

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

2 Sources 

Source GHG Emission Results 

Nuclear—230,000 tons CO2 

Hydropower—78,000 tons CO2

Wind power—54,000 tons CO2

Tidal power—52,500 tons CO2

Mortimer (1990) 

Note: Future GHG emissions from nuclear to increase because of declining ore 

grade. 

Andseta (1998) Author did not evaluate nuclear versus renewable energy sources. 

Nuclear—2.5 to 5.7 g Ceq/kWh 

Solar PV—27.3 to 76.4 g Ceq/kWh 

Hydroelectric—1.1 to 64.6 g Ceq/kWh 

Biomass—8.4 to 16.6 g Ceq/kWh 

Spadaro (2000) 

Wind—2.5 to 13.1 g Ceq/kWh 

Storm van Leeuwen 

and Smith (2005) 

Author did not evaluate nuclear versus renewable energy sources. 

Nuclear—33 g Ceq/kWh 

Solar PV—125 g Ceq/kWh 

Hydroelectric—50 g Ceq/kWh 

Fritsche (2006) (Values 

estimated from graph 

in Figure 4) 

Wind—20 g Ceq/kWh 

Nuclear—5 g Ceq/kWh 

Biomass—25 to 93 g Ceq/kWh 

Solar PV—35 to 58 g Ceq/kWh 

Wave/Tidal—25 to 50 g Ceq/kWh 

Hydroelectric—5 to 30 g Ceq/kWh 

Wind—4.64 to 5.25 g Ceq/kWh 

POST (2006) (Nuclear 

calculations from AEA, 

2006) 

Note: Decrease of uranium ore grade to 0.03 percent would raise nuclear to 

6.8 g Ceq/kWh. 

Nuclear—2.8 to 24 g Ceq/kWh 

Solar PV—43 to 73 g Ceq/kWh 

Hydroelectric—1 to 34 g Ceq/kWh 

Biomass—35 to 99 g Ceq/kWh 

Weisser (2006) 

(Compilation of results 

from other studies) 

Wind—8 to 30 g Ceq/kWh 

Fthenakis and Kim Nuclear—16 to 55 g Ceq/kWh 

(2007) Solar PV—17 to 49 g Ceq/kWh 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

February 2010 6-9 Draft NUREG-1437, Supplement 42 

Source GHG Emission Results 

Dones (2007) Author did not evaluate nuclear versus renewable energy sources. 

1 

2 6.2.2 Conclusions: Relative GHG Emissions 

3 The sampling of data presented in Tables 6-2, 6-3, and 6-4 above demonstrates the 

4 challenges of any attempt to determine the specific amount of GHG emission attributable to 

5 nuclear energy production sources, as different assumptions and calculation methodology 

6 will yield differing results. The differences and complexities in these assumptions and 

7 analyses will further increase when they’re used to project future GHG emissions. 

8 Nevertheless, several conclusions can be drawn from the information presented. 

9 First, the various studies indicate a general consensus that nuclear power currently 

10 produces fewer GHG emissions than fossil-fuel-based electrical generation, e.g., the GHG 

11 emissions from a complete nuclear fuel cycle currently range from 2.5 to 55 g Ceq/kWh, as 

12 compared to the use of coal plants (264 to 1250 g Ceq/kWh) and natural gas plants (120 to 

13 780 g Ceq/kWh). The studies also provide estimates of GHG emissions from five renewable 

14 energy sources based on current technology. These estimates included solar-photovoltaic 

15 (17 to 125 g Ceq/kWh), hydroelectric (1 to 64.6 g Ceq/kWh), biomass (8.4 to 99 g Ceq/kWh), 

16 wind (2.5 to 30 g Ceq/kWh), and tidal (25 to 50 g Ceq/kWh). The range of these estimates is 

17 wide, but the general conclusion is that current GHG emissions from the nuclear fuel cycle 

18 are of the same order of magnitude as from these renewable energy sources. 

19 Second, the studies indicate no consensus on future relative GHG emissions from nuclear 

20 power and other sources of electricity. There is substantial disagreement among the various 

21 authors regarding the GHG emissions associated with declining uranium ore concentrations, 

22 future uranium enrichment methods, and other factors, including changes in technology. 

23 Similar disagreement exists regarding future GHG emissions associated with coal and 

24 natural gas for electricity generation. Even the most conservative studies conclude that the 

25 nuclear fuel cycle currently produces fewer GHG emissions than fossil-fuel-based sources, 

26 and is expected to continue to do so in the near future. The primary difference between the 

27 authors is the projected cross-over date (the time at which GHG emissions from the nuclear 

28 fuel cycle exceed those of fossil-fuel-based sources) or whether cross-over will actually 

29 occur. 

30 Considering the current estimates and future uncertainties, it appears that GHG emissions 

31 associated with the proposed DAEC relicensing action are likely to be lower than those 

32 associated with fossil-fuel-based energy sources. The NRC staff bases this conclusion on 

33 the following rationale: 

34 1. As shown in Tables 6-2 and 6-3, the current estimates of GHG emissions from the 

35 nuclear fuel cycle are far below those for fossil-fuel-based energy sources; 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

Draft NUREG-1437, Supplement 42 6-10 February 2010 

1 2. DAEC license renewal will involve continued GHG emissions due to uranium mining, 

2 processing, and enrichment, but will not result in increased GHG emissions 

3 associated with plant construction or decommissioning (as the plant will have to be 

4 decommissioned at some point whether the license is renewed or not); and 

5 3. Few studies predict that nuclear fuel cycle emissions will exceed those of fossil fuels 

6 within a timeframe that includes the DAEC period of extended operation. Several 

7 studies suggest that future extraction and enrichment methods, the potential for 

8 higher grade resource discovery, and technology improvements could extend this 

9 timeframe. 

10 With respect to comparison of GHG emissions among the proposed DAEC license renewal 

11 action and renewable energy sources, it appears likely that there will be future technology 

12 improvements and changes in the type of energy used for mining, processing, and 

13 constructing facilities of all types. Currently, the GHG emissions associated with the nuclear 

14 fuel cycle and renewable energy sources are within the same order of magnitude. Because 

15 nuclear fuel production is the most significant contributor to possible future increases in 

16 GHG emissions from nuclear power, and because most renewable energy sources lack a 

17 fuel component, it is likely that GHG emissions from renewable energy sources would be 

18 lower than those associated with DAEC at some point during the period of extended 

19 operation. 

20 The NRC staff also provides an additional discussion about the contribution of GHG to 

21 cumulative air quality impacts in Section 4.11.2 of this SEIS, 

22 6.3 REFERENCES 

23 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

24 Protection Regulations for Domestic Licensing and Related Regulatory Functions.” 

25 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

26 Renewal of Operating Licenses for Nuclear Power Plants.” 

27 10 CFR Part 63. Code of Federal Regulations, Title 10, Energy, Part 63, “Disposal of High28 Level Radioactive Wastes in a Geologic Repository at Yucca Mountain, Nevada.” 

29 40 CFR Part 191. Code of Federal Regulations, Title 40, Protection of Environment, Part 

30 191, “Environmental Radiation Protection Standards for Management and Disposal of Spent 

31 Nuclear Fuel, High-Level and Transuranic Radioactive Waste.” 

32 AEA Technology (AEA). 2006. “Carbon Footprint of the Nuclear Fuel Cycle, Briefing Note.” 

33 Prepared for British Energy. March 2006. 
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

February 2010 6-11 Draft NUREG-1437, Supplement 42 

1 Andseta, S., M.J. Thompson, J.P. Jarrell, and D.R. Pendergast. 1998. “CANDU Reactors 

2 and Greenhouse Gas Emissions.” Canadian Nuclear Association, 11th Pacific Basin 

3 Nuclear Conference, Banff, Alberta, Canada. May 1998. 

4 Dones, R. 2007. “Critical Note on the Estimation by Storm Van Leeuwen J.W., and Smith P. 

5 of the Energy Uses and Corresponding CO2 Emissions for the Complete Nuclear Energy 

6 Chain.” Paul Sherer Institute. April 2007. 

7 Fritsche, U.R. 2006. “Comparison of Greenhouse-Gas Emissions and Abatement Cost of 

8 Nuclear and Alternative Energy Options from a Life-Cycle Perspective.” Oko-Institut, 

9 Darmstadt Office. January 2006. 

10 Fthenakis, V.M. and H.C. Kim. 2007. Greenhouse-gas emissions from solar-electric and 

11 nuclear power: A life cycle study. Energy Policy, Volume 35, Number 4. 

12 International Atomic Energy Agency (IAEA). 2000. “Nuclear Power for Greenhouse Gas 

13 Mitigation under the Kyoto Protocol: The Clean Development Mechanism (CDM).” 

14 November 2000. 

15 Mortimer, N. 1990. “World Warms to Nuclear Power.” SCRAM Safe Energy Journal. 

16 December 1989 and January 1990. Available URL: 

17 http://www.no2nuclearpower.org.uk/articles/mortimer_se74.php (accessed February 29, 

18 2007). 

19 Nebraska Public Power District (NPPD). 2008. Cooper Nuclear Station License Renewal 

20 Application. Environmental Report. 

21 Organization for Economic Co-Operation and Development, Nuclear Energy Agency (NEA). 

22 2002. Nuclear Energy and the Kyoto Protocol. 

23 Parliamentary Office of Science and Technology (POST). 2006. “Carbon Footprint of 

24 Electricity Generation.” Postnote, Number 268. October 2006. 

25 Schneider, M. 2000. Climate Change and Nuclear Power. World Wildlife Fund for Nature. 

26 April 2000. 

27 Spadaro, J.V., L. Langlois and B. Hamilton. 2000. “Greenhouse Gas Emissions of Electricity 

28 Generation Chains: Assessing the Difference.” IAEA Bulletin 42/2/2000, Vienna, Austria. 

29 Storm van Leeuwen, J.W. and P. Smith 2005. Nuclear Power—The Energy Balance. August 

30 2005. 

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

32 Statement for License Renewal of Nuclear Plants. NUREG-1437, Volumes 1 and 2, 

33 Washington, D.C, 1996. ADAMS Accession Nos. ML040690705 and ML040690738. 

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

35 Statement for License Renewal of Nuclear Plants, Main Report, “Section 6.3 –
Uranium Fuel Cycle, Solid Waste Management and Greenhouse Gaseous Emissions 

Draft NUREG-1437, Supplement 42 6-12 February 2010 

1 Transportation, Table 9.1, Summary of Findings on NEPA Issues for License Renewal of 

2 Nuclear Power Plants, Final Report.” NUREG-1437, Volume 1, Addendum 1, Washington, 

3 D.C. 

4 Weisser, D. 2006. “A Guide to Life-Cycle Greenhouse Gas (GHG) Emissions from Electric 

5 Supply Technologies.” Available URL: 

6 http://www.iaea.org/OurWork/ST/NE/Pess/assets/GHG_manuscript_pre7 print_versionDanielWeisser.pdf (accessed May 19, 2009) 
February 2010 7-1 Draft NUREG-1437, Supplement 42 

1 7.0 ENVIRONMENTAL IMPACTS OF DECOMMISSIONING 

2 Environmental impacts from the activities associated with the decommissioning of any reactor 

3 before or at the end of an initial or renewed license are evaluated in the Generic Environmental 

4 Impact Statement on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the 

5 Decommissioning of Nuclear Power Reactors, NUREG-0586, Supplement 1 (NRC 2002). The 

6 staff's evaluation of the environmental impacts of decommissioning, presented in NUREG-0586, 

7 Supplement 1, identifies a range of impacts for each environmental issue. 

8 The incremental environmental impacts associated with decommissioning activities resulting 

9 from continued plant operation during the renewal term are discussed in the Generic 

10 Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS), NUREG-1437, 

11 Volumes 1 and 2 (NRC 1996; 1999). 

12 7.1 DECOMMISSIONING

13 Category 1 issues in Table B-1 of Title 10 of the Code of Federal Regulations (CFR) Part 51, 

14 Subpart A, Appendix B that are applicable to Duane Arnold Energy Center (DAEC) 

15 decommissioning following the renewal term are listed in Table 7-1. 

16 Table 7-1. Category 1 Issues Applicable to the Decommissioning of DAEC 

17 Following the Renewal Term 

18 

ISSUE—10 CFR Part 51, Subpart A, Appendix B, Table B-1 GEIS Section

DECOMMISSIONING

Radiation doses 7.3.1 

Waste management 7.3.2 

Air quality 7.3.3 

Water quality 7.3.4 

Ecological resources 7.3.5 

Socioeconomic impacts 7.3.7 

19 

20 A brief description of the Staff’s review and the GEIS conclusions, as codified in Table B-1, 10 

21 CFR Part 51, for each of the issues follows: 

22 

23  Radiation doses. Based on information in the GEIS, the Commission found that: 

24 

25 Doses to the public will be well below applicable regulatory standards regardless 

26 of which decommissioning method is used. Occupational doses would increase 
Environmental Impacts of Decommissioning 

Draft NUREG-1437, Supplement 42 7-2 February 2010 

1 no more than 1 man-rem caused by buildup of long-lived radionuclides during the 

2 license renewal term. 

3 

4  Waste management. Based on information in the GEIS, the Commission found that: 

5 

6 Decommissioning at the end of a 20-year license renewal period would generate no 

7 more solid wastes than at the end of the current license term. No increase in the 

8 quantities of Class C or greater than Class C wastes would be expected. 

9 

10  Air quality. Based on information in the GEIS, the Commission found that: 

11 

12 Air quality impacts of decommissioning are expected to be negligible either at the 

13 end of the current operating term or at the end of the license renewal term. 

14 

15  Water quality. Based on information in the GEIS, the Commission found that: 

16 

17 The potential for significant water quality impacts from erosion or spills is no 

18 greater whether decommissioning occurs after a 20-year license renewal period 

19 or after the original 40-year operation period, and measures are readily available 

20 to avoid such impacts. 

21 

22  Ecological resources. Based on information in the GEIS, the Commission found that: 

23 

24 Decommissioning after either the initial operating period or after a 20-year 

25 license renewal period is not expected to have any direct ecological impacts. 

26 

27  Socioeconomic Impacts. Based on information in the GEIS, the Commission found that: 

28 

29 Decommissioning would have some short-term socioeconomic impacts. The 

30 impacts would not be increased by delaying decommissioning until the end of a 

31 20-year relicense period, but they might be decreased by population and 

32 economic growth. 

33 

34 The NRC staff has not identified any new and significant information during the review of the 

35 FPL Energy Duane Arnold, LLC (FPL-DA) environmental report (ER) (NPPD, 2008), the site 

36 audit, or the scoping process; therefore, there are no impacts related to these issues beyond 

37 those discussed in the GEIS (NRC 1996, 1999). For the issues listed in Table 7-1 above, the 

38 GEIS concluded that the impacts are SMALL. 
Environmental Impacts of Decommissioning 

February 2010 7-3 Draft NUREG-1437, Supplement 42 

1 7.2 REFERENCES 

2 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

3 Protection Regulations for Domestic Licensing and Related Regulatory Functions 

4 FPL Energy Duane Arnold LLC, (FPL-DA). Duane Arnold Energy Center, License Renewal 

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

6 Stage, Duane Arnold Energy Center. September 2008. 

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

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

9 ADAMS Accession No. ML061770605. 

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

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

12 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final 

13 Report.” NUREG-1437, Volume 1, Addendum 1, Washington, D.C. 

14 U.S. Nuclear Regulatory Commission (NRC). 2002. Generic Environmental Impact Statement 

15 on Decommissioning of Nuclear Facilities: Supplement 1, “Regarding the Decommissioning of 

16 Nuclear Power Reactors.” NUREG-0586, Supplement 1, Volumes 1 and 2, Washington, D.C.

February 2010 8-1 Draft NUREG-1437, Supplement 42 

1 8.0 ENVIRONMENTAL IMPACTS OF ALTERNATIVES 

2 The National Environmental Policy Act (NEPA) mandates that each environmental impact 

3 statement (EIS) consider alternatives to any proposed major Federal action significantly 

4 affecting the quality of the human environment. U.S. Nuclear Regulatory Commission (NRC) 

5 regulations implementing NEPA for license renewal require that a supplemental environmental 

6 impact statement (SEIS) consider and weigh “ the environmental effects of the proposed action 

7 (license renewal); the environmental impacts of alternatives to the proposed action; and 

8 alternatives available for reducing or avoiding adverse environmental impacts,” (Title 10 of the 

9 Code of Federal Regulations (CFR) 51.71d). 

10 This SEIS considers the proposed Federal action of issuing a renewed license for the Duane 

11 Arnold Energy Center (DAEC), which would allow the plant to operate for 20 years beyond its 

12 current license expiration date. In this chapter, the NRC staff (Staff) examines the potential 

13 environmental impacts of alternatives to issuing a renewed operating license for DAEC, as well 

14 as alternatives that may reduce or avoid adverse environmental impacts from license renewal, 

15 when and where these alternatives are applicable. 

16 While the Generic Environmental Impact Statement (GEIS) for License Renewal of Nuclear 

17 Plants, NUREG-1437 (NRC 1996, 1999), reached generic conclusions regarding many 

18 environmental issues associated with license renewal, it did not determine which alternatives 

19 are reasonable or reach conclusions about site-specific environmental impact levels. As such, 

20 the Staff must evaluate environmental impacts of alternatives on a site-specific basis. 

21 Alternatives to the proposed action of issuing a renewed DAEC operating license must meet the 

22 purpose and need for issuing a renewed license; they must 

23 provide an option that allows for power generation capability beyond the term of 

24 a current nuclear power plant operating license to meet future system generating 

25 needs, as such needs may be determined by State, utility, and, where 

26 authorized, Federal (other than NRC) decision makers. 

27 The Staff ultimately makes no decision as to which alternative (or the proposed action) to 

28 implement, since that decision falls to utility, State, or other Federal officials to decide. 

29 Comparing the environmental effects of these alternatives will assist the Staff in deciding 

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

31 license renewal for energy-planning decision-makers would be unreasonable (10 CFR 

32 51.95[c][4]). If the NRC acts to issue a renewed license, all of the alternatives, including the 

33 proposed action, will be available to energy-planning decision-makers. If NRC decides not to 

34 renew the license (or takes no action at all), then energy-planning decision-makers may no 

35 longer elect to continue operating DAEC and will have to resort to another alternative—which 

36 may or may not be one of the alternatives considered in this section—to meet their energy 

37 needs. 

38 In evaluating alternatives to license renewal, the Staff first selects energy technologies or 

39 options currently in commercial operation as well as some technologies not currently in 

40 commercial operation but likely to be commercially available by the time the current DAEC 

41 operating license expires. The current DAEC operating license will expire on February 21, 2014, 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-2 February 2010 

1 and an alternative must be available (constructed, permitted, and connected to the grid) by the 

2 time the current DAEC license expires. 

3 Second, the Staff screens the alternatives to remove 

4 those that cannot meet future system needs, and then 

5 screens the remaining options to remove those whose 

6 costs or benefits do not justify inclusion in the range 

7 of reasonable alternatives. Any alternatives 

8 remaining, then, constitute alternatives to the 

9 proposed action that the Staff evaluates in detail 

10 throughout this section. In Section 8.4, the SEIS 

11 briefly addresses each alternative that the Staff 

12 removed during screening and explains why each 

13 alternative was removed. 

14 The Staff initially considered 17 discrete potential 

15 alternatives to the proposed action, and then 

16 narrowed the list to the two discrete alternatives and 

17 one combination alternative considered in sections 

18 8.1 through 8.3. 

19 Once the Staff identifies alternatives for in-depth 

20 review, the Staff refers to generic environmental 

21 impact evaluations in the GEIS. The GEIS provides 

22 overviews of some energy technologies available at 

23 the time of its publishing in 1996, though it does not 

24 reach any conclusions regarding which alternatives 

25 are most appropriate, nor does it precisely categorize 

26 impacts for each site. In addition, since 1996, many 

27 energy technologies have evolved significantly in 

28 capability and cost, while regulatory structures have 

29 changed to either promote or impede development of 

30 particular alternatives. 

31 As a result, the Staff’s analyses starts with the GEIS 

32 and then includes updated information from sources 

33 like the Energy Information Administration (EIA), other 

34 organizations within the Department of Energy (DOE), 

35 the Environmental Protection Agency (EPA), industry 

36 sources and publications, and information submitted 

37 in the applicant’s (FPL Energy Duane Arnold, LLC 

38 [FPL-DA]) environmental report (ER). 

39 For each in-depth analysis, the Staff analyzes environmental impacts across seven impact 

40 categories: (1) air quality, (2) groundwater use and quality, (3) surface water use and quality, (4) 

41 biological, (5) human health, (6) socioeconomics, and (7) waste management. As in earlier 

42 chapters of this draft SEIS, the Staff uses the NRC’s three-level standard of significance—

In-Depth 

Alternatives: 

 Coal-fired 

supercritical 

 Natural gas-fired 

combined-cycle 

 Combination 

Other Alternatives 

Considered: 

 Coal-fired integrated 

gasification 

combined-cycle 

(IGCC) 

 New nuclear 

 Wind power 

 Conservation 

 Purchased power 

 Solar power 

(photovoltaic and 

concentrating) 

 Wood-fired 

combustion 

 Conventional 

hydroelectric power 

 Wave and ocean 

energy 

 Geothermal power 

 Municipal solid waste 

 Biofuels 

 Methane 

 Oil-fired power 

 Fuel cells 

 Delayed retirement 
Environmental Impacts of Alternatives 

February 2010 8-3 Draft NUREG-1437, Supplement 42 

Energy Outlook: Each year the Energy 

Information Administration (EIA), part of the 

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

its updated Annual Energy Outlook (AEO). 

AEO 2009 indicates that natural gas, coal, 

and renewable are likely to fuel most new 

electrical capacity through 2030, with some 

growth in nuclear capacity (EIA, 2009a), 

though all projections are subject to future 

developments in fuel price or electricity 

demand: 

“Natural-gas-fired plants account for 53 

percent of capacity additions in the 

reference case, as compared with 22 

percent for renewable, 18 percent for 

coal-fired plants, and 5 percent for nuclear

Capacity expansion decisions consider 

capital, operating, and transmission costs. 

Typically, coal-fired, nuclear, and renewable 

plants are capital-intensive, whereas 

operating (fuel) expenditures account for 

most of the costs associated with naturalgas-fired capacity.” 

1 SMALL, MODERATE, or LARGE—to indicate the degree of the environmental effect on each of 

2 the seven aforementioned categories that have been evaluated. 

3 The in-depth alternatives that the Staff 

4 considered include a supercritical coal5 fired plant in section 8.1, a natural gas6 fired combined-cycle power plant in 8.2, 

7 and a combination of alternatives in 8.3, 

8 that includes some natural gas-fired 

9 capacity, energy conservation, and a 

10 wind power component. In section 8.4, 

11 the Staff explains why it dismissed many 

12 other alternatives from in-depth 

13 consideration. Finally, in section 8.5, the 

14 Staff considers the environmental effects 

15 that may occur if NRC takes no action 

16 and does not issue a renewed license for 

17 DAEC. 

18 8.1 SUPERCRITICAL COAL-FIRED 

19 GENERATION 

20 The GEIS indicates that a 610 megawatt21 electric (MWe) supercritical coal-fired 

22 power plant (a plant equivalent in 

23 capacity to DAEC) could require 1,040 

24 acres (421 hectares [ha]) and thus would 

25 not fit on the existing DAEC site; 

26 however, the Staff notes that many coal27 fired power plants with larger capacities have been located on smaller sites. In the ER, FPL-DA 

28 also indicated that onsite construction of a coal-fired alternative would be preferred over an 

29 offsite location. The Staff believes this to be reasonable and, as such, will consider a coal-fired 

30 alternative located on the current DAEC site. 

31 Coal-fired generation accounts for a greater share of U.S. electrical power generation than any 

32 other fuel (EIA, 2009b). Furthermore, the EIA projects that coal-fired power plants will account 

33 for the greatest share of added capacity through 2030—more than natural gas, nuclear or 

34 renewable generation options. While coal-fired power plants are widely used and likely to 

35 remain widely used, the Staff notes that future coal capacity additions may be affected by 

36 perceived or actual efforts to limit greenhouse gas (GHG) emissions. For now, the Staff 

37 considers a coal-fired alternative to be a feasible, commercially available option that could 

38 provide electrical generating capacity after DAEC’s current license expires. 

39 Supercritical technologies are increasingly common in new coal-fired plants. Supercritical plants 

40 operate at higher temperatures and pressures than most existing coal-fired plants (beyond 

41 water’s “critical point”, where boiling no longer occurs and no clear phase change occurs 

42 between steam and liquid water). Operating at higher temperatures and pressures allows this 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-4 February 2010 

1 coal-fired alternative to function at a higher thermal efficiency than many existing coal-fired 

2 power plants do. While supercritical facilities are more expensive to construct, they consume 

3 less fuel for a given output, reducing environmental impacts. Based on technology forecasts 

4 from EIA, the Staff expects that a new, supercritical coal-fired plant beginning operation in 2014 

5 would operate at a heat rate of 9069 British thermal units/kilowatt hour (Btu/kWh), or 

6 approximately 38 percent thermal efficiency (EIA, 2009a). 

7 In a supercritical coal-fired power plant, burning coal heats pressurized water. As the 

8 supercritical steam/water mixture moves through plant pipes to a turbine generator, the 

9 pressure drops and the mixture flashes to steam. The heated steam expands across the turbine 

10 stages, which then spin and turn the generator to produce electricity. After passing through the 

11 turbine, any remaining steam is condensed back to water in the plant’s condenser. 

12 In most modern U.S. facilities, condenser cooling water circulates through cooling towers or a 

13 cooling pond system (either of which are closed-cycle cooling systems). Older plants often 

14 withdraw cooling water directly from existing rivers or lakes and discharge heated water directly 

15 to the same body of water (called open-cycle cooling). In this case, a coal-fired alternative 

16 constructed on the Duane Arnold site would withdraw makeup water from and discharge 

17 blowdown (water containing concentrated dissolved solids and biocides) from cooling towers 

18 back to the Cedar River. Because DAEC already utilizes two mechanical draft cooling towers 

19 onsite, the coal-fired alternative would likely use these existing cooling towers for its closed20 cycle cooling system. Because nuclear plants require more cooling capacity than the 

21 equivalently sized coal-fired plant, the existing cooling towers are expected to be adequate to 

22 support a coal-fired alternative without amendment or expansion. A coal-fired alternative may 

23 also make use of the existing river intake and discharge towers if such a retrofit can take place 

24 while DAEC continues operating. 

25 In order to replace the 610 net MWe that DAEC currently supplies, the coal-fired alternative 

26 would need to produce roughly 575 net MWe, using about 6 percent of power output for onsite 

27 power usage (FPL-DA, 2008). Onsite electricity demands include scrubbers, cooling towers, 

28 coal-handling equipment, lights, communication, and other onsite needs. A supercritical coal29 fired plant equivalent in capacity to DAEC would require less cooling water than DAEC because 

30 the alternative operates at a higher thermal efficiency. 

31 This 610 MWe power plant would consume 2.25 million tons (2.04 million metric tons (MT)) of 

32 coal annually assuming an average heat content of 8,668 British Thermal Units per pound 

33 (btu/lb) (EIA, 2006). EIA reported that most coal consumed in Iowa originates in Wyoming. 

34 Given current coal mining operations in the state of Wyoming, the coal used in this alternative 

35 would likely be mined in surface mines, then mechanically processed and washed, before being 

36 transported—via an existing rail spur—to the power plant site. Limestone for scrubbers would 

37 also arrive by rail. This coal-fired alternative would produce roughly 116,800 tons (106,000 MT) 

38 of ash, and roughly 47,300 tons (43,000 MT) scrubber sludge annually. As noted above, much 

39 of the coal ash and scrubber sludge could be reused depending on local recycling and reuse 

40 markets. 

41 The coal-fired alternative would also include construction impacts such as clearing the plant site 

42 of vegetation, excavation, and preparing the site surface before other crews begin actual 
Environmental Impacts of Alternatives 

February 2010 8-5 Draft NUREG-1437, Supplement 42 

1 construction of the plant and any associated infrastructure. Because this alternative would be 

2 constructed at the DAEC site, it is unlikely that new transmission lines or a new rail spur would 

3 be necessary. 

4 Table 8-1. Summary of Environmental Impacts of the Supercritical Coal-Fired Alternative 

5 Compared to Continued Operation of Duane Arnold Energy Center 

Supercritical Coal-Fired 

Generation 

Continued DAEC Operation 

Air Quality MODERATE SMALL 

Groundwater SMALL SMALL to MODERATE 

Surface Water SMALL SMALL 

Aquatic and Terrestrial Resources SMALL to MODERATE SMALL 

Human Health SMALL SMALL 

Socioeconomics SMALL to MODERATE SMALL to MODERATE 

Waste Management MODERATE SMALL 

6 8.1.1 Air Quality 

7 Air quality impacts from coal-fired generation can be substantial increased because they emit 

8 significant quantities of sulfur oxides (SOx), nitrogen oxides (NOx), particulates, carbon 

9 monoxide (CO), and hazardous air pollutants such as mercury. However, many of these 

10 pollutants can be substantially reduced using various pollution control technologies. 

11 DAEC is located in Linn County, Iowa. There are no areas designated by the EPA as 

12 nonattainment or maintenance for any of the criteria pollutants in the 50-mile (81-km) vicinity of 

13 DAEC. A new coal-fired generating plant would qualify as a new major-emitting industrial facility 

14 and would be subjected to Prevention of Significant Deterioration of Air Quality Review under 

15 requirements of Clean Air Act (CAA), adopted by Iowa Department of Natural Resources (IDNR) 

16 Air Quality Bureau in Section 567 of the Iowa Administrative Code (IAC) (IDNR, 2008). A new 

17 coal-fired generating plant would need to comply with the new source performance standards 

18 for coal-fired plants set forth in 40 CFR 60 Subpart Da. The standards establish limits for 

19 particulate matter and opacity (40 CFR 60.42(a)), sulfur dioxide (SO2) (40 CFR 60.43(a)), and 

20 NOx (40 CFR 60.44(a)). Regulations issued by IDNR adopt the EPA's CAA rules (with 

21 modifications) to limit power plant emissions of SOx, NOx, particulate matter, and hazardous air 

22 pollutants. The new coal-fired generating plant would qualify as a Class I major source as 

23 identified in Section 567 of the IAC and would be required to obtain Class I major source 

24 permits from IDNR, which the EPA may also elect to review prior to issuance of the permits 

25 (IDNR, 2008). 

26 Section 169A of the CAA (42 United States Code (U.S.C.) 7401) establishes a national goal of 

27 preventing future and remedying existing impairment of visibility in mandatory Class I Federal 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-6 February 2010 

1 areas when impairment results from man-made air pollution. The EPA issued a new regional 

2 haze rule in 1999 (64 Federal Register (FR) 35714). The rule specifies that for each mandatory 

3 Class I Federal area located within a state, the State must establish goals that provide for 

4 reasonable progress towards achieving natural visibility conditions. The reasonable progress 

5 goals must provide an improvement in visibility for the most-impaired days over the period of 

6 implementation plan and ensure no degradation in visibility for the least-impaired days over the 

7 same period (40 CFR 51.308(d)(1)). Five regional planning organizations (RPO) collaborate on 

8 the visibility impairment issue, developing the technical basis for these plans. The State of Iowa 

9 is among nine member states (Iowa, Nebraska, Kansas, Oklahoma, Texas, Minnesota, 

10 Missouri, Arkansas, and Louisiana) of the Central Regional Air Planning Association (CENRAP), 

11 along with tribes, Federal agencies, and other interested parties that identifies regional haze 

12 and visibility issues and develops strategies to address them. The visibility protection regulatory 

13 requirements, contained in 40 CFR Part 51, Subpart P, include the review of the new sources 

14 that would be constructed in the attainment or unclassified areas and may affect visibility in any 

15 Federal Class I area (40 CFR Part 51, Subpart P, §51.307). If a coal-fired plant were located 

16 close to a mandatory Class I area, additional air pollution control requirements would be 

17 imposed. There are no mandatory Class I Federal areas in the State of Iowa and the closest 

18 mandatory Class I Federal area is Mingo Wilderness Area, which is located 365 miles southeast 

19 from the DAEC in the State of Missouri. 

20 Iowa is also subject to the Clean Air Interstate Rule (CAIR), which has outlined emissions 

21 reduction goals for both SO2 and NOx for the year 2015. CAIR will aid Iowa sources in reducing 

22 SO2 emissions by 7,000 tons (or 5 percent), and NOx emissions by 37,000 tons (or 49 percent). 

23 (EPA, 2008b). 

24 The Staff projects that the coal-fired alternative at the DAEC site would have the following 

25 emissions for criteria and other significant emissions based on published EIA data, EPA 

26 emission factors and on performance characteristics for this alternative and likely emission 

27 controls: 

28 ● Sulfur oxides (SOx) – 898.19 tons (814.83 MT) per year 

29 ● Nitrogen oxides (NOx) – 562.77 tons (510.55 MT) per year 

30 ● Total suspended particles (TSP) – 99.76 tons (90.50 MT) per year 

31 ● Particulate matter (PM) PM10 – 22.95 tons (20.82 MT) per year 

32 ● Particulate matter (PM) PM2.5 – 58.42 tons (52.99 MT) per year 

33 ● Carbon monoxide (CO) – 562.77 tons (510.55 MT) per year 

34 8.1.1.1 Sulfur Oxides 

35 The coal-fired alternative at the DAEC site would likely use wet, limestone-based scrubbers to 

36 remove SOx. The EPA indicates that this technology can remove more than 95 percent of SOx 

37 from flue gases. The Staff projects total SOx emissions after scrubbing would be 898.19 tons 
Environmental Impacts of Alternatives 

February 2010 8-7 Draft NUREG-1437, Supplement 42 

1 (814.83 MT) per year. SOx emissions from a new coal-fired power plant would be subject to the 

2 requirements of Title IV of the CAA. Title IV was enacted to reduce emissions of SO2 and NOx, 

3 the two principal precursors of acid rain, by restricting emissions of these pollutants from power 

4 plants. Title IV caps aggregate annual power plant SO2 emissions and imposes controls on SO2

5 emissions through a system of marketable allowances. The EPA issues one allowance for each 

6 ton of SO2 that a unit is allowed to emit. New units do not receive allowances, but are required 

7 to have allowances to cover their SO2 emissions. Owners of new units must therefore purchase 

8 allowances from owners of other power plants or reduce SO2 emissions at other power plants 

9 they own. Allowances can be banked for use in future years. Thus, provided a new coal-fired 

10 power plant is able to purchase sufficient allowances to operate, it would not add to net regional 

11 SO2 emissions, although it might do so locally. 

12 8.1.1.2 Nitrogen Oxides 

13 A coal-fired alternative at the DAEC site would most likely employ various available NOx-control 

14 technologies, which can be grouped into two main categories: combustion modifications and 

15 post-combustion processes. Combustion modifications include low-NOx burners, over fire air, 

16 and operational modifications. Post-combustion processes include selective catalytic reduction 

17 and selective non-catalytic reduction. An effective combination of the combustion modifications 

18 and post-combustion processes allow the reduction of NOx emissions by up to 95 percent 

19 (EPA, 1998). FPL-DA indicated in its ER that it would use a combination of low-NOx burners, 

20 overfire air, and selective catalytic reduction technologies to reduce NOx emissions from this 

21 alternative. Assuming the use of such technologies at the DAEC site, NOx emissions after 

22 scrubbing are estimated to be 562.77 tons (510.55 MT) annually. 

23 Section 407 of the CAA establishes technology-based emission limitations for NOx emissions. A 

24 new coal-fired power plant would be subject to the new source performance standards for such 

25 plants as indicated in 40 CFR 60.44a(d)(1). This regulation, issued on September 16, 1998 

26 (63 FR 49453), limits the discharge of any gases that contain nitrogen oxides (NO2) to 200 

27 nanograms (ng) of NOx per joule (J) of gross energy output (equivalent to 1.6 lb/MWh), based 

28 on a 30-day rolling average. Based on the projected emissions, the proposed alternative would 

29 easily meet this regulation. 

30 8.1.1.3 Particulates 

31 The new coal-fired power plant would use fabric filters to remove particulates from flue gases. 

32 FPL-DA indicates that fabric filters would remove 95 percent of particulate matter (FPL-DA, 

33 2008). The EPA notes that filters are capable of removing in excess of 99 percent of particulate 

34 matter, and that SO2 scrubbers further reduce particulate matter emissions (EPA, 2008a). 

35 Based on EPA emission factors, the new supercritical coal-fired plant would emit 99.76 tons 

36 (90.50 MT) per year and approximately 22.95 tons (20.82 MT) per year of particulate matter 

37 having an aerodynamic diameter less than or equal to 10 microns (PM10) annually (EPA, 

38 2009e). In addition, coal burning would also result in approximately 58.42 tons (52.99 MT) per 

39 year of particulate emissions with an aerodynamic diameter of 2.5 microns or less (PM2.5). Coal40 handling equipment would introduce fugitive dust emissions when fuel is being transferred to 

41 onsite storage and then reclaimed from storage for use in the plant. During the construction of a 

42 coal-fired plant, onsite activities would also generate fugitive dust. Vehicles and motorized 

43 equipment would create exhaust emissions during the construction process. These impacts 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-8 February 2010 

1 would be intermittent and short-lived, however, and to minimize dust generation construction 

2 crews would use applicable dust-control measures. 

3 8.1.1.4 Carbon Monoxide 

4 Based on EPA emission factors (EPA, 1998). Based on these emission factors and assumed 

5 plant characteristics, the Staff computed that the total CO emissions would be approximately 

6 562.77 tons (510.55 MT) per year. 

7 8.1.1.5 Hazardous Air Pollutants 

8 Consistent with the D.C. Circuit Court’s February 8, 2008 ruling that vacated its Clean Air 

9 Mercury Rule (CAMR), the EPA is in the process of developing mercury emissions standards for 

10 power plants under the CAA (Section 112) (EPA, 2009 at 3). Before CAMR, the EPA 

11 determined that coal-and oil-fired electric utility steam-generating units are significant emitters of 

12 hazardous air pollutants (HAPs) (EPA, 2000b). The EPA determined that coal plants emit 

13 arsenic, beryllium, cadmium, chromium, dioxins, hydrogen chloride, hydrogen fluoride, lead, 

14 manganese, and mercury (EPA, 2000b). The EPA concluded that mercury is the HAP of 

15 greatest concern; it further concluded that: 

16 (1) a link exists between coal combustion and mercury emissions 

17 (2) electric utility steam-generating units are the largest domestic source of mercury 

18 emissions, and 

19 (3) certain segments of the U.S. population (e.g., the developing fetus and subsistence fish20 eating populations) are believed to be at potential risk of adverse health effects resulting 

21 from mercury exposures caused by the consumption of contaminated fish (EPA, 2000b). 

22 On February 6, 2009, the Supreme Court dismissed the EPA’s request to review the 2008 

23 Circuit Court’s decision, and also denied a similar request by the Utility Air Regulatory Group 

24 later that month (EPA, 2009 at 3). 

25 8.1.1.6 Carbon Dioxide 

26 A coal-fired plant would also have unregulated carbon dioxide (CO2) emissions during 

27 operations as well as during mining, processing, and transportation, which the GEIS indicates 

28 could contribute to global warming. The coal-fired plant would emit between 4,123,000 tons 

29 (3,741,000 MT) and 4,272,000 tons (3,876,600 MT) of CO2 per year, depending on the type and 

30 quality of the coal burned. 

31 8.1.1.7 Summary of Air Quality 

32 While the GElS analysis mentions global warming from unregulated CO2 emissions and acid 

33 rain from SOx and NOx emissions as potential impacts, it does not quantify emissions from 

34 coal-fired power plants. However, the GElS analysis does imply that air impacts would be 

35 substantial (NRC, 1996). The above analysis shows that emissions of air pollutants, including 

36 SOx, NOx, CO, and particulates, exceed those produced by the existing nuclear power plant, as 

37 well as those of the other alternatives considered in this section. Operational emissions of CO2 
Environmental Impacts of Alternatives 

February 2010 8-9 Draft NUREG-1437, Supplement 42 

1 are also much greater under the coal-fired alternative, as reviewed by the Staff in Section 6.2 

2 and in the previous paragraph. Adverse human health effects such as cancer and emphysema 

3 have also been associated with air emissions from coal combustion, and are discussed further 

4 in Section 8.1.5. 

5 The NRC analysis for a coal-fired alternative at the DAEC site indicates that impacts from the 

6 coal-fired alternative would have clearly noticeable effects, but given existing regulatory 

7 regimes, permit requirements, and emissions controls, the coal-fired alternative would not 

8 destabilize air quality. Therefore, the appropriate characterization of air impacts from coal-fired 

9 plant located at DAEC site would be MODERATE. Existing air quality would result in varying 

10 needs for pollution control equipment to meet applicable local requirements, or varying degrees 

11 of participation in emissions trading schemes. 

12 8.1.2 Groundwater Use and Quality 

13 If the onsite coal-fired alternative continued to use groundwater for drinking water and service 

14 water, the need for groundwater at the plant would be minor. Total usage would likely be less 

15 than DAEC because many fewer workers would be onsite, and because the coal-fired unit 

16 would have fewer auxiliary systems requiring service water. No effect on groundwater quality 

17 would be apparent. 

18 Construction of a coal-fired plant could have a localized effect on groundwater due to temporary 

19 dewatering and run-off control measures. Because of the temporary nature of construction and 

20 the likelihood of reduced groundwater usage during operation, the impact of the coal-fired 

21 alternative would be SMALL. 

22 8.1.3 Surface Water Use and Quality 

23 The alternative would draw approximately 9,000 gallons per minute (gpm) from the Cedar River, 

24 with an average consumption of about 11 million gallons per day (mgd). This consumptive loss 

25 is less than 0.1 percent of the average annual flow of the Cedar River, and as such the NRC 

26 concludes the impact of surface water use would be SMALL. A new coal-fired plant would be 

27 required to obtain a National Pollutant Discharge and Elimination System (NPDES) permit from 

28 the IDNR for regulation of industrial wastewater, storm water, and other discharges. Assuming 

29 the plant operates within the limits of this permit, the impact from any cooling tower blowdown, 

30 site runoff, and other effluent discharges on surface water quality would be SMALL. 

31 8.1.4 Aquatic and Terrestrial Ecology 

32 8.1.4.1 Aquatic Ecology 

33 The number of fish and other aquatic resource organisms affected by impingement, 

34 entrainment, and thermal impacts would be smaller than that associated with license renewal 

35 because water consumption from and blowdown to the Cedar River would be lower. Some 

36 temporary impacts to aquatic organisms might occur due to any construction that might occur or 

37 due to any effluent discharges to the river, but these activities would be monitored by the IDNR 

38 under the project’s NPDES permit. Although the number of affected organisms would be less 

39 than for license renewal, the NRC level of impact for license renewal is already small, and so 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-10 February 2010 

1 NRC expects that the levels of impact for impingement, entrainment, and thermal effects would 

2 also be SMALL for this alternative. 

3 8.1.4.2 Terrestrial Ecology 

4 As indicated in the applicant’s ER, constructing the coal-fired alternative onsite would require 

5 less than 96 acres (39 ha) of land (FPL-DA, 2008). Coal-mining would also affect terrestrial 

6 ecology in offsite coal mining areas, although some of the land is likely already disturbed by 

7 mining operations. Onsite and offsite land disturbances form the basis for impacts to terrestrial 

8 ecology. 

9 Onsite impacts to terrestrial ecology would be minor because most of the site has been 

10 previously disturbed and is currently used for agricultural activities. This could change if 

11 additional roads would need to be constructed through less disturbed areas. These construction 

12 activities may fragment or destroy habitats and could include a loss of onsite farmland. These 

13 land disturbances could affect food supply and habitat of native wildlife and migratory waterfowl, 

14 however, these impacts are not expected to be significant. Cooling tower operation could 

15 produce a visible plume as well as some deposition of dissolved solids on surrounding 

16 vegetation and soil from cooling tower drift, however, the GEIS indicated that the impact of 

17 cooling towers on agricultural crops is relatively small, and most of the land surrounding the 

18 DAEC site is farmland. 

19 Any onsite or offsite waste disposal by landfilling would also affect terrestrial ecology at least 

20 through the period when the disposal area is reclaimed. Deposition of acid rain resulting from 

21 NOx or SOx emissions, as well as the deposition of other pollutants, can also affect terrestrial 

22 ecology. Given the emission controls discussed in Section 8.1.1, air deposition impacts may be 

23 noticeable, but are not likely to be destabilizing. Primarily because of the potential habitat 

24 disturbances, impacts to terrestrial resources from a coal-fired alternative would be SMALL to 

25 MODERATE, and would occur mostly during construction. 

26 8.1.5 Human Health 

27 Coal-fired power plants introduce worker risks from coal and limestone mining, from coal and 

28 limestone transportation, and from disposal of coal combustion and scrubber wastes. In 

29 addition, there are public risks from inhalation of stack emissions (as addressed in Section 

30 8.1.1) and the secondary effects of eating foods grown in areas subject to deposition from plant 

31 stacks. 

32 Human health risks of coal-fired power plants are described, in general, in Table 8-2 of the 

33 GEIS (NRC, 1996). Cancer and emphysema as a result of the inhalation of toxins and 

34 particulates are identified as potential health risks to occupational workers and members of the 

35 public (NRC, 1996). The human health risks of coal-fired power plants, both to occupational 

36 workers and to members of the public, are greater than those of the current DAEC due to 

37 exposures to chemicals such as mercury; SOx; NOx; radioactive elements such as uranium and 

38 thorium contained in coal and coal ash; and polycyclic aromatic hydrocarbon (PAH) compounds, 

39 including benzo(a)pyrene. 
Environmental Impacts of Alternatives 

February 2010 8-11 Draft NUREG-1437, Supplement 42 

1 Regulations restricting emissions—enforced by EPA or State agencies—have acted to 

2 significantly reduce potential health effects but have not entirely eliminated them. These 

3 agencies also impose site-specific emission limits as needed to protect human health. Even if 

4 the coal-fired alternative were located in a nonattainment area, emission controls and trading or 

5 offset mechanisms could prevent further regional degradation; however, local effects could be 

6 visible. Many of the byproducts of coal combustion responsible for health effects are largely 

7 controlled, captured, or converted in modern power plants (as described in Section 8.1.1), 

8 although some level of health effects may remain. 

9 Aside from emission impacts, the coal-fired alternative introduces the risk of coal pile fires and 

10 for those plants that use coal combustion liquid and sludge waste impoundments, the release of 

11 the waste due to a failure of the impoundment. Although there have been several instances of 

12 this occurring in recent years, these types of events are still relatively rare. 

13 Overall, given extensive health-based regulation, the Staff expects human health impacts to be 

14 SMALL. 

15 8.1.6 Socioeconomics 

16 8.1.6.1 Land Use 

17 The GEIS generically evaluates the impacts of nuclear power plant operations on land use both 

18 on and off each power plant site. The analysis of land use impacts focuses on the amount of 

19 land area that would be affected by the construction and operation of a new supercritical coal20 fired power plant on the DAEC site. 

21 FPL-DA indicated that approximately 96 acres (39 ha) of land would be needed to support a 

22 coal-fired alternative capable of replacing the DAEC. This amount of land use includes power 

23 plant structures and associated coal delivery and waste disposal infrastructure. FPL-DA 

24 indicated that the site has an existing rail spur, however an additional 100 acres (40 ha) of land 

25 area may be needed for waste disposal, which FPL-DA indicated could be accommodated 

26 onsite (FPL-DA, 2008). 

27 Offsite land use impacts would occur from coal mining in addition to land use impacts from the 

28 construction and operation of the new power plant. Scaling from GEIS estimates, approximately 

29 13,450 acres (5,450 ha) of land could be affected by mining coal and waste disposal to support 

30 the coal-fired alternative during its operational life (NRC, 1996). However, most of the land in 

31 existing coal-mining areas has already experienced some level of disturbance. The elimination 

32 of the need for uranium mining to supply fuel for the DAEC would partially offset this offsite land 

33 use impact. Scaling from GEIS estimates, approximately 610 acres (247 ha) of land would be 

34 used for uranium mining and processing would no longer be needed. 

35 Based on this information, land use impacts could range from SMALL to MODERATE. 

36 8.1.6.2 Socioeconomics 

37 Socioeconomic impacts are defined in terms of changes to the demographic and economic 

38 characteristics and social conditions of a region. For example, the number of jobs created by the 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-12 February 2010 

1 construction and operation of a new coal-fired power could affect regional employment, income, 

2 and expenditures. Two types of job creation result from this alternative: (1) construction-related 

3 jobs, and (2) operation-related jobs in support of power plant operations, which have the greater 

4 potential for permanent, long-term socioeconomic impacts. The Staff estimated workforce 

5 requirements during power plant construction and operation for the coal-fired alternative in order 

6 to measure their possible effect on current socioeconomic conditions. 

7 Based on GEIS estimates, FPL-DA projected a peak construction workforce of 937 to 1,500 

8 workers would be required to construct the coal-fired alternative at the DAEC (FPL-DA, 2008). 

9 During the construction period, the communities surrounding the plant site would experience 

10 increased demand for rental housing and public services. The relative economic contributions of 

11 these relocated workers to local business and tax revenues would vary over time. 

12 After construction, local communities may be temporarily affected by the loss of construction 

13 jobs and associated loss in demand for business services. In addition, the rental housing market 

14 could experience increased vacancies and decreased prices. As noted in the GEIS, the 

15 socioeconomic impacts at a rural construction site could be larger than at an urban site, 

16 because the workforce would need to relocate closer to the construction site. Although the ER 

17 indicates that DAEC is a rural site, it is located near three metropolitan areas: Waterloo (34 

18 miles), Iowa City (32 miles), and Cedar Rapids (5.7 miles). Therefore, these effects may be 

19 somewhat lessened because workers are likely to commute to the site from these areas instead 

20 of relocating closer to the construction site. Based on the site’s proximity to these metropolitan 

21 areas, construction impacts would be SMALL. 

22 FPL-DA estimated an operational workforce of 66 to 150 workers for the 610 MWe alternative 

23 based on GEIS estimates (FPL-DA, 2008). The FPL-DA estimate appears reasonable and is 

24 consistent with trends calling for decreased workforces at power facilities. Even at a rural site 

25 like DAEC, impacts are unlikely to be large. Operational impacts would likely be SMALL. 

26 8.1.6.3 Transportation 

27 During construction, 900 to 1,500 workers would be commuting to the site. In addition to 

28 commuting workers, trucks would transport construction materials and equipment to the 

29 worksite increasing the amount of traffic on local roads, while trains would transport some of the 

30 largest components to the plant site. The increase in vehicular traffic on roads would peak 

31 during shift changes resulting in temporary levels of service impacts and delays at intersections. 

32 Trains would likely be used to deliver large components to the DAEC site given its existing rail 

33 spur. Transportation impacts are likely to be MODERATE during construction. 

34 Transportation impacts would be greatly reduced after construction, but would not disappear 

35 during plant operations. The maximum number of plant operating personnel commuting to the 

36 DAEC would be approximately 150 workers. Frequent deliveries of coal and limestone by rail 

37 would add to the overall transportation impact. Onsite coal storage would make it possible to 

38 receive several trains per day. Limestone delivered by rail could also add traffic (though 

39 considerably less traffic than that generated by coal deliveries). 

40 The coal-fired alternative would likely create SMALL to MODERATE transportation impacts 

41 during plant operations. 
Environmental Impacts of Alternatives 

February 2010 8-13 Draft NUREG-1437, Supplement 42 

1 8.1.6.4 Aesthetics 

2 The aesthetics impact analysis focuses on the degree of contrast between the coal-fired 

3 alternative and the surrounding landscape and the visibility of the coal plant. 

4 The coal-fired alternative would be up to 200 feet (61 m) tall with an exhaust stack up to 500 

5 feet (152 m) and may be visible offsite in daylight hours. The coal-fired plant could therefore be 

6 somewhat taller than the current DAEC reactor building, which stands at 140 feet (43 m) with a 

7 328-foot (100-m) offgas stack. The mechanical draft towers would generate a condensate 

8 plume, but this would be no more noticeable than the existing DAEC plume. Depending on 

9 need, the coal-fired alternative may only require the use of one cooling tower instead of the 

10 current two, thus minimizing the size of the condensate plume. Noise and light from plant 

11 operations, as well as lighting on plant structures, may be detectable offsite. 

12 Overall, aesthetic impacts associated with the coal-fired alternative would likely be SMALL to 

13 MODERATE. 

14 8.1.6.5 Historic and Archaeological Resources 

15 Cultural resources are the indications of human occupation and use of the landscape as defined 

16 and protected by a series of Federal laws, regulations, and guidelines. Prehistoric resources are 

17 physical remains of human activities that predate written records; they generally consist of 

18 artifacts that may alone or collectively yield information about the past. Historic resources 

19 consist of physical remains that postdate the emergence of written records; in the United States, 

20 they are architectural structures or districts, archaeological objects, and archaeological features 

21 dating from 1492 and later. Ordinarily, sites less than 50 years old are not considered historic, 

22 but exceptions can be made for such properties if they are of particular importance, such as 

23 structures associated with the development of nuclear power (e.g., Shippingport Atomic power 

24 Station) or Cold War themes. American Indian resources are sites, areas, and materials 

25 important to American Indians for religious or heritage reasons. Such resources may include 

26 geographic features, plants, animals, cemeteries, battlefields, trails, and environmental features. 

27 The cultural resource analysis encompassed the power plant site and adjacent areas that could 

28 potentially be disturbed by the construction and operation of alternative power plants. 

29 The potential for historic and archaeological resources can vary greatly depending on the 

30 location of the proposed site. To consider a project's effects on historic and archaeological 

31 resources, any proposed areas would need to be surveyed to identify and record historic and 

32 archaeological resources, identify cultural resources (e.g., traditional cultural properties), and 

33 develop possible mitigation measures to address any adverse effects from ground disturbing 

34 activities. Studies would be needed for all areas of potential disturbance at the proposed plant 

35 site and along associated corridors where construction would occur (e.g., roads, transmission 

36 corridors, rail lines, or other ROWs). Areas with the greatest sensitivity should be avoided. 

37 The impact for a coal-fired alternative at the DAEC site would be MODERATE. As noted in 

38 Section 4.9.6, potential impacts to historic and archaeological resources could be minimized or 

39 avoided if DAEC develops procedures and a cultural resource management plan that effectively 

40 consider historic and archaeological resources. This plan would ensure that informed decisions 

41 are made prior to any ground disturbing activities onsite. Plant procedures would also include an 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-14 February 2010 

1 inadvertent discovery (stop work) provision. Depending on the resource richness of area 

2 ultimately chosen for the coal-fired alternative, impacts could be MODERATE. 

3 8.1.6.6 Environmental Justice 

4 The environmental justice impact analysis evaluates the potential for disproportionately high and 

5 adverse human health and environmental effects on minority and low-income populations that 

6 could result from the construction and operation of a new coal-fired power plant. Adverse health 

7 effects are measured in terms of the risk and rate of fatal or nonfatal adverse impacts on human 

8 health. Disproportionately high and adverse human health effects occur when the risk or rate of 

9 exposure to an environmental hazard for a minority or low-income population is significant and 

10 exceeds the risk or exposure rate for the general population or for another appropriate 

11 comparison group. 

12 According to 2000 census data, 7.6 percent of the population (approximately 49,296 individuals) 

13 residing within a 50-mile radius of DAEC were minority individuals. The largest minority group 

14 was Black or African American (18,883 individuals, or 2.9 percent), followed by Hispanic 

15 (11,772 individuals, or about 1.8 percent). Approximately 6 percent of the Linn County 

16 populations are minorities, with Black or African American (2.5 percent) the largest minority 

17 group, followed by Hispanic (1.4 percent). In Benton County, 1.2 percent of the populations are 

18 minorities, with Hispanic (0.6 percent) the largest minority group, followed by Black or African 

19 American (0.2 percent).The 50-mile radius around DAEC consists of each county with at least 

20 one census block group located within the 50-mile radius. The population demographic data 

21 from these counties were added together to derive average regional percentages. Of the 512 

22 census block groups located wholly or partly within the 50-mile radius of DAEC, 23 block groups 

23 were determined to have minority population percentages that exceeded the regional 

24 percentages by 20 percentage points or more, or that were more than 50 percent minority. The 

25 largest number of minority block groups was Black or African American, with 14 block groups 

26 that exceed the regional percentage of 20 percent or more, or that were more than 50 percent 

27 Black or African American. 

28 These block groups are concentrated in urban areas with high population densities in Black 

29 Hawk County and Linn County. The closest high density minority population to DAEC is located 

30 in the city of Cedar Rapids, Iowa. Based on 2000 census data, Figure 4-1 shows minority block 

31 groups within a 50-mile radius of DAEC. 

32 According to 2000 census data, 59,848 individuals (approximately 9.2 percent) residing within a 

33 50-mile radius of DAEC were identified as living below the Federal poverty threshold. The 1999 

34 Federal poverty threshold was $17,029 for a family of four. According to Census Bureau data, 

35 the median household income for Iowa in 2007 was $47,324, while 11.0 percent of the State 

36 population was determined to be living below the 1999 Federal poverty threshold. Linn County 

37 had one of the higher median household incomes ($53,076) in the State, and a lower 

38 percentage (9.9 percent) of individuals living below the poverty level, when compared to the 

39 State. 

40 Census block groups were considered low-income block groups if the percentage of households 

41 below the Federal poverty threshold exceeded the State average by 20 percent or more. Based 

42 on 2000 Census data, there were 15 block groups within the 50-mile radius of DAEC that 
Environmental Impacts of Alternatives 

February 2010 8-15 Draft NUREG-1437, Supplement 42 

1 exceeded the State average for low income households by 20 percent or more, or that were 

2 more than 50 percent low-income. The majority of census block groups with low-income 

3 populations were located in Black Hawk County. The nearest high density low-income 

4 population to DAEC is located in Cedar Rapids, Iowa. Based on 2000 Census data, Figure 4-2

5 shows low-income block groups within a 50-mile radius of DAEC. 

6 Based on the analysis of impacts for other resource areas, the construction and operation of a 

7 coal-fired power plant alternative at the DAEC site may have adverse impacts on minority and 

8 low-income populations. However, minority and low-income populations in the area are 

9 relatively small and only a small number of workers are needed to construct and operate a 

10 natural gas-fired power plant and wind farm; impacts on these communities would not be 

11 disproportionate with that of the rest of the population within the 50-mile radius. Therefore, 

12 because there are no high or adverse impacts, by definition, there is also no disproportionate 

13 impact upon low income or minority populations. 

14 8.1.7 Waste Management 

15 Coal combustion generates several waste streams including ash (a dry solid) and sludge (a 

16 semi-solid byproduct of emission control system operation). The Staff estimates that 610 MW 

17 power plant would generate annually a total of 126,800 tons (115,000 MT) of dry solid ash and 

18 scrubber sludge. About 90,000 tons (81,600 MT) of this waste would be recycled. Disposal of 

19 the remaining waste from the 40-year operation of this alternative would require approximately 

20 44 acres (18 ha). Disposal of the remaining waste could noticeably affect land use and 

21 groundwater quality, but would require proper citing in accordance with the Title 567, Chapter 

22 101 “Solid Waste Comprehensive Planning Requirements” of the Iowa Administrative Code and 

23 the implementation of the required monitoring and management practices in order to minimize 

24 these impacts (IDNR, 2009). After closure of the waste site and revegetation, the land could be 

25 available for other uses. 

26 In May 2000, the EPA issued a “Notice of Regulatory Determination on Wastes from the 

27 Combustion of Fossil Fuels” (EPA, 2000a) stating that it would issue regulations for disposal of 

28 coal combustion waste under Subtitle D of the Resource Conservation and Recovery Act. The 

29 EPA has not yet issued these regulations. 

30 The impacts from waste generated during operation of this coal-fired alternative would be 

31 MODERATE; the impacts would be clearly visible, but would not destabilize any important 

32 resource. 

33 The amount of the construction waste would be small compared to the amount of waste 

34 generated during operational stage and much of it could be recycled. Overall, the impacts from 

35 waste generated during construction stage would be SMALL. 

36 Therefore, the Staff concludes that the overall impacts from construction and operation of this 

37 alternative would be MODERATE. 

38 
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Draft NUREG-1437, Supplement 42 8-16 February 2010 

1 8.2 NATURAL GAS COMBINED-CYCLE GENERATION 

2 In this section, the Staff evaluates the environmental impacts of a natural gas-fired combined3 cycle generation plant at the DAEC site.

4 Natural gas fueled 22 percent of electric generation in the US in 2007 (the most recent year for 

5 which data are available); this accounted for the second greatest share of electrical power after 

6 coal (EIA, 2009b). Like coal-fired power plants, natural gas-fired plants may be affected by 

7 perceived or actual actions to limit GHG emissions; they produce markedly lower GHG 

8 emissions per unit of electrical output than coal-fired plants. Natural gas-fired power plants are 

9 feasible and provide commercially available options for providing electrical generating capacity 

10 beyond DAEC’s current license expiration date. 

11 Combined-cycle power plants differ significantly from coal-fired and existing nuclear power 

12 plants. They derive the majority of their electrical output from a gas-turbine cycle, and then 

13 generate additional power—without burning any additional fuel—through a second, steam14 turbine cycle. The first, gas turbine stage (similar to a large jet engine) burns natural gas that 

15 turns a driveshaft that powers an electric generator. The exhaust gas from the gas turbine is still 

16 hot enough, however, to boil water into steam. Ducts carry the hot exhaust to a heat recovery 

17 steam generator, which produces steam to drive a steam turbine and produce additional 

18 electrical power. The combined-cycle approach is significantly more efficient than any one cycle 

19 on its own; thermal efficiency can exceed 60 percent. Since the natural gas-fired alternative 

20 derives much of its power from a gas turbine cycle, and because it wastes less heat than either 

21 the coal-fired alternative or the existing DAEC, it requires significantly less cooling. 

22 In order to replace the 610 MWe that DAEC currently supplies, the Staff selected a gas-fired 

23 alternative that uses two Siemens SCC6-5000F combined-cycle generating units. While any 

24 number of commercially available combined-cycle units could be installed in a variety of 

25 combinations to replace the power currently produced by DAEC, the SCC6-5000F is a highly 

26 efficient model that would help minimize environmental impacts. Other manufacturers, like 

27 General Electric, offer similarly high efficiency models. This gas-fired alternative produces a net 

28 275 MWe per unit. Two units produce a total of 590 MWe, or nearly the same output as the 

29 existing DAEC. 

30 The combined-cycle alternative operates at a heat rate of 5960 btu/kWh, or about 57 percent 

31 thermal efficiency (Siemens, 2007). Allowing for onsite power usage, including cooling towers 

32 and site lighting, the gross output of these units would be roughly 615 MWe. As noted above, 

33 this gas-fired alternative would require much less cooling water than DAEC because it operates 

34 at a higher thermal efficiency and because it requires much less water for steam cycle 

35 condenser cooling. This alternative would likely make use of the site’s existing mechanical draft 

36 cooling towers, and may only require the use of one tower instead of the currently operating 

37 two. 

38 In addition to the already existing mechanical draft cooling towers, other visible structures onsite 

39 include the turbine buildings and HRSGs (which may be enclosed in a single building), two 

40 exhaust stacks, an electrical switchyard, and, possibly, equipment associated with a natural gas 

41 pipeline, like a compressor station. While GEIS estimates indicate that this 590 MWe plant 
Environmental Impacts of Alternatives 

February 2010 8-17 Draft NUREG-1437, Supplement 42 

1 would require 68 acres (27 ha), FPL-DA indicated that a natural gas alternative of comparable 

2 size (610 MWe) would require only 24 acres (10 ha) (FPL-DA, 2008). The Staff believes 

3 FPL-DA’s estimate to be sound and will refer to it for the analysis of this alternative. 

This 590 MWe power plant would consume 26.5 billion cubic feet (ft3 4 ) (752 million cubic meters 

[m3

]) of natural gas annually assuming an average heat content of 1,029 btu/ft3 5 (EIA, 2009c). 

6 Natural gas would be extracted from the ground through wells, then treated to remove impurities 

7 (like hydrogen sulfide), and blended to meet pipeline gas standards, before being piped through 

8 the interstate pipeline system to the power plant site. This gas-fired alternative would produce 

9 relatively little waste, primarily in the form of spent catalysts used for emissions controls. 

10 Environmental impacts from the gas-fired alternative would be greatest during construction. Site 

11 crews would clear vegetation from the site, prepare the site surface, and begin excavation 

12 before other crews begin actual construction on the plant and any associated infrastructure, 

13 including a 15-mile pipeline spur to serve the plant and electricity transmission infrastructure 

14 connecting the plant to existing transmission lines. Constructing the gas-fired alternative on the 

15 DAEC site would allow the gas-fired alternative to make use of the existing electric transmission 

16 system. 

17 Table 8-2. Summary of Environmental Impacts of the Natural Gas Combined-Cycle 

18 Generation Alternative Compared to Continued Operation of Duane Arnold Energy 

19 Center 

Natural Gas Combined-Cycle 

Generation 

Continued DAEC Operation 

Air Quality SMALL to MODERATE SMALL 

Groundwater SMALL SMALL to MODERATE 

Surface Water SMALL SMALL 

Aquatic and Terrestrial Resources SMALL SMALL 

Human Health SMALL SMALL 

Socioeconomics SMALL to MODERATE SMALL to MODERATE 

Waste Management SMALL SMALL 

20 8.2.1 Air Quality 

21 Linn County, Iowa is in the EPA Region 7. All counties in the State of Iowa are in attainment for 

22 all criteria pollutants, except Muscatine County, which is a maintenance county for SO2. A new 

23 gas-fired generating plant developed at the DAEC site would qualify as a new major-emitting 

24 industrial facility and require a New Source Review (NSR)/Prevention of Significant 

25 Deterioration of Air Quality review under CAA requirements, adopted by Iowa Department of 

26 Natural Resources (IDNR) in Section 567 of the Iowa Administrative Code (IDNR, 2008). The 

27 natural gas-fired plant would need to comply with the standards of performance for stationary 

28 gas turbines set forth in 40 CFR Part 60 Subpart GG. 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-18 February 2010 

1 40 CFR Part 51, Subpart P contains the visibility protection regulatory requirements, including 

2 the review of the new sources that would be constructed in the attainment or unclassified areas 

3 and may affect visibility in any Federal Class I area (40 CFR Part 51, Subpart P, §51.307). If a 

4 gas-fired alternative were located close to a mandatory Class I area, additional air pollution 

5 control requirements would potentially apply. There are no mandatory Class I Federal areas in 

6 the State of Iowa and the closest mandatory Class I Federal area is Mingo Wilderness Area, 

7 which is located 365 miles southeast of DAEC in Missouri. 

8 The Staff projects the following emissions for a gas-fired alternative based on data published by 

9 the EIA, the EPA, and on performance characteristics for this alternative and its emissions 

10 controls: 

11 ● Sulfur oxides (SOx) – 46.40 tons (42.10 MT) per year 

12 ● Nitrogen oxides (NOx) – 148.77 tons (134.96 MT) per year 

13 ● Carbon monoxide (CO) – 30.93 tons (28.06 MT) per year 

14 ● Total suspended particles (TSP) – 25.93 tons (23.53 MT) per year 

15 ● Particulate matter (PM) PM10 – 25.93 tons (23.53 MT) per year 

16 ● Carbon dioxide (CO2) – 1,581,300 tons (1,434,500 MT) per year 

17 A new natural gas-fired plant would have to comply with Title IV of the CAA reduction 

18 requirements for SO2 and NOx, which are the main precursors of acid rain and the major cause 

19 of reduced visibility. Title IV establishes maximum SO2 and NOx emission rate from the existing 

20 plants and a system of the SO2 emission allowances that can be used, sold or saved for future 

21 use by new plants. 

22 8.2.1.1 Sulfur and Nitrogen Oxides 

23 As stated above, the new natural gas-fired alternative would produce 46.40 tons (42.10 MT) per 

24 year of SOx and 148.77 tons (134.96 MT) per year of NOx based on the use of the dry low NOx 

25 combustion technology and use of the selective catalytic reduction (SCR) in order to 

26 significantly reduce NOx emissions. 

27 The new plant would be subjected to the continuous monitoring requirements of SO2, NOx and 

28 CO2 specified in 40 CFR Part 75. The Staff computed that the natural gas-fired plant would emit 

29 approximately 1.6 million tons (approximately 1.4 million MT) per year of unregulated CO2

30 emissions. As of today, there is no required reporting of GHG emissions for plants in Iowa. In 

31 response to the Consolidated Appropriations Act of 2008, the EPA has proposed a rule that 

32 requires mandatory reporting of GHG emissions from large sources that would allow collection 

33 of accurate and comprehensive emissions data to inform future policy decisions (EPA, 2009c). 

34 The EPA proposes that suppliers of fossil fuels or industrial GHGs, manufacturers of vehicles 

35 and engines, and facilities that emit 25,000 MT or more per year of GHG emissions submit 

36 annual reports to the EPA. The gases covered by the proposed rule are carbon dioxide (CO2), 
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February 2010 8-19 Draft NUREG-1437, Supplement 42 

1 methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur 

2 hexafluoride (SF6), and other fluorinated gases including nitrogen trifluoride (NF3) and 

3 hydrofluorinated ethers (HFE). 

4 8.2.1.2 Particulates 

5 The new natural gas-fired alternative would produce 25.93 tons (23.53 MT) per year of TSP, all 

6 of which would be emitted as PM10

7 8.2.1.3 Hazardous Air Pollutants 

8 The EPA issued in December 2000 regulatory findings (EPA, 2000b) on emissions of hazardous 

9 air pollutants from electric utility steam-generating units, which identified that natural gas-fired 

10 plants emit hazardous air pollutants such as arsenic, formaldehyde and nickel and stated that 

11 . . . the impacts due to HAP emissions from natural gas-fired electric utility steam 

12 generating units were negligible based on the results of the study. The 

13 Administrator finds that regulation of HAP emissions from natural gas-fired 

14 electric utility steam generating units is not appropriate or necessary. 

15 8.2.1.4 Carbon Monoxide 

16 Based on EPA emission factors (EPA, 1998), Staff estimates that the total CO emissions would 

17 be approximately 30.93 tons (28.06 MT) per year. 

18 8.2.1.5 Construction Impacts 

19 Activities associated with the construction of the new natural gas-fired plant at the DAEC site 

20 would cause some additional air effects as a result of equipment emissions and fugitive dust 

21 from operation of the earth-moving and material handling equipment. Workers’ vehicles and 

22 motorized construction equipment would generate temporary exhaust emissions. The 

23 construction crews would employ dust-control practices in order to control and reduce fugitive 

24 dust, which would be temporary in nature. The Staff concludes that the impact of vehicle 

25 exhaust emissions and fugitive dust from operation of earth-moving and material handling 

26 equipment would be SMALL. 

27 The overall air-quality impacts of a new natural gas-fired plant located at the DAEC site would 

28 be SMALL to MODERATE. 

29 8.2.2 Groundwater Use and Quality 

30 The use of groundwater for a natural gas-fired combined-cycle plant would likely be limited to 

31 supply wells for drinking water and possibly filtered service water for system cleaning purposes. 

32 Total usage would likely be much less than DAEC because many fewer workers would be 

33 onsite, and because the gas-fired alternative would have fewer auxiliary systems requiring 

34 service water. 

35 No effects on groundwater quality would be apparent except during the construction phase due 

36 to temporary dewatering and run-off control measures. Because of the temporary nature of 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-20 February 2010 

1 construction and the likelihood of reduced groundwater usage during operation, the impact of 

2 the natural gas-fired alternative would be SMALL. 

3 8.2.3 Surface Water Use and Quality 

4 Total withdrawals of surface water from the Cedar River would be much less for a gas-fired 

plant than the 11,200 gpm (0.85 cubic meters per second [m3 5 /s]) currently used on average by 

6 DAEC, as well as the amount needed for the coal-fired alternative. Similarly, consumptive 

7 losses would be reduced, especially if the gas-fired alternative only requires the use of one of 

8 the mechanical draft cooling towers instead of the current two. Consumptive losses from the 

9 current DAEC unit are less than 0.1 percent of the average annual flow of the Cedar River, and 

10 would become much smaller if this gas-fired alternative were to replace DAEC. As such, the 

11 NRC concludes the impact of surface water use would be SMALL. 

12 A new gas-fired plant would be required to obtain a National Pollutant Discharge and 

13 Elimination System (NPDES) permit from the Iowa Department of Natural Resources (IDNR) for 

14 regulation of industrial wastewater, storm water, and other discharges. Assuming the plant 

15 operates within the limits of this permit, the impact from cooling tower blow down, site runoff, 

16 and other effluent discharges on surface water quality would be SMALL. 

17 8.2.4 Aquatic and Terrestrial Ecology 

18 8.2.4.1 Aquatic Ecology 

19 Aquatic ecology actually benefits from the onsite, gas-fired alternative, compared to the existing 

20 plant as the combined-cycle plant injects significantly less heat to the environment, thus 

21 requiring less water. The number of fish and other aquatic organisms affected by impingement, 

22 entrainment, and thermal impacts would be smaller than that associated with license renewal 

23 because water consumption and blow down to the Cedar River would be substantially lower. 

24 Some temporary impacts to aquatic organisms might occur due to any construction or effluent 

25 discharge to the river, but NRC assumes that the appropriate agencies would be monitoring and 

26 regulating such activities. Although the number of affected organisms would be substantially 

27 less than for license renewal, the NRC level of impact for license renewal is already small, and 

28 so NRC expects that the levels of impact for impingement, entrainment, and thermal effects of 

29 this alternative would likewise be SMALL. 

30 8.2.4.2 Terrestrial Ecology 

31 As indicated in previous sections, constructing the natural gas alternative would require 24 

32 acres (10 ha) of land. These land disturbances form the basis for impacts to terrestrial ecology. 

33 Impacts to terrestrial ecology would be minor because the selected site has been previously 

34 disturbed and is mostly used for agricultural activities. (Gas extraction and collection would also 

35 affect terrestrial ecology in offsite gas fields, although, much of this land is likely already 

36 disturbed by gas extraction, and the incremental effects of this alternative on gas field terrestrial 

37 ecology are difficult to gauge.) 
Environmental Impacts of Alternatives 

February 2010 8-21 Draft NUREG-1437, Supplement 42 

1 Construction of the two natural gas-fired units could result in the loss of farmland, which could 

2 affect food supply and habitat of native wildlife. However, these effects are not expected to be 

3 significant. Operation of the cooling towers would produce a visible plume and cause some 

4 deposition of dissolved solids on surrounding vegetation (including some wetlands) and soil 

5 from cooling tower drift, however, the GEIS indicates that the impact of cooling towers on 

6 agricultural crops is of small significance, and most of the land surrounding the cooling towers is 

7 farmland. These effects would be no more severe than the current DAEC operating cooling 

8 towers and could even be less if the gas-fired alternative uses only one of the two mechanical 

9 draft towers. 

10 Construction of the 15 mile gas pipeline (to the nearest assumed tie-in) could lead to a 

11 conversion of up to 136 acres (55 ha) of forested lands used by terrestrial wildlife to a mowed 

12 right-of-way (ROW) as well as the loss of cropland from agricultural production, which could 

13 impact wildlife that use the croplands as a food source. Pipeline construction may fragment 

14 surrounding habitat and may increase edge habitat, which may adversely impact forest interior 

15 dwelling species, including migratory songbirds, as well as any threatened and endangered 

16 species in the affected area. However, much of the area surrounding DAEC is in agricultural use 

17 and therefore has been previously disturbed, so it is unlikely that a significant amount of 

18 forested land would be affected. FPL-DA also indicated that the pipeline would be routed along 

19 existing, previously disturbed ROWs to minimize any impacts. Because of the relatively small 

20 potential for undisturbed land to be affected, impacts from construction of the pipeline are 

21 expected to be small. 

22 Based on this information, impacts to terrestrial resources would be SMALL. 

23 8.2.5 Human Health 

24 Like the coal-fired alternative discussed above, a gas-fired plant would emit criteria air 

25 pollutants, but in smaller quantities (except NOx, which requires additional controls to reduce 

26 emissions). Human health effects of gas-fired generation are generally low, although in Table 8-

27 2 of the GEIS (NRC, 1996), the Staff identified cancer and emphysema as potential health risks 

28 from gas-fired plants. NOx emissions contribute to ozone formation, which in turn contributes to 

29 human health risks. Emission controls on this gas-fired alternative maintain NOx emissions well 

30 below air quality standards established for the purposes of protecting human health, and 

31 emissions trading or offset requirements mean that overall NOx in the region would not 

32 increase. Health risks to workers may also result from handling spent catalysts that may contain 

33 heavy metals. 

34 Overall, human health risks to occupational workers and to members of the public from gas-fired 

35 power plant emissions sited at DAEC would be less than the risks described for coal-fired 

36 alternative and therefore, would likely be SMALL. 

37 8.2.6 Socioeconomics 

38 8.2.6.1 Land Use 

39 As discussed in Section 8.1.6, the GEIS generically evaluates the impacts of nuclear power 

40 plant operations on land use both on and off each power plant site. The analysis of land use 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-22 February 2010 

1 impacts focuses on the amount of land area that would be affected by the construction and 

2 operation of a two unit natural gas-fired combined-cycle power plant at the DAEC site. 

3 Based on GEIS estimates, FPL-DA indicated that approximately 24 acres (10 ha) of land would 

4 be needed to support a natural gas-fired alternative to replace DAEC (FPL-DA, 2008). This 

5 amount of onsite land use would include other plant structures and associated infrastructure, 

6 and is unlikely to exceed 64 acres (26 ha), excluding land for natural gas wells and collection 

7 stations. Onsite land use impacts from construction would be SMALL. 

8 In addition to onsite land requirements, land would be required offsite for natural gas wells and 

9 collection stations. Scaling from GEIS estimates, approximately 5,200 acres (2,100 ha) would 

10 be required for wells, collection stations, and a 15 mile pipeline to bring the gas to the plant. 

11 Most of this land requirement would occur on land where gas extraction already occurs. In 

12 addition, some natural gas could come from outside of the United States and be delivered as 

13 liquefied gas. 

14 The elimination of uranium fuel for the DAEC could partially offset offsite land requirements. 

15 Scaling from GEIS estimates, the Staff estimated that approximately 610 acres (247 ha) would 

16 not be needed for mining and processing uranium during the operating life of the plant. Overall 

17 land use impacts from a gas-fired power plant would be SMALL to MODERATE. 

18 8.2.6.2 Socioeconomics 

19 Socioeconomic impacts are defined in terms of changes to the demographic and economic 

20 characteristics and social conditions of a region. For example, the number of jobs created by the 

21 construction and operation of a new natural gas-fired power plant could affect regional 

22 employment, income, and expenditures. Two types of job creation would result: (1) construction23 related jobs, which are transient, short in duration, and less likely to have a long-term 

24 socioeconomic impact; and (2) operation-related jobs in support of power plant operations, 

25 which have the greater potential for permanent, long-term socioeconomic impacts. Staff 

26 evaluated workforce requirements for construction and operation of the natural gas-fired power 

27 plant alternative in order to measure their possible effect on current socioeconomic conditions. 

28 The socioeconomic impacts from constructing and operating a gas-fired plant would have little 

29 noticeable effect. Compared to the coal-fired alternative, the small size of the construction and 

30 operations workforce would have little or no socioeconomic impact. 

31 While the GEIS estimates a peak workforce of 700, FPL-DA projected a maximum construction 

32 workforce of 344 (FPL-DA, 2008). The Staff finds this estimate to be reasonable and will refer to 

33 it for this analysis. During construction, the communities surrounding the power plant site would 

34 experience increased demand for rental housing and public services. The relative economic 

35 effect of construction workers on local economy and tax base would vary over time. 

36 After construction, local communities may be temporarily affected by the loss of construction 

37 jobs and associated loss in demand for business services, and the rental housing market could 

38 experience increased vacancies and decreased prices. As noted in the GEIS, the 

39 socioeconomic impacts at a rural construction site could be larger than at an urban site, 

40 because the workforce may have to move to be closer to the construction site. Although the ER 
Environmental Impacts of Alternatives 

February 2010 8-23 Draft NUREG-1437, Supplement 42 

1 identifies the DAEC site as a primarily rural site, it is located near three metropolitan areas: 

2 Waterloo (34 mi), Iowa City (32 mi), and Cedar Rapids (5.7 mi). Therefore, these effects would 

3 likely be lessened because workers are likely to commute to the site from these areas instead of 

4 relocating closer to the construction site. Because of the site’s proximity to these highly 

5 populated areas, the impact of construction on socioeconomic conditions would be SMALL. 

6 Scaling down from GEIS estimates of an operational workforce of 88 employees, FPL-DA 

7 estimated a power plant operations workforce of approximately 19 (FPL-DA, 2008). The FPL8 DA estimate appears reasonable and is consistent with trends toward lowering labor costs by 

9 reducing the size of power plant operations workforces. The small number of operations 

10 workers are unlikely to have a noticeable effect on socioeconomic conditions in the region. 

11 Socioeconomic impacts associated with the operation of a gas-fired power plant at the DAEC 

12 would be SMALL. 

13 8.2.6.3 Transportation 

14 Transportation impacts associated with construction and operation of a two unit gas-fired power 

15 plant would consist of commuting workers and truck deliveries of construction materials to the 

16 DAEC site. During construction, between 340 and 700 workers would be commuting to the site. 

17 In addition to commuting workers, trucks would transport construction materials and equipment 

18 to the worksite increasing the amount of traffic on local roads. The increase in vehicular traffic 

19 would peak during shift changes resulting in temporary levels of service impacts and delays at 

20 intersections. Some plant components are likely to be delivered by train via the existing onsite 

21 rail spur. Pipeline construction and modification to existing natural gas pipeline systems could 

22 also have an impact. 

23 During plant operations, transportation impacts would almost disappear. According to FPL-DA, 

24 approximately 19 workers would be needed to operate the gas-fired power plant. Because fuel 

25 for the plant is transported by pipeline, a new gas-fired plant would have to be supported by the 

26 current gas pipeline system. If the required capacity is not available, any upgrades to the current 

27 pipeline system could have additional transportation impacts on the Midwest region. 

28 The transportation infrastructure would experience little to no increased use from plant 

29 operations. Overall, the gas-fired alternative would have a SMALL impact on transportation 

30 conditions in the region around the DAEC. 

31 8.2.6.4 Aesthetics 

32 The aesthetics impact analysis focuses on the degree of contrast between the natural gas-fired 

33 alternative and the surrounding landscape and the visibility of the gas-fired plant. 

34 The two gas-fired units would be approximately 100 foot (30 m) tall, with an exhaust stack up to 

35 500 feet (152 m) and may be visible offsite in daylight hours. However, the gas-fired plant would 

36 be shorter than the current DAEC reactor building, which stands at 140 feet (43 m) with a 328–

37 foot (100-m) offgas stack. The mechanical draft towers would generate a condensate plume, but 

38 this would be no more noticeable than the existing DAEC plume. Depending on need, the coal39 fired alternative may only require the use of one cooling tower instead of the current two, thus 

40 minimizing the size of the condensate plume. Noise and light from plant operations, as well as 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-24 February 2010 

1 lighting on plant structures, may be detectable offsite. Pipelines delivering natural gas fuel could 

2 be audible offsite near gas compressors. 

3 In general, aesthetic changes would be limited to the immediate vicinity of the DAEC and would 

4 likely be less than the currently operating DAEC plant. Impacts would likely be SMALL. 

5 8.2.6.5 Historic and Archaeological Resources 

6 Cultural resources are the indications of human occupation and use of the landscape as defined 

7 and protected by a series of Federal laws, regulations, and guidelines. Prehistoric resources are 

8 physical remains of human activities that predate written records; they generally consist of 

9 artifacts that may alone or collectively yield information about the past. Historic resources 

10 consist of physical remains that postdate the emergence of written records; in the United States, 

11 they are architectural structures or districts, archaeological objects, and archaeological features 

12 dating from 1492 and later. Ordinarily, sites less than 50 years old are not considered historic, 

13 but exceptions can be made for such properties if they are of particular importance, such as 

14 structures associated with the development of nuclear power (e.g., Shippingport Atomic power 

15 Station) or Cold War themes. American Indian resources are sites, areas, and materials 

16 important to American Indians for religious or heritage reasons. Such resources may include 

17 geographic features, plants, animals, cemeteries, battlefields, trails, and environmental features. 

18 The cultural resource analysis encompassed the power plant site and adjacent areas that could 

19 potentially be disturbed by the construction and operation of alternative power plants. 

20 The potential for historic and archaeological resources can vary greatly depending on the 

21 location of the proposed site. To consider a project's effects on historic and archaeological 

22 resources, any proposed areas would need to be surveyed to identify and record historic and 

23 archaeological resources, identify cultural resources (e.g., traditional cultural properties), and 

24 develop possible mitigation measures to address any adverse effects from ground disturbing 

25 activities. Site specific studies and surveys would be needed for all areas of potential 

26 disturbance at the proposed plant site and along associated corridors where construction would 

27 occur (e.g., roads, transmission corridors, rail lines, or other ROWs). Areas with the greatest 

28 sensitivity should be avoided. 

29 The impact for a gas-fired alternative at the DAEC site would be MODERATE. As noted in 

30 Section 4.9.6, potential impacts to historic and archaeological resources could be minimized or 

31 avoided if DAEC develops procedures and a cultural resource management plan that effectively 

32 consider historic and archaeological resources. This plan would ensure that informed decisions 

33 are made prior to any ground disturbing activities onsite. Plant procedures would also include an 

34 inadvertent discovery (stop work) provision. Depending on the resource richness of area 

35 ultimately chosen for the natural gas-fired alternative, impacts could be MODERATE. 

36 8.2.6.6 Environmental Justice 

37 The environmental justice impact analysis evaluates the potential for disproportionately high and 

38 adverse human health and environmental effects on minority and low-income populations that 

39 could result from the construction and operation of a new natural gas-fired power plant. Adverse 

40 health effects are measured in terms of the risk and rate of fatal or nonfatal adverse impacts on 

41 human health. Disproportionately high and adverse human health effects occur when the risk or 
Environmental Impacts of Alternatives 

February 2010 8-25 Draft NUREG-1437, Supplement 42 

1 rate of exposure to an environmental hazard for a minority or low-income population is 

2 significant and exceeds the risk or exposure rate for the general population or for another 

3 appropriate comparison group. For socioeconomic data regarding the analysis of environmental 

4 justice issues, the reader is referred to subsection on Environmental Justice in Section 8.1.6. 

5 Based on the analysis of impacts for other resource areas, the construction and operation of a 

6 gas-fired alternative at the DAEC site may have adverse impacts on minority and low-income 

7 populations. However, minority and low-income populations in the area are relatively small and 

8 only a small number of workers are needed to construct and operate a natural gas-fired power 

9 plant and wind farm; impacts on these communities would not be disproportionate with that of 

10 the rest of the population within the 50-mile radius. Therefore, because there are no high or 

11 adverse impacts, by definition, there is also no disproportionate impact upon low income or 

12 minority populations. 

13 8.2.7 Waste Management 

14 During the construction phase of this alternative, land clearing and other construction activities 

15 would generate waste that can be recycled, disposed onsite or shipped to an offsite waste 

16 disposal facility. Because the alternative would be constructed on the previously disturbed 

17 DAEC site, the amounts of wastes produced during land clearing would be reduced. 

18 During the operational stage, spent SCR catalysts used to control NOx emissions from the 

19 natural gas-fired plants, would make up the majority of the waste generated by this alternative. 

20 This waste would be disposed of according to applicable Federal and state regulations. 

21 The Staff concluded in the GEIS (NRC, 1996), that a natural gas-fired plant would generate 

22 minimal waste and the waste impacts would be SMALL for a natural gas-fired alternative 

23 located at the DAEC site. 

24 8.3 COMBINATION ALTERNATIVE 

25 Consistent with a comment received from the public recommending that a wind-based energy 

26 alternative be investigated, the Staff has evaluated the environmental impacts of a combination 

27 of alternatives in this section. This combination would include a portion of the combined-cycle 

28 gas-fired capacity identified in 8.2, a conservation capacity component, and a wind power 

29 component. This alternative would require construction of a single gas-fired unit installed at the 

30 DAEC site and the construction of roughly 147 wind turbines (294-MWe nameplate capacity) at 

31 an offsite, or several different offsite locations.

32 In this alternative, a portion of DAEC’s output—100 MWe—would be replaced by conservation. 

33 Inclusion of this conservation component of the alternative is based on Iowa’s energy efficiency 

34 goals for the year 2013 (EPA, 2009b). Wind turbines constructed offsite would account for 

35 roughly 100 MWe of capacity (the 294 MWe of installed capacity would likely function at an 

36 average capacity factor of slightly greater than 30 percent, based on IDNR estimates) and 400 

37 MWe would come from one GE S107H combined cycle power plant (IDNR, 2003). 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-26 February 2010 

1 The only major construction the Staff anticipates would happen at the current DAEC site where 

2 the combined-cycle gas-fired power plant would be erected; Additionally, wind turbines would be 

3 constructed at an offsite location. No construction is necessary for the conservation portion. 

4 The appearance of the gas-fired facility would be similar to that of the full gas-fired alternative 

5 considered in 8.2, though a slightly larger, single unit would be constructed. The Staff estimates 

6 that this unit would require about 65 percent of the space necessary for the alternative 

7 considered in 8.2, and that all construction effects—as well as operational aesthetic, fuel-cycle, 

8 air quality, socioeconomic, land use, environmental justice, and water consumption effects—will 

9 scale accordingly.

10 Table 8-3. Summary of Environmental Impacts of the Combination Alternative Compared 

11 to Continued Operation of Duane Arnold Energy Center 

Combination Alternative Continued DAEC Operation 

Air Quality SMALL SMALL 

Groundwater SMALL SMALL 

Surface Water SMALL SMALL to MODERATE 

Aquatic and Terrestrial Resources SMALL to MODERATE SMALL 

Human Health SMALL SMALL 

Socioeconomics SMALL to LARGE SMALL to MODERATE 

Waste Management SMALL SMALL 

12 8.3.1 Air Quality 

13 Linn County, Iowa, where DAEC is located, is in EPA Region 7. All counties in the State of Iowa 

14 are in attainment for all criteria pollutants, except Muscatine County, which is a maintenance 

15 county for SO2. Iowa Department of Natural Resources (IDNR) is responsible for managing and 

16 monitoring air quality in the State of Iowa. 

17 This alternative is a combination of one 400-MW natural gas-fired combined-cycle generating 

18 unit, constructed onsite, 100 MW equivalent of conservation/demand-side management, and 

19 294 MW of wind capacity constructed offsite, possibly at several different locations. The 

20 alternative would be similar in air quality impacts to the gas-fired alternative considered in 8.2, 

21 but would emit lower levels of pollutants. The wind power and conservation portions would have 

22 little to no effect on air quality during operations, though construction of wind power installations 

23 and infrastructure may have short-term effects on air quality when site preparation or other 

24 construction activities generate fugitive dust. The wind option would also result in a net offset in 

25 air pollutant emissions that would otherwise be generated by the fossil-fuel alternative to 

26 compensate for the 294 MW of wind generated capacity. 

27 A new gas-fired generating plant on the DAEC site would qualify as a new major-emitting 

28 industrial facility and require a New Source Review (NSR) under Clean Air Act (CAA) and 

29 Section 567 of Iowa Administrative Code. The NSR program requires that a permit must be 
Environmental Impacts of Alternatives 

February 2010 8-27 Draft NUREG-1437, Supplement 42 

1 obtained before construction of the new major-emitting industrial facility (42 U.S.C. §7475(a)). 

2 The permit would be issued only if the new plant includes pollution control measures that reflect 

3 the best available control technology (BACT). The natural gas-fired unit would need to comply 

4 with the standards of performance for stationary gas turbines set forth in 40 CFR Part 60 

5 Subpart GG. 

6 40 CFR Part 51, Subpart P contains the visibility protection regulatory requirements, including 

7 the review of the new sources that would be constructed in attainment or unclassified areas and 

8 may affect visibility in any Federal Class I area (40 CFR Part 51, Subpart P, §51.307). If a 

9 gas-fired unit were located close to a mandatory Class I area, additional air pollution control 

10 requirements would apply. There are no mandatory Class I Federal areas in the State of Iowa 

11 and the closest mandatory Class I Federal area is Mingo Wilderness Area, which is located 365 

12 miles southeast from the DAEC in Missouri. 

13 The Staff projects the following emissions for the gas-fired portion of this alternative based on 

14 data published by the EIA, the EPA, and on performance characteristics for this alternative and 

15 its emissions controls: 

16 ● Sulfur oxides (SOx) – 31.33 tons (28.42 MT) per year 

17 ● Nitrogen oxides (NOx) (with SCR) – 100.44 tons (91.12 MT) per year 

18 ● Carbon monoxide (CO) – 20.88 tons (18.94 MT) per year 

19 ● Total suspended particles (TSP) – 17.51 tons (15.88 MT) per year 

20 ● Particulate matter (PM) PM10 – 17.51 tons (15.88 MT) per year 

21 ● Carbon dioxide (CO2) – 1,099,000 tons (997,000 MT) per year 

22 The natural gas-fired component of this alternative would produce 17.51 tons (15.88 MT) per 

23 year of TSP, all of which would be emitted as PM10. 

24 The EPA issued in December 2000 regulatory findings (EPA, 2000a) on emissions of hazardous 

25 air pollutants from electric utility steam-generating units, which identified that natural gas-fired 

26 plants emit hazardous air pollutants such as arsenic, formaldehyde and nickel and stated that 

27 . . . the impacts due to HAP emissions from natural gas-fired electric utility steam 

28 generating units were negligible based on the results of the study. The 

29 Administrator finds that regulation of HAP emissions from natural gas-fired 

30 electric utility steam generating units is not appropriate or necessary. 

31 The natural gas-fired plant would have to comply with Title IV of the CAA reduction 

32 requirements for SO2 and NOx, which are the main precursors of acid rain and major causes of 

33 reduced visibility. Title IV establishes maximum SO2 and NOx emission rate from the existing 

34 plants and a system of the SO2 emission allowances that can be used, sold or saved for future 

35 use by the new plants. 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-28 February 2010 

1 As stated above, the new natural gas-fired unit would produce 31.33 tons (28.42 MT) per year 

2 of SOx and 100.44 tons (91.12 MT) per year of NOx based on the use of the dry low NOx 

3 combustion technology and the use of dry, low-NOx burners and SCR in order to significantly 

4 reduce NOx emissions. 

5 The natural gas-fired component of this alternative would be subjected to the continuous 

6 monitoring requirements of SO2, NOx and CO2 specified in 40 CFR Part 75. The natural gas7 fired plant would emit approximately 1.1 million tons (approximately 1.0 million MT) per year of 

8 unregulated CO2 emissions. As of today, there is no required reporting of GHG emissions in 

9 Iowa. In response to the Consolidated Appropriations Act of 2008, the EPA has proposed a rule 

10 that requires mandatory reporting of GHG emissions from large sources, applicable to the 

11 presented alternative, in the United States that would allow collection of accurate and 

12 comprehensive emissions data to inform future policy decisions. The EPA proposes that 

13 suppliers of fossil fuels or industrial GHGs, manufacturers of vehicles and engines, and facilities 

14 that emit 25,000 MT or more per year of GHG emissions submit annual reports to the EPA 

15 (EPA, 2009c). The gases covered by the proposed rule are carbon dioxide (CO2), methane 

16 (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur 

17 hexafluoride (SF6), and other fluorinated gases including nitrogen trifluoride (NF3) and 

18 hydrofluorinated ethers (HFE). American Wind Energy Association data shows that Iowa takes 

19 second place in the nation with the greatest existing total wind power capacity. There would be 

20 no direct emissions from operating the wind component of the combination alternative. 

21 Activities associated with the construction of the new natural gas-fired plant at the DAEC site 

22 would cause some additional air effects as a result of equipment emissions and fugitive dust 

23 from operation of the earth-moving and material handling equipment. Workers’ vehicles and 

24 motorized construction equipment would generate temporary exhaust emissions. The 

25 construction crews would employ dust-control practices in order to control and reduce fugitive 

26 dust, which would be temporary in nature. The Staff concludes that the impact of vehicle 

27 exhaust emissions and fugitive dust from operation of the earth-moving and material handling 

28 equipment would be SMALL. 

29 The overall air-quality impacts of the combination alternative consisting of natural gas-fired plant 

30 located at DAEC site, energy conservation, and an offsite wind component would be SMALL. 

31 8.3.2 Groundwater Use and Quality 

32 If the onsite gas-fired plant continued to use groundwater for drinking water and service water, 

33 the total usage would likely be much less than DAEC uses, because many fewer workers are 

34 onsite, and because the gas-fired unit would have fewer auxiliary systems requiring service 

35 water. The current annual average withdrawal rate is 1,394 gpm, and pumping tests indicate 

36 this rate would not cause an effect on nearby supply wells. A reduction in this withdrawal rate 

37 means that impacts of the combination alternative would remain SMALL. 

38 8.3.3 Surface Water Use and Quality 

39 Using a combined alternative with conservation and wind power as major components would 

40 reduce the amount of surface water consumed for cooling purposes as compared to the 
Environmental Impacts of Alternatives 

February 2010 8-29 Draft NUREG-1437, Supplement 42 

1 proposed action and other alternatives considered in this section. The maximum consumptive 

2 use would be reduced from the amount of surface water consumed by the closed-cycle cooling 

3 system currently in use by DAEC. This represents less than 0.1 percent of the average annual 

4 flow rate in the Cedar River. The impact of this withdrawal would be SMALL. 

5 8.3.4 Aquatic and Terrestrial Ecology 

6 8.3.4.1 Aquatic Ecology 

7 The wind and conservation components would have no associated impingement, entrainment, 

8 and thermal impacts. The number of fish and other aquatic resource organisms affected by 

9 impingement, entrainment, and thermal impacts would be less than those associated with 

10 license renewal because water consumption and blowdown returned to the Cedar River would 

11 be substantially lower when compared to the gas-fired component or any of the other 

12 alternatives considered in this section. Some temporary impacts to aquatic organisms might 

13 occur due to any construction that might occur in the river or cause effluent to the river, although 

14 NRC assumes that the appropriate agencies would be monitor and regulate such activities. 

15 Although the number of affected organisms would be substantially less than for license renewal, 

16 the NRC level of impact for license renewal is already small, and so NRC expects that the levels 

17 of impact for impingement, entrainment, and thermal effects would also be SMALL. 

18 8.3.4.2 Terrestrial Ecology 

19 The gas-fired component of this alternative would incorporate existing disturbed land and 

20 possibly some farmland at DAEC for the natural gas unit. This alternative would also require 

21 land offsite for the gas pipeline, and would require much additional land offsite to accommodate 

22 the number of turbines necessary in a wind farm to offset the power generated by DAEC. 

23 This alternative would use the existing plant site land, switchyard, one of the two existing 

24 mechanical draft cooling towers, and transmission line system for construction of the gas-fired 

25 unit. Scaling from FPL-DA’s previous estimation of a slightly larger gas-fired plant, 

26 approximately 16 acres (6.6 ha) of land would be required on the DAEC site to support a 400 

27 MWe natural gas plant. 

28 Impacts to terrestrial ecology from onsite construction of this single gas-fired unit would be less 

29 than the impacts described for the two-unit gas-fired alternative. The impacts to farmland onsite 

30 would be approximately two-thirds of the impacts of the two-unit natural gas plant alternative. 

31 These onsite impacts are expected to be minor. Impacts to terrestrial ecology from offsite 

32 construction of the gas pipeline for a single gas-fired unit would be the same as for the two gas33 fired unit alternative previously discussed (FPL-DA 2008). 

34 Based upon data in the GEIS, the wind farm component of the combination alternative 

35 producing 294 MWe of electricity would require approximately 19,000 acres (7,600 ha) spread 

36 over several offsite locations, with approximately 74 acres (30 ha) in actual use. The remainder 

37 of the land would remain in agriculture. Additional land may be needed for construction of 

38 support infrastructure to connect to existing transmission lines. 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-30 February 2010 

1 Impacts to terrestrial ecology from construction of the wind farm portion of the combination 

2 alternative and any needed transmission lines could include loss of terrestrial habitat, an 

3 increase in habitat fragmentation and corresponding increase in edge habitat, and may impact 

4 threatened and endangered species. The GEIS notes that habitat fragmentation may lead to 

5 declines of migrant bird populations. Although bird mortality and disruptions to wildlife migratory 

6 routes could increase from construction of the wind farm, the GEIS notes that wind farms 

7 typically do not cause significant adverse impacts to bird populations (NRC, 1996). 

8 Based on this information, impacts to terrestrial resources would be MODERATE. 

9 8.3.5 Human Health 

10 The human health risks from a combination of alternatives include the already discussed 

11 combined cycle gas-fired plant. The GEIS (NRC, 1996) notes that the environmental impacts of 

12 conservation/demand-side management alternative are likely to be centered on indoor air 

13 quality. This is due to increased weatherization of homes in the form of extra insulation and 

14 reduced air turnover rates from the reduction in air leaks. However, the actual impact from the 

15 conservation alternative is highly site specific and not yet well-established. For wind capacity, 

16 the GEIS notes that, except for a potential small number of occupational injuries, human health 

17 would not be affected by routine operations. 

18 The human health risks from the combination of alternatives are uncertain, but considered to be 

19 SMALL given that the construction and operation of the facilities are expected to comply with 

20 health-based Federal and State safety and emission standards. 

21 8.3.6 Socioeconomics 

22 8.3.6.1 Land Use 

23 The analysis of land use impacts for the combination alternative focuses on the amount of land 

24 area that would be affected by the construction and operation of a single natural gas-fired unit at 

25 the DAEC and an offsite wind energy generating facility, and demand-side energy conservation. 

26 Land use impacts of an energy efficiency alternative would be SMALL. Quickly replacing and 

27 disposing of old equipment could generate waste material and potentially increase the size of 

28 landfills. However, given the time for program development and implementation, the cost of 

29 replacements, and the average life of equipment, the replacement process would probably be 

30 more gradual. Older equipment would likely be replaced by more efficient equipment as it fails 

31 (especially in the case of frequently replaced items, like light bulbs). In addition, many items (like 

32 home appliances or industrial equipment) have substantial recycling value and would likely not 

33 be disposed of in landfills. 

34 Based on FPL-DA estimates, approximately 16 acres (6.5 ha) would be needed to support the 

35 single natural gas-fired unit portion of the combination alternative. Land use impacts from 

36 construction of the natural gas-fired power plant at DAEC would be SMALL. 

37 In addition to onsite land requirements, land would be required offsite for natural gas wells and 

38 collection stations. Scaling from GEIS estimates, the natural gas-fired power plant at the DAEC 
Environmental Impacts of Alternatives 

February 2010 8-31 Draft NUREG-1437, Supplement 42 

1 could require 1,469 acres (594 ha) for wells, collection stations, and pipelines to bring the gas to 

2 the facility. Most of this land requirement would occur on land where gas extraction already 

3 occurs. In addition, some natural gas could come from outside of the United States and be 

4 delivered as liquefied gas. 

5 The wind farm component of the combination alternative producing 294 MWe of electricity 

6 capacity would require approximately 19,000 acres (7,600 ha) spread over several locations 

7 with approximately 74 acres (30 ha) in actual use. Most likely, the land used to site these 

8 turbines would be agricultural cropland that would be largely unaffected by having the wind 

9 turbines onsite. 

10 Although the offsite wind component of this alternative requires a large amount of land, only a 

11 small portion of that land would be in actual use. Also, the elimination of uranium fuel for the 

12 DAEC could partially offset offsite land requirements. Scaling from GEIS estimates, 

13 approximately 610 acres (247 ha) would not be needed for mining and processing uranium 

14 during the operating life of the plant. For these reasons, land use impacts from the combination 

15 alternative could range from SMALL to MODERATE. 

16 8.3.6.2 Socioeconomics 

17 As previously discussed, socioeconomic impacts are defined in terms of changes to the 

18 demographic and economic characteristics and social conditions of a region. For example, the 

19 number of jobs created by the construction and operation of a new single natural gas-fired 

20 power plant at the DAEC and wind farm could affect regional employment, income, and 

21 expenditures. Two types of jobs would be created: (1) construction-related jobs, which are 

22 transient, short in duration, and less likely to have a long-term socioeconomic impact; and (2) 

23 operation-related jobs in support of power generating operations, which have the greater 

24 potential for permanent, long-term socioeconomic impacts. The Staff conducted evaluations of 

25 construction and operations workforce requirements in order to measure their possible effect on 

26 current socioeconomic conditions. 

27 Based on GEIS projections and a workforce of 1,200 for a 1,000-MWe plant, a single 400 MWe 

28 unit at DAEC would require a peak estimated construction workforce of 490 workers. Additional 

29 estimated construction workforce requirements for this combination alternative would include 

30 300 construction workers for the wind farm. The number of additional workers would cause a 

31 short-term increase in the demand for services and temporary (rental) housing in the region 

32 around the construction site. 

33 After construction, some local communities may be temporarily affected by the loss of the 

34 construction jobs and associated loss in demand for business services. The rental housing 

35 market could also experience increased vacancies and decreased prices. The impact of 

36 construction on socioeconomic conditions would be SMALL. 

37 Following construction, a single unit gas-fired power plant at the DAEC could provide up to 13 

38 jobs, based on FPL-DA estimates. Additional estimated operations workforce requirements for 

39 this combination alternative would include 50 operations workers for the wind farm. Given the 

40 small numbers of operations workers at these facilities, socioeconomic impacts associated with 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-32 February 2010 

1 the operation of the natural gas-fired power plant at the DAEC and the wind farm would be 

2 SMALL. 

3 Socioeconomic effects of an energy efficiency program would be SMALL. As noted in the GEIS, 

4 the program would likely employ additional workers. Lower-income families could benefit from 

5 weatherization and insulation programs. This effect would be greater than the effect for the 

6 general population because low-income households experience home energy burdens more 

7 than four times larger than the average household (OMB, 2007). 

8 8.3.6.3 Transportation 

9 Transportation impacts would be SMALL, because the number of employees commuting to the 

10 DAEC site, where the gas-fired portion is located, would be small. Any transportation effects 

11 from the energy efficiency alternative would be widely distributed across the State, and would 

12 not be noticeable or would only be temporarily noticeable when large wind turbine components 

13 are transported to the turbine sites. 

14 Construction and operation of a natural gas-fired power plant and wind farm would increase the 

15 number of vehicles on roads in the vicinity of these facilities. During construction, cars and 

16 trucks would deliver workers, materials, and equipment to the worksites. The increase in 

17 vehicular traffic would peak during shift changes resulting in temporary levels of service impacts 

18 and delays at intersections. Pipeline construction and modification to existing natural gas 

19 pipeline systems could also have an impact. Highway delivery of large wind farm components 

20 may also cause impacts to traffic. 

21 During plant operations, transportation impacts would almost disappear. Given the small 

22 numbers of operational workers at these facilities, levels of service impacts on local roads from 

23 the operation of the natural gas-fired power plant at the DAEC as well as the wind farm would 

24 be SMALL. Transportation impacts at the wind farm site or sites would also depend on current 

25 road capacities and average daily traffic volumes, but are likely to be small given the low 

26 number of workers employed by that component of the alternative. 

27 8.3.6.4 Aesthetics 

28 Aesthetic impact analysis focuses on the degree of contrast between the power plant and the 

29 surrounding landscape and the visibility of the power plant. 

30 A single natural gas-fired unit located at the DAEC could be approximately 100 feet (30 m) tall, 

31 with an exhaust stack up to 175 feet (53 m) tall. This is likely to be less noticeable than the 

32 current DAEC reactor building at 140 feet (42 m) with a 328-foot (100-m) offgas stack. The 

33 impact would be moderated as higher elevations and vegetation along the river valley could 

34 make it difficult to see or hear the power plant outside of the river valley. Power plant 

35 infrastructure would generally be smaller and less noticeable than the DAEC containment and 

36 turbine buildings. Noise during power plant operations would be limited to industrial processes 

37 and communications. In addition to the power plant structures, construction of natural gas 

38 pipelines would have a short-term impact. Noise from the pipelines could be audible offsite near 

39 compressors. 
Environmental Impacts of Alternatives 

February 2010 8-33 Draft NUREG-1437, Supplement 42 

1 In general, aesthetic changes would be limited to the immediate vicinity of the DAEC and the 

2 wind farm facilities. The wind farm would have the greatest aesthetic effect. The 147 wind 

3 turbines at over 300 feet (100 m) tall and spread across multiple sites covering 19,000 acres 

4 (7,600 ha) may, in some locations, dominate the view and be a major focus of viewer attention. 

5 However, the overall impact would depend on the sensitivity of the site. Therefore, overall 

6 aesthetic impacts from the construction and operation of combination alternative would be 

7 SMALL to LARGE. 

8 Impacts from energy efficiency programs would be SMALL. Some noise impacts could occur in 

9 instances of energy efficiency upgrades to major building systems, though this impact would be 

10 intermittent and short-lived. 

11 8.3.6.5 Historic and Archaeological Resources 

12 Cultural resources are the indications of human occupation and use of the landscape as defined 

13 and protected by a series of Federal laws, regulations, and guidelines. Prehistoric resources are 

14 physical remains of human activities that predate written records; they generally consist of 

15 artifacts that may alone or collectively yield information about the past. Historic resources 

16 consist of physical remains that postdate the emergence of written records; in the United States, 

17 they are architectural structures or districts, archaeological objects, and archaeological features 

18 dating from 1492 and later. Ordinarily, sites less than 50 years old are not considered historic, 

19 but exceptions can be made for such properties if they are of particular importance, such as 

20 structures associated with the development of nuclear power (e.g., Shippingport Atomic power 

21 Station) or Cold War themes. American Indian resources are sites, areas, and materials 

22 important to American Indians for religious or heritage reasons. Such resources may include 

23 geographic features, plants, animals, cemeteries, battlefields, trails, and environmental features. 

24 The cultural resource analysis encompassed the power plant site and adjacent areas that could 

25 potentially be disturbed by the construction and operation of alternative power plants. 

26 The analysis of land use impacts for combination alternative focuses on the amount of land that 

27 would be affected by the construction and operation of a new natural gas-fired power plant at 

28 the DAEC site, an offsite wind farm, and a conservation energy component. The impact of 

29 constructing and operating a combination alternative at the DAEC site would be MODERATE, 

30 As noted in Section 4.9.6, potential impacts to historic and archaeological resources could be 

31 minimized or avoided if DAEC develops procedures and a cultural resource management plan 

32 that effectively consider historic and archaeological resources. This plan would ensure that 

33 informed decisions are made prior to any ground disturbing activities onsite. Plant procedures 

34 would also include an inadvertent discovery (stop work) provision. As discussed in Section 

35 8.2.6, depending on the resource richness of the area selected for onsite development the 

36 impact would be MODERATE. 

37 The wind farm component of the combination alternative would require approximately 19,000 ac 

38 (7,600 ha) spread over several locations with approximately 74 ac (30 ha) in actual use. Lands 

39 not previously surveyed should be investigated by a qualified archaeologist prior to any ground 

40 disturbing activity. Depending on the location of the wind farm, the visual impacts would also 

41 need to be assessed. The 147 wind turbines at over 300 ft (100 m) tall and spread across 

42 multiple sites covering 19,000 ac (7,600 ha) may, in some locations, dominate the view and 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-34 February 2010 

1 could present historic viewshed impacts. Depending on the resource richness of the alternative 

2 site ultimately chosen for the wind power alternative, the impacts could range between SMALL 

3 to MODERATE. 

4 Impacts to historic and archaeological resources from implementing the energy efficiency 

5 programs would be SMALL. A conservation alternative would not affect land use or historical or 

6 cultural resources onsite or elsewhere in the State. 

7 8.3.6.6 Environmental Justice 

8 The environmental justice impact analysis evaluates the potential for disproportionately high and 

9 adverse human health and environmental effects on minority and low-income populations that 

10 could result from the construction and operation of a new natural gas-fired power plant and wind 

11 farm. Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal 

12 adverse impacts on human health. Disproportionately high and adverse human health effects 

13 occur when the risk or rate of exposure to an environmental hazard for a minority or low-income 

14 population is significant and exceeds the risk or exposure rate for the general population or for 

15 another appropriate comparison group. For socioeconomic data regarding the analysis of 

16 environmental justice issues, the reader is referred to subsection on Environmental Justice in 

17 Section 8.1.6. 

18 Weatherization programs could target low-income residents as a cost-effective energy efficiency 

19 option since low-income populations tend to spend a larger proportion of their incomes paying 

20 utility bills (according to the Office of Management and Budget, low income populations 

21 experience energy burdens more than four times as large as those of average households 

22 [OMB, 2007]). Impacts to minority and low-income populations from energy efficiency programs 

23 would be nominal, depending on program design and enrollment. 

24 Based on the analysis of impacts for other resource areas, the construction and operation of the 

25 gas-fired component at the DAEC site and the offsite wind component may have adverse 

26 impacts on minority and low-income populations, somewhat depending on the location of the 

27 wind component. Minority and low-income populations in the area are relatively small and only a 

28 small number of workers are needed to construct and operate a natural gas-fired power plant 

29 and wind farm; impacts on these communities would not be disproportionate with that of the rest 

30 of the population within the 50-mile radius. Therefore, because there are no high or adverse 

31 impacts, by definition there is also no disproportionate impact upon low income or minority 

32 populations. 

33 8.3.7 Waste Management 

34 During the construction stage of this alternative, land clearing and other construction activities 

35 would generate waste that can be recycled, disposed onsite or shipped to the offsite waste 

36 disposal facility. During operational stage, spent SCR catalysts, which are used to control NOx 

37 emissions from the natural gas-fired plants, would make up the majority of the waste generated 

38 by this alternative. 

39 There would be an increase in wastes generated during installation or implementation of 

40 conservation measures, such as appropriate disposal of old appliances, installation of control 
Environmental Impacts of Alternatives 

February 2010 8-35 Draft NUREG-1437, Supplement 42 

1 devices and building modifications. New and existing recycling programs would help to minimize 

2 the amount of generated waste. 

3 The Staff concludes that overall waste impacts from the combination of the natural gas-fired unit 

4 constructed onsite, wind capacity, and conservation are SMALL. 

5 8.4 ALTERNATIVES CONSIDERED BUT DISMISSED 

6 In this section, the Staff presents the alternatives it initially considered for analysis as 

7 alternatives to license renewal of DAEC, but later dismissed due to technical, resource 

8 availability, or commercial limitations that currently exist and that the Staff believes are likely to 

9 continue to exist when the existing DAEC license expires. Under each of the following 

10 technology headings, the Staff indicates why it dismissed each alternative from further 

11 consideration. 

12 8.4.1 Offsite Coal- and Gas-Fired Capacity 

13 While it is possible that coal- and gas-fired alternatives like those considered in 8.1 and 8.2, 

14 respectively, could be constructed at sites other than DAEC, the Staff determined that they 

15 would likely result in greater impacts than alternatives constructed at the DAEC site. Greater 

16 impacts would occur from construction of support infrastructure, like transmission lines, roads, 

17 and railway spurs that are already present on the DAEC site. Further, the community around 

18 DAEC is already familiar with the appearance of a power facility and it is an established part of 

19 the region’s aesthetic character. Workers skilled in power plant operations would also be 

20 available in this area. The availability of these factors are only likely to be available on other 

21 recently-industrial sites. In cases where recently-industrial sites exist, other remediation may 

22 also be necessary in order to ready the site for redevelopment. In short, an existing power plant 

23 site would present the best location for a new power facility. 

24 8.4.2 Coal-Fired Integrated Gasification Combined-Cycle 

25 While utilities across the United States have considered or are considering plans for integrated 

26 gasification combined-cycle (IGCC) coal-fired power plants, few IGCC facilities have yet been 

27 constructed. All facilities constructed in the United States to date have been smaller than DAEC, 

28 though Duke Energy’s proposed Edwardsport IGCC would be similar in size (Duke Energy, 

29 2008). The technology, however, is commercially available and essentially relies on a gasifier 

30 stage and a combined-cycle turbine stage. Existing combined-cycle gas turbines (like the ones 

31 considered in Section 8.2) could be used as a part of an IGCC alternative. Emissions would 

32 likely be slightly greater than those from the gas-fired alternative, but significantly lower than 

33 those from the coal-fired alternative. In addition, an IGCC alternative would require slightly less 

34 onsite space than the coal-fired alternative in 8.1 and operate at a higher thermal efficiency. 

35 Depending on gasification technology employed, it would likely use a similar quantity of water. 

36 EIA indicates that IGCC and other advanced coal plants may become increasingly common in 

37 coming years, though uncertainties about construction time periods and commercial viability in 

38 the near future leads Staff to believe that IGCC is an unlikely alternative to DAEC license 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-36 February 2010 

1 renewal (EIA, 2009a). For plants whose licenses expire at later dates, IGCC (with or without 

2 carbon capture and storage) may prove to be a viable alternative. 

3 8.4.3 New Nuclear 

4 In its ER, FPL-DA indicated that it is unlikely that a nuclear alternative could be sited, 

5 constructed and operational by the time DAEC operating license expires in February of 2014 

6 (FPL-DA, 2008). Sources in the nuclear industry have recently indicated that reactor projects 

7 currently under development are likely eight or nine years from completion (Nucleonics Week, 

8 2008), or possibly online in the 2016-2017 timeframe. A potential plant would also require 

9 additional time to develop an application. Given the relatively short time remaining on the 

10 current DAEC operating license, the Staff has not evaluated new nuclear generation as an 

11 alternative to license renewal. 

12 8.4.4 Energy Conservation/Energy Efficiency 

13 Though often used interchangeably, energy conservation and energy efficiency are different 

14 concepts. Energy efficiency typically means deriving a similar level of services by using less 

15 energy, while energy conservation simply indicates a reduction in energy consumption. Both fall 

16 into a larger category known as demand-side management (DSM). DSM measures—unlike the 

17 energy supply alternatives discussed in previous sections—address energy end uses. DSM can 

18 include measures that shift energy consumption to different times of the day to reduce peak 

19 loads, measures that can interrupt certain large customers during periods of high demand or 

20 measures than interrupt certain appliances during high demand periods, and measures like 

21 replacing older, less efficient appliances, lighting, or control systems. DSM also includes 

22 measures that utilities use to boost sales, such as encouraging customers to switch from gas to 

23 electricity for water heating. 

24 Unlike other alternatives to license renewal, the GEIS notes that conservation is not a discrete 

25 power generating source; it represents an option that states and utilities may use to reduce their 

26 need for power generation capability (NRC, 1996). 

27 In February of 2008, a “green government” initiative was established in the State of Iowa, 

28 creating a task force tasked with the goal of reducing electricity use in office buildings by at least 

29 15 percent by 2013. In addition, in May of 2008 S.F. 2386 was signed into effect by the 

30 governor which requires Iowa consumer-owned electric utilities to establish efficiency goals, 

31 setting an annual goal of a 1.5 percent improvement in demand-side energy efficiency (EPA, 

32 2009d). On November 15, 2007, Iowa signed the Midwestern Regional Greenhouse Gas 

33 Reduction Accord, committing to an overall 2 percent reduction in energy use by 2015. If this 

34 goal was to be realized, however, conservation would still not be enough to replace the capacity 

35 of DAEC. Also, because these goals are considered optional (the utilities are only required to 

36 report back on their progress), it is unlikely that increased energy efficiency in the State of Iowa 

37 would have grown enough to offset the loss of DAEC by the license expiration in 2014. Because 

38 of this, the Staff has not evaluated energy conservation/efficiency as a discrete alternative to 

39 license renewal. It has, however, been considered as a component of the combination 

40 alternative. 
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February 2010 8-37 Draft NUREG-1437, Supplement 42 

1 8.4.5 Purchased Power 

2 In its ER, FPL-DA indicated that purchased electrical power is not an economical alternative to 

3 DAEC license renewal. The Staff recognizes the potential for purchased power to offset a 

4 portion of the electricity generated by DAEC, however, for the 2014 to 2034 time frame of DAEC 

5 renewal, FPL-DA indicated that there are no guaranteed available power sources to replace the 

6 610 MWe that DAEC provides (FPL-DA, 2008). Because of the lack of assured available 

7 purchased electrical power, the Staff has not evaluated purchased power as an alternative to 

8 license renewal. 

9 8.4.6 Solar Power 

10 Solar technologies use the sun’s energy to produce electricity. Currently, the DAEC site 

11 receives approximately 3.5 to 4.5 kilowatt hour (kWh) per square meter per day, for solar 

12 collectors oriented at an angle equal to the installation’s latitude (NREL, 2008). Since flat-plate 

13 photovoltaics tend to be roughly 25 percent efficient, a solar-powered alternative would require 

14 at least 23,000 acres (9,300 ha) of collectors to provide an amount of electricity equivalent to 

15 that generated by DAEC. Space between parcels and associated infrastructure increase this 

16 land requirement. This amount of land, while large, is consistent with the land required for coal 

17 and natural gas fuel cycles. In the GEIS, the Staff noted that, by its nature, solar power is 

18 intermittent (i.e., it does not work at night and cannot serve baseload when the sun is not 

19 shining), and the efficiency of collectors varies greatly with weather conditions. A solar-powered 

20 alternative would require energy storage or backup power supply to provide electric power at 

21 night. Given the challenges in meeting baseload requirements, the Staff did not evaluate solar 

22 power as an alternative to license renewal of DAEC. 

23 8.4.7 Wood Waste 

24 In 1999, DOE researchers estimated that Iowa has biomass fuel resources consisting of forest, 

25 mill, agricultural, and urban residues, as well as energy crop potential. Excluding potential 

26 energy crops, DOE researchers projected that Iowa had 24,490,500 tons (22,217,800 MT) of 

27 plant-based biomass available at $50 per ton delivered (Walsh et al., 2000; costs are in 1995 

28 dollars). The Bioenergy Feedstock Development Program at Oak Ridge National Laboratory 

29 estimated that each air-dry pound of wood residue produces approximately 6,400 Btu of heat 

30 (ORNL, 2007). Assuming a 33 percent conversion efficiency, using all biomass available in 

31 Nebraska at $50 per ton—the maximum price the researchers considered—would generate 

32 roughly 30.3 terawatt hours of electricity. 

33 Walsh et al. (2000), go on to note that these estimates of biomass capacity contain substantial 

34 uncertainty, and that potential availability does not mean biomass would actually be available at 

35 the prices indicated or that resources would be usably free of contamination. Some of these 

36 plant wastes already have reuse value, and would likely be more costly to deliver because of 

37 competition. Others, such as forest residues, may prove unsafe and unsustainable to harvest on 

38 a regular basis (the majority of biomass capacity in Iowa, however, comes from agricultural 

39 residues, with very little potential from forest residues). As a result, the available resource 

40 potential is likely less than the estimates totals in Walsh et al., and the total resource is not likely 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-38 February 2010 

1 to be sufficient to substitute for the capacity provided by DAEC. As a result, the Staff has not 

2 considered a wood-fired alternative to DAEC license renewal. 

3 8.4.8 Hydroelectric Power 

4 According to researchers at Idaho National Energy and Environmental Laboratory, Iowa has an 

5 estimated 455 MW of technically available, undeveloped hydroelectric resources at 79 sites 

6 throughout the State (INEEL, 1997). Most of these sites have a potential capacity of less than 1 

7 MWe, though the largest undeveloped site in Iowa is in the Iowa River Basin, which has 99 MW 

8 of potential. Given that the available hydroelectric potential in the State of Iowa constitutes less 

9 than the generating capacity of DAEC, the Staff did not evaluate hydropower as an alternative 

10 to license renewal. 

11 8.4.9 Wave and Ocean Energy 

12 Wave and ocean energy has generated considerable interest in recent years. Ocean waves, 

13 currents, and tides are often predictable and reliable. Ocean currents flow consistently, while 

14 tides can be predicted months and years in advance with well-known behavior in most coastal 

15 areas. Most of these technologies are in relatively early stages of development, and while some 

16 results have been promising, they are not likely to be able to replace the capacity of DAEC by 

17 the time its license expires. Testing of new technologies to produce electricity from the ocean 

18 continues. However, because the DAEC site is not located near an ocean, the NRC did not 

19 consider wave and ocean energy as an alternative to DAEC license renewal. 

20 8.4.10 Geothermal Power 

21 Geothermal energy has an average capacity factor of 90 percent and can be used for baseload 

22 power where available. However, geothermal electric generation is limited by the geographical 

23 availability of geothermal resources (NRC, 1996). Although Iowa has some geothermal potential 

24 in a heating capacity, it does not have geothermal electricity potential for electricity generation 

25 (DOE, 2007). The Staff concluded that geothermal energy is not a reasonable alternative to 

26 license renewal at DAEC. 

27 8.4.11 Municipal Solid Waste 

28 Municipal solid waste combustors use three types of technologies—mass burn, modular, and 

29 refuse-derived fuel. Mass burning is currently the method used most frequently in the United 

30 States and involves no (or little) sorting, shredding, or separation. Consequently, toxic or 

31 hazardous components present in the waste stream are combusted, and toxic constituents are 

32 exhausted to the air or become part of the resulting solid wastes. Currently, approximately 89 

33 waste-to-energy plants operate in the United States. These plants generate approximately 

34 2,700 MWe, or an average of 30 MWe per plant (Integrated Waste Services Association, 2007). 

35 More than 27 average-sized plants would be necessary to provide the same level of output as 

36 the other alternatives to DAEC license renewal. 

37 Estimates in the GEIS suggest that the overall level of construction impact from a waste-fired 

38 plant would be approximately the same as that for a coal-fired power plant. Additionally, waste39 fired plants have the same or greater operational impacts than coal-fired technologies (including 
Environmental Impacts of Alternatives 

February 2010 8-39 Draft NUREG-1437, Supplement 42 

1 impacts on the aquatic environment, air, and waste disposal). The initial capital costs for 

2 municipal solid-waste plants are greater than for comparable steam-turbine technology at coal3 fired facilities or at wood-waste facilities because of the need for specialized waste separation 

4 and handling equipment (NRC, 1996). 

5 The decision to burn municipal waste to generate energy is usually driven by the need for an 

6 alternative to landfills rather than energy considerations. The use of landfills as a waste disposal 

7 option is likely to increase in the near term as energy prices increase; however, it is possible 

8 that municipal waste combustion facilities may become attractive again. 

9 Given the small average installed size of municipal solid waste plants and the unfavorable 

10 regulatory environment, the Staff does not consider municipal solid waste combustion to be a 

11 feasible alternative to DAEC license renewal. 

12 8.4.12 Biofuels 

13 In addition to wood and municipal solid waste fuels, there are other concepts for biomass-fired 

14 electric generators, including direct burning of energy crops, conversion to liquid biofuels, and 

15 biomass gasification. In the GEIS, the Staff indicated that none of these technologies had 

16 progressed to the point of being competitive on a large scale or of being reliable enough to 

17 replace a baseload plant such as DAEC. After reevaluating current technologies, the Staff finds 

18 other biomass-fired alternatives are still unable to reliably replace the DAEC capacity. For this 

19 reason, the Staff does not consider other biomass-derived fuels to be feasible alternatives to 

20 DAEC license renewal. 

21 8.4.13 Oil-Fired Power 

22 EIA projects that oil-fired plants would account for very little of the new generation capacity 

23 constructed in the United States during the 2008 to 2030 time period. Further, EIA does not 

24 project that oil-fired power would account for any significant additions to capacity (EIA, 2009b). 

25 The variable costs of oil-fired generation tend to be greater than those of the nuclear or coal26 fired operations, and oil-fired generation tends to have greater environmental impacts than 

27 natural gas-fired generation. In addition, future increases in oil prices are expected to make oil28 fired generation increasingly more expensive (EIA, 2009b). The high cost of oil has prompted a 

29 steady decline in its use for electricity generation. Thus, the Staff did not consider oil-fired 

30 generation as an alternative to DAEC license renewal. 

31 8.4.14 Fuel Cells 

32 Fuel cells oxidize fuels without combustion and its environmental side effects. Power is 

33 produced electrochemically by passing a hydrogen-rich fuel over an anode and air (or oxygen) 

34 over a cathode and separating the two by an electrolyte. The only byproducts (depending on 

35 fuel characteristics) are heat, water, and CO2. Hydrogen fuel can come from a variety of 

36 hydrocarbon resources by subjecting them to steam under pressure. Natural gas is typically 

37 used as the source of hydrogen. 
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Draft NUREG-1437, Supplement 42 8-40 February 2010 

1 At the present time, fuel cells are not economically or technologically competitive with other 

2 alternatives for electricity generation. EIA projects that fuel cells may cost $5,374 per installed 

3 kW (total overnight costs) (EIA, 2009b), or 3.5 times the construction cost of new coal-fired 

4 capacity and 7.5 times the cost of new, advanced gas-fired, combined-cycle capacity. In 

5 addition, fuel cell units are likely to be small in size (the EIA reference plant is 10 MWe). While it 

6 may be possible to use a distributed array of fuel cells to provide an alternative to DAEC, it 

7 would be extremely costly to do so and would require many units. Accordingly, the Staff does 

8 not consider fuel cells to be an alternative to DAEC license renewal. 

9 8.4.15 Delayed Retirement 

10 FPL-DA indicated in the ER that it has no knowledge of any retired plants or any plans to retire 

11 plants in the State of Iowa prior to 2014 (FPL-DA, 2008). As a result, delayed retirement is not a 

12 feasible alternative to license renewal. Other generation capacity may be retired prior to the 

13 expiration of the DAEC license, but this capacity is likely to be older, less efficient, and without 

14 modern emissions controls. 

15 8.5 NO-ACTION ALTERNATIVE 

16 This section examines environmental effects that would occur if NRC takes no action. No action 

17 in this case means that NRC does not issue a renewed operating license for DAEC and the 

18 license expires at the end of the current license term, in February 2014. If NRC takes no action, 

19 the plant would shutdown at or before the end of the current license. After shutdown, plant 

20 operators would initiate decommissioning according to 10 CFR 50.82. Table 8-4 provides a 

21 summary of environmental impacts of No Action compared to continued operation of the DAEC.

22 The Staff notes that the option of no-action is the only alternative considered in-depth that does 

23 not satisfy the purpose and need for this SEIS, as it does not provide power generation capacity 

24 nor would it meet the needs currently met by DAEC or that the alternatives evaluated in sections 

25 8.1 through 8.3 would satisfy. Assuming that a need currently exists for the power generated by 

26 DAEC, the no-action alternative would require that the appropriate energy planning decision27 makers rely on an alternative to replace the capacity of DAEC or reduce the need for power. 

28 This section addresses only those impacts that arise directly as a result of plant shutdown. The 

29 environmental impacts from decommissioning and related activities have already been 

30 addressed in several other documents, including the Final Generic Environmental Impact 

31 Statement on Decommissioning of Nuclear Facilities, NUREG-0586, Supplement 1 (NRC, 

32 2002); the license renewal GEIS (chapter 7; NRC, 1996); and Chapter 7 of this SEIS. These 

33 analyses either directly address or bound the environmental impacts of decommissioning 

34 whenever FPL-DA ceases operating DAEC. 

35 The Staff notes that, even with a renewed operating license, DAEC would eventually shut down, 

36 and the environmental effects addressed in this section would occur at that time. Since these 

37 effects have not otherwise been addressed in this SEIS, the impacts will be addressed in this 

38 section. As with decommissioning effects, shutdown effects are expected to be similar whether 

39 they occur at the end of the current license or at the end of a renewed license. 
Environmental Impacts of Alternatives 

February 2010 8-41 Draft NUREG-1437, Supplement 42 

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

2 Operation of Duane Arnold Energy Center

No Action Continued DAEC Operation 

Air Quality SMALL SMALL 

Groundwater SMALL SMALL 

Surface Water SMALL SMALL to MODERATE 

Aquatic and Terrestrial Resources SMALL SMALL 

Human Health SMALL SMALL 

Socioeconomics SMALL to MODERATE SMALL to MODERATE 

Waste Management SMALL SMALL 

3 8.5.1 Air Quality 

4 When the plant stops operating, there would be a reduction in emissions from activities related 

5 to plant operation such as use of diesel generators and employees vehicles. In Chapter 4, the 

6 Staff determined that these emissions would have a SMALL impact on air quality during the 

7 renewal term. Therefore, if the emissions decrease, the impact to air quality would also 

8 decrease and would be SMALL. 

9 8.5.2 Groundwater Use and Quality 

10 The use of groundwater would diminish as plant personnel are removed from the site and 

11 operations cease. Some consumption of groundwater may continue as a small staff remains 

12 onsite to maintain facilities prior to decommissioning. Overall impacts would be smaller than 

13 during operations, but would remain SMALL. 

14 8.5.3 Surface Water Use and Quality 

15 The rate of consumptive use of surface water would decrease as the plant is shut down and the 

16 reactor cooling system continues to remove the heat of decay. Wastewater discharges would 

17 also be reduced considerably. Shutdown would reduce the already SMALL impact on surface 

18 water resources and quality. 

19 8.5.4 Aquatic and Terrestrial Resources 

20 8.5.4.1 Aquatic Ecology 

21 If the plant were to cease operating, impacts to aquatic ecology would decrease, as the plant 

22 would withdraw and discharge less water than it does during operations. Shutdown would 

23 reduce the already SMALL impacts to aquatic ecology. 

24 8.5.4.2 Terrestrial Ecology 

25 Terrestrial ecology impacts would be SMALL. No additional land disturbances on or offsite 

26 would occur. 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-42 February 2010 

1 8.5.5 Human Health 

2 Human health risks would be smaller following plant shutdown. The plant, which is currently 

3 operating within regulatory limits, would emit less gaseous and liquid radioactive material to the 

4 environment. In addition, following shutdown, the variety of potential accidents at the plant 

5 (radiological or industrial) would be reduced to a limited set associated with shutdown events 

6 and fuel handling and storage. In Chapter 4 of this draft supplemental EIS, the Staff concluded 

7 that the impacts of continued plant operation on human health would be SMALL. In Chapter 5, 

8 the Staff concluded that the impacts of accidents during operation were SMALL. Therefore, as 

9 radioactive emissions to the environment decrease, and as the likelihood and variety of 

10 accidents decrease following shutdown, the Staff concludes that the risks to human health 

11 following plant shutdown would be SMALL. 

12 8.5.6 Socioeconomics 

13 8.5.6.1 Land Use 

14 Plant shutdown would not affect onsite land use. Plant structures and other facilities would 

15 remain in place until decommissioning. Most transmission lines connected to DAEC would 

16 remain in service after the plant stops operating. Maintenance of most existing transmission 

17 lines would continue as before. Impacts on land use from plant shutdown would be SMALL. 

18 8.5.6.2 Socioeconomics 

19 Plant shutdown would have an impact on socioeconomic conditions in the region around DAEC. 

20 Plant shutdown would eliminate approximately 669 jobs and would reduce tax revenue in the 

21 region. The loss of these contributions, which may not entirely cease until after 

22 decommissioning, would have a MODERATE impact. See Appendix J to NUREG-0586, 

23 Supplement 1 (NRC, 2002), for additional discussion of the potential socioeconomic impacts of 

24 plant decommissioning. 

25 8.5.6.3 Transportation 

26 Traffic volumes on the roads in the vicinity of DAEC would be reduced after plant shutdown. 

27 Most of the reduction in traffic volume would be associated with the loss of jobs at the plant. 

28 Deliveries of materials and equipment to the plant would be reduced until decommissioning. 

29 Transportation impacts would be SMALL as a result of plant shutdown. 

30 8.5.6.4 Aesthetics 

31 Plant structures and other facilities would remain in place until decommissioning. Noise caused 

32 by plant operation would cease. Aesthetic impacts of plant closure would be SMALL. 

33 8.5.6.5 Historic and Archaeological Resources 

34 Impacts from the no-action alternative would be SMALL, since DAEC would be 

35 decommissioned. A separate environmental review would be conducted for decommissioning. 

36 That assessment would address the protection of historic and archaeological resources. 

37 8.5.6.6 Environmental Justice 
Environmental Impacts of Alternatives 

February 2010 8-43 Draft NUREG-1437, Supplement 42 

1 Termination of power plant operations would not disproportionately affect minority and low2 income populations outside of the immediate vicinity of DAEC. Impacts to all other resource 

3 areas would be SMALL to MODERATE. For socioeconomic data regarding the analysis of 

4 environmental justice issues, the reader is referred to subsection on Environmental Justice in 

5 Section 8.1.6. Minority and low-income populations in the area are relatively small and only a 

6 small number of workers are needed to construct and operate a natural gas-fired power plant 

7 and wind farm; impacts on these communities would not be disproportionate with that of the rest 

8 of the population within the 50-mile radius. Therefore, because there are no high or adverse 

9 impacts, by definition, there is also no disproportionate impact upon low income or minority 

10 populations. See Appendix J of NUREG-0586, Supplement 1 (NRC, 2002), for additional 

11 discussion of these impacts. 

12 8.5.7 Waste Management 

13 If the no-action alternative were implemented the generation of high-level waste would stop and 

14 generation of low-level and mixed waste would decrease. Impacts from implementation of no15 action alternative are expected to be SMALL. 

16 8.6 ALTERNATIVES SUMMARY 

17 In this chapter, the Staff considered the following alternatives to DAEC license renewal: 

18 supercritical coal-fired generation; natural gas combined-cycle generation; and a combination 

19 alternative. No action by the NRC and the effects it would have were also considered. The 

20 impacts for all alternatives are summarized in Table 8-5 on the following page. 

21 Socioeconomic and groundwater impacts could range from SMALL to MODERATE. The Staff 

22 did not determine a single significance level for these impacts, but the Commission determined 

23 them to be Category 1 issues nonetheless. The environmental impacts of the proposed action 

24 (issuing a renewed DAEC operating license) would be SMALL for all other impact categories, 

25 except for the Category 1 issue of collective offsite radiological impacts from the fuel cycle, high 

26 level waste (HLW), and spent fuel disposal. 

27 In the Staff’s professional opinion, the coal-fired alternative would have the greatest over all 

28 adverse environmental impact. This alternative would result in MODERATE waste 

29 management, land use, and air quality impacts. Its impacts upon socioeconomic and biological 

30 resources could range from SMALL to MODERATE. This alternative is not an environmentally 

31 preferable alternative due to air quality impacts from nitrogen oxides, sulfur oxides, particulate 

32 matter, PAHs, carbon monoxide, carbon dioxide, and mercury (and the corresponding human 

33 health impacts), as well as construction impacts to aquatic, terrestrial, and potential historic and 

34 archaeological resources. 

35 With the exception of land use, socioeconomic, and air quality impacts, the gas-fired alternative 

36 would result in SMALL impacts. Socioeconomic, land use, and air quality impacts could range 

37 from SMALL to MODERATE. This alternative would result in substantially lower air emissions, 

38 and waste management than the coal-fired alternative. 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-44 February 2010 

1 The combination alternative would have lower air emissions and waste management impacts 

2 than both the gas-fired and coal-fired alternatives, however it would have relatively higher 

3 construction impacts in terms of land use, aquatic and terrestrial resources, and potential 

4 disruption to historic and archaeological resources, mainly as a result of the wind turbine 

5 component. 

6 Under the no-action alternative, plant shutdown would eliminate approximately 669 jobs and 

7 would reduce tax revenue in the region. The loss of these contributions, which may not entirely 

8 cease until after decommissioning, would have a SMALL to MODERATE impact. However, the 

9 no-action alternative does not meet the purpose and need stated in this draft SEIS. 

10 Therefore, in the Staff’s best professional opinion, the environmentally preferred alternative in 

11 this case is the license renewal of DAEC. All other alternatives capable of meeting the needs 

12 currently served by DAEC entail potentially greater impacts than the proposed action of license 

13 renewal of DAEC. 
Environmental I

February 2010 8-45 Draft NUREG

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

Impact Area 

Alternative 

Air Quality 

Groundwater 

Surface Water 

Aquatic and Terrestrial 

Resources 

Human Health 

Socio-economics 

License Renewal SMALL SMALL SMALL to MODERATE SMALL SMALL SMALL t

MODERA

Supercritical Coal-fired 

Alternative MODERATE SMALL SMALL SMALL to MODERATE SMALL SMALL t

MODERA

Gas-fired Alternative SMALL to MODERATE SMALL SMALL SMALL SMALL SMALL t

MODERA

Combination Alternative SMALL SMALL SMALL SMALL to MODERATE SMALL SMALL t

MODERA

No Action Alternative SMALL SMALL SMALL SMALL SMALL SMALL t

MODERA

(a) 2 For the DAEC license renewal alternative, waste management was evaluated in Chapter 6. Consistent with the findings in the GEIS

3 determined to be SMALL with the exception of collective offsite radiological impacts from the fuel cycle and from high-level waste an
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-46 February 2010 

1 8.7 REFERENCES 

2 10 CFR 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental Protection 

3 Regulations for Domestic Licensing and Related Regulatory Functions.” 

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6 http://www.acaausa.org/associations/8003/files/2006_CCP_Survey_(Final-8-24-07).pdf

7 (accessed April 15, 2008.) 

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9 URL: http://www1.eere.energy.gov/geothermal/gpw/profile_nebraska.html (accessed July 2009). 

10 Duke Energy. 2008. Edwardsport Integrated Gasification Combined-Cycle (IGCC) Station. 

11 Available URL: http://www.duke-energy.com/pdfs/igcc-fact-sheet.pdf (accessed August 2009). 

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13 2009 With Projections to 2030. DOE/EIA 0383(2009). Washington, D.C. Available URL: 

14 http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2009).pdf (accessed July 2009). 

15 Energy Information Administration (EIA). 2009b. “Summary Statistics for the United States.” 

16 Table ES1 from Electric Power Annual with data for 2007. Available URL: 

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18 Energy Information Administration (EIA). 2009c. Table A4. Approximate Heat Content of Natural 

19 Gas, 1949–2008 (Btu per Cubic Foot). Available URL: 

20 http://www.eia.doe.gov/emeu/aer/txt/ptb1304.html (accessed July 2009). 

21 Environmental Protection Agency (EPA). 2000a. “Notice of Regulatory Determination on Wastes 

22 from the Combustion of Fossil Fuels.” Federal Register, Vol. 65, pp.32214–32237. Washington, 

23 D.C. 

24 Environmental Protection Agency (EPA). 2008a. “Basic concepts of Environmental Science. 

25 Module 6: Fabric filters.” Available URL: 

26 http://www.epa.gov/apti/bces/module6/matter/control/control.htm#fabric (accessed June 2009). 

27 ADAMS Accession No. ML091760654. 

28 Environmental Protection Agency (EPA). 2009b. Geopowering the West: Iowa State Profile. 

29 Available URL: http://www.epa.gov/cleanenergy/energy-programs/state-and-local/states/ia.html

30 (accessed July 2009). 

31 Environmental Protection Agency (EPA). 2009c. Proposed Mandatory Greenhouse Gas 

32 Reporting Rule. Available URL: 

33 http://www.epa.gov/climatechange/emissions/ghgrulemaking.html (accessed August 2009). 

34 Environmental Protection Agency (EPA). 2009d. Iowa: State Best Practices. Available URL: 

35 http://www.epa.gov/cleanenergy/energy-programs/state-and-local/states/ia.html (accessed June 

36 2009). 

37 Environmental Protection Agency (EPA). 1998. Compilation of Air Pollutant Emission Factors, 

38 Volume 1: Stationary Point and Area Sources: AP 42, Fifth Edition. “Section 1.1: Bituminous 

39 and Subbituminous Coal Combustion: Final Section Supplement E.” Washington, D.C. 
Environmental Impacts of Alternatives 

February 2010 8-47 Draft NUREG-1437, Supplement 42 

1 Environmental Protection Agency (EPA). 2000b. “Regulatory Finding on the Emissions of 

2 Hazardous Air Pollutants from Electric Utility Steam Generating Units.” Federal Register, Vol. 

3 65, No. 245, pp. 79825–79831. Washington, D.C. December 20, 2000. 

4 Environmental Protection Agency (EPA). 2008b. Clean Air Interstate Rule: Iowa. Available URL: 

5 http://www.epa.gov/CAIR/ia.html (accessed August 2009). 

6 Environmental Protection Agency (EPA). 2008c. New Resource Review. Available URL: 

7 http://www.epa.gov/nsr/ (accessed June 2009). ADAMS Accession No.ML083450073 

8 Environmental Protection Agency (EPA). 2009a. Emissions Factors & AP 42. Available URL: 

9 http://www.epa.gov/ttn/chief/ap42/index.html (accessed August 2009). 

10 General Electric (GE). 2007. “Gas Turbine and Combined Cycle Products.” May 2007. Available 

11 URL: http://www.gepower.com/prod_serv/products/gas_turbines_cc/en/downloads/

12 gasturbine_cc_products.pdf (accessed June 2009). 

13 Idaho National Engineering and Environmental Laboratory (INEEL). 1997. “U.S. Hydropower 

14 Resource Assessment for Iowa.” DOE/ID-10430(NE). Available URL: 

15 http://hydropower.inl.gov/resourceassessment/pdfs/states/ia.pdf (accessed July 2009). 

16 Iowa Department of Natural Resources (IDNR). 2003. Iowa Wind Energy Checklist. Available 

17 URL: http://www.iowadnr.gov/energy/newfiles/new_checklist.pdf (accessed August 2009). 

18 Iowa Department of Natural Resources (IDNR). 2008. Prevention of Significant Deterioration 

19 (PSD) Permit Review Technical Support Document for Permit Issuance. Available URL: 

20 http://aq48.dnraq.state.ia.us:8080/psd/7001008/PSD_PN_06-494/factsheet.pdf (accessed July 

21 2009). 

22 Iowa Department of Natural Resources (IDNR). 2009. Iowa Administrative Code 567—Chapter 

23 101: “Solid Waste Comprehensive Planning Requirements.” Available URL: 

24 http://www.iowadnr.gov/waste/policy/files/101_responsiveness.pdf (accessed July 2009). 

25 National Renewable Energy Laboratory (NREL). 2008. “United States Atlas of Renewable 

26 Resources.” Interactive Map. Available URL: 

27 http://mapserve2.nrel.gov/website/Resource_Atlas/viewer.htm (accessed August 2009). 

28 Nucleonics Week. 2008. “US new reactors more likely online in 2016 and beyond, NEI official 

29 says.” Vol. 49, No. 15. April 10, 2008. 

30 Siemens Power Generation. 2007. “Technical Data: Combined Cycle Power Plant Performance 

31 Data.” Available URL: http://www.powergeneration.siemens.com/products-solutions32 services/power-plant-soln/combined-cycle-power-plants/technical-data (accessed July 2009). 

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

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

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

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

37 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final 

38 Report.” NUREG-1437, Vol. 1, Add. 1. Washington, D.C. 

39 U.S. Nuclear Regulatory Commission (NRC). 2002. Generic Environmental Impact Statement 

40 on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the Decommissioning of 

41 Nuclear Power Reactors. NUREG-0586, Supplement 1, Vols. 1 and 2. Washington, D.C. 
Environmental Impacts of Alternatives 

Draft NUREG-1437, Supplement 42 8-48 February 2010 

1 U.S. Office of Management and Budget (OMB). 2007. Expectmore.gov. “Detailed Information on 

2 the Low Income Home Energy Assistance Program Assessment.” Available URL: 

3 http://www.whitehouse.gov/omb/expectmore/detail/10001059.2003.html (accessed June 2009). 

4 ADAMS Accession No. ML082880730. 
February 2010 9-1 Draft NUREG-1437, Supplement 42 

1 9.0 CONCLUSION 

2 

3 This draft supplemental environmental impact statement (SEIS) contains the preliminary 

4 environmental review of FPL Energy Duane Arnold, LLC (FPL-DA) application for a renewed 

5 operating license for Duane Arnold Energy Center (DAEC) as required by Part 51 of Title 10, of 

6 the Code of Federal Regulations (10 CFR Part 51), which are the Nuclear Regulatory 

7 Commission’s (NRC) regulations for implementing the National Environmental Policy Act 

8 (NEPA) of 1969. The following chapter: 

9 

10  Provides a summary of environmental impacts of license renewal (Section 9.1); 

11 

12  Compares environmental impacts of license renewal and alternatives (Section 9.2); 

13 

14  Addresses three basic requirements required under Section 102(C) of NEPA (Section 

15 9.3); and 

16 

17  Provides a preliminary NRC staff (Staff) recommendation regarding the License 

18 Renewal Alternative for DAEC (Section 9.4).

19 

20 9.1 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL 

21 

22 License renewal impact issues have been previously reviewed and categorized in Chapter 4. 

23 Generic issues (Category 1) rely on the analysis provided in the Generic Environmental Impact 

24 Statement for License Renewal of Nuclear Power Plants (GEIS) prepared by the U.S. Nuclear 

25 Regulatory Commission (NRC) and are discussed briefly in this SEIS (NRC 1996; 1999a). The 

26 Staff has also analyzed site-specific issues (Category 2) for DAEC. As explained in Chapter 1, 

27 impacts can be assigned a significance level of: SMALL, MODERATE, or LARGE. 

28 

29 The Staff has reviewed the site-specific Category 2 issues in this draft supplemental EIS. As 

30 applicable, mitigation measures were considered for Category 2 issues. In conducting this 

31 review, the Staff has conclude that with only two exceptions (water use conflicts, and historic 

32 and archaeological resources), issuing a license renewal would result in a SMALL impact to the 

33 issues reviewed in this SEIS. These two exceptions are described as follows. 

34 

35 The first exception involves withdrawing surface water from the Cedar River, which could 

36 affect the underlying groundwater system. The Staff concluded that the impact to the 

37 groundwater system could range from SMALL to MODERATE. For both the Cedar River 

38 and underlying groundwater system, current practices for managing the impact of plant 

39 water usage were found to be adequate. 

40 

41 The second exception involves potential impacts on historic and archaeological 

42 resources at DAEC, which could result in a MODERATE impact. Potential impacts could 

43 be minimized or avoided altogether, if DAEC develops procedures that more effectively 

44 consider historic and archaeological resources and develops a cultural resource 

45 management plan. 

46 
Conclusion 

Draft NUREG-1437, Supplement 42 9-2 February 2010 

1 9.1.1 Other Environmental Impacts 

2 

3 No impacts beyond those discussed in the GEIS were identified for the issue of land use. The 

4 GEIS concluded that the impacts on land use are SMALL, and that additional site-specific 

5 mitigation measures are unlikely to be sufficiently beneficial to be warranted. 

6 

7 No impacts beyond those discussed in the GEIS were identified for the issue of air quality. The 

8 GEIS concluded that the impacts on air quality are SMALL, and that additional site-specific 

9 mitigation measures are unlikely to be sufficiently beneficial to be warranted. 

10 

11 No impacts beyond those discussed in the GEIS were identified for any aquatic or terrestrial 

12 resources. Consistent with the GEIS, the Staff therefore concludes that the impacts to aquatic 

13 and terrestrial resources, including threatened and endangered species are SMALL, and 

14 additional site-specific mitigation measures are unlikely to be sufficiently beneficial to warrant 

15 implementation. 

16 

17 No impacts beyond those discussed in the GEIS were identified for any health-related issues. 

18 The GEIS concluded that health-related impacts are SMALL, and that additional site-specific 

19 mitigation measures are unlikely to be sufficiently beneficial to be warranted. 

20 

21 

22 With the exception of historic and archaeological resources (described above), the 

23 socioeconomic impacts (environmental justice considerations were not assigned a significance 

24 level) were determined to be SMALL, and plant-specific mitigation measures would not be 

25 sufficiently beneficial to be warranted. 

26 

27 No waste management impacts beyond those discussed in the GEIS were identified. Consistent 

28 with the GEIS, the Staff therefore concludes that the waste management impacts are SMALL, 

29 and additional site-specific mitigation measures are unlikely to be sufficiently beneficial to 

30 warrant implementation. 

31 

32 9.2 COMPARISON OF IMPACTS OF LICENSE RENEWAL AND ALTERNATIVES 

33 

34 The term “energy alternatives” is used to designate the: supercritical coal-fired alternative, 

35 natural gas combined-cycle alternative, and the combination alternative. This section compares 

36 environmental impacts of license renewal with the reasonable energy alternatives, including the 

37 alternative of taking no-action, which are described in Chapter 8. 

38 

39 As noted earlier, the alternative of license renewal could result in a water conflict usage impact 

40 of SMALL to MODERATE, and a MODERATE impact to historical or archaeological resources. 

41 On balance, these impacts are considered to be smaller than the environmental degradation of 

42 terrestrial and aquatic resources, air quality including the release of greenhouse gas (GHG) 

43 emissions, and socioeconomic disruptions as a result of constructing and operating one of the 

44 energy alternatives. 

45 

46 In the Staff’s best professional assessment, the impacts of license renewal are, on balance, less 

47 than or substantially less than those of the supercritical coal-fired alternative, particularly with 
Conclusion 

February 2010 9-3 Draft NUREG-1437, Supplement 42 

1 respect to the issues of criteria pollutants, hazardous air pollutants (HAPs), GHG emissions, 

2 generation of waste products, and the potential for disrupting socioeconomic and biological 

3 resources. 

4 

5 With respect to the gas-fired alternative, the option of license renewal is, on balance, deemed to 

6 be moderately better, particularly with respect to deferring air and GHG emissions that would be 

7 produced if the gas-fired alternative were pursued, as well as potential socioeconomic 

8 disruptions. 

9 

10 When compared with the combination alternative, the option of license renewal is, on balance, 

11 deemed to be marginally better, particularly with respect to aquatic and terrestrial resources, 

12 and potential socioeconomic disruptions. 

13 

14 The only alternative that fairs better than the license renewal alternative is that of taking 

15 no-action. However, in terms of loss jobs and tax revenue, the no-action alternative would result 

16 in a larger socioeconomic impact than license renewal. 

17 

18 In summary, the Staff concludes that the impacts of license renewal are reasonable, and that on 

19 balance, the potential effects are generally less than those of pursuing the energy alternatives. 

20 Only the no-action alternative would result in equivalent or less impact than the alternative of 

21 license renewal; however, the no-action alternative does not meet the purpose and need for 

22 taking action. 

23 

24 9.3 SPECIAL CONSIDERATIONS PURSUANT TO SECTION 102(C) OF NEPA 

25 

26 Environmental impact of the license renewal are described in Chapters 4 and 6 of this SEIS, 

27 while impacts of alternatives are described in Chapter 8. In addition to investigating 

28 environmental impacts and alternatives to a proposed action, Section 102(C) of the NEPA 

29 statute also requires that an EIS specifically address: 

30 

31  any adverse environmental effects which cannot be avoided should the proposal be 

32 implemented, 

33 

34  the relationship between local short-term uses of man's environment and the 

35 maintenance and enhancement of long-term productivity, and 

36 

37  any irreversible and irretrievable commitments of resources which would be involved in 

38 the proposed action should it be implemented. 

39 

40 These requirements are described in the following sections. 

41 

42 9.3.1 Unavoidable Adverse Environmental Impacts 

43 

44 Unavoidable adverse environmental impacts are those effects that would occur after 

45 implementation of all feasible mitigation measures. Implementing license renewal alternative or 

46 any one of the energy alternatives considered in this supplemental EIS would result in some 

47 unavoidable adverse environmental impacts. With the exception of water use conflicts and 
Conclusion 

Draft NUREG-1437, Supplement 42 9-4 February 2010 

1 potential disruption to historical and archaeological resources, these unavoidable impacts would 

2 be SMALL. 

3 

4 Under the license renewal alternative, the existing plant and transmission corridors would 

5 continue to be used for their current mission. This alternative would continue to limit other land 

6 use options. However, no additional land would be required to support this alternative. 

7 

8 The alternative of license renewal would result in relatively minor unavoidable adverse impact 

9 on air quality as a result of equipment such as diesel generators and vehicles. Workers would 

10 be exposed to small amounts of hazardous nonradiological chemicals and waste, and the public 

11 would be exposed to small levels of chemical emissions. Many of these chemicals are also 

12 routinely used at other industrial and power plants, which are similar in size to DAEC. Use of 

13 chemicals would comply with applicable Federal and state regulations and emissions standards. 

14 

15 As described earlier, withdrawing surface water from the Cedar River could adversely affect the 

16 underlying groundwater system, which could be limit water use for other purposes. This impact 

17 could range from SMALL to MODERATE in scale. For both the Cedar River and underlying 

18 groundwater system, current practices for managing the impact of plant water usage are 

19 considered to be adequate. 

20 

21 Under the alternative of license renewal, the existing plant and transmission corridors would 

22 continue to be used for their current mission. This land would continue to pose a SMALL impact 

23 on biological resources. However, no additional biological disturbances would occur under this 

24 alternative. 

25 

26 Workers and members of the public would face exposure to small amounts of radioactive 

27 emissions. Workers would be exposed to radiation during routine plant operations, including 

28 routine nuclear fuel operations. Workers would have higher levels of exposure than members of 

29 the public, but doses would be administratively controlled and would comply with all applicable 

30 regulatory standards and administrative control limits. Chemical and radiological emissions 

31 would not exceed the National Emission Standards for criteria pollutants or hazardous air 

32 pollutants (HAPs). In comparison, alternatives involving the construction and operation of a non33 nuclear power generating facility would also result in unavoidable exposure to hazardous and 

34 toxic chemicals to workers and the general public. 

35 

36 Potential disturbance to historic and archaeological artifacts could result in a MODERATE 

37 impact to these resources. Potential impacts could be minimized or avoided altogether, if FPL38 DA implements procedures that more effectively consider historic and archaeological resources 

39 and develops a cultural resource management plan. 

40 

41 Workers would also face unavoidable exposure to small amounts of radiation from radioactive 

42 spent nuclear fuel and waste operations. Radiation levels that workers are exposed to are 

43 closely monitored. Exposures would not exceed applicable federal regulatory standards. All 

44 personal operations are also conducted in strict compliance with applicable federal regulations. 

45 Wastes streams generated during plant operation would be collected, stored, and shipped for 

46 suitable treatment, recycling, or disposal in accordance with applicable Federal and State 

47 regulations. Due to the costs of handling these materials, power plant operators would be 
Conclusion 

February 2010 9-5 Draft NUREG-1437, Supplement 42 

1 expected to conduct all activities and optimize all operations in a way that generates the 

2 smallest amount of waste practical. Management and disposal of this waste would require long3 term funding and monitoring, and would consume space at treatment, storage, or disposal 

4 facilities to prevent release to the biosphere. 

5 

6 9.3.2 Relationship Between Local Short-Term Uses of the Environment and the 

7 Maintenance and Enhancement of Long-Term Productivity 

8 

9 As used in this section, the term “short term” refers to the period of time during which DAEC 

10 power generating activities would continue. The principle short-term benefit derived from the 

11 alternative of license renewal would be generation of a relatively clean (the impacts of 

12 radiological waste are described below) and an economical supply of energy. 

13 

14 As described in Chapters 4 and 6, continued operation of the DAEC over the license renewal 

15 term would result in a number of short-term uses and impacts upon environmental resources. 

16 Operation of DAEC would continue to consume diesel and gasoline to power equipment and 

17 vehicles, electricity to power equipment. The plant site and the utility corridors would also result 

18 in a continued short-term impact to surrounding biological habitat and resources, and would limit 

19 land use options. After decommissioning the plant, the land might be released for other long20 term productive uses, which could include re-establishment of biological habitat. Once the plant 

21 was shut down, water currently used for cooling purposes could be diverted to other long-term 

22 uses. 

23 

24 Water use could result in a long-term decrease in groundwater productivity. However, once the 

25 plant was shutdown and withdraw of water from the Cedar River ceased, the groundwater 

26 aquifer could be recharged. 

27 

28 DAEC air emissions would, over the short-term, introduce small amounts of hazardous and 

29 radioactive constituents into the biosphere. However, the exposure to hazardous and 

30 radioactive constituents is low, and it is unlikely that public health and long-term productivity of 

31 the environment would be significantly jeopardized. In comparison, the energy alternatives, 

32 particularly the Supercritical Coal-Fired Alternative, would result in emissions of criteria 

33 pollutants or hazardous air pollutants with potentially more serious health concerns to humans 

34 and biota. 

35 

36 In comparison, construction of any of the energy alternatives described in Chapter 8 would 

37 result in a long-term or permanent consumption of sizeable quantities of materials and 

38 resources such as steel, concrete, diesel and gasoline fuels, electricity, water, land, and 

39 potentially loss of biological habitat. In addition to construction resource usage, the energy 

40 alternatives would also consume fuel and other operational resources. With the possible 

41 exception of the Combination Alternative, the construction and operational resource impacts 

42 resulting from pursuing one of the energy alternatives would generally be greater than that 

43 consumed in operating the DAEC over a comparable timeframe; the combination alternative 

44 could result in long-term or permanent changes to land use, biological resources, and socio45 economic disruptions. 

46 
Conclusion 

Draft NUREG-1437, Supplement 42 9-6 February 2010 

1 Continued operation of the DAEC would produce spent nuclear fuel, and low-level radioactive 

2 waste, as well as hazardous and nonhazardous waste, which could have a long-term 

3 detrimental impact on biosphere and environmental productivity. Management and disposal of 

4 this waste would require long-term funding and monitoring, and would consume space at 

5 treatment, storage, or disposal facilities. Regardless of the location, geological containment and 

6 use of land to meet waste disposal needs would reduce the long-term productivity of the land 

7 and geological resources. In contrast, Supercritical Coal-Fired Alternative, and to a less extent 

8 the natural-gas alternative could produce sizeable quantities of hazardous waste with 

9 associated long-term impacts on environmental productivity. 

10 

11 Continued employment and employee expenditures, as well as tax revenues generated during a 

12 license renewal term would directly benefit local, regional, and state economies over the short 

13 term. Local agencies investing project-generated tax revenues into infrastructure and other 

14 public services could enhance socioeconomic productivity over a longer-term. 

15 

16 When compared with the no-action alternative, the short-term benefit of license renewal and the 

17 energy alternatives would be production of electricity. Conversely, there would be no short-term 

18 electrical generation benefit derived from pursuing the no-action alternative. 

19 

20 9.3.3 Irreversible and Irretrievable Commitments of Resources 

21 

22 This section describes the irreversible and irretrievable commitments of resources described in 

23 this SEIS. An irreversible commitment of a resource refers to primary or secondary impacts 

24 which limit future options for a resource. An irretrievable commitment of resources refers to the 

25 use or consumption of a resource that is neither renewable nor recoverable for future use. 

26 With respect to license renewal, irreversible actions include the short-term commitment of land 

27 for the plant and corridors, which would limit other land use options. Also related to this issue 

28 are the irreversible loss of biological habitat and species, at least until the plant is 

29 decommissioned and the land is released. 

30 

31 The license renewal alternative would result in an irretrievable commitment of cooling water 

32 which is diverted from other potential uses, including support of natural and biological 

33 resources. While surface water consumption represents a short-term loss of a renewable 

34 resource, lack of adequate groundwater recharge could constitute a longer-term irretrievable 

35 loss to the underlying aquifer. 

36 

37 An irretrievable commitment of material resources includes materials that cannot be recovered 

38 or recycled, materials that are rendered radioactive and cannot be decontaminated, and 

39 materials consumed or reduced to unrecoverable forms of waste. 

40 

41 One of the principle irreversible impacts is the generation of radioactive, and to a lesser extent, 

42 hazardous waste. The treatment, storage, and disposal of spent nuclear fuel, LLW, hazardous 

43 waste, and nonhazardous waste would require the long-term or permanent irretrievable 

44 commitment of land, as well as capital and personnel to manage and monitor the waste at 

45 storage, treatment, and disposal facilities. As an irreversible action, such waste might also have 

46 the potential to adversely affect the biosphere and other natural resources. In general, the 
Conclusion 

February 2010 9-7 Draft NUREG-1437, Supplement 42 

1 commitment of capital and labor to provide long-term monitoring of this waste is an irretrievable 

2 commitment of socioeconomic resources. 

3 

4 In comparison, one of the principle irreversible impacts of a fossil-fuel alternative involves 

5 release of hazardous air constituents into the biosphere which can have long-term adverse 

6 effects on human health and biological resources. Unlike the alternative of license renewal, a 

7 fossil-fuel plant would also release substantial amounts of CO2 and other GHGs. These GHGs 

8 might result in an irretrievable loss of ecological and natural resources. 

9 

10 The irreversible and irretrievable commitment of resources involved in constructing and 

11 operating any of the energy alternatives would be generally similar to, albeit, probably larger 

12 than those cited for the license renewal alternative. With respect to the energy alternatives, 

13 consumption of fossil fuels would be one of the irretrievable resource of principle concern. For 

14 the alternative of license renewal, the principle irretrievable resource commitment would be 

15 consumption of uranium-235. 

16 

17 The energy alternatives would also have the potential to result in an irretrievable loss of 

18 biological resources, water resources, and could adversely disrupt socioeconomic resources 

19 including historical and archaeological resources. 

20 

21 9.4 RECOMMENDATIONS 

22 

23 Based on (1) the analysis and findings in the GEIS, (2) information provided in the 

24 environmental report (ER) submitted by FPL Energy (3) consultation with Federal, State, and 

25 local agencies, (4) a review of pertinent documents and reports, and (5) consideration of public 

26 comments received during scoping, the preliminary recommendation of the Staff is that the NRC 

27 Commission determine that the adverse environmental impacts of license renewal for DAEC are 

28 not so great that preserving the option of license renewal for energy planning decision-makers 

29 would be unreasonable 

30 

31 9.5 REFERENCES 

32 

33 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

34 Protection Regulations for Domestic Licensing and Related Regulatory Functions.” 

35 

36 The National Environmental Policy Act of 1969. Pub. L. 91-190, 42 U.S.C. 4321-4347, January 

37 1, 1970, as amended by Pub. L. 94-52, July 3, 1975, Pub. L. 94-83, August 9, 1975, and Pub. L. 

38 97-258, § 4(b), Sept. 13, 1982. 

39 

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

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

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

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

44 

45 NRC (U.S. Nuclear Regulatory Commission). 1999b. Environmental Standard Review Plan: 

46 Standard Review Plans for Environmental Reviews for Nuclear Power Plants. NUREG-1555, 

47 October 1999. 

February 2010 10-1 Draft NUREG-1437, Supplement 42 

1 10.0 LIST OF PREPARERS 

2 This supplemental environmental impact statement (SEIS) was prepared by members of the 

3 Office of Nuclear Reactor Regulation, with assistance from other NRC organizations and 

4 contract support from Argon National Laboratory. 

5 Table 10-1. List of Preparers. Argon National Laboratory provided contract support for 

6 preparing the SEIS. Information Systems Laboratories provided contract 

7 support in preparing the severe accident mitigation alternatives (SAMA) 

8 analysis, presented in Chapter 5 and Appendix F. 

9 

Name Affiliation Function or Expertise 

Nuclear Regulatory Commission 

Charles Eccleston Nuclear Reactor Regulation Project Manager 

Dennis Beissel Nuclear Reactor Regulation Hydrology 

Stephen Klementowicz Nuclear Reactor Regulation Radiation Protection 

Jennifer Davis Nuclear Reactor Regulation Historic and Archaeological 

Resources 

Ekaterina Lenning Nuclear Reactor Regulation Air Quality; Human Health 

Jeffrey Rikhoff Nuclear Reactor Regulation Socioeconomics; Land Use; 

Environmental Justice 

Robert Palla Nuclear Reactor Regulation Severe Accident Mitigation 

Alternatives 

Andrew Stuyvenburg Nuclear Reactor Regulation Alternatives (oversight) 

Allison Travers Nuclear Reactor Regulation Alternatives 

Briana Balsam Nuclear Reactor Regulation Aquatic/Terrestrial Ecology 

SEIS Contractor(a)

Ron Kolpa Argon National Laboratory Air Quality/Meteorology 

John Quinn Argon National Laboratory Hydrology 

Tim Allison Argon National Laboratory Socioeconomics 

Dan O’Rourke Argon National Laboratory Cultural Resources 

SAMA Contractor 

Bruce Mrowca Information Systems Laboratories Severe Accidents Mitigation 

Alternatives 

Robert Schmidt Information Systems Laboratories Severe Accidents Mitigation 

Alternatives 

10 (a) Argon National Laboratory, U.S. Department of Energy

February 2010 11-1 Draft NUREG-1437, Supplement 42 

11.0 INDEX 

accidents ........xvii, 5-1, 5-2, 5-5, 8-41, 8-42, 

Appendix A -17, B-14, Appendix F 

aesthetic xvi, 2-41, 2-42, 4-14, 4-15, 8-12, 

8-22, 8-30, 8-40 

alternatives ....iii, xvii, xviii, 1-6, 5-3 - 5-7 8-1 

- 8-42, 9-2, 9-3, 9-4, 10-1, Appendix A, 

Appendix B 

archaeological resources .....xvi, 1-7, 1-8, 2-

47 - 2-50, 4-15, 4-18 - 4-20, 8-12, 8-13, 8-

22, 8-23, 8-31, 8-40, 8-41, B-13, 

Appendix D 

burnup ..................................................... 2-8 

chronic effects ..........xv, 1-4, 4-8, 4-13, 4-14 

Clean Air Act ...................... 2-22, 8-5, 8-25 

closed-cycle cooling ..... 4-110, 8-4, 8-27, B6, B-7 

Commission....xiii, xiv, xvii, 2-1, 4-1, 4-12, 4-

14, 4-15, 4-21 

cultural resources......3-12, 4-44, 8-12, 8-13, 

8-22, 8-31, 10-1, Appendix C 

decommissioning ... 7-1, 8-38 8-41Appendix 

demography 2-43 -2-47, 4-11, 8-11, 8-13, 8-

21 

design-basis accidents..................... 5-1, 5-2 

discharges. ...xv, 2-8 2-12, 2-17, 2-19, 2-20, 

2-23 - 2-26, 2-27, 4-2 - 4-6, 4-11 - 4-12, 

4-30, 4-34, 8-4, 8-9, 8-19, 8-39, 8-44, B-1, 

B-3, B-4, B-11, Appendix C 

dose 2-9, 4-9, 4-10, 4-27, 5-5, 5-6, 

Appendix A, B-11, B-14, B-16, Appendix 

F 

Duane Arnold Energy CenterXV, 1-1, 1-2, 2-

1, 2-3 - 2-17, 3-1 - 3-3 

dredging .....................................Appendix C 

education...... ...2-40, 4-14, 4-15, B-12, B-13 

electromagnetic fields......xv, xvi, 4-6, 4-8, 4-

18, 4-12 - 4-14, 4-34, B-9, B-12 

environmental justice......1-4, 4-15, 4-20 - 4-

26, 8-13, 8-14, 8-23, 8-24, 8-31, 8-32, 8-

40, 9-2, B-20 

EPA.....2-10 - 2-12, 2-16, 2-21, 2-22, 4-2, 4-

29, 4-33, 4-34, 8-2, 8-5, 8-7, 8-8, 8-10, 8-

14, 8-16 - 8-18, 8-24 - 8-26, 8-34, B-17, 

C-1, C-5 

GEIS xiv - xvi, xviii, 1-3 - 1-6, 2-43, 4-1 - 4-

19, 4-27 - 4-36, 5-1 - 5-3, 6-1, 6-2, 7-1, 8-

1, 8-2, 8-3, 8-9 - 8-12, 8-13, 8-14, 8-15, 8-

19 - 8-21, 8-23, 8-27 - 8-29, 8-34 - 8-37, 

B-14 

ground water ....xiv, xvii, 2-18, 2-23, 2-24, 4-

2 - 4-5, 4-9, 4-16, 4-26, 4-27, 4-30, 4-35, 

8-2, 8-5, 8-8, 8-9, 8-14, 8-16, 8-18, 8-24, , 

8-26, , 8-27, 8-38, 8-39, 8-41B-5, B-6, B7, C-1 

hazardous waste... ....2-10 - 2-12, 8-36, 9-3, 

9-5, C-6 

high level waste ....... B-14, B-15, B-16, B-17 

impingement 4-6, 4-31, 8-9, 8-19, 8-27, B-3, 

B-5 

invasive species........................... 4-31, 4-32 

mitigation xvi, xvii, 1-4 - 1-6, 4-1 - 4-34, 5-3 - 

5-7, 8-13, 8-23, 9-1 - 9-3 

mixed waste................................. 8-41, B-18 

NEPA ...xiii, xiv, 1-1, 4-21, 5-1, 6-3, 8-41, 8-

42, 9-3, B-1, B-15, B-17 

no-action alternative............8-38, 8-41, 8-42 

nonattainment .........................8-5, 8-10, B-9 

NPDES...2-12, 2-24 - 2-26, 4-2, 4-11 - 4-13, 

B-2 

postulated accidents ....................... 5-1 - 5-3 

radon-222....................................... 4-9, B-14 

reactor... ... 2-6 - 2-8, 5-1 - 5-3, 5-7, 8-12 8--

22, 8-30, 8-33, 8-39, B-6, B-14 

refurbishment.. ...xv, xvi, 2-10, 3-1, 3-2, 3-3, 

3, 4-10, 4-18, 4-20, 4-29, 4-34, B-1, B-3, 

B-5, B-9, B-10, B-11, B-12, B-13 

replacement power ..................................5-5 

scoping...................xvii, 1-3, 1-6, 4-1 - 4-27, 

Appendix A 

severe accidents (SAMA)....xxv, 5-3 - 5-7, 

10-1, Appendix A 

solid waste...2-9 - 2-12, 6-1, 6-2, 8-13, 8-36, 

8-37, Appendix B 

spent fuel ....xxiv, 1-4, 2-6, 4-19, 6-1, 6-2, 8-

41, 8-42, B-14, B-15, B-17, B-18, B-19 

stormwater .................................. 2-23 - 2-26 

surface water .. ...xvi, xviii, 2-18, 2-23 - 2-27, 

3-2, 4-3 - 4-5, 4-9, 4-26, 4-27. 4-30, 4-32, 

4-35, 8-2, 8-5, 8-9, 8-16, 8-18, 8-24, 8-27, 

8-38, 8-39, 8-42, 9-1, 9-4, 9-6, A-8, A-9, 

A-12, B-1, B-6, C-1 

taxes ................2-41, 2-42, 2-46 - 2-48, 4-17 
Index 

Draft NUREG-1437, Supplement 42 11-2 February 2010 

threatened and endangered species....2-16, 

2-29, 2-31 - 2-39, 4-5, 4-7, 4-8, B-7, C-1, 

C-5, D-1 

transmission lines and corridors 2-3, 2-13, 2-

16, 2-33, 2-36 - 2-39, 2-51, 4-7, 4-8, 4-12, 

4-13, 4-19, 4-20, 4-27, 4-31, 4-32, 4-33, 

4-34 

tritium .................2-9, 2-22, 2-23, 4-25, 4-26 

U.S. Fish and Wildlife Service 2-31 - 2-35, 2-

39, 2-52, 4-7, 4-8 

uranium . ...2-6 - 2-8, 4-26, 4-32, 6-1, 6-2, 8-

10, 8-11, 8-20, 8-29 

Yucca ......................................... B-15 - B-14 
Appendix A 

Comments Received on the 

Duane Arnold Energy Center 

Environmental Review 

February 2010 A-1 Draft NUERG-1437, Supplement 42 

1 A. Comments Received On The Duane Arnold Energy Center, 

2 Environmental Review 

3 A.1 Comments Received During Scoping 

4 The Duane Arnold Energy Center (DAEC) scoping process began on March 24, 2009 with the 

5 publication of the U.S. Nuclear Regulatory Commission’s (NRC) Notice of Intent to conduct 

6 scoping in the Federal Register (74 FR 12399). The scoping process included two public 

7 meetings held at Hiawatha City Hall, Iowa on April 22, 2009. Approximately 30 people attended 

8 the meetings. After the NRC’s prepared statements pertaining to the license renewal process, 

9 the meetings were open for public comments. Oral statements were recorded and transcribed 

10 by a certified court reporter. Transcripts of the meeting, were attached to the Scoping Summary 

11 Report dated August 7, 2009 (NRC 2009). A total of two attendees registered to speak at the 

12 afternoon meeting session. When called upon, one of these registered speakers indicated that 

13 he had no comments. No one provided comments at the evening session. No other public 

14 scoping comments were received either through the mail or email. 

15 The commenter was assigned a unique identifier. Table A-1 identifies the individual who 

16 registered to provide comments and the ID associated with the commenter’s set of comments. 

17 To maintain consistency with the Scoping Summary Report, the unique identifier used in that 

18 report is retained in this appendix. 

19 Specific comments were categorized and consolidated by topic. Comments can fall into one of 

20 the following general groups: 

21 Specific comments that address environmental issues within the purview of the NRC 

22 environmental regulations related to license renewal. These comments address Category 1 

23 (generic) or Category 2 (site-specific) issues or issues not addressed in the Generic 

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

25 They also address alternatives to license renewal and related Federal actions. 

26 General comments (1) in support of or opposed to nuclear power or license renewal or (2) 

27 on the renewal process, the NRC’s regulations, and the regulatory process. These 

28 comments may or may not be specifically related to the TMI-1 license renewal application. 

29 Comments that do not identify new information for the NRC to analyze as part of its 

30 environmental review. 

31 Comments that address issues that do not to fall within or are specifically excluded from the 

32 purview of NRC environmental regulations related to license renewal. These comments 

33 typically address issues such as other accidents, emergency response and preparedness, 

34 security and terrorism, energy costs, energy needs, current operational safety issues, and 

35 safety issues related to operation during the renewal period. 
Appendix A 

Draft NUREG-1437, Supplement 42 A-2 February 2010 

1 Table A-1. Commenters on the Scope of the Environmental Review. The comment 

2 is identified along with the affliliation and how their comment was 

3 submitted.

Commenter 

ID Commenter Affiliation Comment Source 

ADAMS 

Accession 

Number 

DAEC-1 Mr. Bennett 

Brown Member of the public Afternoon Scoping Meeting Session ML091910273 

4 

5 Comments received during scoping applicable to this environmental review are presented in the 

6 following sections along with the NRC response. The comments that are general or outside the 

7 scope of the environmental review for DAEC are not included here, but can be found in the 

8 Scoping Summary Report (NRC 2009). 

9 Scoping comments are grouped in the following categories: 

10  Alternatives 

11  Postulated Accidents 

12 

13 A.1.1 Alternatives 

14 Comment DAEC-1: The Department of Natural Resources and the state of Iowa assessed the 

15 state's wind resource and concluded that the state of Iowa [is] developing only class 4 jacobs sites. 

16 These are currently developable at two and-a-half cents a kilowatt hour, would produce six times 

17 as much electricity as needed by the state of Iowa. 

18 The Midwest Independent Systems Operators as well as other utility grid operators have studied 

19 how much wind penetration the grid could sustain given the variability of the wind and concluded 

20 that we could provide 15 to 25 percent of our electricity from wind without any alterations in the 

21 existing grid. So the percentage of electricity produced in the state of Iowa from Duane Arnold 

22 could easily be replaced by wind turbines with existing technology and existing market support. 

23 Response: This comment is related to the environmental impacts of alternatives to license 

24 renewal of the DAEC. The impacts of a range of reasonable alternatives are presented in 

25 Chapter 8 of this supplemental environmental impact statement (SEIS). In response to this 

26 comment, the NRC staff has evaluated a “combination alternative.” The combination alternative 

27 includes a portion of the combined-cycle gas-fired capacity identified in Section 8.2, as well as a 

28 conservation capacity component, and a wind power component. 

29 Comment: The second thing that I'd like to see that the SEIS addresses is the effect on 

30 employment decommissioning. As I see it, this is not a question of whether to extend the life of the 
Appendix A 

February 2010 A-3 Draft NUERG-1437, Supplement 42 

1 plant by 20 years but rather a question as to whether to decommission it in 2014 or 2034. And so 

2 the question is when would we rather have the jobs provided necessary to decommission this plant 

3 and construct a renewable source, or at least some other source of electricity whether that's a new 

4 nuclear plant or a new coal plant or wind plants. And the Congress requires that the operators of 

5 this nuclear plant provide $359,000,000 in a trust fund by 2014. 

6 That money spent beginning in 2014 to provide job decommissioning in this plant would be a boon 

7 to the local economy and the 2.4 billion, and there that's really a number off the top of my head 

8 there just saying, well, 800 megawatts times three per wind because of the name plate issue, I 

9 don't know how familiar you are with wind, but an 800 megawatt nuclear plant takes 2400 

10 megawatts of wind to replace it. So that's roughly $2.4 billion in construction of wind turbines and 

11 the associated jobs that come with that construction on top of some 300 full time jobs maintaining 

12 that wind energy. That would be a significant boon to the state of Iowa and I would encourage the 

13 NRC to look at the economic impact on the state of replacing this nuclear plant with wind as 

14 distributed around the state. 

15 Response: The environmental and socioeconomic impacts of decommissioning have been 

16 reviewed in Chapter 7 of the SEIS. Section 8.5 of the SEIS also examines environmental and 

17 socioeconomic effects that would occur if NRC takes no action to renew the DAEC operating 

18 license. In response to this comment, the NRC staff has also evaluated a “combination 

19 alternative.” This combination alternative includes a portion of the combined-cycle gas-fired 

20 capacity identified in Section 8.2 of the SEIS, as well as a conservation capacity component, 

21 and a wind power component. Section 8.3.6.2 of the SEIS discusses socioeconomic impacts, 

22 including those associated with employment and construction of a wind farm. 

23 A.1.2 Safety and Postulated Accidents 

24 Comment DAEC-1: The third point that I'd like to make has to do with the environmental impact of 

25 a severe accident. And I understand that you also have a safety review portion of the process and 

26 I also understand that the 9th Circuit Court has ruled that your SEIS must include an analysis of 

27 accidents in the jurisdiction of the 9th Circuit Court. So in lack of ruling from this Circuit Court, I 

28 believe that ruling has precedence and I would ask that you include accidents and the impacts of 

29 accidents in the SEIS -- 

30 Specifically on this point I would refer to the Sandia Lab Study commissioned by the NRC in 1982 

31 which calculated the impacts of a severe accident with core damage estimating 3,000 peak 

32 fatalities immediately after the accident within a 25 mile radius, and 12,000 radiation injuries in the 

33 early aftermath of an accident within a 35 mile radius. And calculate the plant operators, calculate 

34 at any given time if all equipment is operating correctly, that the core damage frequency is one in 

35 3,000,000 per reactor year. But sometimes parts are out of operation and the possibility that 

36 there's a severe accident under their calculations go up. 

37 I would ask for this SEIS that the NRC address the likelihood of an accident taking into account 

38 more than the plant operators include in their calculation of the CDF, particularly their probabilistic 

39 risk assessment assumes that all parts operate as though they were new and have not been 

40 subjected to problems of radiation exposure, heat exposure, fluctuation of temperature, pressure 

41 exposure and embrittlement. 
Appendix A 

Draft NUREG-1437, Supplement 42 A-4 February 2010 

1 In this regard, I'd specifically point out that the CDF excludes vessel failure. This is a Mark 1 

2 reactor. It's one of 18 Mark 1 reactors in the country. A study published by the Union of 

3 Concerned Scientists in 1995 looked at the vessel internals aging in the 18 Mark 1 reactors in the 

4 country as a result of discoveries of major fissures and cracks in Mark 1 core shrouds and found 

5 that at about 20 years of operation the exposure to radiation and heat fluctuation caused moderate 

6 or extensive cracking in seven out of the 18 Mark 1 reactors. 

7 Duane Arnold at that time had no cracking evident and I would encourage the NRC to consider the 

8 possibility that a 40 year license that was initially granted to this reactor has allowed the investors 

9 to recoup their losses and that we are lucky today that the aging of the parts has not resulted in an 

10 accident. But a 20 year extension of the license represents too great a risk to this site specific plan 

11 for an accident. 

12 If the core shroud detailed in the UCS report is one of just 21 vessel internal components subject 

13 not only to the cracking that is described in that report, but also to erosion, embrittlement, fatigue, 

14 creep, as well as stress corrosion cracking. So if these vessel internal parts were to prevent an 

15 insertion of the control rods, then the consequences of an accident could be quite severe. 

16 In addition, the secondary containment which is meant to control the impact and mitigate the 

17 impact of such an accident in this particular reactor, was discovered to be faulty in the early days of 

18 operation of this reactor and the 17 other reactors like it in the country. 

19 In fact, in 1986 Harold Denton, at that time a Chief Safety Officer with the NRC, in leading a 

20 meeting of Mark 1 operators declared that the taurus, as it is known, a million gallon tank of water 

21 to suppress heat in the event that the reactor was unable to be shut down and no where for the 

22 heat to go because of a loss of connectivity to the grid for instance, that there was a 90 percent 

23 probability that that taurus would fail at a meeting of Mark 1 operators. 

24 And so as a result of that assessment, Mark 1 operators were instructed to install a bypass system 

25 that instead of trying to contain the pressure from the reactor using secondary containment, would 

26 simply bypass secondary containment and vent the taurus directly to the atmosphere through a 

27 butterfly valve operated in the control room. And Duane Arnold officials here today verify that, in 

28 fact, that is the situation at Duane Arnold, that it's not different than the other 17 Mark 1's. 

29 And I think that I can understand why you would let a plant live out its 40 year operating license 

30 knowing that it had a design deficiency off by a factor of 10 in the size of the secondary 

31 containment in order to allow investors to recoup their investment. But to extend the plant's life for 

32 another 20 years when a viable alternative exists that would be a boon to the state's economy, I 

33 think is something that should be viewed with skepticism. 

34 Finally, I think that the NRC should look at the history of scrams. Every scram at this reactor 

35 significantly ages the components. It subjects the components to significant changes in 

36 temperature, just like when you take a hot glass and submerge it suddenly in cold water. It can 

37 shatter parts inside a reactor every time you scram the reactor or suddenly subject it from one 

38 pressure extreme to another, from one temperature extreme to another and this significantly ages 

39 parts. 
Appendix A 

February 2010 A-5 Draft NUERG-1437, Supplement 42 

1 If the reactor, for instance, had in the non-radiation side, had a metal part break off at a filet weld 

2 simply because it had been cycled between hot and cold, and that metal part found its way through 

3 the system, scored open a number of tubes. Finally, the problem was turned up because water 

4 leaked first into one part and then overflowed into another part of the plant, and it was only once 

5 the plant was shut down and people investigated that they found tubes slashed open and 

6 eventually found the metal part that worked its way loose. That sort of risk is simply unnecessary 

7 and there's a viable alternative to the nuclear plant's continued operation. 

8 The final point that I'd like to make concerning the reactor itself is this plant's specific risk to a 

9 terrorist attack. The plant is in proximity to the Rockwell Collins plant that used to be in the Soviet 

10 Union's top three list of targets because of its role in our nation's nuclear arsenal, missile guidance 

11 and intelligence. That means that both an attack on Rockwell Collins would have an impact on the 

12 plant, on its safety, on its ability to evacuate and so on. 

13 It also means that there could be an indirect threat to the plant because a terrorist attack might find 

14 the plant a useful target in order to move military protection away from Rockwell Collins or the 

15 further strategic air command in Omaha in order to free up the vulnerability of SEC. So the specific 

16 location of this plant represents a hazard that needs to be looked at from the perspective of a 

17 terrorist attack. 

18 And in addition, the Mark 1 design has a spent fuel pool that's on top of a building that is essentially 

19 unprotected, that various studies have concluded that a piece of weaponry that can be moved 

20 around in the trunk of a car and launched from somebody's shoulder, a howitzer, could penetrate 

21 that building and create a fire in the spent fuel pool. In addition, that spent fuel pool would be 

22 committed to use for five years beyond decommissioning because if we were to decommission the 

23 plant even today, then we would need to store the spent fuel for a minimum of five years on that 

24 local site. 

25 So we're looking at a terrorist threat, a target, an attractive target for five years beyond 

26 decommission and I think it needs to be considered whether in this day and age it's really 

27 necessary to continue maintaining such an attractive target. 

28 Response: 

29 As part of the license renewal environmental review, the NRC staff evaluates the environmental 

30 impacts of postulated accidents. This evaluation is documented in Chapter 5 of this DSEIS. This 

31 comment raises concerns regarding several different aspects of consequences from such 

32 potential accidents. 

33 First, with respect to a ruling from the Ninth Circuit Court of Appeals stating that the issue of 

34 terrorism must be considered in NEPA documents. The Commission respectfully disagreed with 

35 the Ninth Circuit's view, but stated that it will follow that ruling in the Ninth Circuit, indicating its 

36 belief that a different outcome might be reached by other Courts of Appeals (Oyster Creek, CLI37 07-8, 65 NRC at 128). The DAEC is not located within the jurisdiction of the Ninth Circuit and 

38 therefore this DSEIS is not subject to the court’s finding. However, Section 5.2 of this DSEIS 

39 does provide a discussion regarding the GEIS’s consideration of severe accidents from 

40 phenomena such as sabotage, and its conclusion that the core damage and radiological release 
Appendix A 

Draft NUREG-1437, Supplement 42 A-6 February 2010 

1 from such acts would be no worse that the damage and release expected from internally 

2 initiated events. 

3 Further, in a recent case of The State of New York v. NRC, two states filed rulemaking petitions 

4 asking NRC to reverse its GEIS conclusion, which found that spent fuel pools located at nuclear 

5 reactors do not create a significant environmental impact--the GEIS classifies on-site storage of 

6 spent fuel in pools as a category I issues that causes a small impact. The risks posed by storing 

7 nuclear fuel in such pools, including the risk of fire, have been considered in various studies. 

8 Some of these studies (including those conducted since September 2001) have also considered 

9 the risk of fire precipitated by a terrorist attack and have classified that risk as low. In a ruling in 

10 favor of the NRC, the Second Circuit Court of Appeals concluded that NRC’s decision denying 

rulemaking petitions was reasoned.1 11 

12 Secondly, the commenter raised an issue concerning the “Sandia Lab Study” (Sandia Siting 

13 Study). The 1982 Sandia Siting Study (also referred to as the CRAC-II report) attempted to 

14 estimate source terms (i.e., magnitude, timing, and characteristics of the radioactive material 

15 released to the environment from a severe accident) for a severe nuclear reactor accident. A 

16 later study, NUREG-0773, concluded that the source terms used in Sandia Siting Study were 

17 based on “known deficiencies which would tend to give overestimates of the magnitude of the 

18 releases” (NRC 1982). Another study, NUREG-1150, used a probabilistic risk assessment to 

19 improve upon the Sandia Siting Study. The NUREG-1150 study confirmed that the Sandia 

20 Siting Study had produced invalid results because it looked at the effects of very unlikely severe 

21 accidents. 

22 The 1996 GEIS used information from 28 plant-specific EISs, where the impacts from severe 

23 accidents were analyzed in their plant-specific EISs to project the environmental impact from all 

24 U.S. plants (see Table 5.5, GEIS 1996). As stated in Section 5.3.3.1 of the 1996 GEIS, the 

25 source terms used in assessing these severe accidents were generally based on those 

26 documented in the NUREG-0773 study (NRC 1982). Since completion of NUREG-0773 study, 

27 additional information on source terms has been developed through experimental and analytical 

28 programs. The comparison of the new source term information to that used in the 1996 GEIS 

29 impact projection shows that the amount of released radioactive material in a postulated severe 

30 accident to be less than that estimated in the 1996 GEIS. Thus, the environmental impacts used 

31 as the basis for the 1996 GEIS are even more conservative than an estimate using more recent 

32 source term information. In addition, a substantial effort is also ongoing to re-quantify realistic 

33 severe accident source terms under the state-of-the-art reactor consequence analysis 

34 (SOARCA) project. Preliminary results indicate that source terms, timing, and magnitude may 

35 be significantly later and lower than quantified in previous studies, including the 1996 GEIS. 

36 Thirdly, the commenter asked that NRC address the likelihood of an accident, taking into 

37 account more than the current assumptions used for calculating CDF. Specifically, the 

38 commenter raised various concerns about systems and components including those identified in 

39 a 1995 Union of Concerned Scientists report. As stated above, with respect to the environment 

40 impacts associated with all postulated accidents, Chapter 5 of this DSEIS provides a discussion 

 

1 The State of New York v. NRC, United States Court of Appeals for the Second Circuit, Docket Nos. 08-3903-ag 

(L), 08-4833-ag (con), 08-5571-ag (con). Decided: December 21, 2009.
Appendix A 

February 2010 A-7 Draft NUERG-1437, Supplement 42 

1 of the NRC staff’s evaluation. With respect to the safety aspect of such systems and 

2 components being able to operate for another 20 years, the NRC staff makes that determination 

3 as part of its license renewal safety review, which focuses on the programs and processes that 

4 are designed to assure adequate protection of the public health and safety is maintained during 

5 the 20-year license renewal period through management of aging components. As part of the 

6 license renewal safety review, the applicant will be required to demonstrate that the effects of 

7 aging will be adequately managed. 

8 Finally, the commenter also raised various concerns about systems and components that are 

9 related to the safe day-to-day operation of the plant, such as scram history and the secondary 

10 containment’s ability to mitigate impacts of an accident involving a Mark 1 reactor. Although not 

11 within the scope of the license renewal review, which focuses on aging management, these 

12 issues are addressed as part of the NRC’s ongoing oversight role, which includes, among other 

13 things, rigorous inspections, performance monitoring, and enforcement capability to ensure safe 

14 operation of commercial reactors. 

15 A.2 References 

16 74 FR 12399. U.S. Nuclear Regulatory Commission, Washington, D.C, “FPL Energy Duane 

17 Arnold, LLC; Notice of Intent to Prepare an Environmental Impact Statement and Conduct 

18 Scoping Process.” Federal Register: Vol. 74, No. 55, pp. 12399–12401. March 24, 2009. 

19 NRC 1982. NUREG-0773, “The Development of Severe Reactor Accident Source Terms: 1957-

20 1981.” November 1982. 

21 NRC 1991. NUREG-1150, "Severe Accident Risks: An Assessment for Five U.S. Nuclear Power 

22 Plants", 1991. 

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

24 License Renewal of Nuclear Plants. NUREG-1437, Vols. 1 and 2, Washington, D.C. 1996. 

25 ADAMS Accession Nos. ML040690705 and ML040690738. 

26 NRC (U.S. Nuclear Regulatory Commission). 2009. “Issuance of the Environmental Scoping 

27 Summary Report, For the Staff’s Review of the License Renewal Application for Duane Arnold 

28 Energy Center” ADAMS Accession No. ML092030185. 

29 Sandia National Laboratory 1982. Sandia Siting Study (also referred to as the CRAC-II report), 

30 NUREG/CR-2239. 

Appendix B 

NEPA Issues for License Renewal of Nuclear Power Plants 

February 2010 B-1 Draft NUREG-1437, Supplement 42 

1 B. NEPA Issues for License Renewal of Nuclear Power Plants 

2 Table B-1. Summary of Issues and Findings. This table is taken from Table B-1 in 

3 Appendix B, Subpart A, to 10 CFR Part 51. Data supporting this table are 

4 contained in NUREG-1437, Generic Environmental Impact Statement for 

5 License Renewal of Nuclear Plants. Throughout this report, “Generic” 

6 issues are also referred to as Category 1 issues, and “Site-specific” issues 

7 are also referred to as Category 2 issues. 

8 

Issue Type of Issue Finding

Surface Water Quality, Hydrology, and Use 

Impacts of 

refurbishment on 

surface water 

quality 

Generic SMALL. Impacts are expected to be negligible during 

refurbishment because best management practices are 

expected to be employed to control soil erosion and 

spills. 

Impacts of 

refurbishment on 

surface water use 

Generic SMALL. Water use during refurbishment will not 

increase appreciably or will be reduced during plant 

outage. 

Altered current 

patterns at intake 

and discharge 

structures 

Generic SMALL. Altered current patterns have not been found 

to be a problem at operating nuclear power plants and 

are not expected to be a problem during the license 

renewal term. 

Altered salinity 

gradients 

Generic SMALL. Salinity gradients have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term. 

Altered thermal 

stratification of 

lakes 

Generic SMALL. Generally, lake stratification has not been 

found to be a problem at operating nuclear power 

plants and is not expected to be a problem during the 

license renewal term. 

Temperature 

effects on 

sediment 

transport capacity 

Generic SMALL. These effects have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term. 

Scouring caused 

by discharged 

cooling water 

Generic SMALL. Scouring has not been found to be a problem 

at most operating nuclear power plants and has caused 

only localized effects at a few plants. It is not expected 

to be a problem during the license renewal term. 

Eutrophication Generic SMALL. Eutrophication has not been found to be a 

problem at operating nuclear power plants and is not 

expected to be a problem during the license renewal 

term. 
Appendix B 

Draft NUREG-1437, Supplement 42 B-2 February 2010 

Issue Type of Issue Finding

Discharge of 

chlorine or other 

biocides 

Generic SMALL. Effects are not a concern among regulatory 

and resource agencies, and are not expected to be a 

problem during the license renewal term. 

Discharge of 

sanitary wastes 

and minor 

chemical spills 

Generic SMALL. Effects are readily controlled through NPDES 

permit and periodic modifications, if needed, and are 

not expected to be a problem during the license 

renewal term. 

Discharge of 

other metals in 

wastewater 

Generic SMALL. These discharges have not been found to be a 

problem at operating nuclear power plants with coolingtower-based heat dissipation systems and have been 

satisfactorily mitigated at other plants. They are not 

expected to be a problem during the license renewal 

term. 

Water use 

conflicts (plants 

with once-through 

cooling systems) 

Generic SMALL. These conflicts have not been found to be a 

problem at operating nuclear power plants with oncethrough heat dissipation systems. 

Water use 

conflicts (plants 

with cooling 

ponds or cooling 

towers using 

make-up water 

from a small river 

with low flow) 

Site-specific SMALL OR MODERATE. The issue has been a 

concern at nuclear power plants with cooling ponds and 

at plants with cooling towers. Impacts on instream and 

riparian communities near these plants could be of 

moderate significance in some situations. See § 

51.53(c)(3)(ii)(A). 

Aquatic Ecology 

Refurbishment Generic SMALL. During plant shutdown and refurbishment there 

will be negligible effects on aquatic biota because of a 

reduction of entrainment and impingement of 

organisms or a reduced release of chemicals. 

Accumulation of 

contaminants in 

sediments or 

biota 

Generic SMALL. Accumulation of contaminants has been a 

concern at a few nuclear power plants but has been 

satisfactorily mitigated by replacing copper alloy 

condenser tubes with those of another metal. It is not 

expected to be a problem during the license renewal 

term. 

Entrainment of 

phytoplankton 

and zooplankton 

Generic SMALL. Entrainment of phytoplankton and zooplankton 

has not been found to be a problem at operating 

nuclear power plants and is not expected to be a 

problem during the license renewal term. 

Cold shock Generic SMALL. Cold shock has been satisfactorily mitigated at 

operating nuclear plants with once-through cooling 
Appendix B 

February 2010 B-3 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

systems, has not endangered fish populations or been 

found to be a problem at operating nuclear power 

plants with cooling towers or cooling ponds, and is not 

expected to be a problem during the license renewal 

term. 

Thermal plume 

barrier to 

migrating fish 

Generic SMALL. Thermal plumes have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term. 

Distribution of 

aquatic organisms 

Generic SMALL. Thermal discharge may have localized effects 

but is not expected to affect the larger geographical 

distribution of aquatic organisms. 

Premature 

emergence of 

aquatic insects 

Generic SMALL. Premature emergence has been found to be a 

localized effect at some operating nuclear power plants 

but has not been a problem and is not expected to be a 

problem during the license renewal term. 

Gas 

supersaturation 

(gas bubble 

disease) 

Generic SMALL. Gas supersaturation was a concern at a small 

number of operating nuclear power plants with oncethrough cooling systems but has been satisfactorily 

mitigated. It has not been found to be a problem at 

operating nuclear power plants with cooling towers or 

cooling ponds and is not expected to be a problem 

during the license renewal term. 

Low dissolved 

oxygen in the 

discharge 

Generic SMALL. Low dissolved oxygen has been a concern at 

one nuclear power plant with a once-through cooling 

system but has been effectively mitigated. It has not 

been found to be a problem at operating nuclear power 

plants with cooling towers or cooling ponds and is not 

expected to be a problem during the license renewal 

term. 

Losses from 

predation, 

parasitism, and 

disease among 

organisms 

exposed to 

sublethal stresses 

Generic SMALL. These types of losses have not been found to 

be a problem at operating nuclear power plants and are 

not expected to be a problem during the license 

renewal term. 

Stimulation of 

nuisance 

organisms (e.g., 

shipworms) 

Generic SMALL. Stimulation of nuisance organisms has been 

satisfactorily mitigated at the single nuclear power plant 

with a once-through cooling system where previously it 

was a problem. It has not been found to be a problem 

at operating nuclear power plants with cooling towers or 
Appendix B 

Draft NUREG-1437, Supplement 42 B-4 February 2010 

Issue Type of Issue Finding

cooling ponds and is not expected to be a problem 

during the license renewal term. 

Aquatic Ecology (for plants with once-through and cooling pond heat dissipation systems) 

Entrainment of 

fish and shellfish 

in early life stages 

Site-specific SMALL, MODERATE, OR LARGE. The impacts of 

entrainment are small at many plants but may be 

moderate or even large at a few plants with oncethrough and cooling-pond cooling systems. Further, 

ongoing efforts in the vicinity of these plants to restore 

fish populations may increase the numbers of fish 

susceptible to intake effects during the license renewal 

period, such that entrainment studies conducted in 

support of the original license may no longer be valid. 

See § 51.53(c)(3)(ii)(B). 

Impingement of 

fish and shellfish Site-specific SMALL, MODERATE, OR LARGE. The impacts of 

impingement are small at many plants but may be 

moderate or even large at a few plants with oncethrough and cooling-pond cooling systems. See § 

51.53(c)(3)(ii)(B). 

Heat shock Site-specific SMALL, MODERATE, OR LARGE. Because of 

continuing concerns about heat shock and the possible 

need to modify thermal discharges in response to 

changing environmental conditions, the impacts may be 

of moderate or large significance at some plants. See § 

51.53(c)(3)(ii)(B). 

Aquatic Ecology (for plants with cooling-tower-based heat dissipation systems) 

Entrainment of 

fish and shellfish 

in early life stages 

Generic SMALL. Entrainment of fish has not been found to be a 

problem at operating nuclear power plants with this 

type of cooling system and is not expected to be a 

problem during the license renewal term. 

Impingement of 

fish and shellfish 

Generic SMALL. The impingement has not been found to be a 

problem at operating nuclear power plants with this 

type of cooling system and is not expected to be a 

problem during the license renewal term. 

Heat shock Generic SMALL. Heat shock has not been found to be a 

problem at operating nuclear power plants with this 

type of cooling system and is not expected to be a 

problem during the license renewal term. 

Ground Water Use and Quality 

Impacts of 

refurbishment on 

ground water use 

Generic SMALL. Extensive dewatering during the original 

construction on some sites will not be repeated during 

refurbishment on any sites. Any plant wastes produced 
Appendix B 

February 2010 B-5 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

and quality during refurbishment will be handled in the same 

manner as in current operating practices and are not 

expected to be a problem during the license renewal 

term. 

Ground water 

use conflicts 

(potable and 

service water; 

plants that use 

<100 gpm) 

Generic SMALL. Plants using less than 100 gpm are not 

expected to cause any ground water use conflicts. 

Ground water use 

conflicts (potable 

and service water, 

and dewatering 

plants that use 

>100 gpm) 

Site-specific SMALL, MODERATE, OR LARGE. Plants that use 

more than 100 gpm may cause ground water use 

conflicts with nearby ground water users. See § 

51.53(c)(3)(ii)(C). 

Ground water use 

conflicts (plants 

using cooling 

towers 

withdrawing 

make-up water 

from a small river) 

Site-specific SMALL, MODERATE, OR LARGE. Water use conflicts 

may result from surface water withdrawals from small 

water bodies during low flow conditions which may 

affect aquifer recharge, especially if other ground water 

or upstream surface water users come on line before 

the time of license renewal. See § 51.53(c)(3)(ii)(A). 

Ground water use 

conflicts (Ranney 

wells) 

Site-specific SMALL, MODERATE, OR LARGE. Ranney wells can 

result in potential ground water depression beyond the 

site boundary. Impacts of large ground water 

withdrawal for cooling tower makeup at nuclear power 

plants using Ranney wells must be evaluated at the 

time of application for license renewal. See § 

51.53(c)(3)(ii)(C). 

Ground water 

quality 

degradation 

(Ranney wells) 

Generic SMALL. Ground water quality at river sites may be 

degraded by induced infiltration of poor-quality river 

water into an aquifer that supplies large quantities of 

reactor cooling water. However, the lower quality 

infiltrating water would not preclude the current uses of 

ground water and is not expected to be a problem 

during the license renewal term. 

Ground water 

quality 

degradation 

(saltwater 

intrusion) 

Generic SMALL. Nuclear power plants do not contribute 

significantly to saltwater intrusion. 

Ground water 

quality 

degradation 

Generic SMALL. Sites with closed-cycle cooling ponds may 

degrade ground water quality. Because water in salt 

marshes is brackish, this is not a concern for plants 
Appendix B 

Draft NUREG-1437, Supplement 42 B-6 February 2010 

Issue Type of Issue Finding

(cooling ponds in 

salt marshes) 

located in salt marshes. 

Ground water 

quality 

degradation 

(cooling ponds at 

inland sites) 

Site-specific SMALL, MODERATE, OR LARGE. Sites with closedcycle cooling ponds may degrade ground water quality. 

For plants located inland, the quality of the ground 

water in the vicinity of the ponds must be shown to be 

adequate to allow continuation of current uses. See § 

51.53(c)(3)(ii)(D). 

Terrestrial Ecology 

Refurbishment 

impacts 

Site-specific SMALL, MODERATE, OR LARGE. Refurbishment 

impacts are insignificant if no loss of important plant 

and animal habitat occurs. However, it cannot be 

known whether important plant and animal communities 

may be affected until the specific proposal is presented 

with the license renewal application. See § 

51.53(c)(3)(ii)(E). 

Cooling tower 

impacts on crops 

and ornamental 

vegetation 

Generic SMALL. Impacts from salt drift, icing, fogging, or 

increased humidity associated with cooling tower 

operation have not been found to be a problem at 

operating nuclear power plants and are not expected to 

be a problem during the license renewal term. 

Cooling tower 

impacts on native 

plants 

Generic SMALL. Impacts from salt drift, icing, fogging, or 

increased humidity associated with cooling tower 

operation have not been found to be a problem at 

operating nuclear power plants and are not expected to 

be a problem during the license renewal term. 

Bird collisions 

with cooling 

towers 

Generic SMALL. These collisions have not been found to be a 

problem at operating nuclear power plants and are not 

expected to be a problem during the license renewal 

term. 

Cooling pond 

impacts on 

terrestrial 

resources 

Generic SMALL. Impacts of cooling ponds on terrestrial 

ecological resources are considered to be of small 

significance at all sites. 

Power line right of 

way management 

(cutting and 

herbicide 

application) 

Generic SMALL. The impacts of right-of-way maintenance on 

wildlife are expected to be of small significance at all 

sites. 

Bird collisions 

with power lines 

Generic SMALL. Impacts are expected to be of small 

significance at all sites. 

Impacts of Generic SMALL. No significant impacts of electromagnetic fields 
Appendix B 

February 2010 B-7 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

electromagnetic 

fields on flora and 

fauna 

on terrestrial flora and fauna have been identified. Such 

effects are not expected to be a problem during the 

license renewal term. 

Floodplains and 

wetland on power 

line right of way 

Generic SMALL. Periodic vegetation control is necessary in 

forested wetlands underneath power lines and can be 

achieved with minimal damage to the wetland. No 

significant impact is expected at any nuclear power 

plant during the license renewal term. 

Threatened and Endangered Species 

Threatened or 

endangered 

species 

Site-specific SMALL, MODERATE, OR LARGE. Generally, plant 

refurbishment and continued operation are not 

expected to adversely affect threatened or endangered 

species. However, consultation with appropriate 

agencies would be needed at the time of license 

renewal to determine whether threatened or 

endangered species are present and whether they 

would be adversely affected. See § 51.53(c)(3)(ii)(E). 

Air Quality 

Air quality during 

refurbishment 

(non-attainment 

and maintenance 

areas) 

Site-specific SMALL, MODERATE, OR LARGE. Air quality impacts 

from plant refurbishment associated with license 

renewal are expected to be small. However, vehicle 

exhaust emissions could be cause for concern at 

locations in or near nonattainment or maintenance 

areas. The significance of the potential impact cannot 

be determined without considering the compliance 

status of each site and the numbers of workers 

expected to be employed during the outage. See § 

51.53(c)(3)(ii)(F). 

Air quality effects 

of transmission 

lines 

Generic SMALL. Production of ozone and oxides of nitrogen is 

insignificant and does not contribute measurably to 

ambient levels of these gases. 

Land Use 

Onsite land use Generic SMALL. Projected onsite land use changes required 

during refurbishment and the renewal period would be 

a small fraction of any nuclear power plant site and 

would involve land that is controlled by the applicant. 

Power line right of 

way 

Generic SMALL. Ongoing use of power line right of ways would 

continue with no change in restrictions. The effects of 

these restrictions are of small significance. 

Human Health 
Appendix B 

Draft NUREG-1437, Supplement 42 B-8 February 2010 

Issue Type of Issue Finding

Radiation 

exposures to the 

public during 

refurbishment 

Generic SMALL. During refurbishment, the gaseous effluents 

would result in doses that are similar to those from 

current operation. Applicable regulatory dose limits to 

the public are not expected to be exceeded. 

Occupational 

radiation 

exposures during 

refurbishment 

Generic SMALL. Occupational doses from refurbishment are 

expected to be within the range of annual average 

collective doses experienced for pressurized-water 

reactors and boiling-water reactors. Occupational 

mortality risk from all causes including radiation is in 

the mid-range for industrial settings. 

Microbiological 

organisms 

(occupational 

health) 

Generic SMALL. Occupational health impacts are expected to 

be controlled by continued application of accepted 

industrial hygiene practices to minimize worker 

exposures. 

Microbiological 

organisms (public 

health)(plants 

using lakes or 

canals, or cooling 

towers or cooling 

ponds that 

discharge to a 

small river) 

Site-specific SMALL, MODERATE, OR LARGE. These organisms 

are not expected to be a problem at most operating 

plants except possibly at plants using cooling ponds, 

lakes, or canals that discharge to small rivers. Without 

site-specific data, it is not possible to predict the effects 

generically. See § 51.53(c)(3)(ii)(G). 

Noise Generic SMALL. Noise has not been found to be a problem at 

operating plants and is not expected to be a problem at 

any plant during the license renewal term. 

Electromagnetic 

fields – acute 

effects (electric 

shock) 

Site-specific SMALL, MODERATE, OR LARGE. Electrical shock 

resulting from direct access to energized conductors or 

from induced charges in metallic structures have not 

been found to be a problem at most operating plants 

and generally are not expected to be a problem during 

the license renewal term. However, site-specific review 

is required to determine the significance of the electric 

shock potential at the site. See § 51.53(c)(3)(ii)(H). 

Electromagnetic 

fields – chronic 

effects 

Uncategorized UNCERTAIN. Biological and physical studies of 60-Hz 

electromagnetic fields have not found consistent 

evidence linking harmful effects with field exposures. 

However, research is continuing in this area and a 

consensus scientific view has not been reached. 

Radiation 

exposures to 

public (license 

renewal term) 

Generic SMALL. Radiation doses to the public will continue at 

current levels associated with normal operations. 
Appendix B 

February 2010 B-9 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

Occupational 

radiation 

exposures 

(license renewal 

term) 

Generic SMALL. Projected maximum occupational doses 

during the license renewal term are within the range of 

doses experienced during normal operations and 

normal maintenance outages, and would be well below 

regulatory limits. 

Socioeconomic Impacts 

Housing impacts Site-specific SMALL, MODERATE, OR LARGE. Housing impacts 

are expected to be of small significance at plants 

located in a medium or high population area and not in 

an area where growth control measures that limit 

housing development are in effect. Moderate or large 

housing impacts of the workforce associated with 

refurbishment may be associated with plants located in 

sparsely populated areas or in areas with growth 

control measures that limit housing development. See 

§ 51.53(c)(3)(ii)(I). 

Public services: 

public safety, 

social services, 

and tourism, and 

recreation 

Generic SMALL. Impacts to public safety, social services, and 

tourism and recreation are expected to be of small 

significance at all sites. 

Public services: 

public utilities 

Site-specific SMALL OR MODERATE. An increased problem with 

water shortages at some sites may lead to impacts of 

moderate significance on public water supply 

availability. See § 51.53(c)(3)(ii)(I). 

Public services: 

education 

(refurbishment) 

Site-specific SMALL, MODERATE, OR LARGE. Most sites would 

experience impacts of small significance but larger 

impacts are possible depending on site- and projectspecific factors. See § 51.53(c)(3)(ii)(I). 

Public services: 

education 

(license renewal 

term) 

Generic SMALL. Only impacts of small significance are 

expected 

Offsite land use 

(refurbishment) 

Site-specific SMALL OR MODERATE. Impacts may be of moderate 

significance at plants in low population areas. See § 

51.53(c)(3)(ii)(I). 

Offsite land use 

(license renewal 

term) 

Site-specific SMALL, MODERATE, OR LARGE. Significant changes 

in land use may be associated with population and tax 

revenue changes resulting from license renewal. See § 

51.53(c)(3)(ii)(I). 

Public services: Site-specific SMALL, MODERATE, OR LARGE. Transportation 
Appendix B 

Draft NUREG-1437, Supplement 42 B-10 February 2010 

Issue Type of Issue Finding

transportation impacts (level of service) of highway traffic generated 

during plant refurbishment and during the term of the 

renewed license are generally expected to be of small 

significance. However, the increase in traffic 

associated with the additional workers and the local 

road and traffic control conditions may lead to impacts 

of moderate or large significance at some sites. See § 

51.53(c)(3)(ii)(J). 

Historic and 

archaeological 

resources 

Site-specific SMALL, MODERATE, OR LARGE. Generally, plant 

refurbishment and continued operation are expected to 

have no more than small adverse impacts on historic 

and archaeological resources. However, the National 

Historic Preservation Act requires the Federal agency 

to consult with the State Historic Preservation Officer to 

determine whether there are properties present that 

require protection. See § 51.53(c)(3)(ii)(K). 

Aesthetic impacts 

(refurbishment) 

Generic SMALL. No significant impacts are expected during 

refurbishment. 

Aesthetic impacts 

(license renewal 

term) 

Generic SMALL. No significant impacts are expected during the 

license renewal term. 

Aesthetic impacts 

of transmission 

lines (license 

renewal term) 

Generic SMALL. No significant impacts are expected during the 

license renewal term. 

Postulated Accidents 

Design basis 

accidents 

Generic SMALL. The NRC staff has concluded that the 

environmental impacts of design basis accidents are of 

small significance for all plants. 

Severe accidents Site-specific SMALL. The probability weighted consequences of 

atmospheric releases, fallout onto open bodies of 

water, releases to ground water, and societal and 

economic impacts from severe accidents are small for 

all plants. However, alternatives to mitigate severe 

accidents must be considered for all plants that have 

not considered such alternatives. See § 

51.53(c)(3)(ii)(L). 

Uranium Fuel Cycle and Waste Management 

Offsite 

radiological 

impacts 

(individual effects 

Generic SMALL. Off-site impacts of the uranium fuel cycle have 

been considered by the Commission in Table S-3 of 

this part. Based on information in the GEIS, impacts on 

individuals from radioactive gaseous and liquid 
Appendix B 

February 2010 B-11 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

from other than 

the disposal of 

spent fuel and 

high level waste) 

releases including radon-222 and technetium-99 are 

small. 

Offsite 

radiological 

impacts 

(collective 

effects) 

Generic The 100 year environmental dose commitment to the 

U.S. population from the fuel cycle, high level waste 

and spent fuel disposal excepted, is calculated to be 

about 14,800 person rem, or 12 cancer fatalities, for 

each additional 20-year power reactor operating term. 

Much of this, especially the contribution of radon 

releases from mines and tailing piles, consists of tiny 

doses summed over large populations. This same 

dose calculation can theoretically be extended to 

include many tiny doses over additional thousands of 

years as well as doses outside the U. S. The result of 

such a calculation would be thousands of cancer 

fatalities from the fuel cycle, but this result assumes 

that even tiny doses have some statistical adverse 

health effect which will not ever be mitigated (for 

example no cancer cure in the next thousand years), 

and that these doses projected over thousands of 

years are meaningful. However, these assumptions are 

questionable. In particular, science cannot rule out the 

possibility that there will be no cancer fatalities from 

these tiny doses. For perspective, the doses are very 

small fractions of regulatory limits, and even smaller 

fractions of natural background exposure to the same 

populations. 

Nevertheless, despite all the uncertainty, some 

judgment as to the regulatory NEPA implications of 

these matters should be made and it makes no sense 

to repeat the same judgment in every case. Even 

taking the uncertainties into account, the Commission 

concludes that these impacts are acceptable in that 

these impacts would not be sufficiently large to require 

the NEPA conclusion, for any plant, that the option of 

extended operation under 10 CFR Part 54 should be 

eliminated. Accordingly, while the commission has not 

assigned a single level of significance for the collective 

effects of the fuel cycle, this issue is considered 

Category 1 [Generic]. 

Offsite 

radiological 

Generic For the high level waste and spent fuel disposal 

component of the fuel cycle, there are no current 
Appendix B 

Draft NUREG-1437, Supplement 42 B-12 February 2010 

Issue Type of Issue Finding

impacts (spent 

fuel and high 

level waste 

disposal) 

regulatory limits for offsite releases of radionuclides for 

the current candidate repository site. However, if we 

assume that limits are developed along the lines of the 

1995 National Academy of Sciences (NAS) report, 

"Technical Bases for Yucca Mountain Standards," and 

that in accordance with the Commission's Waste 

Confidence Decision, 10 CFR 51.23, a repository can 

and likely will be developed at some site which will 

comply with such limits, peak doses to virtually all 

individuals will be 100 millirem per year or less. 

However, while the Commission has reasonable 

confidence that these assumptions will prove correct, 

there is considerable uncertainty since the limits are 

yet to be developed, no repository application has 

been completed or reviewed, and uncertainty is 

inherent in the models used to evaluate possible 

pathways to the human environment. The NAS report 

indicated that 100 millirem per year should be 

considered as a starting point for limits for individual 

doses, but notes that some measure of consensus 

exists among national and international bodies that the 

limits should be a fraction of the 100 millirem per year. 

The lifetime individual risk from 100 millirem annual 

dose limit is about 3 x 10-3. 

Estimating cumulative doses to populations over 

thousands of years is more problematic. The likelihood 

and consequences of events that could seriously 

compromise the integrity of a deep geologic repository 

were evaluated by the Department of Energy in the 

"Final Environmental Impact Statement: Management 

of Commercially Generated Radioactive Waste," 

October 1980. The evaluation estimated the 70-year 

whole-body dose commitment to the maximum 

individual and to the regional population resulting from 

several modes of breaching a reference repository in 

the year of closure, after 1,000 years, after 100,000 

years and after 100,000,000 years. Subsequently, the 

NRC and other federal agencies have expended 

considerable effort to develop models for the design 

and for the licensing of a high level waste repository, 

especially for the candidate repository at Yucca 

Mountain. More meaningful estimates of doses to 

population may be possible in the future as more is 

understood about the performance of the proposed 

Yucca Mountain repository. Such estimates would 
Appendix B 

February 2010 B-13 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

involve very great uncertainty, especially with respect 

to cumulative population doses over thousands of 

years. The standard proposed by the NAS is a limit on 

maximum individual dose. The relationship of potential 

new regulatory requirements, based on the NAS 

report, and cumulative population impacts has not 

been determined, although the report articulates the 

view that protection of individuals will adequately 

protect the population for a repository at Yucca 

Mountain. However, EPA's generic repository 

standards in 40 CFR Part 191 generally provide an 

indication of the order of magnitude of cumulative risk 

to population that could result from the licensing of a 

Yucca Mountain repository, assuming the ultimate 

standards will be within the range of standards now 

under consideration. The standards in 40 CFR Part 

191 protect the population by imposing amount of 

radioactive material released over 10,000 years. The 

cumulative release limits are based on EPA's 

population impact goal of 1,000 premature cancer 

deaths worldwide for a 100,000 metric ton (MTHM) 

repository. 

Nevertheless, despite all the uncertainty, some 

judgment as to the regulatory NEPA implications of 

these matters should be made and it makes no sense 

to repeat the same judgment in every case. Even 

taking the uncertainties into account, the Commission 

concludes that these impacts are acceptable in that 

these impacts would not be sufficiently large to require 

the NEPA conclusion, for any plant, that the option of 

extended operation under 10 CFR Part 54 should be 

eliminated. Accordingly, while the Commission has not 

assigned a single level of significance for the impacts 

of spent fuel and high level waste disposal, this issue is 

considered in Category 1 [Generic]. 

Nonradiological 

impacts of the 

uranium fuel 

cycle 

Generic SMALL. The nonradiological impacts of the uranium 

fuel cycle resulting from the renewal of an operating 

license for any plant are found to be small. 

Low-level waste 

storage and 

disposal 

Generic SMALL. The comprehensive regulatory controls that 

are in place and the low public doses being achieved 

at reactors ensure that the radiological impacts to the 

environment will remain small during the term of a 

renewed license. The maximum additional on-site land 
Appendix B 

Draft NUREG-1437, Supplement 42 B-14 February 2010 

Issue Type of Issue Finding

that may be required for low-level waste storage during 

the term of a renewed license and associated impacts 

will be small. 

Nonradiological impacts on air and water will be 

negligible. The radiological and nonradiological 

environmental impacts of long-term disposal of lowlevel waste from any individual plant at licensed sites 

are small. In addition, the Commission concludes that 

there is reasonable assurance that sufficient low-level 

waste disposal capacity will be made available when 

needed for facilities to be decommissioned consistent 

with NRC decommissioning requirements. 

Mixed waste 

storage and 

disposal 

Generic SMALL. The comprehensive regulatory controls and 

the facilities and procedures that are in place ensure 

proper handling and storage, as well as negligible 

doses and exposure to toxic materials for the public 

and the environment at all plants. License renewal will 

not increase the small, continuing risk to human health 

and the environment posed by mixed waste at all 

plants. The radiological and nonradiological 

environmental impacts of long-term disposal of mixed 

waste from any individual plant at licensed sites are 

small. In addition, the Commission concludes that 

there is reasonable assurance that sufficient mixed 

waste disposal capacity will be made available when 

needed for facilities to be decommissioned consistent 

with NRC decommissioning requirements. 

On-site spent fuel Generic SMALL. The expected increase in the volume of spent 

fuel from an additional 20 years of operation can be 

safely accommodated on site with small environmental 

effects through dry or pool storage at all plants if a 

permanent repository or monitored retrievable storage 

is not available. 

Nonradiological 

waste 

Generic SMALL. No changes to generating systems are 

anticipated for license renewal. Facilities and 

procedures are in place to ensure continued proper 

handling and disposal at all plants. 

Transportation Generic SMALL. The impacts of transporting spent fuel 

enriched up to 5 percent uranium-235 with average 

burnup for the peak rod to current levels approved by 

NRC up to 62,000 MWd/MTU and the cumulative 

impacts of transporting high-level waste to a single 

repository, such as Yucca Mountain, Nevada are found 

to be consistent with the impact values contained in 10 
Appendix B 

February 2010 B-15 Draft NUREG-1437, Supplement 42 

Issue Type of Issue Finding

CFR 51.52(c), Summary Table S–4 – Environmental 

Impact of Transportation of Fuel and Waste to and 

from One Light-Water-Cooled Nuclear Power Reactor. 

If fuel enrichment or burnup conditions are not met, the 

applicant must submit an assessment of the 

implications for the environmental impact values 

reported in § 51.52. 

Decommissioning 

Radiation doses Generic SMALL. Doses to the public will be well below 

applicable regulatory standards regardless of which 

decommissioning method is used. Occupational doses 

would increase no more than 1 man-rem caused by 

buildup of long-lived radionuclides during the license 

renewal term. 

Waste 

management 

Generic SMALL. Decommissioning at the end of a 20-year 

license renewal period would generate no more solid 

wastes than at the end of the current license term. No 

increase in the quantities of Class C or greater than 

Class C wastes would be expected. 

Air quality Generic SMALL. Air quality impacts of decommissioning are 

expected to be negligible either at the end of the 

current operating term or at the end of the license 

renewal term. 

Water quality Generic SMALL. The potential for significant water quality 

impacts from erosion or spills is no greater whether 

decommissioning occurs after a 20-year license 

renewal period or after the original 40-year operation 

period, and measures are readily available to avoid 

such impacts. 

Ecological 

resources 

Generic SMALL. Decommissioning after either the initial 

operating period or after a 20-year license renewal 

period is not expected to have any direct ecological 

impacts. 

Socioeconomic 

impacts 

Generic SMALL. Decommissioning would have some shortterm socioeconomic impacts. The impacts would not 

be increased by delaying decommissioning until the 

end of a 20-year relicense period, but they might be 

decreased by population and economic growth. 

Environmental Justice 

Environmental 

Justice 

Uncategorized NONE. The need for and the content of an analysis of 

environmental justice will be addressed in plant-
Appendix B 

Draft NUREG-1437, Supplement 42 B-16 February 2010 

Issue Type of Issue Finding

specific reviews. 

1 
Appendix C 

Applicable Regulations, Laws, and Agreements 

Appendix C 

February 2010 C-1 Draft NUREG-1437, Supplement 42 

1 C. Applicable Regulations, Laws, and Agreements 

2 Table C-1 lists environmental authorizations for current Duane Arnold Energy Center (DAEC) 

3 operations. In this context “authorizations” includes any permits, licenses, approvals, or other 

4 entitlements. FPL Energy Duane Arnold, LLC (FPL-DA) expects to continue renewing these 

5 authorizations during the current license period and through the U.S. Nuclear Regulatory 

6 Commission (NRC) license renewal period. 

7 

8 Table C-2 lists additional environmental authorizations and consultations related to FPL-DA 

9 renewal of the DAEC license to operate. As indicated, FPL-DA anticipates needing relatively 

10 few such authorizations and consultations. Sections C.1 through C.5 discuss some of these 

11 items in more detail. 

12 

13 C.1 HISTORIC PRESERVATION 

14 

15 Under Section 106 of the National Historic Preservation Act (16 USC 470 et seq.), federal 

16 agencies having the authority to license any undertaking, prior to issuing the license, shall take 

17 into account the effect of the undertaking on historic properties and shall afford the Advisory 

18 Committee on Historic Preservation an opportunity to comment on the undertaking. Committee 

19 regulations provide for establishing an agreement with any State Historic Preservation Officer 

20 (SHPO) to substitute state review for Committee review (35 CFR 800.7). The results of this 

21 review are presented in Chapter 4. 

22 

23 C.2 THREATENED OR ENDANGERED SPECIES 

24 

25 Pursuant to Section 7 of the Endangered Species Act (16 USC 1531 et seq.), federal agencies 

26 are required to ensure that agency action is not likely to jeopardize any species that is listed or 

27 proposed for listing as endangered or threatened. Depending on the action involved, the Act 

28 requires consultation with the U.S. Fish and Wildlife Service (FWS) regarding effects on non29 marine species, the National Marine Fisheries Service (NMFS) for marine species, or both. 

30 FWS and NMFS have issued joint procedural regulations at 50 CFR 402, Subpart B, that 

31 address consultation, and FWS maintains the joint list of threatened and endangered species at 

32 50 CFR 17. An assessment of the effects on threatened or endangered species is presented in 

33 Chapter 4. 

34 

35 C.3 WATER QUALITY (401) CERTIFICATION 

36 

37 Under the Federal Clean Water Act, Section 401, applicants for a federal license to conduct an 

38 activity that might result in a discharge into navigable waters are required to provide the 

39 licensing agency a certification from the state that the discharge will comply with applicable 

40 Clean Water Act requirements (33 USC 1341). NRC has indicated in its Generic Environmental 

41 Impact Statement for License Renewal of Nuclear Power Plants (GEIS) that issuance of a 

42 National Pollutant Discharge Elimination System (NPDES) permit implies certification by the 

43 state (NRC 1996e). The U.S. Environmental Protection Agency granted the State of Iowa 

44 authority to issue NPDES permits. FPL-DA is applying to NRC for license renewal to continue 

45 DAEC operations. Hydrological Impacts are presented in Chapter 4. 
Appendix C 

Draft NUREG-1437, Supplement 42 C-2 February 2010 

1 C.4 COASTAL ZONE MANAGEMENT PROGRAM COMPLIANCE 

2 

3 The Federal Coastal Zone Management Act (16 USC 1451 et seq.) imposes requirements on 

4 applicants for a federal license to conduct an activity that could affect a state’s coastal zone. 

5 The Act requires an applicant to certify to the licensing agency that the proposed activity would 

6 be consistent with the state’s federally approved coastal zone management program [16 USC 

7 1456(c)(3)(A)]. The National Oceanic and Atmospheric Administration has promulgated 

8 implementing regulations indicating that the requirement is applicable to renewal of federal 

9 licenses for activities not previously reviewed by the state [15 CFR 930.51(b)(1)]. The regulation 

10 requires that the license applicant provide its certification to the federal licensing agency and a 

11 copy to the applicable state agency [15 CFR 930.57(a)]. Iowa is not included in the coastal zone 

12 management program and therefore this requirement is not applicable to DAEC. 
Appendix C 

February 2010 C-3 Draft NUREG-1437, Supplement 42 

1 TABLE C-1 

2 Environmental Authorizations for Current DAEC Operations

Agency Authority Requirement Issuance or 

Expiration Date 

Federal and State Requirements

U.S. Nuclear 

Regulatory 

Commission

Atomic Energy Act 

(42 USC 2011, et 

seq.), 10 CFR 50.10 

License to operate Issued: 02/21/1974 

Expires: 02/21/2014

U.S. Department of 

Transportation

49 USC 5108 Registration Issued: 07/09/2008 

Expires: 06/30/2011 

U.S. Environmental 

Protection 

Agency

Federal Resource 

Conservation and 

Recovery Act 

(42 USC 6912) 

Notification of 

Regulated Waste 

Activity

NA

Iowa Department of 

Natural 

Resources

Code of Iowa 455B 

and 

IAC 567:71

Permit for water 

intake and discharge 

structures and low 

head dam on Cedar 

River 

Issued: 08/06/1971

Iowa Department of 

Natural Resources 

Code of Iowa 455B 

and IAC 567:50-51 

Permit to store water 

in Pleasant Creek 

Reservoir and 

withdraw water from 

Cedar River 

Issued: 03/14/2004 

Expires:03/13/2014

Iowa Department of 

Natural Resources 

Clean Water Act 

Section 401 (33 

U.S.C. 1341) 

Water Quality 

Certification

Issued: 08/26/2005

U.S. Army Corps 

of Engineers

Rivers and Harbors 

Act of 1899 Section 

10 (33 U.S.C. 403) 

Clean Water Act 

Section 404 (33 

U.S.C. 1344) 

Marine Protection, 

Research and 

Sanctuaries Act of 

1972 Section 103 (33 

U.S.C. 1413) 

Dredging 

Permit

Issued: 09/20/2005 

Expires: 12/31/2010

Linn County Linn County Flood 

Plain 

Management 

Regulations 

Flood Plain 

Development 

Permit 

Issued: 12/04/2007 

Expires: 12/04/2008 
Appendix C 

Draft NUREG-1437, Supplement 42 C-4 February 2010 

Agency Authority Requirement Issuance or 

Expiration Date 

Iowa Department 

of Natural Resources 

Code of Iowa Chapter 

461A

Sovereign Lands 

Construction Permit 

Issued: 10/10/2006 

Expires:12/31/2008

Iowa Department 

of Natural Resources 

Code of Iowa Chapter 

461A 

Sovereign Lands 

Construction Permit 

Issued: 11/07/2007 

Expires:12/31/2009

Iowa Department 

of Natural Resources 

Code of Iowa 455B 

and IAC 567:50-51 

Operator certification Issued: 08/29/2007 

Expires: 06/30/2009

Iowa Department 

of Natural Resources 

Clean Water Act (33 

USC Section 1251 et 

seq.), Iowa Code 

455B.174, IAC 567- 

64.3 

NPDES Permit Issued: 07/06/2007 

Expires: 07/05/2009

Linn County Federal Clean Air Act 

(42 USC 7661-7671), 

Iowa Code 455B:567, 

IAC 20-31, LCCO 

10.5 

Air Operation Permit Expires 11/10/2008

Iowa Department 

of Public Health

Iowa Homeland 

Security Emergency 

Management 

Transportation 

Service License 

Issued: 06/25/2007 

Expires: 06/30/2009

Iowa Department 

of Natural Resources 

Code of Iowa Chapter 

455B and part 567 

Permit to operate 

public water system 

Issued: 11/21/2006 

Expires: 12/31/2009

Iowa Department 

of Natural Resources 

Code of Iowa 455B 

and IAC 567:50-51 

Permit to operate 4- 

well system for 

potable water 

Issued: 07/01/2002 

Expires: 06/30/2012

Iowa Department 

of Natural Resources 

IAC 467-135.1(3)c Deferral of UST 

regulation to NRC 

NA

Tennessee 

Department of 

Environment and 

Conservation 

Tennessee Code 

Annotated 68-202-206 

License to ship 

Radioactive material 

Expires: 12/31/2008

Utah Department 

of Environmental 

Quality 

Utah Rule 313-26 License to ship 

Radioactive material 

Expires: 10/27/2008

NA- Not Applicable NRC – Nuclear Regulatory Commission 

US- United States Code IAC – Iowa Administrative Code 

LCCO – Linn County Code of Ordinances NPDES – National 

Pollutant Discharge Elimination System UST – Underground 

Storage Tank 

 
Appendix C 

February 2010 C-5 Draft NUREG-1437, Supplement 42 

1 TABLE C-2 

2 Environmental Authorizations for DAEC License Renewal

Agency Authority Requirement Remarks

U.S. Nuclear 

Regulatory Commission 

Atomic Energy Act 

(42 USC 2011 et seq.) 

License renewal Environmental Report 

submitted in support 

of license renewal 

Application 

U.S. Fish and Wildlife 

Service

Endangered Species 

Act Section 7 

(16 USC 1536)

Consultation Requires federal 

agency issuing 

a license to consult 

with the FWS 

(Appendix C) 

Iowa Department of 

Natural Resources

Endangered and 

Threatened Species 

Laws (State Statute 

29.604 & 

Administrative Rule 

NR 27)

Endangered 

Resources Review

Review explains what 

rare species, natural 

communities, or 

natural features 

tracked in the Natural 

Heritage Inventory 

database are found in 

or near the proposed 

project area. And 

any additional steps to 

assure compliance 

with the Iowa 

endangered species 

protection laws and 

regulations. 

(Attachment C) 

Iowa Department of 

Natural Resources

Clean Water Act 

Section 401 

(33 USC 1341)

Certification Requires State 

certification that 

proposed action 

would comply with 

Clean Water Act 

standards 

Iowa Historic 

Preservation Office

National Historic 

Preservation Act 

Section 106 

(16 USC 470f)

Consultation Requires federal 

agency issuing 

a license to consider 

cultural impacts and 

consult with State 

Historic Preservation 

Officer (Attachment D)

Appendix D 

Consultation Correspondence 

February 2010 D-1 Draft NUREG-1437, Supplement 42 

D. Consultation Correspondences 

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

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

1966 require that Federal agencies consult with applicable State and Federal agencies 

and groups prior to taking action that may affect threatened and endangered species, 

essential fish habitat, or historic and archaeological resources, respectively. This 

appendix contains consultation documentation.

Table D-1. Consultation Correspondences. This is a list of the consultation 

documents sent between the NRC and other agencies we are required to 

consult with based on NEPA requirements.(a) 

Author Recipient Date of Letter

U.S. Nuclear Regulatory 

Commission 

Iowa Department of Natural 

Resources (W. Gleselman) 

May 6, 2009 

U.S. Nuclear Regulatory 

Commission 

National Oceanographic and 

Atmospheric Administration, 

National Marine Fisheries Service 

(R. Crabtree) 

May 6, 2009 

U.S. Nuclear Regulatory 

Commission 

U.S. Fish and Wildlife Service, 

Region 3 (T. Melius) May 6, 2009 

U.S. Nuclear Regulatory 

Commission 

Iowa Office of the State 

Archaeologist, State Archaeologist 

(J. Doershuck) 

May 7, 2009 

U.S. Nuclear Regulatory 

Commission 

Advisory Council on Historic 

Preservation (C. Vuaghin) 

May 7, 2009 

U.S. Nuclear Regulatory 

Commission 

Historic Preservation Officer State 

Historical Society of Iowa (J. 

Thompson) 

May 7, 2009 

U.S. Nuclear Regulatory 

Commission ITC Midwest, LLC September 28, 2009 

Iowa Department of Natural 

Resources 

U.S. Nuclear Regulatory 

Commission

May 18, 2009

U.S. Fish and Wildlife Service U.S. Nuclear Regulatory 

Commission 

May 29, 2009 

(a) Similar letters went to nineteen Native American Tribes listed in Section 1.8. 
Appendix D 

Draft NREG-1437, Supplement 42 D-2 February 2010 

D.1 Consultation Correspondence 

The following pages contain copies of the letters listed in Table D-1. 
Appendix D 

February 2010 D-3 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-4 February 2010 
Appendix D 

February 2010 D-5 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-6 February 2010 
Appendix D 

February 2010 D-7 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-8 February 2010 
Appendix D 

February 2010 D-9 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-10 February 2010 
Appendix D 

February 2010 D-11 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-12 February 2010 
Appendix D 

February 2010 D-13 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-14 February 2010 
Appendix D 

February 2010 D-15 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-16 February 2010 
Appendix D 

February 2010 D-17 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-18 February 2010 
Appendix D 

February 2010 D-19 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-20 February 2010 
Appendix D 

February 2010 D-21 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-22 February 2010 
Appendix D 

February 2010 D-23 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-24 February 2010 
Appendix D 

February 2010 D-25 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-26 February 2010 
Appendix D 

February 2010 D-27 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-28 February 2010 
Appendix D 

February 2010 D-29 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-30 February 2010 
Appendix D 

February 2010 D-31 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-32 February 2010 
Appendix D 

February 2010 D-33 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-34 February 2010 
Appendix D 

February 2010 D-35 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-36 February 2010 
Appendix D 

February 2010 D-37 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-38 February 2010 
Appendix D 

February 2010 D-39 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-40 February 2010 
Appendix D 

February 2010 D-41 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-42 February 2010 
Appendix D 

February 2010 D-43 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-44 February 2010 
Appendix D 

February 2010 D-45 Draft NUREG-1437, Supplement 42 
Appendix D 

Draft NREG-1437, Supplement 42 D-46 February 2010 
Appendix E 

Chronology of Environmental Review 

Draft NUREG-1437, Supplement 42 E-1 February 2010 

1 E. 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 environmental review for 

4 Three Mile Island Nuclear Station, Unit 1. All documents, with the exception of those containing 

5 proprietary information are available electronically from the NRC’s Public Electronic Reading 

6 Room found on the Internet at the following Web address: http://www.nrc.gov/reading-rm.html. 

7 From this site, the public can gain access to the NRC’s Agencywide Document Access and 

8 Management System (ADAMS), which provides text and image files of NRC’s public documents 

9 in ADAMS. The ADAMS accession number for each document is included below. 

10 

11 E.1 Environmental Review Correspondence 

September 30, 2008 Application submitted by FPL Energy Duane Arnold, LLC (FPL-DA) for 

renewal of Facility Operating License No. DPR-49 for an additional 20 

years of operation at Duane Arnold Energy Center (DAEC). 

February 17, 2009 United States Nuclear Regulatory Commission (NRC) issued “United 

states nuclear regulatory commission Notice of acceptance for docketing 

of the application and notice of opportunity for hearing regarding renewal 

of facility operating license no. Dpr-49 for an additional 20-year period, 

Duane arnold energy center docket no. 50-331” 

March 24, 2009 NRC issued Notice of Intent to prepare an environmental Impact 

statement and conduct scoping process, Docket no. 50-331 

May 6, 2009 Consultation letter to Robyn Thorson, Regional Director Region 3, U.S. 

Fish and Wildlife Service “Request For List Of Protected Species within 

the Area Under Evaluation For The Duane Arnold Energy Center License 

Renewal Application Review” 

May 6, 2009 Consultation letter to Wayne Gieselman, Administrator Iowa Department 

of Natural Resources “Request For List Of Protected Species And Water 

Usage Impacts Within The Area Under Evaluation For The Duane Arnold 

Energy Center License Renewal Application Review” 

May 6, 2009 Consultation letter to Patricia Kurkul, Regional Administrator, National 

Marine Fisheries Service, “Request for list of protected species and 

essential fish habitat within the area under evaluation for the (plant name, 

e.g. millstone power station, units 2 and 3) license renewal application 

review” 

May 6, 2009 Letter to Christie Modlin, Chairperson Iowa Tribe of Oklahoma inviting 

them to participate in the scoping process related to NRC’s environmental 

review of the license application for the Duane Arnold Energy Center. 
Appendix E 

Draft NUREG-1437, Supplement 42 E-2 February 2010 

May 7, 2009 Consultation letter to Charlene Dwin Vaughn, Assistant Director Federal 

Permitting, Licensing, and Assistance Section Advisory Council on 

Historic Preservation 

May 7, 2009 Consultation letter to John Doershuck State Archaeologist Office of the 

State Archaeologist 

May 7, 2009 Consultation letter to Mr. Jerome Thompson, Interim-SHPO, State 

Historical Society of Iowa 

May 14, 2009 George Thurman, Principal Chief Sac and Fox Nation of Oklahoma 

inviting them to participate in the scoping process related to NRC’s 

environmental review of the license application for the Duane Arnold 

Energy Center. 

May 14, 2009 Letter to Fredia Perkins, Chairperson Sac and Fox Nation of Missouri 

inviting them to participate in the scoping process related to NRC’s 

environmental review of the license application for the Duane Arnold 

Energy Center. 

May 14, 2009 Letter to Steve Ortiz, Chairman Prairie Band of Potawatomi Indians 

inviting them to participate in the scoping process related to NRC’s 

environmental review of the license application for the Duane Arnold 

Energy Center. 

May 14, 2009 Letter to Joshua Weston, President Flandreau Santee Sioux Tribe inviting 

them to participate in the scoping process related to NRC’s environmental 

review of the license application for the Duane Arnold Energy Center. 

May 14, 2009 Letter to Mr. Roger Trudell, Chairman Santee Sioux Nation inviting them 

to participate in the scoping process related to NRC’s environmental 

review of the license application for the Duane Arnold Energy Center. 

May 14, 2009 Letter to John Blackhawk, Chairman Winnebago Tribe of Nebraska 

inviting them to participate in the scoping process related to NRC’s 

environmental review of the license application for the Duane Arnold 

Energy Center. 

May 14, 2009 Letter to Ronald Johnson, President Prairie Island Indian Community 

inviting them to participate in the scoping process related to NRC’s 

environmental review of the license application for the Duane Arnold 

Energy Center. 

May 14, 2009 Letter to Stanley R. Crooks, Chairman Shakopee Mdewakanton Sioux 

Community of Minnesota inviting them to participate in the scoping 

process related to NRC’s environmental review of the license application 
Appendix E 

February 2010 E-3 Draft NUREG-1437, Supplement 42 

 for the Duane Arnold Energy Center. 

May 14, 2009 Letter to Kevin Jensvold, Chairman Upper Sioux Community of 

Minnesota inviting them to participate in the scoping process related to 

NRC’s environmental review of the license application for the Duane 

Arnold Energy Center. 

May 14, 2009 Letter to Wilfred Cleveland, President Ho-Chunk Nation inviting them to 

participate in the scoping process related to NRC’s environmental review 

of the license application for the Duane Arnold Energy Center. 

May 14, 2009 Letter to The Sac and Fox Tribe of the Mississippi: Adrian Pushetonequa, 

Chairman inviting them to participate in the scoping process related to 

NRC’s environmental review of the license application for the Duane 

Arnold Energy Center. 

May 26, 2009 Letter to Lori Nelson, Acting Lower Sioux Indian Community of 

Minnesota inviting them to participate in the scoping process related to 

NRC’s environmental review of the license application for the Duane 

Arnold Energy Center. 

May 26, 2009 Letter to Amen Sheriden, Chairman Omaha Tribal Council inviting them 

to participate in the scoping process related to NRC’s environmental 

review of the license application for the Duane Arnold Energy Center. 

May 26, 2009 Letter to Marlon E. Frye, Chairman Kickapoo Tribe of Oklahoma inviting 

them to participate in the scoping process related to NRC’s environmental 

review of the license application for the Duane Arnold Energy Center. 

May 26, 2009 Letter to John Shotton Otoe-Missouria Tribe of Indians inviting them to 

participate in the scoping process related to NRC’s environmental review 

of the license application for the Duane Arnold Energy Center. 

May 26, 2009 Letter to Leon Campbell, Chairman Iowa Tribe of Kansas and Nebraska 

inviting them to participate in the scoping process related to NRC’s 

environmental review of the license application for the 

June 17, 2009 Summary of public license renewal overview and environmental scoping 

meetings related to the review of the Duane Arnold Energy Center license 

renewal application (TAC No. MD 9770) 

August 7, 2009 Issuance of environmental scoping summary report associated with the 

staff’s review of the application for renewal of the operating license. 

1 

 

Appendix F 

U.S. Nuclear Regulatory Commission Staff Evaluation of Severe 

Accident Mitigation Alternatives for Duane Arnold Energy Center in 

Support of License Renewal Application Review 

February 2010 F-1 Draft NUREG-1437, Supplement 42 

1 F. U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 

2 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR DUANE 

3 ARNOLD ENERGY CENTER IN SUPPORT OF LICENSE RENEWAL 

4 APPLICATION REVIEW 

5 F.1. Introduction 

6 FPL Energy Duane Arnold, (FPL-DA) submitted an assessment of severe accident mitigation 

7 alternatives (SAMAs) for the Duane Arnold Energy Center (DAEC) as part of the environmental 

8 report (ER) (FPL-DA, 2008). Supplemental information on the SAMA assessment was provided 

9 in response to a U.S. Nuclear Regulatory Commission (NRC) staff request (FPL-DA, 2009). 

10 This assessment was based on the most recent DAEC probabilistic risk assessment (PRA) 

11 available at that time, a plant-specific offsite consequence analysis using the MELCOR Accident 

12 Consequence Code System 2 (MACCS2) computer code, and insights from the DAEC 

13 individual plant examination (IPE) (IELP, 1992) and individual plant examination of external 

14 events (IPEEE) (IES, 1995a). In identifying and evaluating potential SAMAs, FPL-DA 

15 considered SAMAs that addressed the major contributors to core damage frequency (CDF) as 

16 well as SAMA candidates for other operating plants that have submitted license renewal 

17 applications. FPL-DA initially identified 166 potential SAMAs. This list was reduced to 24 unique 

18 SAMA candidates by eliminating SAMAs that: are not applicable to DAEC due to design 

19 differences, have already been implemented at DAEC, are similar in nature and could be 

20 combined with another SAMA candidate, or have excessive implementation cost. FPL-DA 

21 assessed the costs and benefits associated with each of the potential SAMAs and concluded in 

22 the ER that several of the candidate SAMAs evaluated are potentially cost-beneficial. 

23 F.1.1. Based on a review of the SAMA assessment, the NRC staff issued a request for 

24 additional information (RAI) to FPL-DA by letter dated June 25, 2009 (NRC, 2009a) 

25 and a request for RAI response clarification by letter dated August 24, 2009 (NRC, 

26 2009b). Key questions concerned: the dominant contributors to CDF; clarification 

27 to the historical development of the Level 1 PRA; source term and release time 

28 category assignment assumptions used in the Level 2 and Level 3 analyses; 

29 additional details on the seismic and fire risk assessment models and their results; 

30 further information on the selection and screening of SAMA candidates; and 

31 further information on the cost benefit analysis of several specific candidate 

32 SAMAs and low cost alternatives. FPL-DA (under the name of NextEra Energy 

33 Duane Arnold, LLC) submitted additional information by letters dated July 9, 2009 

34 (NextEra, 2009a) and September 23, 2009 (NextEra, 2009b). Corrections to the 

35 license renewal application were contained in an amendment to the application 

36 dated September 30, 2009 (NextEra, 2009c). In the responses, FPL-DA provided: a 

37 listing of the contribution to CDF by initiating an event and a tabulation of risk 

38 reduction worth (RRW) importance; clarification of PRA revision dates and CDF 

39 results; a discussion of the Level 2 analysis and the process for assigning severe 

40 accident source terms and binning release categories; further details on the 

41 external events PRA models, their results, and the potential for additional SAMAs 
Appendix F 

Draft NUREG-1437, Supplement 42 F-2 February 2010 

1 based on these results; further support for the screening of certain SAMA 

2 candidates; and additional information regarding several specific SAMAs. 

3 The licensee’s responses addressed the NRC staff’s concerns and resulted in the 

4 identification of one 

5 Two distinct analyses are combined additional potentially cost-beneficial SAMA. 

6 F.2. Estimate of Risk for Duane Arnold Energy Center 

7 FPL-DA’s estimates of offsite risk at DAEC are summarized in Section G 2.1. The summary is 

8 followed by the NRC staff’s review of FPL-DA’s risk estimates in Section G 2.2. 

9 FPL Energy Duane Arnold, LLC’s Risk Estimates to form the basis for the risk estimates used in 

10 the SAMA analysis: (1) the DAEC Level 1 and 2 PRA model, which is an updated version of the 

11 IPE (IELP, 1992), and (2) a supplemental analysis of offsite consequences and economic 

12 impacts (essentially a Level 3 PRA model) developed specifically for the SAMA analysis. The 

13 SAMA analysis is based on the most recent DAEC Level 1 and Level 2 PRA models available at 

14 the time of the ER, referred to as the DAEC PRA (Revision 5C, July 2007 model). While FPL15 DA states that the scope of the current DAEC Level 1 PRA includes external (fire and seismic) 

16 events, the SAMA analysis did not explicitly include the external events models for identifying 

17 SAMAs or evaluating the benefit of SAMAs. FPL-DA stated that fire and seismic models were 

18 not explicitly included in determining the benefit of a SAMA because Level 2 models were not 

19 available for external events; thus risk impacts could not be determined for these events 

20 (NextEra, 2009a). 

21 The baseline CDF for the purpose of the SAMA evaluation is approximately 1.08  10-5 per 

22 year. The CDF is based on the risk assessment for internally initiated events. FPL-DA did not 

23 explicitly include the contribution from external events within the DAEC risk estimates; however, 

24 it did account for the potential risk reduction benefits associated with external events by 

25 multiplying the estimated benefits for internal events by a factor of 1.57. This is discussed 

26 further in Sections G 2.2 and G 6.2. 

27 The breakdown of CDF by initiating event is provided in Table G-1. As shown in this table, 

28 events initiated by loss of offsite power and other transients (turbine trip, main steam isolation 

29 valve (MSIV) closure and inadvertent open relief valve) are the dominant contributors to the 

30 CDF. Although not reported separately, station blackout (SBO) sequences account for 34 

31 percent of the CDF, and anticipated transient without scram (ATWS) sequences account for 29 

32 percent of the CDF. Internal floods contribute less than 1 percent of the CDF (NextEra, 2009a). 
Appendix F 

February 2010 F-3 Draft NUREG-1437, Supplement 42 

1 Table F-1. Duane Arnold Energy Center Core Damage Frequency for Internal Events 

Initiating Event 

CDF(a) 

(per year) 

Percent Contribution 

to CDF 

Loss of Offsite Power 4.0  10–6 37 

Turbine Trip with Bypass 1.6  10–6 15 

MSIV Closure 1.4  10–6 13 

Inadvertent Open Relief Valve 1.2  10–6 11 

Loss of Condenser Vacuum 5.9  10–7 6 

Div 2 125 Volt DC Bus Failure 3.2  10–7 3 

Manual shutdown 2.8  10–7 3 

Loss of River Water Supply 2.8  10–7 3 

Small loss of coolant accident (LOCA) 2.7  10–7 3 

Loss of Feedwater 2.5  10–7 2 

Medium LOCA 1.9  10–7 2 

Div 1 125 Volt DC Bus Failure 1.3  10–7 1 

Others (less than 1 percent each) 2.8  10–7 3 

Total CDF (internal events)(b)

1.08  10–5 100 

(a) 2 Based on percent contribution from ER (NextEra, 2009a) and total CDF 

(b) 3 Column totals may be different due to round off 

4 The Level 2 DAEC PRA model that forms the basis for the SAMA evaluation is essentially the 

5 original IPE Level 2 model applied to the revised Level 1 model. The Level 2 model utilizes 

6 three containment event trees (CETs) containing both phenomenological and systemic events. 

7 The Level 1 core damage sequences are binned into accident classes which provide the 

8 interface between the Level 1 and Level 2 CET analysis. The CETs are linked directly to the 

9 Level 1 event trees and CET nodes are evaluated using supporting fault trees. 

10 The result of the Level 2 PRA is a set of 12 release categories, also referred to as source term 

11 categories (STCs), with their respective frequency and release characteristics. The results of 

12 this analysis for DAEC are provided in Table 3.4.3-2 of Appendix F to the ER (FPL-DA, 2008). 

13 The frequency of each release category was obtained by summing the frequency of the 

14 individual accident progression CET endpoints binned into the release category. Source terms 

15 were developed for each of the 12 release categories using the results of Modular Accident 

16 Analysis Program (MAAP 3.0B) computer code calculations. 

17 The offsite consequences and economic impact analyses use the MACCS2 code to determine 

18 the offsite risk impacts on the surrounding environment and general public. Inputs for these 
Appendix F 

Draft NUREG-1437, Supplement 42 F-4 February 2010 

1 analyses include plant-specific and site-specific input values for core radionuclide inventory, 

2 source term and release characteristics, site meteorological data, projected population 

3 distribution (within a 50-mile radius) for the year 2040, emergency response evacuation 

4 modeling, and economic data. The core radionuclide inventory corresponds to the end-of-cycle 

5 values for DAEC accounting for the 2007 plant power upgrade to 1,912 (megawatt-thermal 

6 (MWt) and reflects the expected fuel management and burnup during the license renewal period 

7 (NextEra, 2009a). The magnitude of the onsite impacts (in terms of clean-up and 

8 decontamination costs and occupational dose) is based on information provided in NUREG/BR9 0184 (NRC 1997a). 

10 In the ER, FPL-DA estimated the dose to the population within 50-miles (80-km) of the DAEC 

11 site to be approximately 19.8 person-roentgen equivalent man (rem) per year. The breakdown 

12 of the total population dose by containment release mode is summarized in Table G-2. 

13 Containment failures within the early time frame (0 to less than 6 hours following event initiation) 

14 dominate the population dose risk at DAEC. 

15 Table G-2. Breakdown of Population Dose by Containment Release Mode 

Containment Release Mode 

Population Dose 

(Person-Rem(a) Per Year) Percent Contribution 

Early Releases (< 6 hrs) 14.1 71 

Intermediate Releases (6 to <24 hrs) 4.2 21 

Late Releases (≥ 24 hrs) 1.5 8 

Total 19.8 100 

(a)One person-rem = 0.01 person-sievert (Sv)

16 F.2.1. Review of FPL Energy Duane Arnold, LLC’s Risk Estimates 

17 FPL-DA’s determination of offsite risk at DAEC is based on the following three major elements 

18 of analysis: 

19 ● Level 1 and 2 risk models that form the bases for the 1992 IPE submittal 

20 (IELP,1992), and the external event analyses of the 1996 IPEEE submittal 

21 (IES, 1995a) 

22 ● Major modifications to the IPE model that have been incorporated in the 

23 DAEC PRA 

24 ● MACCS2 analyses to translate fission product source terms and release 

25 frequencies from the Level 2 PRA model into offsite consequence 

26 measures 

27 Each of these analyses was reviewed to determine the acceptability of FPL-DA’s risk estimates 

28 for the SAMA analysis, as summarized below. 
Appendix F 

February 2010 F-5 Draft NUREG-1437, Supplement 42 

1 The NRC staff's review of the DAEC IPE is described in an NRC report dated November 12, 

2 1996 (NRC, 1996). Based on a review of the original IPE submittal, responses to RAIs, and a 

3 revised IPE submittal, the NRC staff concluded that the IPE submittal met the intent of GL 88-20 

4 (NRC, 1988); that is, the licensee’s IPE process is capable of identifying the most likely severe 

5 accidents and severe accident vulnerabilities. 

6 No vulnerabilities or specific improvements to either hardware or procedures identified as a 

7 result of the original IPE submittal (IELP, 1992) or in the response to IPE RAIs (IES, 1995b) 

8 were deemed to be necessary. However, the licensee identified a number of potential 

9 improvements and evaluations in conjunction with the original IPE process. Specific 

10 improvements or evaluations identified were to: 

11 ● Develop an Abnormal Operating Procedure or Emergency Operating 

12 Procedure (EOP) to address total loss of 125 VDC. 

13 ● Evaluate the existing EOP guidance to terminate vessel injection from 

14 outside containment if drywell pressure exceeds 53 psia. 

15 ● Maintain heightened awareness regarding timely use of standby liquid 

16 control for ATWS. 

17 ● Test diesel fire pump capability for vessel injection and evaluate DC 

18 reserve needed to accomplish this. 

19 ● Evaluate appropriateness of terminating water injection to containment 

20 under any circumstances for which core degradation may be aggravated. 

21 ● Evaluate the use of drywell sprays as a means to control drywell 

22 temperature to avoid premature containment failure. 

23 ● Provide guidance to operators related to protection of containment and 

24 cooling debris using methods that do not require venting. 

25 ● Prioritize injection systems for use in degraded core conditions. 

26 ● Evaluate the benefits of resetting the Automatic Depressurization System 

27 (ADS) timer instead of immediately locking out the automatic initiation of 

28 ADS. 

29 The first seven of these improvements were included in the list of Phase I SAMAs evaluated. In 

30 response to an RAI, FPL-DA discussed the resolution of the two remaining items. With regard to 

31 the prioritizing injection systems, FPL-DA indicates that it has implemented Severe Accident 

32 Guidelines based on the boiling water reactor owner’s group (BWROG) strategies for degraded 

33 core conditions that include prioritization of injection sources. With regard to the potential benefit 

34 of not locking out the ADS, FPL-DA indicates that this has been reviewed as part of the boiling 

35 water reactor (BWR) industry’s Emergency Operating Procedure and Severe Accident Guideline 
Appendix F 

Draft NUREG-1437, Supplement 42 F-6 February 2010 

1 (EOP/SAG) activities and has been concluded that the undesirable impacts of automatic ADS 

2 initiation outweighs the benefit of not locking out the ADS (NextEra, 2009a). 

3 The original IPE took credit for a hardened containment vent to be installed shortly after IPE 

4 submittal. In addition, two improvements were identified during the revision of the original IPE 

5 that would significantly reduce the potential for flood-related accidents in the control building. 

6 These modifications to change the control building fire protection system from a “wet” pipe 

7 system to a “dry” pipe system were completed and credited in the revised IPE. 

The CDF value from the 1992 IPE (7.8  10

-6

8 per year) is near the middle of the range of the 

9 CDF values reported in the IPEs for other BWR 3/4 plants while the value from the 1995 update 

(3.3  10

-5

10 per year) is in the upper third of the values reported for other BWR 3/4 plants. Figure 

11 11.2 of NUREG-1560 shows that the IPE-based total internal events CDF for BWR 3/4 plants 

ranges from 9  10

-8

 per year to 8  10

-5 per year, with an average CDF for the group of 2  10-5

12 

13 per year (NRC 1997b). It is recognized that other plants have updated the values for CDF 

14 subsequent to the IPE submittals to reflect modeling and hardware changes. The current 

15 internal events CDF results for DAEC are comparable to that for other plants of similar vintage 

16 and characteristics. 

17 There have been seven revisions to the IPE model since the 1992 IPE submittal. A listing of the 

18 major changes made to the DAEC PRA since the original IPE submittal was provided in the ER 

19 (FPL-DA, 2008) and in response to an RAI (NextEra, 2009a) and is summarized in Table G-3. 

20 While a comparison of internal events CDF between the 1992 IPE and the current PRA model 

indicates an increase of about 40 percent in the total CDF (from 7.8 10

-6

 per year to 1.1  10

-5

21 

22 per year), the CDF from the current PRA is about 33 percent of that from the revised IPE (from 

3.3  10

-5

 per year to 1.1  10

-5

23 per year). 
Appendix F 

February 2010 F-7 Draft NUREG-1437, Supplement 42 

1 Table G-3. Duane Arnold Energy Center Probabilistic Risk Assessment Historical 

2 Summary 

Version Description/changes from previous model CDF (per year) 

IPE 

1992 

Original IPE 7.8 x 10-6 

3 (3A) 

3/1995 

Revised IPE 

- Revision of HPCI/RCIC battery life estimates 

- Re-evaluation of LOOP initiating event frequency 

- Addition of sole dependence of DC power on 125 VDC battery (chargers 

excluded) for L OOP and LOCA 

- Incorporation of revised control building HVAC assessment 

- Inclusion of control building flood 

3.3 x 10-5 

3B 

1/1996 

- Incorporation of design modification that eliminated control building flood 

scenario from ruptured fire water propagating to essential switchgear room 

 Model reviewed by BWROG 

1.5 x 10-5 

4 (4A) 

3/1998 

- Relaxation of essential switchgear room’s ventilation requirements 

- Addition of dependency of HPCI/RCIC on decay heat removal for small 

LOCAs 

- Addition of credit for river water supply recovery 

- LOOP sequences with SORV transferred to IORV event tree rather than to 

the MSIV closure event tree 

- Addition of credit for drywell venting 

- Revision of human error probability for containment heat removal models 

- Addition of credit for total loss of 125 VDC procedure 

- Updated initiating event frequencies for transients and manual shutdown 

- Inclusion of well water system design modification 

- Inclusion of common cause failure of SRVs 

- Incorporation of updated maintenance unavailabilities from maintenance rule 

database 

- Incorporation of explicit models for important transformers, breakers, and 

power source lines 

1.1 x 10-5 

4B 

12/2001 

- Conversion from REBECA to CAFTA 1.2 x 10-5 

5 (5A) - Incorporation of updated human error probabilities as result of power uprate 

- Incorporation of updated LOOP frequency based on operating experience 

- Incorporation of instrument air fault tree model as result of BWROG 

certification comment 

- Incorporation of plant-specific equipment performance data for major 

equipment 

1.0 x 10-5 

5B 

2/2005 

- Addition of energy service reactor/residual heat removal service water 

(ESW/RHRSW) pump house ventilation dependency 

- Addition of explicit model for recirculation pump trip failure 

- Incorporation of updated LOOP frequency based on SBO analysis 

1.1 x 10-5 

5C 

7/2007 

- Correction of quantification flag settings 1.1 x 10-5 

3 The NRC staff questioned the licensee regarding the reasons for the relatively large contribution 

4 to CDF from ATWS and SBO events. In responses to RAIs (NextEra 2009a, 2009b) the 

5 licensee attributed the ATWS frequency to a relatively high ratio of power to suppression pool 

6 volume that leads to a shorter time available to initiate boron injection, and attributed the SBO 

7 frequency to DAEC being a single unit site and thus not having the additional AC power 

8 resources that would be available if another unit were at the site. 
Appendix F 

Draft NUREG-1437, Supplement 42 F-8 February 2010 

1 The NRC staff considered the peer reviews completed for the DAEC PRA, and the potential 

2 impact of the review findings on the SAMA evaluation. In the ER (FPL-DA, 2008) and in 

3 response to an NRC staff RAI (NextEra 2009a, 2009b), FPL-DA described the BWROG Peer 

4 Review of Revision 3B conducted in March 1997, as well as a PRA program self-assessment 

5 studied in 2004. 

6 The BWROG review concluded “the DAEC PRA certification resulted in a very consistent 

7 evaluation across all the elements. For each element, the certification team assigned a 

8 summary grade level of 3 which supports risk significance determinations supplemented by 

9 appropriate deterministic analyses.” FPL-DA identified all Level A and B (extremely important 

10 and important, respectively) facts and observations from the BWROG Peer Review and their 

11 disposition in the ER. All appear to have been satisfactorily resolved. 

12 The 2004 self-assessment of the PRA program was analyzed by a team that included 

13 individuals from one neighboring PWR and one neighboring BWR with a primary focus on 

14 ensuring that the DAEC PRA program complies with applicable standards and to identify 

15 potential program enhancement opportunities. The assessment team concluded that, in general, 

16 the DAEC had established, implanted, and maintained a PRA program consistent with 

17 applicable fleet (at that time Nuclear Management Company) standards. 

18 In response to an RAI, FPL-DA described the PRA update process in use at DAEC. Department 

19 instructions define the overall quality assurance control responsibilities, authorities, and 

20 requirements, as well as provide guidance on the maintenance, revision and configuration 

21 management of the model, and associated documentation and software. PRA model changes 

22 and associated documentation are reviewed by qualified individuals within FPL-DA’s corporate 

23 PRA department which includes DAEC PRA personnel. If appropriate, changes and associated 

24 documentation are also reviewed by site System Engineering, Training or Operations personnel. 

25 Completed documents are approved by either site or corporate supervisory personnel 

26 responsible for PRA activities. 

27 FPL-DA states that the Revision 5 PRA incorporates all plant modifications completed up to 

28 approximately 1999 and that a review of modification packages initiated since late 1997 was 

29 performed to assess their potential impact on the SAMA analysis. It was determined that no 

30 completed modifications would have a non-conservative impact on the SAMA results. 

31 Given that the DAEC internal events PRA model has been peer-reviewed and the peer review 

32 findings were all addressed, and that FPL-DA has satisfactorily addressed NRC staff questions 

33 regarding the PRA, the NRC staff concludes that the internal events Level 1 PRA model is of 

34 sufficient quality to support the SAMA evaluation. 

35 As indicated above, FPL-DA maintains a current DAEC external events PRA that explicitly 

36 models seismic and fire initiated core damage accidents. The models are stated to be based on 

37 the original DAEC IPEEE. Both the original IPEEE and current models are described in the ER. 

38 The DAEC IPEEE was submitted in November 1995 (IES, 1995a), in response to Supplement 4 

39 of Generic Letter 88-20 (NRC, 1991b). This analysis included a seismic margins analysis, a fire 

40 screening analysis, and a screening analysis for other external events. While no fundamental 

41 weaknesses or vulnerabilities to severe accident risk in regard to the external events were 
Appendix F 

February 2010 F-9 Draft NUREG-1437, Supplement 42 

1 identified, a list of improvement opportunities was developed as discussed below. In a letter 

2 dated March 10, 2000, the NRC staff concluded that the submittal met the intent of Supplement 

3 4 to Generic Letter 88-20, and that the licensee’s IPEEE process is capable of identifying the 

4 most likely severe accidents and severe accident vulnerabilities (NRC, 2000). 

5 The DAEC IPEEE seismic analysis utilized a seismic margin assessment (SMA) approach 

6 following NRC guidance (NRC, 1991a) and Electric Power Research Institute (EPRI) guidance 

7 (EPRI, 1991). This method is qualitative and does not provide numerical estimates of the CDF 

8 contributions from seismic initiators. The seismic analysis was completed in conjunction with the 

9 Seismic Qualification User Group (SQUG) program (SQUG, 1992). The review level earthquake 

10 (RLE) was taken to be the safe shutdown earthquake (SSE). 

11 Approximately 850 items identified for the safe shutdown equipment list (SSEL) were evaluated 

12 using the four screening considerations in the SQUG Generic Implementation Procedure, i.e., 

13 seismic capacity versus demand, equipment class caveats, equipment anchorage, and seismic 

14 interactions. Exceptions were shown to be acceptable by calculation or were resolved by 

15 modification or maintenance action (NRC, 2000). For structures, one masonry wall was 

16 identified as an outlier and was subsequently qualified for SSE loadings, and inspection of the 

17 control room ceiling indicated potential outliers that were resolved by selected modifications. 

18 Several seismic-induced fire and flood outliers were noted including unanchored gas storage 

19 bottles, air-handlers in the HPCI room and inadequate supports for the turbine lube oil storage 

20 tank. The first was resolved by providing restraints or removing the bottles, the second shown 

21 by analysis to have adequate clearance, while the latter was shown not to be risk significant 

(CDF less than 1  10

-6

22 per year) (NRC 2000, 2002). The NRC review and closeout of USI A-46 

23 for DAEC is documented in a letter dated July 29, 1998 (NRC, 1998). 

24 While the DAEC individual plant examination of external events (IPEEE) did not identify any 

25 vulnerabilities due to seismic events, potential improvements and strategies were discussed. 

26 These improvements involved the resolution of the outliers identified during the IPEEE process. 

27 While all were indicated to have been completed in the IPEEE submittal, they were incorporated 

28 in the Phase I SAMA list for completeness. This is discussed further in Section G3. 

29 Subsequent to the IPEEE, the licensee created a seismic PRA. The DAEC seismic PRA utilizes 

30 the 1994 seismic hazard curves from Lawrence Livermore National Laboratory (NRC, 1994). 

31 The seismic CDF model credits only the equipment in the SSEL developed for the IPEEE. 

32 Fragilities of the equipment were obtained from high confidence low probability of failure 

33 (HCLPF) values from industry studies. The probability of failure due to earthquake motion was 

34 then combined with random failures in modified versions of system fault trees. The Revision 5C 

seismic CDF is 7.0  10

-7

35 per year. In response to an RAI, FPL-DA provided additional 

36 information on the seismic PRA including the SSEL systems and equipment of interest, the 

37 issues included in the seismic event trees, the treatment of fragility dependencies, human errors 

38 employed, and the treatment of the turbine lube oil tank issue. FPL-DA also identified 

39 conservatisms and non-conservatisms in the analysis (NextEra, 2009a). Based on the 

40 information provided, the staff concludes that while the above seismic CDF value may be 

41 appropriate for DAEC, the best estimate seismic CDF value might also be higher than that given 
Appendix F 

Draft NUREG-1437, Supplement 42 F-10 February 2010 

1 above due to the lack of DAEC-specific fragilities, the treatment of fragility dependencies, and 

2 the lack of consideration of increases in human error rates for seismic-initiated events. 

3 To provide additional insight as to the appropriate seismic CDF to use for the SAMA evaluation, 

4 the NRC staff developed an independent estimate of seismic CDF for DAEC using the simplified 

5 hybrid method described in a paper by Robert P. Kennedy, entitled “Overview of Methods for 

6 Seismic PRA and Margin Analysis Including Recent Innovations” (Kennedy, 1999) and using the 

7 1994 LLNL hazard curve from NUREG-1488. This approach uses a median capacity (C50) of 

8 0.30g (based on the DAEC IPEEE of high confidence low probability of failure screening value 

9 for critical equipment) to represent the overall plant fragility. The NRC staff’s independent 

calculation conservatively estimates the seismic CDF for DAEC to be approximately 1 x 10-5 10 per 

11 year. This value is an order of magnitude greater than that given by FPL-DA in the ER. 

12 Based on the above, the NRC staff requested the licensee to assess the impact that a higher 

13 seismic CDF would have on the results of the SAMA analysis. This is discussed further in 

14 Section G 6.2. 

15 The NRC staff inquired about the important contributors to seismic risk. In response to an RAI, 

16 FPL-DA provided a listing and description of the seismic core damage sequences with a CDF of 

1 x 10-8 17 per year or more (NextEra 2009a, 2009b). The dominant seismic core damage 

18 sequences are listed in Table G-4. 
Appendix F 

February 2010 F-11 Draft NUREG-1437, Supplement 42 

1 Table G-4. Dominant Contributors to Seismic Core Damage Frequency 

Seismic Sequence Description CDF per year 

A seismic event with a magnitude of 1.0 g or more causes wide-spread failure of safeshutdown equipment. Core damage occurs due to loss of injection in a potentially 

damaged containment. 

1.5  10–7 

A seismic event with a magnitude between 0.7 and 0.9 g results in loss of off site power 

and failure to scram. HPCI and RCIC are conservatively not credited leading to core 

damage at high RPV pressure. 

5.0  10–8 

A seismic event with a magnitude between 0.7 and 0.9 g results in loss of off site power 

with a successful scram. HPCI and RCIC are conservatively not credited leading to the 

requirement for depressurization. This fails resulting in core damage at high RPV 

pressure. 

4.6  10–8 

A seismic event with a magnitude between 0.7 and 0.9 g causes wide-spread failure of 

safe-shutdown equipment. Core damage occurs due to loss of injection in a potentially 

damaged containment. 

4.1  10–8 

A seismic event with a magnitude between 0.9 and 1.0 g causes wide-spread failure of 

safe-shutdown equipment. Core damage occurs due to loss of injection in a potentially 

damaged containment 

3.8  10–8 

A seismic event with a magnitude between 0.7 and 0.9 g results in loss of off site power 

with a successful scram. HPCI and RCIC are conservatively not credited leading to the 

requirement for depressurization. Depressurization and low pressure injection is 

successful but long term containment heat removal fails resulting in core damage at high 

containment pressure. 

3.3  10–8 

A seismic event with a magnitude between 0.7 and 0.9 g results in loss of off site power 

with a successful scram. HPCI and RCIC are conservatively not credited leading to the 

requirement for depressurization. Depressurization is successful but low pressure 

injection fails leading to core damage. 

3.2  10–8 

A seismic event with a magnitude between 0.7 and 0.9g results in loss of offsite power 

with a successful scram. HPCI and RCIC are conservatively not credited leading to the 

requirement for depressurization. Depressurization is successful but low pressure 

injection fails leading to core damage. 

3.2  10–8 

Others 3.2  10–7 

Total (all seismic sequences) 7.0  10–7 

2 The DAEC IPEEE fire analysis employed EPRI’s fire-induced vulnerability evaluation (FIVE) 

3 method to analyze a qualitative screening and then a progressive probabilistic evaluation that 

4 considers the sequence of events that must occur to prevent safe shutdown. This evaluation 

5 considered fire propagation, damage, and suppression effectiveness if required. An area was 

6 screened out from further analysis once the fire induced core damage frequency dropped below 

1  10

-6

7 per year. A walkdown and verification process was employed to determine weather or 

8 not the assumptions and calculations were supported by the physical condition of the plant. 
Appendix F 

Draft NUREG-1437, Supplement 42 F-12 February 2010 

1 Two fire compartments remained unscreened at the end of the quantification process, Divisions 

2 I and II 4kV essential switchgear rooms. The fire induced CDF for these two rooms was 5.6 

10

-6

 and 4.9  10

-6 per year, respectively, for a total fire CDF of approximately 1 x 10-5 3 per year. 

4 FPL-DA stated that these values are conservative since fire brigade and offsite fire fighting are 

5 not credited. 

6 While no vulnerabilities were identified in the DAEC IPEEE due to fire events, potential 

7 improvements and strategies were identified and discussed in the IPEEE. These improvements 

8 were: prohibiting work in the switchgear room supporting the operating river water train during 

9 river water system maintenance, posting a fire watch in the switchgear room supporting the 

10 operating river water train during river water system maintenance, and converting the two fire 

11 protection pipes in the heating, ventilation, air conditioning (HVAC) control building from a “wet” 

12 pipe system to a “dry pipe” system. In addition, the NRC staff SER for the DAEC IPEEE 

13 indicates that cables for Division II equipment required for the remote shutdown of the plant 

14 were being rerouted so that they do not pass through the cable spreading room and that 

15 implementation of this modification was nearing completion at the time of the IPEEE submittal. 

16 In response to an RAI FPL-DA confirmed that this rerouting had been completed. These 

17 improvements, except for the cable rerouting, were incorporated in the Phase I SAMA list for 

18 completeness. This is discussed further in Section G.3. 

19 Subsequent to the IPEEE, the licensee created a fire PRA. The Revision 5C fire CDF is 3.0 x 

20 10-6 per year. In response to an RAI, FPL-DA provided further information on the fire PRA. The 

21 modeling in the fire PRA consists of three main steps: (1) determining the fire frequency for 

22 each compartment, (2) analyzing fire growth, and (3) suppression analysis and determining the 

23 fire induced CDF. The DAEC fire PRA utilizes the compartment fire ignition frequencies from the 

24 DAEC IPEEE. Fire growth and suppression event trees were developed based on the FIVE 

25 method as implemented in the IPEEE. The end points of the fire growth and suppression event 

26 trees are four fire damage states. Core damage frequency was then determined using a fire 

27 induced core damage event tree for each fire damaged state in each compartment. Fire 

28 compartments that had core damage frequencies of 2.5 10-8 per year or more in the IPEEE 

29 analyses were analyzed further in the fire PRA. 

30 In response to an RAI, FPL-DA provided a listing of the fire initiator contribution to the total fire 

31 CDF as indicated by the fire PRA. The dominant contributors are listed in Table G-5. 
Appendix F 

February 2010 F-13 Draft NUREG-1437, Supplement 42 

1 Table G-5. Important Fire Areas and Their Contributions to Fire Core Damage Frequency 

Fire Area Description CDF (per year) 

Essential Switchgear Room Division I 8.5  10–7 

Lower Non-essential Switchgear Room 7.8  10–7 

Essential Switchgear Room Division II 3.4  10–7 

Control Room Complex 2.0  10–7 

Reactor Building, Third Floor 1.2  10–7 

Battery Room, Division II 1.2  10–7 

Reactor Building, Second Floor 1.2  10–7 

Other 4.7 x 10-7 

Total (all fire areas) 3.0 x 10-6 

2 The licensee also identified a number of conservatisms and non-conservatisms in the fire PRA 

3 model (FPL-DA 2008; NextEra 2009a, 2009b). The conservatisms identified are: 

4 ● The assumption that a reactor trip (either automatic or manual) will be 

5 generated for all fires inside the security fence 

6 ● The susceptibility to failure of unprotected cables entering and exiting the 

7 metal-enclosed components even for low-intensity fires 

8 ● The assumption that internal cabinet fires disable the entire MCC or cabinet 

9 ● Fire suppression or the fire brigade is not credited (See clarification below) 

10 ● ATWS mitigation features (SLC, manual rod insertion, level/power control, 

11 etc.) are not credited 

12 ● Neither Thermo-Lag nor other fire wraps are credited 

13 ● The assumption that systems for which cabling has not been tracked and 

14 located are disabled for all fires 
Appendix F 

Draft NUREG-1437, Supplement 42 F-14 February 2010 

1 Potential non-conservatisms identified are: 

2 ● MCC and other metal-enclosed components are not considered susceptible 

3 to failure by exposure to low-intensity external fires 

4 ● Primary containment is not analyzed due to the inert atmosphere 

5 ● The assumption that the electrical portions of the reactor scram function 

6 fails safe 

7 ● Fire barriers will contain fires up to their listed ratings 

8 In response to an RAI, FPL-DA clarified that while neither fire suppression nor the fire brigade is 

credited if the core damage frequency for the compartment under consideration is 1  10-7 9 per 

10 year or less, they are credited if the initial value exceeds this criteria. The improved realism 

11 provided by the fire growth and suppression event trees resulted in a reduction in CDF for the 

12 Divisions I and II 4KV essential switchgear rooms from the relatively high IPEEE values. 

13 It is noted that the IPEEE and the current PRA screened out the cable spreading room on the 

14 basis of the absence of no fixed fire sources in the room. A screening value for the cable 

spreading room of 2.3  10-7 15 per year was provided in the IPEEE and no CDF for the cable 

16 spreading room was evaluated in the current fire PRA. The lack of a quantified CDF for the 

17 cable spreading room at DAEC is in contrast with the results of a number of similar BWR 3/4 

18 plants. While the lack of a cable spreading room is of concern, the value is not expected to 

19 significantly change the fire CDF. 

20 Considering the above discussion, the conservatisms and non-conservatisms and the response 

to the staff RAIs, the staff concludes that the fire CDF of 3.0  10-6 21 per year is reasonable for the 

22 SAMA analysis. 

23 The IPEEE analysis of high winds and tornadoes estimated there contribution to CDF to be 1.4 

 10-7 24 per year. The NRC staff review of the analysis noted some weaknesses in the analysis; 

25 nevertheless, the staff concluded that nevertheless the CDF from high winds at DAEC is on the 

order of 1 x 10-6 26 per year and would not constitute a vulnerability (NRC, 2000). For external 

27 floods, the IPEEE concluded that DAEC meets the 1975 Standard Review Plan and therefore 

28 no further analysis was needed. For transportation and nearby facility hazards, the IPEEE 

29 concluded that no floods posed a threat to the plant. 

30 While no vulnerabilities to high winds, floods, and other external events were identified in the 

31 DAEC IPEEE, potential improvements and strategies were identified and discussed in the 

32 IPEEE. These improvements were: increasing the distance between a new on-site hydrogen 

33 storage tank and safety-related structures, and constructing barriers around the auxiliary boiler 

34 propane storage tank. These improvements were incorporated in the Phase I SAMA list and all 

35 have been implemented. This is discussed further in Section G 3. 

36 As indicated in Supplement 1 to the License Renewal application (FPL-DA, 2009), a multiplier of 

37 1.57 was used to adjust the internal event risk benefit associated with a SAMA to account for 
Appendix F 

February 2010 F-15 Draft NUREG-1437, Supplement 42 

1 external events. In response to an RAI, FPL-DA indicated that this multiplier was based on a 

total external event CDF of 6.2 x 10-6 2 per year. This CDF is the sum of the total fire and seismic 

CDF from the DAEC external events PRA (3.74 x 10-6 per year rounded up to 4 x 10-6 3 per year) 

plus the high wind and tornado CDF from the IPEEE (1.4 x 10-7 per year rounded up to 2 x 10-7 4 

per year) plus the screening values for external flooding and transportation events (1 x 10-6 5 per 

6 year for each). The external event CDF is thus 56.4 percent of the internal events CDF (1.08 x 

10-6 per year rounded up to 1.1 x 10-6 7 per year). Thus, the total CDF is 1.564 times the internal 

8 events CDF and this was rounded up to 1.57 (NextEra, 2009a). 

9 As indicated above, the NRC staff estimates that the seismic CDF might be as high as 

approximately 1 x 10-5 per year. If this is combined with a fire CDF of 3 x 10-6 10 per year, and if the 

11 other contributions to external events CDF are negligible by comparison, the total multiplier to 

12 account for external events might be as high as 2.3. In response to an RAI, FPL-DA addressed 

13 the impact of using this higher multiplier on the results of the SAMA assessment. This is 

14 discussed further in Section G 6.2. 

15 The NRC staff reviewed the general process used by FPL-DA to translate the results of the 

16 Level 1 PRA into containment releases, as well as the results of the Level 2 analysis, as 

17 described in the ER and in response to NRC staff requests for additional information (FPL-DA 

18 2008; NextEra 2009a, 2009b). The current Level 2 model utilizes a set of CETs containing both 

19 phenomenological and systemic events. The Level 1 core damage sequences are grouped into 

20 core damage accident classes with similar characteristics. All of the sequences in an accident 

21 class are then input to a CET by linking the level 1 event tree sequences with the level 2 CET. 

22 The CETs are analyzed by the linking of fault trees that represent each CET node. Whenever 

23 possible the fault trees utilized in the Level 1 analysis are utilized in the CETs to propagate 

24 dependencies. 

25 Each CET end state represents a radionuclide release to the environment. Each is assigned to 

26 an STC based on magnitude and timing of release. Twelve release categories, as defined in the 

27 IPE, are utilized. Magnitude is given by CsI release fraction: High (H) > 10 percent, Moderate 

28 (M) 1 to 10 percent, Low (L) 0.1 to 1 percent and Low-Low (LL) <0.1 percent. Timing is based 

29 on the time of initial release relative to the time of accident initiation (scram): Early (E) < 6 

30 hours, Intermediate (I), 6 to 24 hours and Late (L) > 24 hours. The assignment to release 

31 magnitude bins was done by consideration of three fundamental variables, initial containment 

32 failure mode, water availability and reactor building effectiveness (NextEra 2009a, 2009b). 

33 The frequency of each STC was obtained by adding the frequencies of the contributing CET 

34 end states. The release characteristics for each STC were developed by using the results of 

35 MAAP 3.0B computer code calculations. The MAAP cases which represented the largest 

36 release fractions of those in an STC were used to characterize the entire STC. The STCs, their 

37 frequencies, and release characteristics are presented in Tables 3.4.3-2 and 3.4.4-1 of 

38 Appendix F to the ER (FPL-DA, 2008). 

39 The NRC staff review of this information noted a number of apparent discrepancies in the STC 

40 assignments with respect to timing and release magnitude and requested the licensee to clarify 

41 the reasons for these discrepancies (NRC 2009a, 2009b). As indicated above, the timing of 

42 release was measured relative to the time of accident initiation rather than the time of 
Appendix F 

Draft NUREG-1437, Supplement 42 F-16 February 2010 

1 declaration of general emergency. This results in assigning sequences to a “Late” bin when they 

2 would be “early”, considering the time of emergency declaration given in the ER. However, the 

3 Level 3 consequence analysis correctly used the period between the time of emergency 

4 declaration and the time of release in evaluating the effectiveness of the evacuation, and a 

5 sensitivity study showed that the population dose and the off-site economic cost results are not 

6 sensitive to the time used. Thus, this inconsistency in treating release timing would not 

7 significantly impact the SAMA analysis. 

8 With regard to release magnitude, the staff noted that the release fractions for a number of 

9 STCs did not agree with the above definitions. In most cases the release fractions utilized were 

10 greater than that prescribed by the STC definition. This apparently was the result of the process 

11 for assigning sequences to the STCs, and selecting the highest release fraction of the assigned 

12 sequences to represent the STC. In one case, STC M/I (moderate release magnitude and 

13 intermediate release timing), the release fraction utilized did not include the scrubbing from the 

14 suppression pool. This was due to the fact that pool scrubbing was not included in the Level 2 

15 MAAP analysis but was added manually. The release fraction used in the Level 3 analysis also 

16 excluded this correction. In response to an RAI, the licensee indicated that use of the correct 

17 release fraction (a factor of 10 lower) would reduce the total population dose by about 8 percent. 

18 The DAEC Level 2 PRA model is essentially that used in the IPE. As indicated in the ER, no 

19 changes to major modeling assumptions, containment event trees structure, accident 

20 progression/source term calculations, or binning of end states in the Level 2 PRA model have 

21 been made since the IPE submittal. The NRC staff’s review of the IPE Level 2 model concluded 

22 that it appeared to have addressed the severe accident phenomena normally associated with 

23 the Mark I containment type, that it met the IPE requirements, and that there were no 

24 weaknesses. It was noted, however, that DAEC appears not to have analyzed a thorough 

25 internal peer review of the back-end (i.e. Level 2) portion of the IPE. The BWROG review did 

26 not have any important (i.e., Level A or B) facts and observations from its review of the Level 2 

27 model. 

28 Since there have been no major changes in the Level 2 PRA since the IPE and the IPE Level 2 

29 model was based on the state of knowledge in the 1991–1992 time frame, the staff asked 

30 FPL-DA to discuss the impact of the current state of knowledge on key BWR accident and 

31 containment failure phenomenology on the Level 2 assumptions and results used for the SAMA 

32 analysis. FPL-DA responded that while the Level 2 analysis was updated to reflect the current 

33 Level 1 model, there have been no major changes in the state of knowledge regarding accident 

34 progression and containment failure mechanisms that would require a change in the Level 2 

35 model. FPL-DA indicated that a peer assessment analyzed in 2007, subsequent to the 

36 preparation of the ER, concluded that the DAEC Level 2 analysis is comprehensive and 

37 acceptable for risk-informed applications such as SAMA, that the model can still be considered 

38 state of the art, and that the sequence binning and release characterization met the American 

39 Society of Mechanical Engineers (ASME) Code Standard. The reviewers suggested that FPL40 DA upgrade from MAAP 3.0B to MAAP 4. FPL-DA has not yet implemented this change. The 

41 staff concludes that, given the conservative release fractions used for the important STCs, 

42 upgrading the MAAP analysis will not adversely impact the SAMA evaluation. 
Appendix F 

February 2010 F-17 Draft NUREG-1437, Supplement 42 

1 Based on the NRC staff’s review of the Level 2 method, the licensee’s responses to RAIs and 

2 the fact that the Level 2 model was reviewed in more detail as part of the BWROG peer review’ 

3 plus a more recent review for conformance to the ASME Code PRA standard was found 

4 acceptable, the NRC staff concludes that the Level 2 PRA provides an acceptable basis for 

5 evaluating the benefits associated with various SAMAs. 

6 FPL-DA used the MACCS2 code and a core inventory from a plant specific ORIGEN2 

7 calculation to determine the offsite consequences of activity release (NextEra, 2009b). FPL-DA 

8 confirmed that the inventory used reflects the expected fuel management/burnup during the 

9 license renewal period (NextEra, 2009a). 

10 The NRC staff reviewed the process used by FPL-DA to extend the containment analysis 

11 (Level 2) portion of the PRA to an assessment of offsite consequences (essentially a Level 3 

12 PRA). This included consideration of the source terms used to characterize fission product 

13 releases for the applicable containment release categories and the major input assumptions 

14 used in the offsite consequence analyses. The MACCS2 code was used to estimate offsite 

15 consequences. Plant-specific input to the code includes the source terms for each source term 

16 category and the reactor core radionuclide inventory (both discussed above), site-specific 

17 meteorological data, projected population distribution within a 50-mile (80-km) radius for the 

18 year 2040, emergency evacuation modeling, and economic data. This information is provided in 

19 Section 3.4 of Appendix F to the ER (FPL-DA, 2008). 

20 All releases were modeled as being from the off-gas stack or the top of the reactor building 

21 depending on the accident sequence release location. In response to an RAI, FPL-DA indicated 

22 the type of sequence released from each location. The results of sensitivity studies on release 

23 height or location provided in the original submittal and in response to an RAI indicated a 

24 negligible impact (less than plus or minus 3 percent) on both population dose and offsite 

25 economic cost. The thermal content of each of the releases was assumed to be the same as 

26 ambient (that is a non-buoyant plume). Wake affects for the 140-foot high and 140-foot wide 

27 reactor building were included in the model. Sensitivity studies were analyzed on these 

28 assumptions and indicated little (approximately 1 percent increase or decrease) or no change in 

29 population dose or offsite economic cost. Another sensitivity study showed that removing the 

30 base case assumption of perpetual rainfall in the 40–50 mile segment surrounding the site 

31 would result in a 9 percent reduction in population dose and a 15 percent reduction in offsite 

32 costs. Based on the information provided, the staff concludes that the release parameters used 

33 are acceptable for the purposes of the SAMA evaluation. 

34 FPL-DA used site-specific meteorological data for the 2005 calendar year as input to the 

35 MACCS2 code. The development of the meteorological data is discussed in Section 3.4.5 of 

36 Appendix F to the ER and in response to an RAI (NextEra, 2009a). The data were collected 

37 from the onsite meteorological monitoring system. Sensitivity analyses using MACCS2 and the 

38 meteorological data for the years 2002 through 2006 show that use of data for the year 2005 

39 results in the largest dose and economic cost risk. Missing meteorological data was filled using 

40 data: from another level on the met tower (accounting for the relationship between the levels as 

41 determined from the preceding hours); by interpolation if the gap were less than 4 hours; or from 

42 the hour and a nearby day of a previous year. Missing precipitation data was obtained from a 

43 nearby airport. The NRC staff notes that previous SAMA analyses results have shown little 
Appendix F 

Draft NUREG-1437, Supplement 42 F-18 February 2010 

1 sensitivity to year-to-year differences in meteorological data and concludes that the use of the 

2 2005 meteorological data in the SAMA analysis is reasonable. 

3 The population distribution that the licensee used as input to the MACCS2 analysis was 

4 estimated for the year 2040 using year 2000 census data as accessed by SECPOP 2000 

5 (NRC, 2003) as a starting point. The 2000 population was adjusted to account for transient 

6 population obtained from the evacuation time estimate study (TOMCOD, 2003). County growth 

7 rates based on projections from State Data Center of Iowa (State Library, 2006) were applied to 

8 obtain the distribution in 2040. These data were used to project county-level resident and 

9 transient populations to the year 2040 using an exponential fit and applied to each zone based 

10 on the fraction of each county within the zone. The NRC staff considers the methods and 

11 assumptions for estimating population reasonable and acceptable for purposes of the SAMA 

12 evaluation. 

13 The emergency evacuation model was modeled as a single evacuation zone extending out 16 

14 kilometers (10 miles) from the plant (the emergency planning zone (EPZ). FPL-DA assumed 

15 that 95 percent of the population would evacuate. This assumption is conservative relative to 

16 the NUREG-1150 study (NRC, 1990), which assumed evacuation of 99.5 percent of the 

17 population within the emergency planning zone. The evacuated population was assumed to 

18 move at an average radial speed of approximately 4.4 miles per hour (2.0 meters per second) 

19 with a delayed start time of 17 minutes after declaration of a general emergency. A general 

20 emergency declaration was assumed to occur at the onset of core damage. The evacuation 

21 speed (0.314 meters per second) was derived from the projected time to evacuate the entire 

22 EPZ under winter, weekday, mid-day, adverse weather conditions during the year 2000 

23 (TOMCOD, 2003) and then adjusted by the ratio of the year 2000 EPZ population to the 

24 projected year 2040 EPZ population. Sensitivity studies on these assumptions indicate that 

25 there is little or no change to the population dose or offsite economic cost by the assumed 

26 variations. The sensitivity studies included setting the general emergency declaration time to 

27 zero (the earliest possible declaration time). This change resulted in a 2 percent reduction in 

28 population dose and no change in offsite economic cost. The NRC staff concludes that the 

29 evacuation assumptions and analysis are reasonable and acceptable for the purposes of the 

30 SAMA evaluation. 

31 Site-specific agriculture and economic data was provided from SECPOP 2000 (NRC, 2003) by 

32 specifying the data for each of the counties surrounding the plant to a distance of 50 miles 

33 (80 km). This included the fraction of land devoted to farming, annual farm sales, the fraction of 

34 farm sales resulting from dairy production, and the value of non-farm land. SECPOP2000 

35 utilizes economic data from the 1997 National Census of Agriculture (USDA, 1998). In response 

36 to an RAI, FPL-DA analyzed a sensitivity study which indicated that replacing the data from the 

37 1997 National Census of Agriculture with data from the 2002 National Census of Agriculture 

38 (USDA, 2002) has a negligible (less than 1 percent) impact on results (NextEra, 2009a). 

39 Area wide farm wealth was determined from 2002 National Census of Agriculture (USDA, 2002) 

40 county statistics for farmland, buildings and machinery, with only the fraction of each county 

41 within 50 miles of DAEC considered. Non-farm wealth was taken as the population-weighted 

42 average of the SECPOP2000 non-farm property value. In addition, generic economic data that 

43 applied to the region as a whole were revised from the MACCS2 sample problem input in order 
Appendix F 

February 2010 F-19 Draft NUREG-1437, Supplement 42 

1 to account for cost escalation since 1986 (the year the input was first specified). This included 

2 parameters describing cost of evacuating and relocating people, land decontamination and 

3 property condemnation. An escalation factor of 1.90 was applied to these parameters to account 

4 for cost escalation from 1986 (the year the input was first specified) to July 2007. 

5 FPL-DA confirmed that the three recently discovered problems in SECPOP2000 have all been 

6 accounted for in preparing the input for DAEC (NextEra, 2009a). These problems involved: (1) 

7 an inconsistency in the format in which several economic parameters were output from the 

8 SECPOP2000 code and input to the MACCS2 code, (2) an error that resulted in use of 

9 agricultural/economic data for the wrong counties in the SECPOP2000 calculations, and (3) an 

10 error that resulted in the economic data for some counties being handled incorrectly. 

11 The NRC staff concludes that the methods used by FPL-DA to estimate the offsite 

12 consequences for DAEC provides an acceptable basis from which to proceed with an 

13 assessment of risk reduction potential for candidate SAMAs. Accordingly, the NRC staff based 

14 its assessment of offsite risk on the CDF and offsite doses reported by FPL-DA. 

15 F.3. Potential Plant Improvements 

16 This section discusses the process for identifying potential plant improvements, an evaluation of 

17 that process, and the improvements evaluated in detail by FPL-DA. 

18 F.3.1. Process for Identifying Potential Plant Improvements 

19 FPL-DA’s process for identifying potential plant improvements (SAMAs) consisted of the 

20 following elements: 

21 ● Review of the most significant basic events from the current, plant-specific 

22 Level 1 PRA, 

23 ● Review of potential plant improvements identified in the DAEC IPE and 

24 IPEEE, 

25 ● Review of generic SAMA candidates from Table 13 of NEI 05-01 (NEI 

26 2005), and 

27 ● Review of the above generic and site-specific SAMAs by an expert panel to 

28 identify any additional candidates. 

29 The expert panel consisted of 16 individuals with a wide range of plant, design, and analysis 

30 experience. The panel identified one additional SAMA, SAMA 156 – Provide an alternate source 

31 of water for the Residual Heat Removal/Emergency Service Water (RHR/ESW) pit. 

32 Based on this process, an initial set of 166 candidate SAMAs, referred to as Phase I SAMAs, 

33 was identified. These are identified in Table 5.5-1 of Appendix F to the ER (FPL-DA, 2008). In 

34 response to an NRC staff RAI, FPL-DA provided further information on the potential for a 
Appendix F 

Draft NUREG-1437, Supplement 42 F-20 February 2010 

1 modification to the lube oil storage tank support structure found in the IPEEE to fail at the DAEC 

2 safe shutdown earthquake. This modification was designated as SAMA 167 and was added to 

3 the Phase I list of SAMA candidates in an update to the ER (NextEra, 2009c). 

4 In Phase I of the evaluation, FPL-DA analyzed a qualitative screening of the initial list of SAMAs 

5 and eliminated SAMAs from further consideration using the following criteria: 

6 ● The SAMA is not applicable at DAEC due to design differences (23 

7 screened out). 

8 ● The SAMA has already been implemented at DAEC (104 screened out 

9 initially; 103 screened out in updated ER after correcting 

10 miss-categorization of SAMA 118). 

11 ● The SAMA is similar in nature and could be combined with another SAMA 

12 candidate (2 screened out). 

13 ● The SAMA requires excessive changes that will obviously exceed the 

14 maximum benefit (13 screened out initially; 15 screened out in updated ER 

15 after correcting miss-categorization of SAMA 118 and adding SAMA 167). 

16 ● The SAMA is related to a non-risk significant system for which changes in 

17 reliability are known to have negligible impact on risk (none screened out). 

18 Based on this screening, a total of 143 SAMAs were eliminated leaving 24 for further evaluation. 

19 The results of the Phase I screening analysis are given in Table 6-1 of Appendix F to the ER. 

20 The remaining SAMAs, referred to as Phase II SAMAs, are listed in Table 7.1.3-1 of Appendix F 

21 to the ER. In Phase II, a detailed evaluation was analyzed for each of the 24 remaining SAMA 

22 candidates, as discussed in forthcoming Sections G 4 and G 6 below. To account for the 

23 potential impact of external events, the estimated benefits based on internal events were 

24 multiplied by a factor of 1.57, as previously discussed. 

25 F.3.2. Review of FPL Energy Duane Arnold, LLC’s Process 

26 FPL-DA’s efforts to identify potential SAMAs focused primarily on areas associated with internal 

27 initiating events. In response to NRC staff RAIs, explicit consideration was also given to 

28 potential SAMAs for fire and seismic events. The initial list of SAMAs generally addressed the 

29 hardware failures and human actions considered to be important to CDF from risk reduction 

30 worth (RRW) perspectives at DAEC, and included selected SAMAs from prior SAMA analyses 

31 for other plants. 

32 FPL-DA provided a tabular listing of the dominant human action contributors (Table 5.1-1 of 

33 Appendix F to the ER) and dominant hardware contributors (Table 5.1-2 of Appendix F to the 

34 ER) to CDF sorted according to their RRW (FPL-DA, 2008). SAMAs impacting these basic 

35 events would have the greatest potential for reducing risk. FPL-DA used a RRW cutoff of 1.005, 

36 which corresponds to about a one-half percent change in CDF given 100-percent reliability of 
Appendix F 

February 2010 F-21 Draft NUREG-1437, Supplement 42 

1 the SAMA. This equates to a benefit of approximately $11,000 (after the benefits have been 

2 multiplied to account for external events). 

3 Initially, no Phase I SAMAs were identified for the human actions on the basis that DAEC 

4 procedures and training meet current industry standards. The NRC staff noted that the CDF 

5 contribution from failure of important operator actions could possibly be reduced by provision of 

6 additional alarms or automating the action. In response to an RAI, FPL-DA indicated that risk 

7 significant operator actions have been prioritized in operator training and scrutinized for 

8 improvement opportunities. Several improvements implemented were described. FPL-DA stated 

9 that appropriate indications and alarms are already in place and any hardware modifications to 

10 automate operator actions would typically cost substantially more than any benefit and may 

11 create the potential for adverse impacts or consequences. In conclusion, no SAMAs in this area 

12 were identified for further consideration. 

13 The FPL-DA review of the important hardware contributors identified four new plant specific 

14 SAMAs. 15 generic SAMAs were stated to address the remaining important contributors. The 

15 NRC staff noted that the most important hardware contributor in the RRW table (event PDI1947, 

16 failure of the RHRSW Loop “B” heat exchanger differential pressure indicator, with a RRW of 

17 1.053) is addressed by SAMA 165, to improve the differential pressure indicators. However, this 

18 SAMA was subsequently screened out on the basis that it was not applicable since the PRA did 

19 not reflect a plant modification that had been implemented at DAEC. In an RAI, the NRC staff 

20 noted that event PDI2046, involving failure of the corresponding pressure indicator in Loop “A”, 

21 has a RRW of only 1.005. In response, FPL-DA indicated that the RRW value for event 

22 PDI1947 reported in the ER was in error and that the correct value should be 1.005 

23 (NextEra, 2009a). Since this value is at the low RRW cutoff, no SAMA is appropriate for these 

24 pressure indicators. This error was corrected in the ER update (NextEra, 2009c). 

25 A total of 17 DAEC specific SAMAs based on improvements identified in the IPE and IPEEE 

26 were included in the Phase I list. All were screened out on the basis that they have been 

27 implemented. 

28 Table 6-1 of the ER provides the results of Phase I screening of the initial list of SAMA 

29 candidates. The NRC staff questioned the screening out of a number of SAMAs on the basis 

30 that they were not applicable to DAEC or were already implemented at DAEC. In response to an 

31 RAI and subsequent request for clarification, FPL-DA provided additional information to support 

32 the screening of the questioned items. The additional information included: (1) results of fire 

33 studies that did not find fire barrier or spurious actuation vulnerabilities or weaknesses, (2) the 

34 identification of equipment, procedures and programs in place at DAEC that effectively 

35 implement the intent of the SAMA and/or result in most of the risk reduction that could be 

36 achieved by the SAMA, and (3) for one SAMA (SAMA 118 – add an independent boron injection 

37 system) a correction to the reported basis for screening. For SAMA 159, which originated from 

38 the IPEEE and involves either posting a fire watch in the switchgear room supporting the 

39 operating river water train, or staging temporary hoses for implementation of abnormal operation 

40 procedure (AOP)-410, Total Loss of River Water, FPL-DA concluded that the need for such a 

41 requirement has been eliminated since the emergency switchgear rooms fire risk has been 

42 reduced by a factor of ten from that in the IPEEE. The NRC staff agrees with this conclusion. 
Appendix F 

Draft NUREG-1437, Supplement 42 F-22 February 2010 

1 The NRC staff also questioned FPL-DA about lower cost alternatives to some of the SAMAs 

2 evaluated, including: 

3 ● Using a portable diesel driven pump for low pressure injection through 

4 existing systems, 

5 ● Using a portable diesel driven pump to provide makeup to the 

6 RHRSW/ESW pit, 

7 ● Using a portable DC power supply to maintain DC power availability for 

8 SBO sequences, 

9 ● Improving the reliability of cross-ties between the RHR system and (1) the 

10 RHR service water, (2) the fire system or (3) other systems that could be 

11 used for alternate low pressure injection, and 

12 ● Creating a procedure to maximize CRD flow to provide early and/or late 

13 injection. 

14 In response to the RAIs, FPL-DA addressed the suggested lower cost alternatives, and 

15 indicated that all of these alternatives are effectively covered by existing procedures 

16 (NextEra, 2009a). This is discussed further in Section G 6.2. 

17 Based on this information, the NRC staff concludes that the set of SAMAs evaluated in the ER 

18 addresses the major contributors to internal event CDF. 

19 Although the Phase I list of potential SAMAs did include candidate SAMAs for external events 

20 based on generic insights and the IPEEE results, FPL-DA did not report that the DAEC seismic 

21 and fire PRA models were systematically reviewed for the purpose of identifying potential 

22 external event SAMAs. In response to an RAI, FPL-DA provided a listing of important 

23 component and human error events for the seismic and fire initiated events sorted by risk 

24 reduction worth. FPL-DA noted that almost all of the important seismic and fire contributors 

25 were the same as those identified for internal events and reviewed for potential SAMAs. FPL26 DA reviewed those events that are not on the internal events list and determined that they were 

27 either covered by existing SAMAs or, for human errors, are unlikely to be reduced by improved 

28 procedures. 

29 The NRC staff noted that all of the important seismic and fire basic events discussed above are 

30 random failures and none are due to the effects of the seismic or fire initiating event. In 

31 response to a NRC staff RAI, FPL-DA attributed this to the manner in which seismic and fire 

32 failures are incorporated in the external events models. 

33 In a further effort to identify external event SAMAs, the NRC staff requested FPL-DA to list the 

34 important seismic and fire initiated core damage sequences and to review them for potential 

35 SAMAs. FPL-DA provided the requested information and stated that a review of the dominant 

36 fire and seismic sequences did not identify any potential SAMAs. The major sequences are 
Appendix F 

February 2010 F-23 Draft NUREG-1437, Supplement 42 

1 extreme magnitude earthquakes that cause widespread damage and significant fires in the 

2 essential and non-essential switchgear rooms. 

3 The staff notes that the largest contributor to fire risk is a sequence involving a severe fire in the 

4 lower (non-essential) switchgear room that disables multiple equipment in the room and has a 

CDF contribution of 7.4 x 10-7 5 per year (NextEra, 2009a) while the largest contributor to seismic 

6 risk is a sequence involving a severe earthquake that causes widespread damage and has a 

CDF contribution of 1.5 x 10-7 7 per year (NextEra, 2009a). These sequences correspond to 

8 7.4 percent and 1.5 percent of the internal events CDF, respectively. Eliminating them entirely 

9 would have a benefit of $110,000 and $22,000, respectively. Considering that the minimum cost 

10 of a hardware modification would likely exceed $100,000, the NRC staff concludes that it is 

11 unlikely that any SAMAs to address these fire or seismic sequences would be cost beneficial. 

12 Failure of the turbine lube oil tank support structure leading to a fire and core damage was 

13 identified in the DAEC IPEEE (IES, 1995a) and discussed extensively in the IPEEE SER 

14 (NRC, 2000). In response to NRC staff RAIs, FPL-DA provided additional information on this 

15 failure, its modeling in the seismic PRA, and the potential for a cost beneficial SAMA to address 

16 the failure. The failure is described as a buckling of the five foot tall support structure leading to 

17 the tank tipping over, breaching the surrounding wall, and spilling oil into the turbine building 

causing a major fire. This is assessed to have a CDF contribution of 1 x 10-7 18 per year. This 

19 corresponds to approximately 1 percent of the internal events CDF. Eliminating or reducing this 

20 risk would involve adding stiffeners to the support structure. The benefit associated with 

21 eliminating this risk is given by FPL-DA as 1 percent of the maximum attainable benefit (MAB) 

22 of $2.3 million or $23,000. FPL-DA points out that since this is less than the minimum cost for a 

23 hardware fix of $100,000, strengthening the lube oil tank support structure would not be cost 

24 effective. 

25 The NRC staff notes that since the MAB used above includes a multiplier of 1.57 to account for 

26 both internal external events, the benefit of eliminating this failure would be only $14,000 (when 

27 the benefit in internal events is not included). The staff further notes that while there is the 

28 possibility that the CDF contribution from the lube oil tank support structure is greater than the 

29 value cited above, even if the seismic contribution were increased by a decade, the modification 

30 would have to cost less than $140,000 to be cost beneficial. This is considered unlikely given 

31 the nature of the required fix and the associated analysis required. Based on the above, the 

32 NRC staff concludes that a SAMA to address the lube oil tank support structure failure need not 

33 be evaluated further. 

34 Based on the licensee’s IPEEE, the A-46 efforts to identify and address seismic outliers, the 

35 modifications that have already been implemented, the review of the results of the DAEC 

36 seismic and fire PRAs, and the expected cost associated with further risk analysis and potential 

37 plant modifications, the NRC staff concludes that the opportunity for seismic and fire-related 

38 SAMAs has been adequately explored and that it is unlikely that there are any cost-beneficial, 

39 seismic- or fire-related SAMA candidates. 

40 As stated earlier, other external hazards (i.e., high winds, external floods, and transportation 

41 and nearby facility accidents) are below the IPEEE threshold screening frequency and are not 

42 expected to impact the conclusions of the SAMA analysis. Two improvements were, however 
Appendix F 

Draft NUREG-1437, Supplement 42 F-24 February 2010 

1 noted in the IPEEE and were implemented. The NRC staff concludes that the licensee’s 

2 rationale for eliminating other external hazard enhancements from further consideration is 

3 reasonable. 

4 The NRC staff notes that the set of SAMAs submitted is not all-inclusive, since additional, 

5 possibly even less expensive, design alternatives can always be postulated. However, the NRC 

6 staff concludes that the benefits of any additional modifications are unlikely to exceed the 

7 benefits of the modifications evaluated and that the alternative improvements would not likely 

8 cost less than the least expensive alternatives evaluated when the subsidiary costs associated 

9 with maintenance, procedures, and training are considered. 

10 The NRC staff concludes that FPL-DA used a systematic and comprehensive process for 

11 identifying potential plant improvements for DAEC, and that the set of potential plant 

12 improvements identified by FPL-DA is reasonably comprehensive and, therefore, acceptable. 

13 This search included reviewing insights from the plant-specific risk studies and reviewing plant 

14 improvements considered in previous SAMA analyses. While explicit treatment of external 

15 events in the SAMA identification process was limited, it is recognized that the prior 

16 implementation of plant modifications for fire and seismic risks and the absence of external 

17 event vulnerabilities reasonably justifies primarily examining the internal events risk results for 

18 this purpose. 

19 F.4. Risk Reduction Potential of Plant Improvements 

20 FPL-DA evaluated the risk-reduction potential of the 24 remaining SAMAs that were applicable 

21 to DAEC. The majority of the SAMA evaluations were analyzed in a bounding fashion in that the 

22 SAMA was assumed to completely eliminate the risk associated with the proposed 

23 enhancement. On balance such calculations overestimate the benefit and are conservative. 

24 FPL-DA used model re-quantification to determine the potential benefits. The CDF, population 

25 dose reductions, and offsite economic cost reductions were estimated using the DAEC PRA 

26 model. The changes made to the model to quantify the impact of SAMAs are described in Table 

27 7.1.3-1 of Appendix F to the ER (FPL-DA, 2008). Table G-6 lists the assumptions considered to 

28 estimate the risk reduction for each of the evaluated SAMAs, the estimated risk reduction in 

29 terms of percent reduction in CDF and population dose, and the estimated total benefit (present 

30 value) of the averted risk. The estimated benefits reported in Table G-6 reflect the combined 

31 benefit in both internal and external events. The determination of the benefits for the various 

32 SAMAs is further discussed in Section G 6. 

33 The NRC staff questioned the assumptions used in evaluating the benefits or risk reduction 

34 estimates of certain SAMAs provided in the ER, as summarized below (NRC, 2009a; 

35 NRC, 2009b). 

36 ● SAMA 41, provide capability for alternate injection via the reactor water 

37 cleanup (RWCU), was initially evaluated as being beneficial only for events 

38 involving steamline breaks or stuck open safety relief valves. In response to 

39 an RAI, FPL-DA indicated that this treatment was based on interpreting the 

40 generic SAMA as providing a means of heat removal and not a source of 
Appendix F 

February 2010 F-25 Draft NUREG-1437, Supplement 42 

1 injection, and that the RWCU system is not capable of being used for 

2 injection (NextEra, 2009a). However, in another response, the cost 

3 estimate was stated to include some of the modifications necessary to use 

4 it for injection (NextEra, 2009a). Although the benefit associated with a 

5 SAMA based on use of the RWCU for injection was not provided by 

6 FPL-DA (NextEra, 2009b), this benefit can be estimated from the assessed 

7 benefits of other SAMAs. This is discussed in Section G 6.2. 

8 ● SAMA 117, increase boron concentration or enrichment, was initially 

9 evaluated by eliminating mechanical failures of the standby liquid control 

10 (SLC) system rather than reducing the human error probability associated 

11 with initiating SLC (NextEra, 2009a). FPL-DA revised this evaluation in 

12 response to an RAI which pointed out that increasing boron concentration 

13 or enrichment would provide more time for the operator to act but would not 

14 prevent mechanical failures. The reevaluation, based on the RRW of the 

15 operator’s failure to inject stand-by liquid control early, indicated a 9.9 

16 percent reduction in CDF and a benefit of approximately $200,000 

17 (NextEra, 2009b). This is discussed in Section G 6.2. 

18 ● SAMA 164, improve the reliability of the river water system (RWS) control 

19 system, was evaluated by revising the base case PRA to more accurately 

20 reflect the current primary and backup RWS control system, and further 

21 modifying this model to account for SAMA implementation. The original 

22 base case PRA model included the primary automatic control system, 

23 whose failure had a RRW that led to the identification of the SAMA. FPL-DA 

24 added an independent backup control system to the base case model with 

25 an assumed reliability equal to that of the primary system. This reduced the 

26 importance of the primary control system and thus the benefit that could 

27 result from further improvements (NextEra 2009a, 2009b). The NRC staff 

28 concludes that this approach to evaluating the risk reduction of this SAMA 

29 was acceptable. 

30 The NRC staff has reviewed FPL-DA’s bases for calculating the risk reduction for the various 

31 plant improvements and concludes, with the above clarifications, that the rationale and 

32 assumptions for estimating risk reduction are reasonable and generally conservative (i.e., the 

33 estimated risk reduction is higher than what would actually be realized). Accordingly, the NRC 

34 staff based its estimates of averted risk for the various SAMAs on FPL-DA’s risk reduction 

35 estimates. 

36 F.5. Cost Impacts of Candidate Plant Improvements 

37 FPL-DA estimated the minimum implementation costs for a procedure change, including training 

38 on the procedure, to be $30,000 and for an integrated hardware modification, including 

39 associated training, to be $100,000. If the calculated benefit exceeded these minimum 

40 implementation costs then an expert panel further assessed the SAMA. 
Appendix F 

Draft NUREG-1437, Supplement 42 F-26 February 2010 

1 The expert panel consisted of plant staff familiar with design, construction, operation, training 

2 and maintenance. The expert panel in their assessment discussed a conceptual design and 

3 degree of complexity to implement the SAMA under consideration. The panel then chose a 

4 similarly complex design modification that had been completed at DAEC and used the actual 

5 cost for this modification as the cost of implementing the SAMA. The cost estimates 

6 conservatively did not include the cost of replacement power during extended outages required 

7 to implement the modifications, nor did they include contingency costs associated with 

8 unforeseen implementation obstacles. The cost estimates provided in the ER did not account for 

9 inflation (NextEra, 2009b). For some SAMAs, particularly when evaluating the cost benefit 

10 associated with sensitivity studies, other licensees’ estimates for similar improvements were 

11 cited to indicate that the DAEC cost estimates were too low. A member of the Design 

12 Engineering department reviewed the cost estimates for four SAMAs (SAMAs 12, 78, 156 and 

13 168) to provide further assurance that the estimates were sufficiently accurate for cost benefit 

14 decision making purposes. 

15 The NRC staff reviewed the bases for the licensee’s cost estimates (presented in Table 7.1.3-1 

16 of Appendix F to the original ER) and requested more information concerning the design and 

17 associated cost for a number of the SAMAs. Also, for a number of SAMAs where the cost was 

18 given only as greater than the MAB, the NRC staff requested specific dollar cost estimates 

19 (NRC, 2009a). In response, FPL-DA described in general terms the nature of the modification 

20 required to implement the SAMA to support the expert panel’s judgment on the cost, and in 

21 some cases cited DAEC experience with similar modifications and/or cost estimates given in 

22 other SAMA evaluations (NextEra, 2009a). For certain improvements, the NRC staff also 

23 compared the cost estimates to estimates developed elsewhere for similar improvements, 

24 including estimates developed as part of other licensee’s analyses of SAMAs for operating 

25 reactors and advanced light-water reactors. The staff reviewed the costs and found them to be 

26 reasonable, and generally consistent with estimates provided in support of other plants’ 

27 analyses. Updated cost estimates provided in support of the NRC staff review were 

28 incorporated in the first annual update of the License Renewal Application (NextEra, 2009c) and 

29 are reflected in Table G-6. 

30 The NRC staff concludes that the cost estimates provided by FPL-DA are sufficient and 

31 appropriate for use in the SAMA evaluation. 
February 2010 F-27 Draft NUREGTable G-6. Severe Accident Mitigation Alternative Cost/Benefit Screening Analysis for Duane Arnold Ene

1 

% Risk Reduction Total Benefit 

DAEC SAMA Number 

Potential Improvement Modeling Assumptions CDF Population Dose Baseline (Internal + External) B

Un

10 - Provide an additional diesel generator 

Standby diesel generators do not fail 38 41 950K 2.4

12 - Improve 4.16-kV bus cross-tie Division 1 diesel generator does not fail 12 18 400K 1.015 - Install a gas turbine generator Standby diesel generators do not fail 38 41 950K 2.417 - Install a steam-driven turbine generator that uses reactor steam and exhausts to suppression pool 

Standby diesel generators do not fail 38 41 950K 2.4

27 - Install an independent active or passive high pressure injection system 

Small, medium and large LOCAs, breaks outside containment, IORV and SORV sequences eliminated 

26 26 570K 1.4

28 - Provide an additional high pressure injection pump with independent diesel 

HPCI does not fail 37 36 810K 2.0

35 - Add signals to open relief valves automatically in an MSIV closure transient 

Safety/relief valves do not fail 15 7.6 190K 460

39 - Increase flow rate of suppression pool cooling 

Torus cooling always successful 8.1 8.4 170K 420

Steam line breaks and SORV sequences eliminated 

41 16 16 350K 860

© - Provide capability for alternate 

injection via reactor cleanup (RWCU)

HPCI does not fail 37 36 810K 2.0

49 - Replace two of the four electric safety injection pumps with dieselpowered pumps 

Small, medium and large LOCAs, breaks outside containment, IORV and SORV sequences eliminated 

26 26 570K 1.4
Appendix F 

Draft NUREG-1437, Supplement 42 F-28 

% Risk Reduction Total Benefit 

DAEC SAMA Number 

Potential Improvement Modeling Assumptions CDF Population Dose Baseline (Internal + External) B

Un

52 - Replace ECCS pump motors with air-cooled motors 

Small, medium and large LOCAs, breaks outside containment, IORV and SORV sequences eliminated 

26 26 570K 1.4

55 - Implement modifications to allow manual alignment of the fire water system to RHR heat exchangers 

RHR Service Water System does not fail 

4.7 8.7 160K 390

56 - Add a service water pump RHR Service Water System does not 

fail 

4.7 8.7 160K 390

75 - Install an independent method of suppression pool cooling 

Torus cooling always successful 8.1 8.4 170K 420

78 - Enable flooding of the drywell head seal 

Failures of the drywell head flange seal eliminated 

0.0 1.8 25K 65K 

107 - Increase leak testing of valves in interfacing system loss of coolant accident (ISLOCA) paths 

Interfacing System LOCA initiated sequences eliminated 

0.6 0.5 11K 26K 

117 - Increase boron concentration or enrichment in the SLC system 

Human error failure to inject stand-by liquid control early eliminated(d)

9.9 (e) 200K 500

120 - Add a system of relief valves to prevent equipment damage from pressure spikes during ATWS 

ATWS events do not occur 30 26 590K 1.5

123 - Install an ATWS sized filtered containment vent to remove decay heat 

ATWS events do not occur 30 26 590K 1.5

139 - Install digital large break LOCA protection system 

Small, medium and large LOCAs, breaks outside containment, IORV and SORV sequences eliminated 

26 26 570K 1.4

156 - Provide an alternate source of water for the RHRSW/ESW pit (Add Tconnection and valve to pipe connecting the RHRSW/ESW pit to the Circ Water pit to allow backflow from the Circ Water pit to the RHRSW/ESW pit) 

All failures of RWS system eliminated 13 15 320K 800
February 2010 F-29 Draft NUREG

% Risk Reduction Total Benefit 

DAEC SAMA Number 

Potential Improvement Modeling Assumptions CDF Population Dose Baseline (Internal + External) B

Un

163 - Improve the reliability of the RWS system control valves CV4914 and CV4915 

All failures of RWS system eliminated 13 15 320K 800

164 - Improve the reliability of the RWS control system 

Failure of hand switches for both RWS supply valves to stilling basin eliminated from revised SAMA baseline model modified to include backup redundant controls not included in original baseline model 

0.4 0.5 10K 25K 

166 - Increase the reliability of the low pressure ECCS RPV low pressure permissive circuitry. Install manual bypass of the low pressure permissive 

All failures of the low pressure ECCS low reactor pressure permissive switches eliminated 

6.4 13 280K 690

1 (a) SAMAs in bold are potentially cost-beneficial 2 (b) Minimum cost values are based on information provided in response to RAIs and incorporated in updated ER (NextEra 2009a, 2003 (c) For SAMA 41 the benefit reported in the ER is based on mitigating only steam break. An RAI response provided an estimated cost 4 modification but no associated benefit information (NextEra, 2009b). The benefit for this enhanced modification was estimated by N5 See Section G 6.2. 6 (d) Analysis revised in response to an RAI (NextEra, 2009b) 7 (e) Not provided. See Section G 6.2 
Appendix F 

Draft NUREG-1437, Supplement 42 F-30 February 2010 

F.6. Cost-Benefit Comparison 

FPL-DA’s cost-benefit analysis and the NRC staff’s review are described in the following 

sections. 

F.6.1. FPL Energy Duane Arnold, LLC’s Evaluation 

The method used by FPL-DA was based primarily on NRC’s guidance for analyzing cost-benefit 

analysis, (i.e., NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook) 

(NRC, 1997a). The guidance involves determining the net value for each SAMA according to 

the following formula: 

Net Value = (APE + AOC + AOE + AOSC) – COE, where, 

APE = present value of averted public exposure ($) 

AOC = present value of averted offsite property damage costs ($) 

AOE = present value of averted occupational exposure costs ($) 

AOSC = present value of averted onsite costs ($) 

COE = cost of enhancement ($) 

If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 

benefit associated with the SAMA and it is not considered cost-beneficial. FPL-DA’s derivation 

of each of the associated costs is summarized below. 

NUREG/BR-0058 has recently been revised to reflect the agency’s policy on discount rates. 

Revision 4 of NUREG/BR-0058 states that two sets of estimates should be developed, one at 

3 percent and one at 7 percent (NRC, 2004). FPL-DA analyzed the SAMA using 7 percent and 

provided a sensitivity analysis using the 3 percent discount rate in order to capture SAMAs that 

may be cost-effective using the lower discount rate, as well as the higher, baseline rate. In 

addition, FPL-DA provided the results of a sensitivity study using an 8.5 percent discount rate 

which was being used by FPL-DA for project cost estimating purposes at the time of the 

submittal (FPL-DA, 2008). This analysis is sufficient to satisfy NRC policy in Revision 4 of 

NUREG/BR-0058. 

Averted Public Exposure (APE) Costs

The APE costs were calculated using the following formula: 

APE = Annual reduction in public exposure (Δperson-rem/year) 

x monetary equivalent of unit dose ($2,000 per person-rem) 

x present value conversion factor (10.76 based on a 20-year period with a 

7-percent discount rate) 
Appendix F 

February 2010 F-31 Draft NUREG-1437, Supplement 42 

As stated in NUREG/BR-0184 (NRC, 1997a), it is important to note that the monetary value of 

the public health risk after discounting does not represent the expected reduction in public 

health risk due to a single accident. Rather, it is the present value of a stream of potential losses 

extending over the remaining lifetime (in this case, the renewal period) of the facility. Thus, it 

reflects the expected annual loss due to a single accident, the possibility that such an accident 

could occur at any time over the renewal period, and the effect of discounting these potential 

future losses to present value. For the purposes of initial screening, which assumes elimination 

of all severe accidents, FPL-DA calculated an APE of approximately $666,000 for the 20-year 

license renewal period (including the 1.57 factor to account for external events). 

Averted Offsite Property Damage Costs (AOC)

The AOCs were calculated using the following formula: 

AOC = Annual CDF reduction 

x offsite economic costs associated with a severe accident (on a per event basis) 

x present value conversion factor 

This term represents the sum of the frequency-weighted offsite economic costs for each release 

category, as obtained for the Level 3 risk analysis. For the purposes of initial screening, which 

assumes all severe accidents are eliminated, FPL-DA calculated an annual offsite economic risk 

of about $76,700 based on the internal events Level 3 risk analysis. This results in a discounted 

value of approximately $1,290,000 for the 20-year license renewal period (including the 1.57 

factor to account for external events). 

Averted Occupational Exposure (AOE) Costs

The AOE costs were calculated using the following formula: 

AOE = Annual CDF reduction 

x occupational exposure per core damage event 

x monetary equivalent of unit dose 

x present value conversion factor 

FPL-DA derived the values for AOE from information provided in Section 5.7.3 of the regulatory 

analysis handbook (NRC 1997a). Best estimate values provided for immediate occupational 

dose (3,300 person-rem) and long-term occupational dose (20,000 person-rem over a 10-year 

cleanup period) were used. The present value of these doses was calculated using the 

equations provided in the handbook in conjunction with a monetary equivalent of unit dose of 

$2,000 per person-rem, a real discount rate of 7 percent, and a time period of 20 years to 

represent the license renewal period. For the purposes of initial screening, which assumes all 

severe accidents are eliminated, FPL-DA calculated an AOE of approximately $6,500 for the 

20-year license renewal period (including the 1.57 factor to account for external events). 

Averted Onsite Costs

Averted onsite costs (AOSC) include averted cleanup and decontamination costs and averted 

power replacement costs. Repair and refurbishment costs are considered for recoverable 
Appendix F 

Draft NUREG-1437, Supplement 42 F-32 February 2010 

accidents only, not for severe accidents. FPL-DA derived the values for AOSC based on 

information provided in Section 5.7.6 of NUREG/BR-0184, the regulatory analysis handbook 

(NRC 1997a). 

FPL-DA divided this cost element into two parts – the onsite cleanup and decontamination cost, 

also commonly referred to as averted cleanup and decontamination costs (ACC), and the 

replacement power cost (RPC). 

ACCs were calculated using the following formula: 

ACC= Annual CDF reduction 

x present value of cleanup costs per core damage event 

x present value conversion factor 

The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 

NUREG/BR-0184 to be $1.5  109 (undiscounted). This value was converted to present costs 

over a 10-year cleanup period and integrated over the term of the proposed license extension. 

Long-term RPCs were calculated using the following formula: 

RPC= Annual CDF reduction 

x present value of replacement power for a single event 

x factor to account for remaining service years for which replacement power is required 

x reactor power scaling factor 

FPL-DA based its calculations on a DAEC net output of 610 megawatt-electric (MWe) and 

scaled down from the 910 MWe reference plant in NUREG/BR-0184 (NRC, 1997a). Therefore 

FPL-DA applied a power scaling factor of 610/910 to determine the replacement power costs. 

The DAEC net output is stated to include a planned power uprate. 

For the purposes of initial screening, which assumes all severe accidents are eliminated, FPLDA calculated AOSC of approximately $296,000 for the 20-year license renewal period 

(including the 1.57 factor to account for external events). 

Using the above equations, FPL-DA estimated the total present dollar-value equivalent 

associated with completely eliminating severe accidents from both internal and external events 

at DAEC to be about $2.26M, also referred to as the Maximum Attainable Benefit (MAB). 
Appendix F 

February 2010 F-33 Draft NUREG-1437, Supplement 42 

FPL-DA’s Results

If the implementation costs for a candidate SAMA exceeded the calculated benefit, the SAMA 

was considered not to be cost-beneficial. In the baseline analysis contained in the ER (using a 7 

percent discount rate, and considering the impact of external events), FPL-DA identified two 

potentially cost-beneficial SAMAs. The potentially cost-beneficial SAMAs are: 

● SAMA 156 – Provide an alternate source of water for the RHRSW/ESW pit 

● SAMA 166 – Increase the reliability of the low pressure ECCS RPV low 

pressure permissive circuitry. Install manual bypass of low pressure 

permissive. 

FPL-DA analyzed additional analyses to evaluate the impact of parameter choices (alternative 

discount rates and remaining plant life) and uncertainties on the results of the SAMA 

assessment. For the Phase I screening, FPL-DA assumed that there was sufficient margin in 

the maximum benefit estimation that this screening would not be impacted by the sensitivity and 

uncertainty analyses. For the Phase II cost benefit analyses, a quantitative assessment 

indicated that, except for SAMA 117, even with the sensitivity and uncertainty impacts 

considered, the costs of the originally non-cost beneficial SAMAs exceed the benefits and no 

additional SAMA candidates were determined to be potentially cost-beneficial (FPL-DA, 2008). 

As discussed above, the benefit of SAMA 117, increase boron concentration or enrichment, was 

originally underestimated in the ER. FPL-DA provided a revised benefit estimate in response to 

an NRC staff RAI and concluded that this SAMA would also be potentially cost-beneficial when 

considering the impact of uncertainties (NextEra, 2009b). 

FPL-DA indicated that they plan to further evaluate these SAMAs for possible implementation, 

and have included these items in FPL-DA’s corrective action program (FPL-DA, 2008; 

NextEra, 2009b). 

The potentially cost-beneficial SAMAs and FPL-DA’s plans for further evaluation of these 

SAMAs are discussed in detail in Section G.6.2. 

F.6.2. Review of FPL Energy Duane Arnold, LLC’s Cost-Benefit Evaluation 

The cost-benefit analysis analyzed by FPL-DA was based primarily on NUREG/BR-0184 

(NRC, 1997a) and the NRC staff review stated the analysis was conducted consistent with this 

guidance. 

NUREG/BR-0058 has recently been revised to reflect the agency’s policy on discount rates. 

Revision 4 of NUREG/BR-0058 states that two sets of estimates should be developed, one at 

3 percent and one at 7 percent (NRC, 2004). FPL-DA provided a base set of results using the 7 

percent discount rate and a sensitivity study using the 3 percent discount rate (FPL-DA, 2008). 

SAMAs identified primarily on the basis of the internal events analysis could provide benefits in 

certain external events, in addition to internal events. To account for the additional benefits in 

external events, FPL-DA multiplied the internal event benefits for each internal event SAMA by 

a factor of 1.57, which is the ratio of the total CDF from internal and external events to the 

internal event CDF. This factor was based on a combined fire and seismic CDF from the DAEC 

external events PRA (3.74 x 10-6 per year rounded up to 4 x 10-6 per year) plus the high wind 

and tornado CDF from the IPEEE (1.4 x 10-7 per year rounded up to 2 x 10-7 per year) plus the 
Appendix F 

Draft NUREG-1437, Supplement 42 F-34 February 2010 

screening values for external flooding and transportation events (1 x 10-6 per year for each). 

The external event CDF is thus 56.4 percent of the internal events CDF (1.08 x 10-6 per year 

rounded up to 1.1 x 10-6 per year). The total CDF is thus 1.564 times the internal events CDF 

and this was rounded up to 1.57 (NextEra, 2009a). 

Potential benefits in external events were estimated in this manner, since the external-event 

models are generally less detailed than the internal-event models, do not lend themselves to 

quantifying the benefits of the specific plant changes associated with internal-event SAMAs and 

for DAEC, the external events models were not extended to incorporate the assessment of 

releases to the environment. For example, the benefits of a procedural change associated with 

an important internal event sequence cannot be readily assessed using the seismic-risk model if 

that operator action or system is not represented in the seismic-risk model. The use of a 

multiplier on the benefits obtained from the internal events PRA to incorporate the impact of 

external events implicitly assumes that each SAMA would offer the same percentage reduction 

in external-event CDF and population dose as it offers in internal events. While this provides 

only a rough approximation of the potential benefits, such an adjustment was considered 

appropriate given the lack of information on which to base a more precise risk reduction 

estimate for external events. In view of the licensee’s further evaluation of the impacts of the 

use of a multiplier on the SAMA screening (as part of the uncertainty assessment discussed 

below), the NRC staff agrees that the use of such a multiplier for external events is reasonable. 

FPL-DA analyzed additional SAMA sensitivity issues, including use of a 3 percent discount rate, 

use of a longer plant life, and use of different evacuation assumptions. It also considered the 

impact of unresolved peer review findings and recent plant modifications on the results of the 

SAMA analysis. These analyses did not identify additional potentially cost-beneficial SAMAs 

beyond those already identified. 

FPL-DA considered the impact that possible increases in benefits from analysis uncertainties 

would have on the results of the SAMA assessment. In the ER, FPL-DA states that upper 

bound benefits were estimated by multiplying the results using the mean risk values by an 

uncertainty factor of 2.5. This factor was stated to be based on a review of similar PRAs. While 

the factor does not represent an upper bound, it does represent the ratio of the 95th percentile 

CDF to the mean CDF and is considered by the NRC staff to be appropriate for use in the 

SAMA sensitivity analyses. 

FPL-DA’s conclusion that there was sufficient margin in the maximum benefit estimation that the 

Phase I screening would not be impacted by the sensitivity and uncertainty analyses was 

reviewed by the NRC staff and further information was requested in an RAI (NRC, 2009a). 

FPL-DA indicated that the MAB was predicated on the basis of elimination of all the risk, that 

none of the Phase I SAMAs screened out (based on exceeding the MAB) would be expected to 

achieve more than about a 37 percent reduction in risk (equal to elimination of all loss of offsite 

peer risk), and that all of the screened SAMAs involve complex design changes with a 

correspondingly high cost (NextEra, 2009a). Based on the additional information provided, the 

NRC staff agrees with the conclusion that the sensitivity and uncertainty analyses will not result 

in any additional Phase I SAMAs being retained for further evaluation in the Phase II costbenefit analyses. 

As indicated in Section G 2.2, the NRC staff developed an independent conservative 

assessment of the seismic CDF that is approximately an order of magnitude greater than that 

indicated by the DAEC seismic PRA. If this higher value is used, the external events multiplier 

would be increased to 2.3 (from the value of 1.57 used in the ER analysis). The NRC staff 
Appendix F 

February 2010 F-35 Draft NUREG-1437, Supplement 42 

requested that FPL-DA assess the impact on SAMA analysis results if this higher multiplier were 

used in the cost-benefit analysis. In response, FPL-DA indicated that only three SAMAs would 

become potentially cost-beneficial using the higher external events multiplier combined with the 

CDF uncertainty factor described above, (i.e., SAMAs 52, 53, and 163). For SAMA 52, replace 

ECCS pump motors with air-cooled motors, and for SAMA 55, implement modifications to allow 

manual alignment of the fire water system to RHR heat exchangers, FPL-DA provided updated 

cost estimates from other SAMA evaluations for similar modifications that were considerably 

higher than those originally estimated for DAEC. Based on the updated cost estimates, these 

SAMAs would not be cost-beneficial even for the higher external events multiplier combined 

with the CDF uncertainty factor. For SAMA 163, improve the reliability of the RWS system 

control valves; the benefit was originally assessed assuming that the modification would 

eliminate all risk associated with the RWS system. FPL-DA argued that based on a more 

realistic estimate of the risk reduction, this SAMA would also not be cost beneficial even for the 

higher external events multiplier combined with CDF uncertainty (NextEra, 2009a). The NRC 

staff agrees with these conclusions. 

As indicated in Section G 4, the NRC staff questioned FPL-DA on the risk reduction potential for 

certain SAMAs, as summarized below. 

● For SAMA 41, provide capability for alternate injection via the reactor water 

cleanup (RWCU), the ER reported a benefit of $345 thousand and an 

implementation cost of $1.3 million assuming the SAMA is only beneficial in 

events involving steamline breaks or stuck open safety relief valves. In 

response to an NRC staff RAI, FPL-DA indicated that the cost associated 

with modifying the RWCU to allow injection at higher pressures would 

increase to $4 million (NextEra 2009b). While FPL-DA did not provide a 

revised assessment of the benefit associated with the more capable RWCU 

modification, the NRC estimates that the benefit for the more extensive 

RWCU modification would be between that determined for SAMA 27 for an 

independent active or passive high pressure injection system ($570 

thousand) and that for SAMA 28 for an additional high pressure injection 

pump with independent diesel ($814 thousand). The NRC staff concludes 

that the more extensive modification for SAMA 41 would not be cost 

beneficial for the base evaluation or for any of the sensitivity study or 

uncertainty cases. 

● For SAMA 117, increase boron concentration or enrichment. The evaluation 

reported in the ER assumed that this SAMA eliminated mechanical failures 

of the standby liquid control (SLC) system rather than reduce human errors 

associated with initiating SLC. When reevaluated based on the RRW of the 

operator’s failure to inject SLC early, FPL-DA indicated that this SAMA 

would provide a 9.9 percent reduction in CDF and a benefit of 

approximately $200 thousand (NextEra, 2009b). Considering uncertainty, 

this benefit could increase to $500K. Since the cost for implementing this 

SAMA is $400 thousand, FPL-DA concluded that this SAMA would be 

potentially cost-beneficial. FPL-DA has indicated that this SAMA has been 

included in the site corrective action program for further evaluation 

(NextEra, 2009b). 
Appendix F 

Draft NUREG-1437, Supplement 42 F-36 February 2010 

The NRC staff noted that for certain SAMAs considered in the ER, there may be alternatives 

that could achieve much of the risk reduction at a lower cost. The NRC staff asked the licensee 

to evaluate several lower cost alternatives to the SAMAs considered in the ER, including 

SAMAs that had been found to be potentially cost-beneficial at other BWR plants. These 

alternatives included: (1) the use of a portable diesel driven pump for low pressure injection 

through existing systems, (2) use of a portable diesel driven pump to provide makeup to the 

RHRSW/ESW pit, (3) use of a portable DC power supply to maintain DC power availability for 

SBO sequences, (4) improve the reliability of cross-ties between the RHR system and the RHR 

service water, the fire system or other systems that could be used for alternate low pressure 

injection, and (5) create a procedure to maximize CRD flow to provide early and/or late injection. 

FPL-DA addressed each of these alternatives and stated that each has been implemented by 

DAEC procedures. For item 4, FPL-DA described the steps already in place to ensure the 

reliability of the RHR cross-ties. No additional reliability improvements were identified. The NRC 

staff concludes that these alternative SAMAs have been satisfactorily addressed. 

FPL-DA indicated that the three potentially cost-beneficial SAMAs (i.e., SAMAs 117, 156 and 

166) have been entered in DAEC’s site corrective action program for further consideration 

(FPL-DA, 2008; NextEra, 2009b). 

The NRC staff concludes that, with the exception of the potentially cost-beneficial SAMAs 

discussed above, the costs of the other SAMAs evaluated would be higher than the associated 

benefits. 

F.7. Conclusions 

FPL-DA compiled a list of 167 SAMAs based on a review of: (1) the most significant basic 

events from the plant-specific PRA, (2) insights from the plant-specific IPE and IPEEE, (3) the 

generic SAMA candidates from NEI 05-01, and (4) a review of the generic and site-specific 

SAMAs by an expert panel to identify any additional candidates. A qualitative screening 

removed SAMA candidates that: (1) are not applicable to DAEC due to design differences, (2) 

have already been implemented at DAEC, (3) are similar and could be combined with another 

SAMA, and (4) have excessive implementation costs that will obviously exceed the maximum 

benefit. Based on this screening, 143 SAMAs were eliminated leaving 24 candidate SAMAs for 

evaluation. 

For the remaining SAMA candidates, a more detailed design and cost estimate were developed 

as shown in Table G-6. The cost-benefit analyses in the ER showed that two of the SAMA 

candidates were potentially cost-beneficial in the baseline analysis (i.e., Phase II SAMAs 156 

and 166). FPL-DA analyzed additional analyses to evaluate the impact of parameter choices 

and uncertainties on the results of the SAMA assessment. One additional SAMA 

(i.e., SAMA 117) was identified as potentially cost-beneficial in the ER. FPL-DA has indicated 

that these potentially cost-beneficial SAMAs have been entered into the DAEC site corrective 

action program for further consideration. 

The NRC staff reviewed the FPL-DA analysis and concludes that the methods used and the 

implementation of those methods was sound. The treatment of SAMA benefits and costs 

support the general conclusion that the SAMA evaluations analyzed by FPL-DA are reasonable 

and sufficient for the license renewal submittal. Although the treatment of SAMAs for external 

events was somewhat limited, the likelihood of there being cost-beneficial enhancements in this 
Appendix F 

February 2010 F-37 Draft NUREG-1437, Supplement 42 

area was minimized by improvements that have been realized as a result of the IPEEE process, 

and inclusion of a multiplier to account for external events. 

The NRC staff concurs with FPL-DA’s identification of areas in which risk can be further reduced 

in a cost-beneficial manner through the implementation of the identified, potentially costbeneficial SAMAs. Given the potential for cost-beneficial risk reduction, the NRC staff agrees 

that further evaluation of these SAMAs by FPL-DA is warranted. However, these SAMAs do not 

relate to adequately managing the effects of aging during the period of extended operation. 

Therefore, they need not be implemented as part of license renewal pursuant to Title 10 of the 

Code of Federal Regulations (CFR), Part 54. 

F.8. References 

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Power Plant Seismic Margin,” Implementation Guide NP-6041, Revision 1. Palo Alto, CA. 

August 1991. 

FPL Energy Duane Arnold, LLC, (FPL-DA). 2008. Duane Arnold Energy Center – License 

Renewal Application, Applicant’s Environmental Report, Operating License Renewal Stage, 

September 2008. ADAMS Accession No. ML082980480. 

FPL Energy Duane Arnold, LLC, (FPL-DA). 2009. Letter from Richard L. Anderson, FPL Energy 

Duane Arnold, LLC, to NRC Document Control Desk, Subject: License Renewal Application, 

Supplement: Changes Resulting from Issues Raised in the Review Status of the License 

Renewal Application for the Duane Arnold Energy Center. January 23, 2009. ADAMS Accession 

No. ML090280418. 

IES Utilities, Inc. (IES). 1995a. “Duane Arnold Energy Center Individual Plant Examination for 

External Events.” November 1995. 

IES Utilities, Inc. (IES). 1995b. Letter from John F. Franz, IES Utilities, Inc. to William T. Russell, 

USNRC. Subject: Duane Arnold Energy Center Docket No: 50-331 Op. License No: DPR-49 

Response to Request for Additional Information on Individual Plant Examination (IPE) dated 

January 6, 1995. June 26, 1995. 

Iowa Electric Light and Power Co. (IELP). 1992. “Duane Arnold Energy Center Individual Plant 

Examination.” November 1992. 

Kennedy, R. P. 1999. “Overview of Methods for Seismic PRA and Margin Analysis Including 

Recent Innovations,” Proceedings of the OECD-NEA Workshop of Seismic Risk, Tokyo, Japan. 

10–12 August 1999 

NextEra Energy Duane Arnold, LLC (NextEra). 2009a. Letter from Richard L. Anderson, 

NextEra Energy Duane Arnold, LLC Energy to U.S. Nuclear Regulatory Commission Document 

Control Desk. Subject: Response to Request for Additional Information Regarding Severe 

Accident Mitigation Alternatives for Duane Arnold Energy Center. July 9, 2009. 

NextEra Energy Duane Arnold, LLC (NextEra). 2009b. Letter from Christopher R. Costanzo, 

NextEra Energy Duane Arnold, LLC Energy to U.S. Nuclear Regulatory Commission Document 

Control Desk. Subject: Clarification of Response to Request for Additional Information 

Regarding Severe Accident Mitigation Alternatives for Duane Arnold Energy Center. September 

23, 2009. 
Appendix F 

Draft NUREG-1437, Supplement 42 F-38 February 2010 

NextEra Energy Duane Arnold, LLC (NextEra). 2009c. Letter from Christopher R. Costanzo, 

NextEra Energy Duane Arnold, LLC Energy to U.S. Nuclear Regulatory Commission Document 

Control Desk. Subject: First Annual Amendment to the Duane Arnold Energy Center License 

Renewal Application. September 30, 2009. 

Nuclear Energy Institute (NEI). 2005. “Severe Accident Mitigation Alternative (SAMA) Analysis 

Guidance Document.” NEI 05-01, Rev. A. November 2005. 

Seismic Qualification Users Group (SQUG). 1992. “Generic Implementation Procedure” Rev. 2. 

February 1992. 

State Library. 2006. “Projections of Total Population of the U. S., Iowa, and its Counties: 

2000-2003,” adapted from Woods & Poole Economics, Inc. Washington D.C. June 2006. 

TOM COD Data Systems (TOMCOD). 2003. “Evacuation Time Estimate Study for the Duane 

Arnold Emergency Center Emergency Planning Zone.” Decorah, Iowa. June 19, 2003 

U.S. Department of Agriculture (USDA). 1998. “1997 Census of Agriculture.” National 

Agriculture Statistics Service. 1998. Available URL: 

http://www.nass.usda.gov/census/census97/volume1/vol1pubs.htm 

U.S. Department of Agriculture (USDA). 2002. “2002 Census of Agriculture, Volume 1 

Geographic Area Census, State County Data” Available URL: 

http://www.nass.usda.gov/Census/Create_Census_US_CNTY.jsp 

U.S. Nuclear Regulatory Commission (NRC). 1988. Generic Letter 88-20, “Individual Plant 

Examination for Severe Accident Vulnerabilities.” November 23, 1988. 

U.S. Nuclear Regulatory Commission (NRC). 1990. Severe Accident Risks: An Assessment for 

Five U.S. Nuclear Power Plants. NUREG-1150. Washington, D.C. 

U.S. Nuclear Regulatory Commission (NRC). 1994. Revised Livermore Seismic Hazard 

Estimates for Sixty-Nine Nuclear Plant Sites East of the Rocky Mountains. NUREG-1488, April 

1994. Washington, D.C. 

U.S. Nuclear Regulatory Commission (NRC). 1996. Letter from Glenn B. Kelly, U.S. NRC, to 

Lee Liu. Subject: Duane Arnold energy Center - Individual Plant Examination (IPE) Submittal - 

Internal Events (TAC No. M74407). November 12, 1996 

U.S. Nuclear Regulatory Commission (NRC). 1997a. Regulatory Analysis Technical Evaluation 

Handbook. NUREG/BR-0184. Washington, D.C. 

U.S. Nuclear Regulatory Commission (NRC). 1997b. Individual Plant Examination Program: 

Perspectives on Reactor Safety and Plant Performance. NUREG-1560. Washington, D.C. 

U.S. Nuclear Regulatory Commission (NRC). 1998. Letter from Richard J. Laufer, U.S. NRC, to 

Lee Liu, IES Utilities Inc. Subject: Safety Evaluation Report for Unresolved Safety Issue A-46 at 

the Duane Arnold Energy Center (TAC No. M69444). July 29, 1998. 

U.S. Nuclear Regulatory Commission (NRC). 2000. Letter from Brenda L. Mozafari, USNRC to 

Eliot Protsch, IES Utilities Subject: Review of Individual Plant Examination of External Events 

(IPEEE) Submittal, Duane Arnold Energy Center (TAC No. M83618). March 10, 2000. 

U. S. Nuclear Regulatory Commission (NRC). 2002. Perspectives Gained From the Individual 

Plant Examination of External Events (IPEEE) Program. Vols. 1 & 2, Final Report, 

NUREG-1742. Washington, D.C. April 2002. 
Appendix F 

February 2010 F-39 Draft NUREG-1437, Supplement 42 

U.S. Nuclear Regulatory Commission (NRC). 2003. SECPOP2000: Sector Population, Land 

Fraction, and Economic Estimation Program. NUREG/CR-6525, Rev. 1. Sandia National 

Laboratories. August 2003 

U.S. Nuclear Regulatory Commission (NRC). 2004. Regulatory Analysis Guidelines of the U.S. 

Nuclear Regulatory Commission. NUREG/BR-0058, Rev. 4. Washington, D.C. 

U.S. Nuclear Regulatory Commission (NRC). 1991a. Procedural and Submittal Guidance for the 

Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities. 

NUREG-1407. Washington, D.C. June 1991. 

U.S. Nuclear Regulatory Commission (NRC). 1991b. Generic Letter No. 88-20, Supplement 4, 

“Individual Plant Examination of External Events for Severe Accident Vulnerabilities. 

NUREG-1407. Washington, D.C. June 28, 1991. 

U.S. Nuclear Regulatory Commission (NRC). 2009a. Letter from Charles Eccleston, U.S. NRC, 

to Richard L. Anderson, FPL-DA. Subject: Request for Additional Information, Including a 

Revision to RAI 3.H, Regarding Severe Accident Mitigation Alternatives for the Duane Arnold 

energy Center (TAC No. MD9770). June 25, 2009. 

U.S. Nuclear Regulatory Commission (NRC). 2009b. Letter from Charles Eccleston, U.S. NRC, 

to Richard L. Anderson, FPL-DA. Subject: Clarification of Responses to the Request for 

Additional Information Regarding Severe Accident Mitigation Alternatives for the License 

Renewal of the Duane Arnold Energy Center (TAC No. MD9770). August 24, 2009.