NUREG-1437 

Supplement 58

Generic Environmental 

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 58 

Regarding River Bend 

Station, Unit 1

Draft Report for Comment

Office of Nuclear Reactor Regulation
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NUREG-1437 

Supplement 58

Generic Environmental

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 58 

Regarding River Bend 

Station, Unit 1 

Draft Report for Comment

Manuscript Completed: May 2018 

Date Published: May 2018 

Office of Nuclear Reactor Regulation
COMMENTS ON DRAFT REPORT

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

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

specify the report number NUREG-1437 in your comments, and send them by the end of the 

comment period specified in the Federal Register notice announcing the availability of this 

report.

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

Docket ID NRC-2017-0141 in the subject line of your comments. Comments submitted in 

writing or in electronic form will be posted on the NRC website and on the Federal rulemaking 

website http://www.regulations.gov. 

Federal Rulemaking Website: Go to http://www.regulations.gov and search for documents 

filed under Docket ID NRC-2017-0141. 

Mail comments to: May Ma, Director, Program Management, Announcements and Editing 

Branch (PMAE), Office of Administration, Mail Stop: TWFN-7-A-60M, U.S. Nuclear Regulatory 

Commission, Washington, DC 20555-0001. 

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

Manager, 1-800-368-5642, extension 6223 or by e-mail at david.drucker@nrc.gov.

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

record and entered into the Agencywide Documents Access and Management System 

(ADAMS). Do not provide information you would not want to be publicly available.
iii

COVER SHEET

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

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

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

Supplement 58, Regarding River Bend Station, Unit 1, Draft Report for Comment 

(NUREG–1437). River Bend Station is located near St. Francisville, LA. 

For additional information or copies of this document contact:

U.S. Nuclear Regulatory Commission

ATTN: David Drucker, Mail Stop O-11F1

11555 Rockville Pike

Rockville, MD 20852

Phone: 1-800-368-5642, extension 6223, email: david.drucker@nrc.gov

ABSTRACT

The U.S. Nuclear Regulatory Commission (NRC) staff prepared this draft supplemental 

environmental impact statement (SEIS) in response to Entergy Louisiana, LLC and Entergy

Operations, Inc.’s application to renew the operating license for River Bend Station, Unit 1 

(RBS) for an additional 20 years. This draft SEIS includes the NRC staff’s preliminary analysis 

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

proposed action. Alternatives considered include: (1) new nuclear power generation, 

(2) supercritical pulverized coal, (3) natural gas combined-cycle, (4) a combination of natural

gas combined-cycle, biomass, and demand-side management, and (5) no renewal of the

license (the no-action alternative). The NRC staff’s preliminary recommendation is that the

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

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

NRC staff based its recommendation on the following factors:

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

Statement for License Renewal of Nuclear Plants”

• the environmental report submitted by Entergy

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

• the NRC staff’s independent environmental review

• the NRC staff’s consideration of public comments

Comments should be filed no later than 45 days after the date on which the Environmental 

Protection Agency notice stating that the draft environmental impact statement has been filed 

with EPA is published in the Federal Register. Comments received after the expiration of the 

comment period will be considered if it is practical to do so but assurance of consideration of 

late comments cannot be given

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TABLE OF CONTENTS

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

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

LIST OF FIGURES ....................................................................................................................xi

LIST OF TABLES....................................................................................................................xiii

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

ABBREVIATIONS AND ACRONYMS .....................................................................................xxi

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

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

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

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

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

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

1.6 Decisions to be Supported by the SEIS......................................................................1-6

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

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

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

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

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

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

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

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

2.1.2 Refurbishment and Other Activities Associated with License Renewal.........2-2

2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning 

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

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

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

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

2.3 Alternatives Considered but Eliminated.................................................................... 2-13

2.3.1 Solar Power................................................................................................ 2-13

2.3.2 Wind Power................................................................................................ 2-14

2.3.3 Biomass Power .......................................................................................... 2-15

2.3.4 Demand-Side Management........................................................................ 2-15

2.3.5 Hydroelectric Power ................................................................................... 2-16

2.3.6 Geothermal Power ..................................................................................... 2-16

2.3.7 Wave and Ocean Energy ........................................................................... 2-17

2.3.8 Municipal Solid Waste ................................................................................ 2-17

2.3.9 Petroleum-Fired Power .............................................................................. 2-18

2.3.10 Coal—Integrated Gasification Combined Cycle.......................................... 2-18

2.3.11 Fuel Cells ................................................................................................... 2-18

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2.3.12 Purchased Power....................................................................................... 2-19

2.3.13 Delayed Retirement.................................................................................... 2-19

2.4 Comparison of Alternatives ...................................................................................... 2-20

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

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

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

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

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

3.1.4 Radioactive Waste Management Systems ...................................................3-8

3.1.5 Nonradioactive Waste Management Systems ............................................ 3-14

3.1.6 Utility and Transportation Infrastructure...................................................... 3-14

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

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

3.2.1 Land Use.................................................................................................... 3-18

3.2.2 Visual Resources ....................................................................................... 3-23

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

3.3.1 Meteorology and Climatology ..................................................................... 3-25

3.3.2 Air Quality .................................................................................................. 3-26

3.3.3 Noise.......................................................................................................... 3-29

3.4 Geologic Environment.............................................................................................. 3-31

3.4.1 Physiography and Geology ........................................................................ 3-31

3.4.2 Economic Resources ................................................................................. 3-32

3.4.3 Soils ........................................................................................................... 3-34

3.4.4 Land Subsidence ....................................................................................... 3-35

3.4.5 Seismic Setting .......................................................................................... 3-35

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

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

3.5.2 Groundwater Resources............................................................................. 3-50

3.6 Terrestrial Resources............................................................................................... 3-68

3.6.1 River Bend Station Ecoregion..................................................................... 3-68

3.6.2 River Bend Station Site Surveys, Studies, and Reports.............................. 3-69

3.6.3 River Bend Station Site .............................................................................. 3-70

3.6.4 Important Species and Habitats.................................................................. 3-74

3.6.5 Invasive and Non-Native Species............................................................... 3-79

3.7 Aquatic Resources ................................................................................................... 3-80

3.7.1 Environmental Changes in the Lower Mississippi River.............................. 3-81

3.7.2 Lower Mississippi River.............................................................................. 3-82

3.7.3 Other Onsite Aquatic Resources ................................................................ 3-88

3.7.4 State-Ranked Species................................................................................ 3-89

3.7.5 Non-Native and Nuisance Species ............................................................. 3-90

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3.8.1 Species and Habitats Protected Under the Endangered Species Act ......... 3-91

3.8.2 Species and Habitats Protected under the Magnuson–Stevens Act ........... 3-94

3.9 Historic and Cultural Resources ............................................................................... 3-94

3.9.1 Cultural Background................................................................................... 3-95

3.9.2 Historic and Cultural Resources at River Bend Station............................... 3-97

3.10 Socioeconomics....................................................................................................... 3-97

3.10.1 Power Plant Employment ........................................................................... 3-98

3.10.2 Regional Economic Characteristics ............................................................ 3-99

3.10.3 Demographic Characteristics ................................................................... 3-100

3.10.4 Housing and Community Services............................................................ 3-105

3.10.5 Tax Revenues .......................................................................................... 3-107

3.10.6 Local Transportation................................................................................. 3-108

3.11 Human Health ........................................................................................................ 3-109

3.11.1 Radiological Exposure and Risk............................................................... 3-109

3.11.2 Chemical Hazards.................................................................................... 3-110

3.11.3 Microbiological Hazards ........................................................................... 3-111

3.11.4 Electromagnetic Fields ............................................................................. 3-113

3.11.5 Other Hazards.......................................................................................... 3-113

3.12 Environmental Justice ............................................................................................ 3-114

3.13 Waste Management and Pollution Prevention........................................................ 3-119

3.13.1 Radioactive Waste ................................................................................... 3-119

3.13.2 Nonradioactive Waste .............................................................................. 3-119

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

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

4.2 Land Use and Visual Resources ................................................................................4-5

4.2.1 Proposed Action...........................................................................................4-5

4.2.2 No-Action Alternative....................................................................................4-5

4.2.3 Replacement Power Alternatives: Common Impacts ....................................4-6

4.2.4 New Nuclear Alternative...............................................................................4-7

4.2.5 Supercritical Pulverized Coal Alternative ......................................................4-7

4.2.6 Natural Gas Combined-Cycle Alternative .....................................................4-8

4.2.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

Demand-Side Management) ........................................................................4-8

4.3 Air Quality and Noise .................................................................................................4-9

4.3.1 Proposed Action...........................................................................................4-9

4.3.2 No-Action Alternative....................................................................................4-9

4.3.3 Replacement Power Alternatives: Air Quality and Noise Common 

Impacts ........................................................................................................4-9

4.3.4 New Nuclear Alternative............................................................................. 4-10

4.3.5 Supercritical Pulverized Coal Alternative .................................................... 4-11

4.3.6 Natural Gas Combined-Cycle Alternative ................................................... 4-12

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4.3.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

Demand-Side Management) ...................................................................... 4-14

4.4 Geologic Environment.............................................................................................. 4-15

4.4.1 Proposed Action......................................................................................... 4-15

4.4.2 No-Action Alternative.................................................................................. 4-15

4.4.3 Replacement Power Alternatives: Common Impacts .................................. 4-15

4.4.4 New Nuclear Alternative............................................................................. 4-16

4.4.5 Supercritical Pulverized Coal Alternative .................................................... 4-16

4.4.6 Natural Gas Combined-Cycle Alternative ................................................... 4-16

4.4.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

Demand-Side Management) ...................................................................... 4-16

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

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

4.5.2 No-Action Alternative.................................................................................. 4-19

4.5.3 Replacement Power Alternatives: Common Impacts .................................. 4-20

4.5.4 New Nuclear Alternative............................................................................. 4-22

4.5.5 Supercritical Pulverized Coal Alternative .................................................... 4-22

4.5.6 Natural Gas Combined-Cycle Alternative ................................................... 4-23

4.5.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

Demand-Side Management) ...................................................................... 4-24

4.6 Terrestrial Resources............................................................................................... 4-24

4.6.1 Proposed Action......................................................................................... 4-24

4.6.2 No-Action Alternative.................................................................................. 4-27

4.6.3 Replacement Power Alternatives: Common Impacts .................................. 4-27

4.7 Aquatic Resources ................................................................................................... 4-29

4.7.1 Proposed Action......................................................................................... 4-29

4.7.2 No-Action Alternative.................................................................................. 4-30

4.7.3 Replacement Power Alternatives: Common Impacts .................................. 4-30

4.8 Special Status Species............................................................................................. 4-32

4.8.1 Proposed Action......................................................................................... 4-32

4.8.2 No-Action Alternative.................................................................................. 4-39

4.8.3 Replacement Power Alternatives: Common Impacts .................................. 4-39

4.9 Historic and Cultural Resources ............................................................................... 4-41

4.9.1 Proposed Action......................................................................................... 4-41

4.9.2 No-Action Alternative.................................................................................. 4-43

4.9.3 Replacement Power Alternatives: Common Impacts .................................. 4-43

4.10 Socioeconomics....................................................................................................... 4-45

4.10.1 Proposed Action......................................................................................... 4-45

4.10.2 No-Action Alternative.................................................................................. 4-46

4.10.3 Replacement Power Alternatives: Common Impacts .................................. 4-46

4.11 Human Health .......................................................................................................... 4-48

4.11.1 Proposed Action......................................................................................... 4-48

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4.11.2 No-Action Alternative.................................................................................. 4-57

4.11.3 Replacement Power Alternatives: Common Impacts .................................. 4-57

4.12 Environmental Justice .............................................................................................. 4-59

4.12.1 Proposed Action......................................................................................... 4-60

4.12.2 No-Action Alternative.................................................................................. 4-62

4.12.3 Replacement Power Alternatives: Common Impacts .................................. 4-62

4.13 Waste Management ................................................................................................. 4-63

4.13.1 Proposed Action......................................................................................... 4-64

4.13.2 No-Action Alternative.................................................................................. 4-64

4.13.3 Replacement Power Alternatives: Common Impacts .................................. 4-64

4.14 Evaluation of New and Significant Information ......................................................... 4-66

4.15 Impacts Common to All Alternatives......................................................................... 4-67

4.15.1 Fuel Cycle .................................................................................................. 4-67

4.15.2 Terminating Power Plant Operations and Decommissioning ...................... 4-68

4.15.3 Greenhouse Gas Emissions and Climate Change...................................... 4-69

4.16 Cumulative Impacts.................................................................................................. 4-74

4.16.1 Air Quality .................................................................................................. 4-75

4.16.2 Water Resources........................................................................................ 4-76

4.16.3 Aquatic Resources ..................................................................................... 4-84

4.16.4 Historic and Cultural Resources ................................................................. 4-87

4.16.5 Socioeconomics ......................................................................................... 4-87

4.16.6 Human Health ............................................................................................ 4-88

4.16.7 Environmental Justice ................................................................................ 4-89

4.16.8 Waste Management and Pollution Prevention............................................ 4-90

4.17 Resource Commitments Associated with the Proposed Action................................. 4-92

4.17.1 Unavoidable Adverse Environmental Impacts ............................................ 4-92

4.17.2 Relationship between Short-Term Use of the Environment and 

Long-Term Productivity .............................................................................. 4-93

4.17.3 Irreversible and Irretrievable Commitment of Resources ............................ 4-93

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

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

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

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

6 REFERENCES....................................................................................................................6-1

7 LIST OF PREPARERS .......................................................................................................7-1

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

THIS SEIS ARE SENT........................................................................................................8-1

9 INDEX.................................................................................................................................9-1

APPENDIX A COMMENTS RECEIVED ON THE RIVER BEND STATION, UNIT 1 

ENVIRONMENTAL REVIEW........................................................................ A-1

APPENDIX B APPLICABLE LAWS, REGULATIONS, AND OTHER 

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

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APPENDIX C CONSULTATION CORRESPONDENCE REVIEW....................................... C-1

APPENDIX D CHRONOLOGY OF ENVIRONMENTAL REVIEW 

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

APPENDIX E PROJECTS AND ACTIONS CONSIDERED IN THE CUMULATIVE 

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

APPENDIX F U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION

OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR RIVER 

BEND STATION, UNIT 1, IN SUPPORT OF LICENSE RENEWAL 

APPLICATION REVIEW............................................................................... F-1

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LIST OF FIGURES

Figure 1-1. Environmental Review Process.........................................................................1-3

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

Figure 3-1. River Bend Station 50-mi (80-km) Radius Map .................................................3-2

Figure 3-2. Closed-Cycle Cooling System with Mechanical Draft Cooling Towers...............3-4

Figure 3-3. River Bend Station Cooling Water Intake and River Discharge Facilities ..........3-5

Figure 3-4. River Bend Station In-Scope Transmission Lines............................................ 3-17

Figure 3-5. River Bend Station Plant Layout ..................................................................... 3-19

Figure 3-6. River Bend Station Site Land Use/Land Cover................................................ 3-20

Figure 3-7. Federal, State, and Local Lands Within a 6-Mi (10-Km) Radius of River 

Bend Station ................................................................................................... 3-24

Figure 3-8. River Bend Site Topography ........................................................................... 3-33

Figure 3-9. River Bend Alluvial Stream Deposits............................................................... 3-34

Figure 3-10. Hydrologic Features of the Lower Mississippi River Basin Near River 

Bend Station ................................................................................................... 3-38

Figure 3-11. Louisiana Pollutant Discharge Elimination System Permitted Outfalls, 

River Bend Station.......................................................................................... 3-47

Figure 3-12. West Feliciana Parish Generalized North-to-South Hydrogeologic Cross 

Section............................................................................................................ 3-51

Figure 3-13. West-East Cross Section of Upland Terrace and Mississippi River 

Aquifers at River Bend Site ............................................................................. 3-54

Figure 3-14. Aquifers Beneath the Power Block Area That Contain Freshwater.................. 3-55

Figure 3-15. Direction of Groundwater Flow in the Upland Terrace Aquifer at the River 

Bend Site ........................................................................................................ 3-57

Figure 3-16. Cross Section Depicting Groundwater Flow through the Upland Terrace 

Aquifer into the Mississippi River Aquifer and then into the Mississippi 

River ............................................................................................................... 3-58

Figure 3-17. Registered Water Wells Within a 2-Mile Band Around River Bend Station 

Property Boundary.......................................................................................... 3-60

Figure 3-18. Areal Extent of Southern Hills Regional Aquifer System.................................. 3-61

Figure 3-19. Wells Used to Monitor the Groundwater at the River Bend Site ...................... 3-64

Figure 3-20. Groundwater Tritium Concentrations as of November 2015 at the River 

Bend Site ........................................................................................................ 3-66

Figure 3-21. RBS Site Natural Areas................................................................................... 3-80

Figure 3-22. 2010 Census—Minority Block Groups Within a 50-mi (80-km) Radius of 

River Bend Station........................................................................................ 3-117

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Figure 3-23. 2011–2015, American Community Survey 5-Year Estimates—

Low-Income Block Groups Within a 50-mi (80 km) Radius of River Bend 

Station .......................................................................................................... 3-118

Figure 4-1. Salt Water Intrusion into Aquifers Beneath Baton Rouge, LA.......................... 4-82

Figure 4-2. Groundwater Level Drop in "2,800-Foot" Sand Aquifer Beneath River 

Bend Station ................................................................................................... 4-83

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LIST OF TABLES

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

Considered In Depth.........................................................................................2-7

Table 2-2. Summary of Environmental Impacts of the Proposed Action and 

Alternatives..................................................................................................... 2-21

Table 3-1. River Bend Station Site Land Use/Land Cover by Area................................... 3-21

Table 3-2. Land Use/Land Cover within a 6-mi (10-km) Radius of River Bend Station..... 3-22

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

Table 3-4. Permitted Air Emission Sources at River Bend Station ................................... 3-27

Table 3-5. Estimated Air Pollutant Emissions................................................................... 3-28

Table 3-6. Common Noise Sources and Noise Levels ..................................................... 3-29

Table 3-7. Annual River Bend Station Surface Water Withdrawals and Return 

Discharges to the Mississippi River................................................................. 3-41

Table 3-8. Louisiana Pollutant Discharge Elimination System Permitted Outfalls, 

River Bend Station.......................................................................................... 3-44

Table 3-9. Common Wildlife Occurring on or in the Vicinity of the River Bend Station 

Site ................................................................................................................. 3-72

Table 3-10. Important Terrestrial Species and Habitats in West Feliciana Parish............... 3-75

Table 3-11. Historical and Recent Fish Species Recorded near River Bend Station.......... 3-85

Table 3-12. State-Ranked and Protected Species in West Feliciana Parish....................... 3-89

Table 3-13. Residence of Entergy Employees by Parish or County ................................... 3-98

Table 3-14. Employment by Industry in the River Bend Station Region of Influence 

(2011–2015, 5-Year Estimates) ...................................................................... 3-99

Table 3-15. Estimated Income Information for the River Bend Station Socioeconomic 

Region of Influence (2011–2015, 5-Year Estimates)..................................... 3-100

Table 3-16. Population and Percent Growth in River Bend Station Socioeconomic 

Region of Interest Parishes 1980–2010, 2015 (Estimated), and 

2020–2060 (Projected) ................................................................................. 3-101

Table 3-17. Demographic Profile of the Population in the River Bend Station Region 

of Influence in 2010....................................................................................... 3-101

Table 3-18. Demographic Profile of the Population in the River Bend Station Region 

of Influence, 2011–2015, 5-Year Estimates................................................... 3-102

Table 3-19. 2011–2015 5-Year Estimated Seasonal Housing in Parishes or Counties 

Located Within 50 mi (80 km) of River Bend Station ..................................... 3-103

Table 3-20. Migrant Farm Workers and Temporary Farm Labor in Parishes or 

Counties Located Within 50 mi (80 km) of RBS (2012) ................................. 3-104

Table 3-21. Housing in the River Bend Station Region of Influence (2011–2015, 

5-Year Estimate)........................................................................................... 3-105

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Table 3-22. Public Water Supply Systems in East Baton Rouge Parish and West 

Feliciana Parish ............................................................................................ 3-106

Table 3-23. Entergy Louisiana, LLC Property Tax Payments, 2011–2016 ....................... 3-107

Table 3-24. Entergy Louisiana, LLC Annual Support Payments to Agencies and 

Parishes........................................................................................................ 3-108

Table 3-25. Louisiana State Routes in the Vicinity of River Bend Station: 2016 

Average Annual Daily Traffic Count .............................................................. 3-109

Table 4-1. Applicable Category 1 (Generic ) Issues for River Bend Station........................4-2

Table 4-2. Applicable Category 2 (Site-Specific) Issues for the River Bend Station 

Site ...................................................................................................................4-4

Table 4-3. Effect Determinations for Federally Listed Species Under U.S. Fish and 

Wildlife Service Jurisdiction............................................................................. 4-32

Table 4-4. Socioeconomic and Transportation Impacts of Replacement Power 

Alternatives..................................................................................................... 4-48

Table 4-5. River Bend Station Core Damage Frequency for Internal Events.................... 4-53

Table 4-6. Breakdown of Population Dose and Offsite Economic Cost by 

Containment Release Mode............................................................................ 4-54

Table 4-7. Estimated Greenhouse Gas Emissions(a) from Operation at River Bend 

Station ............................................................................................................ 4-70

Table 4-8. Direct Greenhouse Gas Emissions from Facility Operations Under the 

Proposed Action and Alternatives ................................................................... 4-72

Table 4-9. Cumulative Surface Water Withdrawals from the Lower Mississippi River, 

St. Francisville Reach, 2014 ........................................................................... 4-77

Table 4-10. Comparison of Greenhouse Gas Emission Inventories ................................... 4-91

Table 7-1. List of Preparers ...............................................................................................7-1

Table 8-1. List of Agencies, Organizations, and Persons to Whom Copies of this 

SEIS Are Sent...................................................................................................8-1

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

Table B-2. Operating Permits and Other Requirements .................................................... B-5

Table C-1. Endangered Species Act Section 7 Consultation Correspondence with the 

U.S. Fish and Wildlife Service.......................................................................... C-2

Table C-2. National Historic Preservation Act Correspondence......................................... C-3

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

Table E-1. Projects and Actions NRC Staff Considered in the Cumulative Impacts 

Analysis ........................................................................................................... E-1

Table F-1. RBS CDF For Internal Events .......................................................................... F-3

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

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

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

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

Table F-4. Fire Areas Included in Final Phase of IPEEE Screening ................................ F-12

Table F-5. Internal Flooding CDF by Building.................................................................. F-13

Table F-6. SAMA Cost/Benefit Analysis for River Bend Station Unit 1 ............................ F-35

Table F-7. Estimated Cost Ranges for SAMA Applications ............................................. F-44

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EXECUTIVE SUMMARY

Background

By letter dated May 25, 2017, Entergy Louisiana, LLC and Entergy Operations, Inc., (Entergy) 

submitted an application to the U.S. Nuclear Regulatory Commission (NRC) to issue a renewed 

operating license for River Bend Station, Unit 1 (RBS) for an additional 20-year period. 

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

power reactor operating license requires preparation of an environmental impact 

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

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

supplement to the Commission’s NUREG–1437, “Generic Environmental Impact Statement 

(GEIS) for License Renewal of Nuclear Plants.” 

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

process described in 10 CFR Part 51, “Environmental Protection Regulations for Domestic 

Licensing and Related Regulatory Functions,” by publishing a notice of intent to prepare a 

supplemental environmental impact statement (SEIS) and to conduct scoping for RBS. To 

prepare this SEIS, the NRC staff performed the following: 

• conducted a public scoping meeting on September 19, 2017, in St. Francisville, LA

• conducted a severe accident mitigation alternatives audit at RBS from

October 23–25, 2017, and an environmental audit at RBS from October 24–26, 2017

• reviewed Entergy’s environmental report (ER) and compared it to the NRC’s license

renewal GEIS

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

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

NUREG–1555, Supplement 1, Revision 1, “Standard Review Plans for

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

Renewal,” Final Report

• considered public comments received during the scoping process

Proposed Action

Entergy initiated the proposed Federal action (i.e., issuance of a renewed power reactor 

operating license) by submitting an application for license renewal of RBS. The existing RBS 

operating license (NPF-47) expires on August 29, 2025. The NRC’s Federal action is to decide 

whether to issue a renewed license for an additional 20 years of operations. The regulation at 

10 CFR 2.109, “Effect of Timely Renewal Application,” states that if a licensee of a nuclear 

power plant files an application to renew an operating license at least 5 years before the 

expiration date of that license, the existing license will not be deemed to have expired until the 

NRC staff completes safety and environmental reviews of the application, and the NRC makes a 

final decision on whether to issue a renewed license for the additional 20 years.

Purpose and Need for Action

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

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

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

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

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

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

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

Act of 1969, as amended, environmental analysis that would lead the NRC to reject a license 

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

whether a particular nuclear power plant should continue to operate.

Environmental Impacts of License Renewal

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

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

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

following criteria: 

• The environmental impacts associated with the issue

are determined to apply either to all plants or, for

some issues, to plants having a specific type of

cooling system or other specified plant or site

characteristics.

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

or LARGE) has been assigned to the impacts except

for collective offsite radiological impacts from the fuel

cycle and from high-level waste and spent fuel

disposal.

• Mitigation of adverse impacts associated with the

issue is considered in the analysis, and it has been

determined that additional plant-specific mitigation

measures are likely not to be sufficiently beneficial to

warrant implementation.

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

and significant information is identified. Chapter 4 of this SEIS presents the process for 

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

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

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

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

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

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

the applicant’s activities, the public scoping process, and the findings from the site audits 

conducted by the NRC staff. Therefore, the NRC staff relied upon the conclusions of the GEIS 

for all Category 1 issues applicable to RBS.

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

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

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

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

SMALL: Environmental 

effects are not detectable or 

are so minor that they will 

neither destabilize nor 

noticeably alter any important 

attribute of the resource.

MODERATE: Environmental 

effects are sufficient to alter 

noticeably, but not to 

destabilize, important 

attributes of the resource.

LARGE: Environmental 

effects are clearly noticeable 

and are sufficient to 

destabilize important 

attributes of the resource. 

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Groundwater Resources Groundwater use conflicts (plants with 

closed-cycle cooling systems that withdraw 

makeup water from a river)

Radionuclides released to groundwater

SMALL

SMALL to MODERATE

Terrestrial Resources Effects on terrestrial resources (non-cooling

system impacts)

Water use conflicts with terrestrial resources 

(plants with cooling ponds or cooling towers 

using makeup water from a river)

SMALL

SMALL

Aquatic Resources Water use conflicts with aquatic resources 

(plants with cooling ponds or cooling towers 

using makeup water from a river)

SMALL

Special Status Species and 

Habitats

Threatened, endangered, and protected 

species, critical habitat, and essential fish 

habitat

may affect, but is not 

likely to adversely affect 

the pallid sturgeon

Historic and Cultural 

Resources

Historic and cultural resources would not adversely 

affect known historic 

properties

Human Health Microbiological hazards to the public

Electric shock hazards

SMALL

SMALL

Environmental Justice Minority and low-income populations no disproportionately 

high and adverse human 

health and environmental 

effects

Severe Accident Mitigation Alternatives

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

an environmental impact statement or environmental assessment for RBS, 

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

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

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

components, systems, procedures, and training.

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

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

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

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

Alternatives

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

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

renewing the RBS operating license (the no-action alternative). The NRC staff considered the 

following feasible and commercially viable replacement power alternatives:

• new nuclear power

• supercritical pulverized coal

• natural gas combined-cycle

• combination alternative: natural gas combined-cycle, biomass, and

demand-side management

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

Renewal at RBS 

Resource Area Relevant Category 2 Issues Impacts

Surface Water Resources Surface water use conflicts (plants with 

cooling ponds or cooling towers using 

makeup water from a river)

SMALL

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

staff believes are likely to continue to exist when the current RBS license expires. The 

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

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

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

considered the following alternatives, but dismissed them:

• solar power

• wind power

• biomass

• demand-side management

• hydroelectric power

• geothermal power

• wave and ocean energy

• municipal solid waste

• petroleum-fired power

• coal—integrated gasification combined-cycle

• fuel cells

• purchased power

• delayed retirement of nearby generating facilities

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

in evaluating impacts from license renewal.

Preliminary Recommendation

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

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

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

recommendation on the following: 

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

Statement for License Renewal of Nuclear Plants”

• the environmental report submitted by Entergy

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

• the NRC staff’s independent environmental review

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

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

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

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ABBREVIATIONS AND ACRONYMS

ac acre(s)

AC alternating current

ACC averted cleanup and decontamination costs

ACHP Advisory Council on Historic Preservation

ADAMS Agencywide Documents Access and Management System

AEA Atomic Energy Act of 1954 (as amended)

AFW auxiliary feedwater

ANL Argonne National Laboratory

ANS American Nuclear Society

AOC averted offsite property damage costs

AOE averted occupational exposure

AOSC averted onsite costs

AP auxiliary power

APE averted public exposure

AQCR Air Quality Control Region

ASLB Atomic Safety and Licensing Board (NRC)

ASME American Society of Mechanical Engineers

ATWS anticipated transient(s) without scram

BLS Bureau of Labor Statistics

BOEM Bureau of Ocean Energy Management

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

BWR boiling-water reactor

CAA Clean Air Act

CCS carbon capture and storage

CCW component cooling water

CDF core damage frequency

CEQ Council on Environmental Quality

CET containment event tree

CFE early containment failure

CFR Code of Federal Regulations

cfs cubic foot (feet) per second

CLB current licensing basis/bases

CO carbon monoxide

CO2 carbon dioxide

CO2/MWh carbon dioxide per megawatt hour

CO2eq carbon dioxide equivalents 

COL combined license

CSP concentrating solar power

CWA Clean Water Act

dBA A-weighted decibels

DOE U.S. Department of Energy

DSIRE Database of State Incentives for Renewables and Efficiency

DSM demand-side management

ECCS emergency core cooling system

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EFH essential fish habitat

EIA Energy Information Administration

EIS environmental impact statement

Elv. elevation

EMF electromagnetic field

EPA U.S. Environmental Protection Agency

EPRI Electric Power Research Institute

EPZ emergency planning zone

ER Environmental Report

ESA Endangered Species Act of 1973, as amended

ESF engineered safety feature

ESP early site permit

ESW emergency service water

F&O fact and observation

FEIS final environmental impact statement

FERC Federal Energy Regulatory Commission

FESOP Federally Enforceable State Operating Permit

FIVE fire-induced vulnerability evaluation

FR Federal Register

FRN Federal Register notice

ft3 cubic foot (feet)

FW feedwater

FWCA Fish and Wildlife Coordination Act of 1934, as amended

FWS U.S. Fish and Wildlife Service

GEIS generic environmental impact statement

GHG greenhouse gases

GI generic issue

GL generic letter

gpd gallon(s) per day

gpm gallon(s) per minute

ha hectare(s)

HAP Hazardous Air Pollutant

HCLPF high confidence in low probability of failure

HEP human error probability

HFE human failure event

HFO high winds, floods, and other

HRA human reliability analysis

HX heat exchanger

IEA International Energy Agency

IGCC integrated gasification combined-cycle 

INEEL Idaho National Engineering and Environmental Laboratory

IPE individual plant examination

IPEEE individual plant examination(s) of external events

ISLOCA interfacing-systems loss-of-coolant accident

km kilometer(s)

kW kilowatt(s)

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kWe kilowatt(s) electric

kWh/m2

/d kilowatt hours per square meter per day

lb pound(s)

LDEQ Louisiana Department of Environmental Quality

LER large early release

LERF large early release frequency

LMFW loss of main feedwater

LOCA loss-of-coolant accident

LOOP loss(es) of offsite power

Lpd liters per day

LRA license renewal application

μg/m3 micrograms per cubic meter

m/s meter(s) per second

m3 cubic meter(s)

MAAP Modular Accident Analysis Program

MACCS2 MELCOR Accident Consequence Code System 2 

MACR maximum averted cost risk

MATS Mercury and Air Toxics Standards

MCR main control room

mgd million gallons per day

mi mile(s)

MISO Midcontinent Independent System Operator

MMPA Marine Mammal Protection Act

MOV motor-operated valve

mph mile(s) per hour

MSA Magnuson–Stevens Fishery Conservation and Management Act

MUR measurement uncertainty recapture

MW megawatt(s)

MWe megawatt(s) electric

MWh megawatt hour(s)

MWt megawatt(s) thermal

NAAQS National Ambient Air Quality Standards

NEIS National Energy Information Service

NEPA National Environmental Policy Act of 1969, as amended

NETL National Energy Technology Laboratory

NGCC natural gas combined-cycle 

NHPA National Historic Preservation Act of 1966, as amended

NMFS National Marine Fisheries Service

NO2 nitrogen dioxide

NOx nitrogen oxide(s)

NPDES National Pollutant Discharge Elimination System

NRC U.S. Nuclear Regulatory Commission

NREL National Renewable Energy Laboratory

NRR Nuclear Reactor Regulation, Office of (NRC)

O3 ozone

OECR offsite economic cost risk

ORNL Oak Ridge National Laboratory

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Pb lead

ppm parts per million

ppb parts per billion

PDR population dose risk

PDS plant damage state

PEIS programmatic environmental impact statement

PL public law

PM particulate matter

PNNL Pacific Northwest National Laboratory

PORV power-operated relief valve

PRA probabilistic risk assessment

PV photovoltaic

PWR pressurized-water reactor

RAI request(s) for additional information

RBS River Bend Station, Unit 1

RCP reactor coolant pump

RCRA Resource Conservation and Recovery Act of 1976, as amended

rem roentgen equivalent(s) man

RHR residual heat removal

ROI region(s) of influence

RPC replacement power cost

RPS reactor protection system

RPV reactor pressure vessel

RRW risk reduction worth

SAMA severe accident mitigation alternative

SAT system auxiliary transformer

SBO station blackout

SCPC supercritical pulverized coal

SEIS supplemental environmental impact statement

SER safety evaluation report

SG steam generator

SI safety injection

SIP State Implementation Plan

SMA seismic margin assessment

SO2 sulfur dioxide

SR supporting requirement

SSC structure, system, and component

SSEL safe shutdown equipment list

Sv sievert(s)

SW service water

syngas synthesis gas

TEEIC Tribal Energy and Environmental Information Clearinghouse

TS technical specification

U.S. United States

U.S.C. United States Code

UFSAR updated final safety analysis report

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USDA U.S. Department of Agriculture

USGS U.S. Geological Survey

VOC volatile organic compound 

yd3 cubic yard(s)

W/m2 watt(s) per square meter

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1 1 INTRODUCTION

2 The U.S. Nuclear Regulatory Commission’s (NRC’s) environmental protection regulations in 

3 Title 10 of the Code of Federal Regulations (10 CFR) Part 51, “Environmental Protection 

4 Regulations for Domestic Licensing and Related Regulatory Functions,” implement the National 

5 Environmental Policy Act of 1969, as amended (42 U.S.C. 4321 et seq.). This Act is commonly 

6 referred to as NEPA. The regulations at 10 CFR Part 51 require the NRC to prepare an 

7 environmental impact statement (EIS) before making a decision on whether to issue an 

8 operating license or renewed operating license for a nuclear power plant.

9 The Atomic Energy Act of 1954, as amended (42 U.S.C. 2011 et seq.), specifies that licenses 

10 for commercial power reactors can be granted for up to 40 years. The initial 40-year licensing 

11 period was based on economic and antitrust considerations rather than on technical limitations 

12 of the nuclear facility. NRC regulations in 10 CFR 54.31, “Issuance of a Renewed License,”

13 allow the NRC to renew a license for up to an additional 20 years beyond the expiration of the 

14 current operating license. 

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

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

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

18 deny a renewed license based on whether the applicant has demonstrated reasonable 

19 assurance that the environmental and safety requirements in the agency’s regulations can be 

20 met during the period of extended operation.

21 1.1 Proposed Federal Action

22 Entergy Louisiana, LLC and Entergy Operations, Inc. (collectively referred to as Entergy) 

23 initiated the proposed Federal action by submitting an application for a renewed license for

24 River Bend Station, Unit 1 (RBS), for which the existing license (NPF-47) expires on 

25 August 29, 2025. The NRC’s Federal action is to decide whether to renew the license for an 

26 additional 20 years. 

27 1.2 Purpose and Need for the Proposed Federal Action

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

29 provide an option that allows for power generation capability beyond the term of a current 

30 nuclear power plant operating license to meet future system generating needs as such needs 

31 may be determined by other energy-planning decisionmakers. This definition of purpose and 

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

33 by the Atomic Energy Act or findings in the NEPA environmental analysis that would lead the 

34 NRC to reject a license renewal application (LRA), the NRC does not have a role in the 

35 energy-planning decisions of state regulators and utility officials as to whether a particular 

36 nuclear power plant should continue to operate.

37 1.3 Major Environmental Review Milestones

38 Entergy submitted an environmental report (ER) (Entergy 2017h) as an appendix to its license 

39 renewal application in May 2017 (Entergy 2017g). In a letter dated July 10, 2017 (NRC 2017h), 

40 the NRC staff informed Entergy that its LRA was insufficient and requested additional 

41 information. Entergy submitted the requested additional information in a letter dated 
1-2

1 August 1, 2017 (Entergy 2017c). After reviewing the additional information, the NRC staff found 

2 the license renewal application (including the environmental report) to be sufficient to proceed 

3 with the staff’s review. On August 14, 2017, the NRC staff published a Federal Register notice 

4 of acceptability and opportunity for hearing (Volume 82 of the Federal Register (FR), 

5 page 37908 (82 FR 37908)). Then, on September 20, 2017, the NRC published another notice 

6 in the Federal Register (82 FR 44004) informing members of the public of the staff’s intent to 

7 conduct an environmental scoping process, thereby beginning a 30-day scoping comment 

8 period.

9 The NRC staff held a public scoping meeting on September 19, 2017, in St. Francisville, LA. In 

10 April 2018, the NRC issued its “Environmental Impact Statement Scoping Process Summary 

11 Report, River Bend Station, Unit 1, St. Francisville, Louisiana,” which includes the comments 

12 received during the scoping process and the NRC staff’s responses to those comments

13 (NRC 2018b). 

14 To independently verify information that Entergy provided in its environmental report, the NRC 

15 staff conducted two site audits at RBS in October 2017. The NRC staff conducted a severe 

16 accident mitigation alternatives audit from October 23–25, 2017. In a letter dated 

17 December 6, 2017, the staff summarized that site audit and listed the attendees (NRC 2017f). 

18 The NRC staff conducted an environmental audit from October 24–26, 2017. In a letter dated 

19 November 27, 2017, the staff summarized that site audit and listed the attendees (NRC 2017g). 

20 During these audits, the NRC staff met with plant personnel, reviewed site-specific 

21 documentation, toured the facility, and met with representatives of the Louisiana Office of 

22 Cultural Development. 

23 Upon completion of the scoping period and site audits, and completion of its review of the 

24 applicant’s environmental report and related documents, the NRC staff compiled its findings in 

25 this draft supplemental environmental impact statement (SEIS). The NRC staff will make this 

26 draft SEIS available for public comment for 45 days. Based on the information gathered, the 

27 NRC staff will amend the draft SEIS findings, as necessary, and will then publish the final SEIS. 

28 Figure 1-1 shows the major milestones of the environmental review portion of the NRC’s license 

29 renewal application review process. 
1-3

1 Figure 1-1. Environmental Review Process

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

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

4 20 years of plant life. This process consists of separate environmental and safety reviews, 

5 which the NRC staff conducts simultaneously and documents in two reports: (1) the 

6 supplemental environmental impact statement (SEIS) documents the environmental review and 

7 (2) the safety evaluation report (SER) documents the safety review. The findings in the SEIS

8 and the SER are both factors in the NRC’s decision to issue or deny a renewed license.

9 1.4 Generic Environmental Impact Statement

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

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

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

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

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

15 plants and operating them for an additional 20 years. The staff analyzed in detail and resolved 

16 those environmental issues that could be resolved generically in the GEIS. The GEIS originally 

17 was issued in 1996, Addendum 1 to the GEIS was issued in 1999, and Revision 1 to the GEIS 

18 was issued in 2013. Unless otherwise noted, all references to the GEIS include the GEIS, 

19 Addendum 1, and Revision 1. 

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

21 evaluate. Appendix B to Subpart A of 10 CFR Part 51, “Environmental Effect of Renewing the 

22 Operating License of a Nuclear Power Plant,” provides a summary of the staff’s findings in the 

23 GEIS. For each environmental issue addressed in the GEIS, the NRC staff:
1-4

1 • describes the activity that affects the environment

2 • identifies the population or resource that is affected

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

4 resource

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

6 • determines whether the results of the analysis apply to all plants

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

8 that would have the same significance level for all plants

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

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

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

12 SMALL: Environmental effects are not detectable or 

13 are so minor that they will neither destabilize nor 

14 noticeably alter any important attribute of the 

15 resource.

16 MODERATE: Environmental effects are sufficient to 

17 alter noticeably, but not to destabilize, important 

18 attributes of the resource.

19 LARGE: Environmental effects are clearly 

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

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

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

23 are assigned a Category 1 or Category 2 designation. As established in the GEIS, Category 1 

24 issues are those that meet the following criteria:

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

26 either to all plants or, for some issues, to plants that have a specific type of cooling

27 system or other specified plant or site characteristics.

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

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

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

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

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

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

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

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

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

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

38 therefore, additional site-specific review for these issues is required. The GEIS evaluates 

39 78 environmental issues, provides generically applicable findings for numerous issues (subject 

40 to the consideration of any new and significant information on a site-specific basis), and 

41 concludes that a site-specific analysis is required for 17 of the 78 issues. Figure 1-2 illustrates 

42 this process. The results of that site-specific review are documented in the SEIS.

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.
1-5

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

2 1.5 Supplemental Environmental Impact Statement

3 This SEIS presents the NRC staff’s analysis of the environmental effects of the continued 

4 operation of RBS through the license renewal period, alternatives to license renewal, and 

5 mitigation measures for minimizing adverse environmental impacts. Chapter 4 contains 

6 analysis and comparison of the potential environmental impacts from license renewal and 

7 alternatives thereto. Chapter 5 presents the NRC’s recommendation on whether the 

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

9 renewal would be unreasonable. The NRC staff will make its final recommendation to the 

10 Commission on RBS license renewal in the final SEIS, which the NRC staff will issue after 

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

12 In the preparation of the RBS draft SEIS, the NRC staff carried out the following activities:

13 • reviewed the information provided in Entergy’s ER

14 • consulted with Federal agencies, State and local agencies, and Tribal Nations

15 • conducted an independent review of the issues during the environmental and severe

16 accident management analysis site audits

17 • considered public comments received during the environmental scoping process
1-6

1 New information can be identified from many 

2 sources, including the applicant, the NRC, other 

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

4 revealed, it is first analyzed to determine whether 

5 it is within the scope of the license renewal 

6 environmental evaluation. If the new issue bears on the proposed action, the NRC staff would 

7 determine the significance of the issue for the plant and document the analysis in the SEIS.

8 1.6 Decisions to be Supported by the SEIS

9 The decision to be supported by the SEIS is whether to renew the operating license for RBS for 

10 an additional 20 years. The regulation at 10 CFR 51.103(a)(5) specifies the NRC’s decision 

11 standard as follows: 

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

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

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

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

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

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

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

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

20 also decisions that are made outside the regulatory scope of license renewal. These include 

21 decisions related to: (1) changes to plant cooling systems, (2) disposition of spent nuclear fuel, 

22 (3) emergency preparedness, (4) safeguards and security, (5) need for power, and

23 (6) seismicity and flooding (NRC 2013b).

24 1.7 Cooperating Agencies

25 During the scoping process, the NRC staff identified no Federal, State, or local agencies as 

26 cooperating agencies in the preparation of this SEIS.

27 1.8 Consultations

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

29 Magnuson-Stevens Fisheries Conservation and Management Act of 1996, as amended

30 (16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 

31 (54 U.S.C. 300101 et seq.), require Federal agencies to consult with applicable State and 

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

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

34 the following agencies and groups during this environmental review: 

35 • U.S. Fish and Wildlife Service

36 • Chitimacha Tribe of Louisiana

37 • Coushatta Tribe of Louisiana

38 • Jena Band of Choctaw Indians

39 • Tunica-Biloxi Tribe of Louisiana

40 • Alabama Coushatta Tribe of Texas

41 • The Choctaw Nation of Oklahoma

New and significant information. To merit 

additional review, information must be both “new” 

and “significant,” and it must bear on the proposed 

action or its impacts. 
1-7

1 • Mississippi Band of Choctaw Indians

2 • The Seminole Nation of Oklahoma

3 • Seminole Tribe of Florida

4 • Louisiana Office of Cultural Development, State Historic Preservation Office

5 • Federal Advisory Council on Historic Preservation

6 Appendix C of this SEIS discusses the consultations conducted in support of this environmental 

7 review.

8 1.9 Correspondence

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

10 local, and Tribal agencies listed in Section 1.8. Appendices C and D contain a chronological list 

11 of all documents sent and received during the environmental review. Appendix C lists the 

12 correspondence associated with the Endangered Species Act, the Magnuson–Stevens

13 Fisheries Conservation and Management Act, and the National Historic Preservation Act. 

14 Appendix D lists all other correspondence.

15 1.10 Status of Compliance

16 Entergy is responsible for complying with all NRC regulations and other applicable Federal, 

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

18 Federal statutes. Numerous permits and licenses are issued by Federal, State, and local 

19 authorities for activities at RBS. Appendix B of this SEIS contains further information about 

20 Entergy’s status of compliance.

21 1.11 Related State and Federal Activities

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

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

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

25 this SEIS.

26 The Tunica-Biloxi Reservation is the only known Native American Reservation or Trust Land 

27 within 50 miles (mi) (80 kilometers (km)) of RBS. The area surrounding the RBS site is 

28 predominantly rural. A number of parks, historic sites, preserves, and refuges are located near 

29 RBS. Approximately 6 mi (10 km) west of the RBS site, Cat Island National Wildlife Refuge 

30 consists of cypress-tupelo swamp and bottomland hardwood forests. The refuge is one of the 

31 few remaining unleveed sections of floodplain along the Lower Mississippi River and, therefore, 

32 is subject to regular inundation by the river. Nine parks and State-managed historic sites lie 

33 within 6 mi (10 km) of the site: St. Francisville Recreational Park, Parker Memorial Park, Garden 

34 Symposium Park, West Feliciana Sports and Recreational Park, West Feliciana Parish Railroad 

35 Park, Audubon State Historic Site, Rosedown Plantation State Historic Site, Port Hudson State 

36 Historic Site, and Locust Grove State Historic Site.

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

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

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

40 course of preparing the SEIS, the NRC consulted with the U.S. Fish and Wildlife Service.

41 Appendix C provides a complete list of consultation correspondence.

2-1

1 2 ALTERNATIVES INCLUDING THE PROPOSED ACTION 

2 The U.S. Nuclear Regulatory Commission’s (NRC’s) decisionmaking authority in license 

3 renewal focuses on deciding whether or not to renew a nuclear power plant’s operating license. 

4 The agency’s implementation of the National Environmental Policy Act of 1969, as amended 

5 (NEPA) (42 U.S.C. 4321 et seq.), requires the NRC to consider potential alternatives to 

6 renewing a plant’s operating license as well as the environmental impacts of these alternatives. 

7 Considering the environmental impacts of renewing the operating license and comparing those 

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

9 environmental impacts of license renewal are so great that it would be unreasonable for the 

10 agency to preserve the option of license renewal for energy-planning decisionmakers (Title 10 

11 of the Code of Federal Regulations (10 CFR) 51.95(c)(4)). Ultimately, decisionmakers such as 

12 the plant operator, State, or other non-NRC Federal officials will decide whether to carry out the 

13 proposed action (if the NRC renews the license) or shut down the plant and choose an 

14 alternative power generation source. Economic and environmental considerations play 

15 important roles in these other decisionmakers’ decisions.

16 In general, the NRC’s responsibility is to ensure the safe operation of nuclear power facilities, 

17 not to formulate energy policy, promote nuclear power, or encourage or discourage the 

18 development of alternative power generation sources. The NRC does not engage in 

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

20 would be the most likely alternative to be selected in any given case.

21 This chapter provides (1) a description of the proposed action (i.e., NRC renewal of the 

22 operating license for River Bend Station, Unit 1 (RBS)), (2) an in-depth evaluation of reasonable

23 alternatives to the proposed action (including the no-action alternative), and (3) a brief 

24 description of alternatives to the proposed action that the NRC staff considered but then 

25 eliminated from in-depth evaluation. The reasonably foreseeable impacts of the proposed 

26 action (license renewal) are described in Chapter 4 of this plant-specific supplemental 

27 environmental impact statement (SEIS). Chapter 4 also compares the impacts of renewing the 

28 RBS operating license and continued plant operations to the environmental impacts of the 

29 alternatives.

30 2.1 Proposed Action

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

32 whether to renew the RBS operating license for an additional 20 years. An evaluation of the 

33 impacts from continued operation of RBS commences with an overview of the facility and the 

34 facility’s operations, and then considers the affected environment and potential impacts thereto. 

35 A description of normal power plant operations during the license renewal term is provided in 

36 Section 2.1.1. In brief, RBS is a single-unit, nuclear-powered, steam-electric generating facility 

37 that began commercial operation in June 1986. The nuclear reactor is a General Electric 

38 boiling-water reactor (BWR) that produces 967 megawatts electric (MWe) (Entergy 2017h).

39 2.1.1 Plant Operations during the License Renewal Term

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

41 occurring during the current license term. NUREG–1437, Volume 1, Revision 1, “Generic 

42 Environmental Impact Statement for License Renewal of Nuclear Power Plants,” (NRC 2013b) 
2-2

1 (also known as the GEIS) describes the issues that would have the same impact at all nuclear 

2 power plants (generically applicable issues) as well as those issues which would have different 

3 impact levels at different nuclear power plants. The impacts of generically applicable issues are 

4 described in NUREG-1437 as Category 1 issues; those impacts are set out in NUREG-1437 

5 and Table B-1 of 10 CFR Part 51, Appendix B, and those determinations apply to each license 

6 renewal application, subject to the consideration of any new and significant information on a 

7 plant-specific basis. A second group of issues (Category 2) was identified in NUREG-1437 as 

8 having potentially different impacts at each plant, on a site-specific basis; those issues with 

9 plant-specific impact levels need to be discussed in a plant-specific supplemental environmental 

10 impact statement (SEIS) like this one. 

11 Section 2.1.1 of the GEIS, “Plant Operations during the License Renewal Term,” describes the 

12 general types of activities that are carried out during the operation of all nuclear power plants. 

13 These general types of activities include the following:

14 • reactor operation

15 • waste management

16 • security

17 • office and clerical work

18 • surveillance, monitoring, and maintenance

19 • refueling and other outages

20 As stated in Entergy’s environmental report (ER), RBS will continue to operate during the 

21 license renewal term in the same manner as it would during the current license term except for, 

22 as appropriate, additional aging management programs to address structure and component 

23 aging in accordance with 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for 

24 Nuclear Power Plants.”

25 2.1.2 Refurbishment and Other Activities Associated with License Renewal

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

27 components (SSCs). The major refurbishment class of activities characterized in the GEIS is 

28 intended to encompass actions that typically take place only once in the life of a nuclear plant, if 

29 at all (NRC 2013b). For example, replacement of boiling-water reactor recirculation piping 

30 systems is a refurbishment activity. Refurbishment activities may have an impact on the 

31 environment beyond those that occur during normal operations and may require evaluation, 

32 depending on the type of action and the plant-specific design.

33 In preparation for its license renewal application, Entergy evaluated major structures, systems,

34 and components in accordance with 10 CFR 54.21, “Contents of Application—Technical 

35 Information,” to identify major refurbishment activities necessary for the continued operation of 

36 RBS during the proposed 20-year period of extended operation (Entergy 2017h).

37 Entergy did not identify any major refurbishment activities necessary for the continued operation 

38 of RBS beyond the end of the existing operating license (Entergy 2017h).

39 2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning after the 

40 License Renewal Term

41 NUREG–0586, Supplement 1, Volumes 1 and 2, “Generic Environmental Impact Statement on 

42 Decommissioning of Nuclear Facilities: Regarding the Decommissioning of Nuclear Power 
2-3

1 Reactors” (NRC 2002), describes the impacts of decommissioning. The majority of plant 

2 operations activities would cease with reactor shutdown. However, some activities 

3 (e.g., security and oversight of spent nuclear fuel) would remain unchanged, whereas others 

4 (e.g., waste management; office and clerical work; laboratory analysis; and surveillance, 

5 monitoring, and maintenance) would continue at reduced or altered levels. Systems dedicated 

6 to reactor operations would cease operations; however, if these systems are not removed from 

7 the site after reactor shutdown, their physical presence may continue to impact the environment. 

8 Impacts associated with dedicated systems that remain in place or with shared systems that 

9 continue to operate at normal capacities could remain unchanged.

10 Decommissioning will occur whether RBS is shut down at the end of its current operating 

11 license or at the end of the period of extended operation 20 years later. There are no 

12 site-specific issues related to decommissioning. The GEIS concludes that license renewal 

13 would have a negligible (SMALL) effect on the impacts of terminating operations and 

14 decommissioning on all resources (NRC 2013b).

15 2.2 Alternatives

16 As stated above, the National Environmental Policy Act of 1969, as amended (NEPA), requires 

17 the NRC staff to consider reasonable alternatives to the proposed action of renewing the RBS 

18 operating license. For a replacement power alternative to be reasonable it must be both 

19 (1) commercially viable on a utility scale and (2) operational before the reactor’s operating

20 license expires or (3) expected to become commercially viable on a utility scale and operational 

21 before the expiration of the reactor’s operating license (NRC 2013b). The 2013 GEIS update 

22 incorporated the latest information on replacement power alternatives; however, rapidly evolving 

23 technologies are likely to outpace the information in the GEIS. As such, for each SEIS, the 

24 NRC staff must perform a site-specific analysis of alternatives that accounts for changes in 

25 technology and science since the preparation of the most recent GEIS update.

26 The first alternative to the proposed action of NRC issuing a 20-year operating license renewal 

27 to RBS is the NRC simply not issuing that license renewal. This is called the no-action 

28 alternative. Section 2.2.1 below describes the no-action alternative. In addition to the 

29 no-action alternative, this chapter discusses four reasonable replacement power alternatives. 

30 These alternatives seek to replace RBS’s generating capacity and meet the region’s energy 

31 needs through other means or sources. Sections 2.2.2.1 through 2.2.2.4 describe replacement 

32 power alternatives for RBS.

33 2.2.1 No-Action Alternative

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

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

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

37 no-action alternative, the NRC does not renew the operating license, and RBS shuts down at or 

38 before the expiration of the current license in 2025. The GEIS describes impacts that arise 

39 directly from plant shutdown. The NRC expects shutdown impacts to be relatively similar 

40 whether they occur at the end of the current license (i.e., after 40 years of operation) or at the 

41 end of a renewed license (i.e., after 60 years of operation).

42 After shutdown, plant operators will initiate decommissioning in accordance with 10 CFR 50.82, 

43 “Termination of License.” Supplement 1 to NUREG–0586 (NRC 2002) describes the 

44 environmental impacts from decommissioning a nuclear power plant and related activities. The 
2-4

1 analysis in NUREG-0586 bounds the environmental impacts of decommissioning at such time 

2 as Entergy terminates reactor operations at RBS. Chapter 4 of the GEIS (NRC 2013b) and 

3 Section 4.15.2 of this SEIS describe the incremental environmental impacts of license renewal 

4 on decommissioning activities.

5 Termination of operations at RBS would 

6 result in the total cessation of electrical power 

7 production by the plant. Unlike the 

8 alternatives described below in Section 2.2.2, 

9 the no-action alternative does not expressly 

10 meet the purpose and need of the proposed 

11 action, as described in Section 1.2, because 

12 it does not provide a means of delivering 

13 baseload power to meet future electric 

14 system needs. Assuming that a need 

15 currently exists for the power generated by 

16 RBS, the no-action alternative would likely 

17 create a need for a replacement power

18 alternative. The following section describes a 

19 wide range of replacement power 

20 alternatives, and Chapter 4 assesses their 

21 potential impacts. Although the NRC’s 

22 authority only extends to deciding whether to 

23 renew the RBS operating license, the 

24 replacement power alternatives described in 

25 the following sections represent possible 

26 options for energy-planning decisionmakers if 

27 the NRC decides not to renew the RBS 

28 operating license.

29 2.2.2 Replacement Power Alternatives

30 In evaluating alternatives to license renewal, 

31 the NRC considered energy technologies or 

32 options currently in commercial operation, as 

33 well as technologies not currently in commercial operation but likely to be commercially 

34 available by the time the current RBS operating license expires on August 29, 2025. 

35 The GEIS presents an overview of some energy technologies, but does not reach conclusions 

36 about which alternatives are most appropriate. Because many energy technologies are 

37 continually evolving in capability and cost and because regulatory structures have changed to 

38 either promote or impede development of particular alternatives, the analyses in this chapter 

39 rely on a variety of sources of information to determine which alternatives would be available 

40 and commercially viable. In accordance with the NRC’s regulations at 10 CFR 51.45(b)(3), the 

41 NRC staff determined that Entergy’s ER provided a discussion of alternatives that was 

42 “sufficiently complete to aid the Commission in developing and exploring, pursuant to section 

43 102(2)(E) of NEPA, ‘appropriate alternatives to recommended courses of action in any proposal 

44 which involves unresolved conflicts concerning alternative uses of available resources.’” In 

45 addition to the information Entergy provided in its environmental report, the NRC staff’s 

46 analyses in this chapter includes updated information from the following sources:

Alternatives Evaluated in Depth:

• new nuclear

• supercritical pulverized coal (SCPC)

• natural gas combined-cycle (NGCC)

• combination alternative (NGCC, biomass,

and demand-side management (DSM)) 

Other Alternatives Considered but Eliminated: 

• solar power

• wind power

• biomass

• demand-side management

• hydroelectric power

• geothermal power

• wave and ocean energy

• municipal solid waste

• petroleum-fired power

• coal-integrated gasification combinedcycle (IGCC) 

• fuel cells

• purchased power

• delayed retirement
2-5

1 • U.S. Department of Energy’s (DOE’s), U.S. Energy Information Administration (EIA)

2 • other offices within DOE

3 • U.S. Environmental Protection Agency (EPA)

4 • industry sources and publications

5 In total, the NRC staff considered 17 alternatives to the proposed action (see text box) and then 

6 narrowed these to four reasonable replacement power alternatives. Sections 2.2.2.1 through 

7 2.2.2.4 contain staff’s in-depth evaluation of these four alternatives.

8 The staff did not perform in-depth evaluations of alternatives that cannot provide the equivalent 

9 of RBS’s current generating capacity, as those alternatives would not be able to satisfy the 

10 objective of replacing the power generated by RBS. Also, in some cases, the staff eliminated 

11 those alternatives whose costs or benefits do not justify inclusion in the range of reasonable 

12 alternatives. Further, the staff eliminated, as unfeasible, those alternatives not likely to be 

13 constructed and operational by the time the RBS license expires in 2025. Section 2.3 of this 

14 report contains a brief discussion of each eliminated alternative and provides the basis for its 

15 elimination. To ensure that the alternatives considered in the SEIS are consistent with State or 

16 regional energy policies, the NRC staff reviewed energy-related statutes, regulations, and 

17 policies within the RBS region.

18 The evaluation of each alternative considers the environmental impacts across the following 

19 impact categories: 

20 • land use and visual resources

21 • air quality and noise

22 • geologic environment

23 • water resources

24 • ecological resources

25 • historic and cultural resources

26 • socioeconomics, human health, environmental justice

27 • waste management

28 The GEIS assigns most site-specific issues (called Category 2 issues) a significance level of 

29 SMALL, MODERATE, or LARGE. For ecological resources subject to the Endangered 

30 Species Act of 1973, as amended (16 U.S.C. 1531 et seq.); and the Magnuson-Stevens Fishery 

31 Conservation and Management Reauthorization Act of 2006, as amended (16 U.S.C. 1801–

32 1884 et seq.); and historic and cultural resources subject to the National Historic 

33 Preservation Act of 1966, as amended (54 U.S.C. 300101 et seq.), the impact significance 

34 determination language is specific to the authorizing legislation. The order in which this SEIS 

35 presents the different alternatives does not imply increasing or decreasing level of impact; nor 

36 does the order presented imply that an energy-planning decisionmaker would be more (or less) 

37 likely to select any given alternative.

38 Region of Influence

39 If the NRC does not issue a renewed license, procurement of replacement power for RBS may 

40 be necessary. RBS is owned by Entergy Louisiana, LLC and operated by Entergy Operations, 

41 Inc.; together, these companies (both of which are subsidiaries of Entergy Corporation) hold the 

42 RBS operating license. RBS provides electricity through the Midcontinent Independent System 

43 Operator (MISO) to the SERC Reliability Corporation (SERC). SERC serves a region that 
2-6

1 includes all or portions of 16 States in the southeastern and central United States (SERC 2015). 

2 The SERC region within Louisiana covers approximately two-thirds of the State and constitutes 

3 the region of influence for the NRC’s analysis of RBS replacement power alternatives. 

4 In 2015, electric generators in Louisiana had a net summer generating capacity of 

5 approximately 26,000 megawatts (MW). This capacity included units fueled by natural gas 

6 (72 percent), coal (11 percent), nuclear power (8 percent), petroleum (4 percent), and 

7 biomass (2 percent). Lesser amounts associated with several other miscellaneous energy 

8 sources comprised the balance of generating capacity in the State (EIA 2017d).

9 The electric industry in Louisiana provided approximately 108 million megawatt hours (MWh) of 

10 electricity in 2015. This electrical production was dominated by natural gas (61 percent), 

11 nuclear (14 percent), coal (14 percent), petroleum (4 percent), and biomass (3 percent). 

12 Hydroelectric and other miscellaneous energy sources collectively produced the other 4 percent 

13 of the electricity in Louisiana (EIA 2017d).

14 Nationwide in the United States, natural gas generation rose from 16 percent of electricity 

15 generated in 2000 to 27 percent in 2013. Given known technological and demographic trends, 

16 the U.S. Energy Information Administration predicts that by 2040, natural gas will account for 

17 34 percent of electricity generated in the United States (EIA 2013a, 2016a). Electricity 

18 generated from renewable energy is expected to grow from 13 percent of total generation in 

19 2015 to 24 percent in 2040 (EIA 2016a). However, Louisiana’s renewable energy growth may 

20 not follow nationwide forecasts. The State does not have a mandatory renewable portfolio 

21 standard, and there are other uncertainties that could affect forecasts. In particular, the 

22 implementation of policies aimed at reducing greenhouse gas (GHG) emissions could have a 

23 direct effect on fossil fuel-based generation technologies (DSIRE 2016). 

24 The remainder of this section describes replacement power alternatives to RBS license renewal 

25 that the NRC staff considered in depth. These include a new nuclear alternative in 

26 Section 2.2.2.1; a supercritical pulverized coal alternative in Section 2.2.2.2; a natural gas 

27 combined-cycle alternative in Section 2.2.2.3; and a combination of natural gas combined cycle, 

28 biomass, and demand-side management (DSM) in Section 2.2.2.4. Table 2–1 summarizes key 

29 design characteristics of these four alternative power replacement technologies. 
2-7

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

2 Considered In Depth

New Nuclear 

Alternative

Supercritical 

Pulverized Coal 

Alternative

Natural Gas 

Combined-Cycle 

Alternative

Combination 

Alternative

Summary of 

Alternative

One 1,080-MWe 

single-unit nuclear 

plant

Two 510-MWe units 

for a total of 

approximately 

1,020 MWe 

Three 348-MWe 

units for a total of 

approximately 

1,040 MWe

Approximately 

700 MWe from 

natural gas 

combined cycle 

(two units), 

160 MWe from 

biomass (four 

units), and 

110 MWe from 

demand-side 

management 

energy savings 

Location On previously 

disturbed land within 

the Entergy

Louisiana, LLC site.

The Entergy

Louisiana, LLC 

property could be 

developed for the 

new nuclear plant 

alternative. Uses 

RBS transmission 

lines and some 

existing RBS 

infrastructure 

(Entergy 2017h).

On previously 

disturbed land within 

the Entergy

Louisiana, LLC site.

Uses the Mississippi 

River for coal delivery 

to the facility. 

Assumes nearby 

geological formation 

capable of storing 

carbon emissions 

(Entergy 2017h). 

On previously 

disturbed land 

within the Entergy

Louisiana, LLC site. 

May require some 

infrastructure 

upgrades as well as 

construction of a 

new or upgraded 

pipeline. Uses RBS 

transmission lines

and some existing 

RBS infrastructure 

(Entergy 2017h).

The natural gas 

combined-cycle and 

biomass units 

would be located on 

previously disturbed 

land within the 

Entergy Louisiana, 

LLC site. Assumes 

demand-side 

management 

energy savings 

within the Entergy 

Louisiana, LLC 

service territory 

(Entergy 2017h).

Cooling 

System

Closed cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—25 mgd; 

consumptive water

use—22 mgd 

(NRC 2014c).

Closed cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—27 mgd; 

consumptive water 

use—20 mgd 

(NETL 2013). 

Closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—

7.2 mgd; 

consumptive water 

use—5.7 mgd 

(NETL 2013).

Natural gas 

combined-cycle and 

biomass units 

would use 

closed-cycle cooling 

systems with 

mechanical draft 

cooling towers. 

Collectively, cooling 

water withdrawal for 

these units would 

be 8.9 mgd; 

consumptive water 

use would be 

5.8 mgd 

(NREL 2011, 

NETL 2013).

No cooling system

requirements 

required for 

demand-side 

management.
2-8

New Nuclear 

Alternative

Supercritical 

Pulverized Coal 

Alternative

Natural Gas 

Combined-Cycle 

Alternative

Combination 

Alternative

Land 

Requirements

Approximately 

250 ac (101 ha) of 

previously disturbed 

land (EOI 2008, 

Entergy 2017h).

Approximately 100 ac 

(40 ha) for major 

permanent facilities 

and up to 26,000 ac 

(10,500 ha) for coal 

mining and waste 

disposal (Entergy

2016d, 2017h; 

NRC 1996). 

Approximately 

50 ac (20 ha) for the 

plant, with up to an 

additional 25 ac 

(10 ha) for 

right-of-way to 

connect with 

existing natural gas 

supply lines east of 

the site. In addition, 

up to 4,300 ac 

(1,700 ha) could be 

needed for wells, 

collection stations, 

and associated 

pipelines 

(Entergy 2017h, 

NRC 1996). 

Approximately 

95 ac (38 ha) for 

the natural gas 

combined-cycle and 

biomass units, with 

up to an additional 

25 ac (10 ha) for 

right-of-way to 

connect with 

existing natural gas 

supply lines east of 

the site. In 

addition, up to 

4,300 ac (1,700 ha) 

could be needed for 

wells, collection 

stations, and 

associated 

pipelines. 

Demand-side 

management 

requires no land

(Entergy 2017h, 

NRC 1996).

Work Force 3,500 workers during 

peak construction 

and 680 workers 

during operations 

(Entergy 2017h, 

Times-Free 

Press 2015).

2,200 workers during 

peak construction 

and 300 workers 

during operations 

(Entergy 2017h, 

NRC 1996).

1,450 workers 

during peak 

construction and 

180 workers during 

operations 

(Entergy 2017h, 

NRC 1996). 

Natural gas 

combined-cycle and 

biomass units 

would collectively 

require 

1160 workers 

during peak 

construction and 

210 workers during 

operations. 

Demand-side 

management 

requires no facility 

construction or 

operations workers. 

(Entergy 2017h, 

NRC 2013a).

Key: ac = acres, DSM = demand-side management, ha = hectares, mgd = million gallons per day, 

MWe = megawatts electric, NGCC = natural gas combined-cycle (alternative), ROI = region of influence, and 

SCPC = supercritical pulverized coal.

1 2.2.2.1 New Nuclear Alternative

2 The NRC staff considers the construction of a new nuclear plant to be a reasonable alternative 

3 to RBS license renewal. Nuclear generation currently provides approximately 14 percent of 

4 electricity in Louisiana (EIA 2017d). Two nuclear power plants operate in the region of 

5 influence: Waterford Steam Electric Station, Unit 3, is approximately 50 miles south-southeast 

6 of RBS and Grand Gulf Nuclear Station is approximately 100 miles north of RBS. The NRC 
2-9

1 staff determined that there may be sufficient time for Entergy to prepare and submit an 

2 application, build, and operate a new nuclear unit using a certified design before the RBS 

3 license expires in August 2025.

4 In evaluating the new nuclear alternative, the NRC staff assumed that one new nuclear reactor

5 would be built on a portion of the approximately 3,300 ac (1,300 ha) of Entergy Louisiana, LLC 

6 property. The construction would allow for the maximum use of existing ancillary facilities 

7 (e.g., support buildings and transmission infrastructure at location). The Entergy Louisiana, LLC 

8 property currently encompasses RBS Unit 1, as well as a large excavated area originally 

9 planned to support a second unit (planned RBS Unit 2) that Entergy never built. Entergy later 

10 submitted to the NRC a license application for constructing RBS Unit 3 in this excavated area, 

11 but withdrew the application in 2016 (Entergy 2017h; NRC 2017c). 

12 Entergy identified several activities that would need to occur onsite to accommodate 

13 replacement power alternatives. These include modification to portions of West Creek, a 

14 man-made drainage ditch, and relocating portions of the ditch west of its current location to 

15 allow space for construction of replacement power buildings. The three abandoned RBS Unit 1 

16 standby service water chemical cleaning waste storage tanks currently in the former planned 

17 RBS Unit 2 excavation area would also be drained and removed, and several buildings in the 

18 immediate area would be rearranged to allow space for the new unit construction 

19 (Entergy 2017c).

20 For the purposes of this analysis, the NRC staff assumed a Westinghouse AP1000 reactor

21 would replace RBS Unit 1. The AP1000 reactor would have an approximate net electrical 

22 output of 1,080 MWe. The heat rejection demands of a new nuclear reactor would be similar to 

23 those of RBS. In its environmental report, Entergy states that the new reactor could use RBS’s 

24 existing mechanical draft closed-cycle cooling water intake and discharge structures with some 

25 modifications (Entergy 2017h). 

26 The NRC staff also considered the installation of multiple small modular reactors as a new 

27 nuclear alternative to renewing the RBS license. The NRC established the Advanced Reactor 

28 Program in the Office of New Reactors because of considerable interest in small modular 

29 reactors along with anticipated license applications by vendors. Small modular reactors are 

30 approximately 300 MW or less, so they have lower initial capacity than that of large-scale units. 

31 However, they have greater siting flexibility because they can fit in locations not large enough to 

32 accommodate traditional nuclear reactors (DOE undated). The NRC received the first design 

33 certification application for a small modular reactor in December 2016 (NRC 2017b). Following 

34 certification, this design could potentially achieve operation on a commercial scale by 2026 

35 (NuScale 2018). Because commercial-scale operation of small modular reactors is not 

36 expected until after RBS’s license expires in 2025, the NRC staff eliminated this technology as a 

37 reasonable option under the new nuclear alternative.

38 2.2.2.2 Supercritical Pulverized Coal Alternative

39 In 2015, coal-fired generation accounted for approximately 14 percent of all electricity generated 

40 in Louisiana, a 44 percent decrease from 2000 levels (EIA 2017d). Although coal has 

41 historically been the largest source of electricity in the United States, the U.S. Energy 

42 Information Administration expects natural gas generation—and potentially even renewable 

43 energy generation—to surpass coal generation by 2040 (EIA 2017d). Nonetheless, coal 

44 provides the third-greatest share of electrical power in Louisiana, and coal-fired plants represent 

45 a feasible, commercially available option for providing electrical generating capacity beyond 
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1 RBS’s current license expiration. Therefore, the NRC staff considered supercritical coal-fired 

2 generation equipped with carbon capture and storage technology to be a reasonable alternative 

3 to RBS license renewal.

4 Baseload coal units have proven their reliability and can routinely sustain capacity factors as 

5 high as 85 percent. Among the technologies available, pulverized coal boilers producing 

6 supercritical steam (supercritical pulverized coal or SCPC boilers) are increasingly common for 

7 new coal-fired plants given their generally high thermal efficiencies and overall reliability. 

8 Supercritical pulverized coal facilities are more expensive than subcritical coal-fired plants to 

9 construct, but they consume less fuel per unit output, reducing environmental impacts. In a 

10 supercritical coal-fired power plant, burning coal heats pressurized water. As the supercritical 

11 steam and water mixture moves through plant pipes to a turbine generator, the pressure drops 

12 and the mixture flashes to steam. The heated steam expands across the turbine stages, which 

13 then spin and turn the generator to produce electricity. After passing through the turbine, any 

14 remaining steam is condensed back to water in the plant’s condenser. 

15 To replace the 967 MWe that RBS generates, the NRC staff considered two hypothetical 

16 supercritical pulverized coal units, each with a net capacity of approximately 510 MWe. These 

17 coal units would be located at the same general location as described in the new nuclear 

18 alternative in Section 2.2.2.1. The NRC staff also assumes the plant would be located on 

19 previously disturbed land, and that the large excavated area originally planned to support 

20 RBS Unit 2 would be backfilled and the existing chemical waste storage tanks removed. 

21 (Entergy 2017h; 2017c). Most of the coal consumed in Louisiana is subbituminous coal shipped 

22 by rail from Wyoming, with a limited amount coming by barge from Illinois, Indiana, and 

23 Kentucky (EIA 2016c). The NRC staff assumes that the Mississippi River would be used to 

24 deliver coal to the facility, and that a geological formation capable of storing carbon emissions 

25 would be available near the site (Entergy 2017h). The supercritical pulverized coal alternative’s 

26 closed-cycle cooling system would use mechanical draft cooling towers and similar amounts of 

27 water from the Mississippi River as compared to what RBS currently draws. The NRC staff 

28 assumes that the supercritical pulverized coal plant could use the existing intake and discharge

29 structures at RBS with some modifications (Entergy 2017h). 

30 The supercritical pulverized coal alternative would require approximately 100 ac (40 ha) of land 

31 for major permanent facilities as well as the development of dock facilities at the river to support 

32 coal deliveries. To build the supercritical pulverized coal alternative, site crews would clear the 

33 plant site of vegetation, prepare the site surface, and begin excavation. Other crews would then 

34 construct the plant and associated infrastructure. Construction materials would be delivered by 

35 truck or barge. In addition, the NRC staff estimates that the supercritical pulverized coal plant 

36 could require up to 26,000 ac (10,500 ha) of land to support coal mining and waste disposal 

37 during the plant’s operational life (Entergy 2016a, Entergy 2017h, NRC 1996).

38 2.2.2.3 Natural Gas Combined-Cycle Alternative

39 As discussed earlier, natural gas represents approximately 72 percent of the installed 

40 generation capacity and electrical power generated in Louisiana (EIA 2017d). The NRC staff 

41 considers the construction of a natural gas combined-cycle power plant to be a reasonable 

42 alternative to RBS license renewal because natural gas is a feasible, commercially available 

43 option for providing baseload electrical-generating capacity beyond the expiration of RBS’s 

44 current license.
2-11

1 Baseload natural gas combined-cycle power plants have proven their reliability and can have 

2 capacity factors as high as 87 percent (EIA 2015b). In a natural gas combined-cycle system, 

3 electricity is generated using a gas turbine that burns natural gas. A steam turbine uses the 

4 heat from gas turbine exhaust through a heat recovery steam generator to produce additional 

5 electricity. This two-cycle process has a high rate of efficiency because the natural gas 

6 combined-cycle system captures the exhaust heat that otherwise would be lost and reuses it. 

7 Similar to other fossil fuel sources, natural gas combined-cycle power plants are a source of 

8 greenhouse gases, including CO2. However, a natural gas combined-cycle power plant 

9 produces significantly fewer greenhouse gases per unit of electrical output than conventional 

10 coal-powered plants (NRC 2013b).

11 For this alternative, the NRC staff assumes that three natural gas combined-cycle units, each 

12 with a net capacity of 348 MWe, would replace RBS’s 967 MWe generating capacity. Each 

13 plant configuration would consist of two combustion turbine generators, two heat recovery 

14 steam generators, and one steam turbine generator with mechanical draft cooling towers for 

15 heat rejection. The NRC staff assumes the power plant incorporates a selective catalytic 

16 reduction system to minimize the plant’s nitrogen oxide emissions (NETL 2007). This natural 

17 gas combined-cycle plant would consume approximately 47 billion cubic feet 

18 (1,200 million cubic meters) of natural gas annually (EIA 2013c). Natural gas would be 

19 extracted from the ground through wells, treated to remove impurities, and then blended to meet 

20 pipeline gas standards before being piped through the State’s pipeline system to the RBS site. 

21 The natural gas combined-cycle alternative would produce waste, primarily in the form of spent 

22 catalysts used for control of nitrogen oxide emissions.

23 Similar to the new nuclear alternative (Section 2.2.2.1), the NRC staff assumes that the natural 

24 gas combined-cycle replacement power facility would be built on a portion of the approximately 

25 3,300 ac (1,300 ha) Entergy Louisiana, LLC property, and would allow for the maximum use of 

26 the location’s existing ancillary facilities (e.g., support buildings and transmission infrastructure). 

27 Approximately 50 ac (20 ha) of previously disturbed land would be used to construct and 

28 operate the natural gas combined-cycle plant (Entergy 2016a). Depending on the specific site 

29 location and proximity of existing natural gas pipelines, the natural gas alternative may also 

30 require up to 25 ac (10 ha) of land for right-of-way to connect with existing natural gas supply 

31 lines east of the site. In addition, the plant could need up to 4,300 acres (1,700 ha) of land for 

32 wells, collection stations, and associated pipelines (Entergy 2017h).

33 The NRC staff assumes that the natural gas combined-cycle plant would use a closed-cycle 

34 cooling system with mechanical draft cooling towers. To support the plant’s cooling needs, this 

35 cooling system would withdraw approximately 7.2 million gallons per day (28,000 cubic meters 

per day (m3

/day)) of water and consume 5.7 million gallons per day (21,000 m3 36 /day) 

37 (NETL 2013). Because of the high overall thermal efficiency of this type of plant, the natural gas 

38 combined-cycle alternative would require less cooling water than RBS. Onsite visible structures 

39 could include the cooling towers, exhaust stacks, intake and discharge structures, transmission 

40 lines, natural gas pipelines, and an electrical switchyard. Construction materials could be 

41 delivered by a combination of rail spur, truck, and barge. 

42 2.2.2.4 Combination Alternative (Natural Gas Combined Cycle, Biomass, and Demand-Side 

43 Management)

44 This alternative combines natural gas and biomass replacement power generation with energy 

45 efficiency measures to meet the needs and purpose of the RBS license renewal. For the 

46 purpose of this evaluation, the NRC staff assumes that this combination alternative would be 
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1 composed of approximately 700 MWe from a natural gas combined-cycle facility, 160 MWe from 

2 biomass-fired units, and 110 MWe of energy savings from energy efficiency initiatives 

3 (i.e., demand-side management) within the region of influence. The NRC staff assumes that 

4 both the natural gas combined-cycle and biomass-fired portions of this alternative would be 

5 located on previously disturbed land within Entergy Louisiana, LLC property, and would use 

6 existing available site infrastructure to the extent practicable.

7 Natural Gas Combined-Cycle Portion of Combination Alternative

8 To produce its required share of power as part of the combination alternative, the natural gas 

9 plant, operating at an expected capacity factor of 87 percent (EIA 2015b), would need to have a 

10 collective nameplate rating of approximately 800 MWe.

11 The NRC staff assumes that a new natural gas combined-cycle plant as described in 

12 Section 2.2.2.3 would be constructed and operated with a total net capacity of 700 MWe. The 

13 appearance of the natural gas plant under the combination alternative would be similar to the 

14 appearance of the plant for full natural gas combined-cycle alternative. However, in the 

15 combination alternative, only two natural gas combined-cycle units would be built instead of 

16 three units. 

17 Approximately 35 ac (14 ha) of land would be required to construct and operate the two natural 

18 gas combined-cycle units (Entergy 2017h). Depending on the specific site location and 

19 proximity of existing natural gas pipelines, the two natural gas units may also require up to 

20 25 ac (10 ha) of land for right-of-way to connect with existing natural gas supply lines east of the 

21 site. In addition, the plant could need up to 4,300 acres (1,700 ha) of land for wells, collection 

22 stations, and associated pipelines (Entergy 2017h). 

23 The NRC staff assumes that the natural gas combined-cycle plant would use a closed-cycle 

24 cooling system with mechanical draft cooling towers. To support the plant’s cooling needs, this 

system would withdraw approximately 4.9 million gallons per day (18,000 m3 25 /day) of water and 

consume 3.8 million gallons per day (14,000 m3 26 /day) of water (NETL 2013).

27 Biomass Portion of Combination Alternative

28 The 160-MWe biomass-fired portion of the combination alternative would be generated using 

29 four 40-MWe units. Assuming a capacity factor of 83 percent (EIA 2015b), these biomass 

30 facilities would need a collective nameplate rating of approximately 192 MWe. 

31 Biomass fuels are abundant in Louisiana. From 2005 to 2015, Louisiana and other southern 

32 states with ample forest resources led U.S. growth in biomass electricity generation 

33 (EIA 2016e). Electricity generated using biomass fuels, particularly wood and wood wastes, 

34 accounts for more than two-thirds of the State’s renewable energy production (EIA 2017c). 

35 Other resources used for biomass-fired generation could include agricultural residues, animal 

36 manure, residues from food and paper industries, municipal green wastes, dedicated energy 

37 crops, and methane from landfills (IEA 2007). With a 2015 installed capacity of nearly 

38 500 MWe, biomass-fired facilities are the primary renewable energy source in operation in 

39 Louisiana (EIA 2017d).

40 Collectively, the four biomass units would require a total of approximately 60 ac (24 ha) of land 

41 for construction and operation (Entergy 2017h, NRC 2014b). Fuel feedstock for the biomass 

42 units would include energy crops, forest and crop residue, wood waste, and municipal solid 
2-13

1 waste. It is assumed that land use impacts associated with the production of this feedstock 

2 would be the same regardless of whether or not the feedstock is used for electricity generation. 

3 However, additional land could be required for storing, loading, and transporting fuel feedstock.

4 The NRC staff assumes that the biomass units would use a closed-cycle cooling system with 

5 mechanical draft cooling towers. Total cooling needs of the four proposed units would withdraw 

approximately 4.0 million gallons per day (15,000 m3 6 /day) of water and consume 2.0 million 

gallons per day (7,500 m3 7 /day) of water (NREL 2011). 

8 Demand-Side Management Portion of Combination Alternative

9 Demand-side management includes programs designed to improve the energy efficiency of 

10 facilities and equipment, reduce energy demand through behavioral changes (energy 

11 conservation), and demand response initiatives aimed to lessen customer usage or change 

12 energy use patterns during peak periods. These programs and initiatives do not require the 

13 construction and operation of new electrical generating capacity. Although Louisiana does not 

14 have a mandatory energy efficiency resource standard, demand-side management programs 

15 represent a fundamental component of Entergy’s, “2015 Integrated Resource Plan” 

16 (Entergy 2015a, CNEE 2017). 

17 Under the combination alternative, demand-side management programs deployed across the 

18 Entergy Louisiana, LLC service area would replace approximately 110 MWe of the electrical 

19 generating capacity that RBS currently provides. 

20 A 2015 study of existing and potentially deployable demand-side management programs across 

21 Entergy’s residential, commercial, and industrial sectors projected that demand-side 

22 management programs could compensate for 457 MWe of electrical demand by 2025, and as 

23 much as 673 MWe by 2034 (Entergy 2015a, ICF 2015, Entergy 2017h). Therefore, the NRC 

24 staff determined that replacement of 110 MW of RBS output through demand-side management 

25 programs to be a reasonable assumption supporting the combination alternative.

26 2.3 Alternatives Considered but Eliminated

27 The NRC staff considered, but then ultimately eliminated for detailed study, a number of 

28 alternatives to the RBS license renewal. The staff eliminated these alternatives because of 

29 technical reasons, resource availability, or current commercial or regulatory limitations. Many of 

30 these limitations will likely still exist when the current RBS license expires in 2025.

31 2.3.1 Solar Power

32 Solar power, including solar photovoltaic (PV) and concentrating solar power (CSP) 

33 technologies, produce power generated from sunlight. Solar photovoltaic components convert 

34 sunlight directly into electricity using solar cells made from silicon or cadmium telluride. 

35 Concentrating solar power uses heat from the sun to boil water and produce steam that drives a 

36 turbine connected to a generator to ultimately produce electricity (NREL 2014). To be 

37 considered a viable alternative, a solar alternative must replace the amount of electricity that 

38 RBS provides. Assuming capacity factors of 25 to 50 percent (DOE 2011), approximately 

39 2,380 to 4,750 MWe of additional solar energy capacity would need to be installed in the region 

40 of influence.
2-14

1 Solar generators are considered an intermittent resource because their availability depends on 

2 ambient exposure to the sun, also known as solar insolation (EIA 2017e). Insolation rates of 

3 solar photovoltaic resources in Louisiana range from 4.5 to 5.5 kilowatt hours per square meter 

per day (kWh/m2 4 /day) (NREL 2017). Due to higher solar insolation requirements associated 

5 with concentrating solar power, utility-scale application of this technology has only occurred in 

6 western States with high solar thermal resources (i.e., California, Arizona, and Nevada) 

7 (EIA 2016d). 

8 Nationwide, rapid growth in large solar photovoltaic facilities (greater than 5 MW) has resulted in 

9 an increase from 70 MW in 2009 to over 9,000 MW fully online at the end of 2015 

10 (Mendelsohn et al. 2012, Bolinger and Seel 2016). However, Louisiana is one of only a few 

11 States having no utility-scale solar generating capacity (EIA 2017e). In 2015, the State’s small 

12 amount of solar generation was limited to small-scale solar photovoltaic units distributed at 

13 customer sites. Further, Louisiana does not have a mandatory renewable portfolio standard 

14 that would require generators to consider solar power (EIA 2016b). Considering the above 

15 factors, the NRC staff concludes that solar power energy facilities would not be a reasonable 

16 alternative to RBS license renewal.

17 2.3.2 Wind Power

18 As is the case with other renewable energy sources, the feasibility of wind power serving as 

19 alternative baseload power is dependent on the location (relative to expected load centers), 

20 value, accessibility, and constancy of the resource. Wind energy must be converted to 

21 electricity at or near the point where it is extracted, and currently there are limited energy 

22 storage opportunities available to overcome the intermittency and variability of wind resources. 

23 To be considered a reasonable alternative to RBS license renewal, the wind power alternative 

24 must replace the amount of electricity that RBS provides. Assuming a capacity factor of 

25 35 percent for land-based wind and 40 percent for offshore wind, a range of 2,970 to 

26 3,395 MWe of electricity would have to be generated by some combination of land-based and 

27 offshore wind energy facilities in the region of influence.

28 The American Wind Energy Association reports a total of more than 84,000 MW of installed 

29 wind energy capacity nationwide as of March 31, 2017 (DOE 2017). Texas leads all other 

30 States in installed land-based capacity with over 21,000 MW. In contrast, Louisiana, which 

31 shares its western border with Texas, currently has no installed land-based wind power 

32 capacity. The U.S. Energy Information Administration indicates that Louisiana has little overall 

33 wind potential, and that in 2013, the State legislature repealed State tax credits for the 

34 development of future wind systems (EIA 2017c). 

35 Similarly, Louisiana does not have any utility-scale offshore wind farms in operation. In 2016, a 

36 30 MW project off the coast of Rhode Island become the first operating offshore wind farm in the 

37 United States (Energy Daily 2016). Although approximately 20 offshore wind projects 

38 representing more than15,000 MW of capacity were in the planning and permitting process as 

39 of 2015, most of these projects are concentrated along the Nation’s North Atlantic coast, and 

40 none are currently planned off the shores of Louisiana (EIA 2015c, NREL 2015). 

41 Given the amount of wind capacity necessary to replace RBS, the intermittency of the resource, 

42 the current lack of any installed wind capacity in the State, and the limited potential for any new 

43 development in the region of influence, the NRC staff finds a wind based alternative—either 
2-15

1 onshore, offshore, or some combination of both—to be an unreasonable alternative to RBS 

2 license renewal. 

3 2.3.3 Biomass Power

4 As described in Section 2.2.2.4, biomass fuels are abundant in Louisiana. Using biomass-fired 

5 generation for baseload power depends on the geographic distribution, available quantities, 

6 constancy of supply, and energy content of biomass resources. For this analysis, the NRC staff 

7 assumed that biomass would be combusted for power generation in the electricity sector. 

8 Biomass is also used for space heating in residential and commercial buildings and can be 

9 converted to a liquid form for use in transportation fuels. 

10 In 2015, Louisiana had an installed capacity of approximately 500 MW, and approximately 

11 2 percent of the State’s total system power was produced from biomass (EIA 2016b, 

12 EIA 2017d).

13 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 

14 used for biomass conversion would be similar to fossil fuel plants, including the direct 

15 combustion of biomass in a boiler to produce steam (NRC 2013b). Biomass generation is 

16 generally more cost effective when co-fired with coal plants (IEA 2007). Biomass-fired 

17 generation plants generally are small and can reach capacities of 50 MWe, which means that 

18 20 new facilities would be required to replace the generating capacity of RBS. Sufficiently 

19 increasing biomass-fired generation capacity by expanding existing biomass units or 

20 constructing new biomass units by the time RBS’s license expires in 2025, is unlikely. For this 

21 reason, the NRC staff does not consider using biomass-fired generation alone to be a 

22 reasonable alternative to RBS license renewal. However, the NRC staff does consider an 

23 alternative using biomass-fired power in combination with natural gas combined-cycle and 

24 demand-side management measures, as described above in Section 2.2.2.4.

25 2.3.4 Demand-Side Management

26 Energy conservation can include reducing energy demand through behavioral changes or 

27 altering the shape of the electricity load and usually does not require the addition of new 

28 generating capacity. Conservation and energy efficiency programs are more broadly referred to 

29 as demand-side management.

30 Conservation and energy efficiency programs can be initiated by a utility, transmission 

31 operators, the State, or other load-serving entities. In general, residential electricity consumers 

32 have been responsible for the majority of peak load reductions and participation in most 

33 programs is voluntary. Therefore, the existence of a program does not guarantee that 

34 reductions in electricity demand would occur. The GEIS concludes that, although the energy 

35 conservation or energy efficiency potential in the United States is substantial, there are likely no 

36 cases where an energy efficiency or conservation program has been implemented expressly to 

37 replace or offset a large baseload generation station (NRC 2013b). A 2015 study of existing 

38 and potentially deployable demand-side management programs across Entergy’s residential, 

39 commercial, and industrial sectors projected that demand-side management programs could 

40 only compensate for 457 MWe of electrical demand by 2025 (Entergy 2015a, ICF 2015, 

41 Entergy 2017h). Therefore, although significant energy savings are possible in the region of 

42 influence through demand-side management and energy efficiency programs, such programs 

43 are not sufficient to replace RBS as a standalone alternative. However, the NRC staff 

44 concludes that, when used in conjunction with other sources of generating capacity, 
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1 demand-side management can provide a potentially viable alternative to license renewal. The 

2 NRC staff considers such a possible combination alternative as described above in 

3 Section 2.2.2.4.

4 2.3.5 Hydroelectric Power

5 Currently, approximately 2,000 hydroelectric facilities operate in the United States. 

6 Hydroelectric technology captures flowing water and directs it to a turbine and generator to 

7 produce electricity (NRC 2013b). There are three variants of hydroelectric power: 

8 (1) run-of-the-river (diversion) facilities that redirect the natural flow of a river, stream, or canal

9 through a hydroelectric facility, (2) store-and-release facilities that block the flow of the river by 

10 using dams that cause water to accumulate in an upstream reservoir, and (3) pumped storage 

11 facilities that use electricity from other power sources to pump water to higher elevations during 

12 off-peak load periods to be released during peak load periods through the turbines to generate 

13 additional electricity. 

14 A comprehensive survey of hydropower resources, completed in 1997, identified Louisiana as 

15 having 200 MWe of hydroelectric capacity when adjusted for environmental, legal, and 

16 institutional constraints (Conner et al., 1998). These constraints could include (1) scenic, 

17 cultural, historical, and geological values, (2) Federal and State land use, and (3) legal 

18 protection issues, such as wild and scenic legislation and threatened or endangered fish and 

19 wildlife legislative protection. A separate DOE assessment of non-powered dams (dams that do 

20 not produce electricity) concluded that there is potential for 857 MW of electricity in Louisiana 

21 (ORNL 2012). These non-powered dams serve various purposes, such as providing water 

22 supply to inland navigation. Aside from biomass power, hydroelectric is the only other 

23 significant source of renewable power generation deployed in Louisiana, producing 

24 approximately 1,000,000 MWh of electricity in 2015, or 1 percent of the State’s electric power 

25 production. Although the U.S. Energy Information Administration projects that hydropower will 

26 remain a leading source of renewable generation in the United States through 2040, there is 

27 little expected growth in hydropower capacity (EIA 2017d). The potential for future construction 

28 of large hydropower facilities has diminished because of increased public concerns over 

29 flooding, habitat alteration and loss, and destruction of natural river courses (NRC 2013b).

30 Given the projected lack of growth in hydroelectric power production, the competing demands 

31 for water resources, and the expected public opposition to the large environmental impacts and 

32 significant changes in land use that would result from the construction of hydroelectric facilities, 

33 the NRC staff concludes that the expansion of hydroelectric power is not a reasonable 

34 alternative to RBS.

35 2.3.6 Geothermal Power

36 Geothermal technologies extract the heat contained in geologic formations to produce steam to 

37 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 

38 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 

39 a potential source of baseload electric power. However, the feasibility of geothermal power 

40 generation to provide baseload power depends on the regional quality and accessibility of 

41 geothermal resources. Utility-scale geothermal energy generation requires geothermal 

42 reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 

43 300 kilowatts electric to 50 MWe and greater (TEEIC undated). Known geothermal resources 

44 are concentrated in the western United States, specifically Alaska, Arizona, California, 

45 Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and 
2-17

1 Wyoming. In general, most assessments of geothermal resources have been concentrated on 

2 these western states (DOE 2013b, USGS 2008). Geothermal resources are used in the region 

3 of influence for heating and cooling purposes, but no electricity is currently being produced from 

4 geothermal resources in the region of influence (EIA 2017b). Given the low resource potential 

5 in the region of influence, the NRC staff does not consider geothermal to be a reasonable 

6 alternative to license renewal.

7 2.3.7 Wave and Ocean Energy

8 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 

9 for potential renewable energy generation. Four major technologies may be suitable to harness 

10 wave energy: (1) terminator devices that range from 500 kilowatts to 2 MW, (2) attenuators, 

11 (3) point absorbers, and (4) overtopping devices (BOEM undated). Point absorbers and

12 attenuators use floating buoys to convert wave motion into mechanical energy, driving a 

13 generator to produce electricity. Overtopping devices trap a portion of a wave at a higher 

14 elevation than the sea surface; waves then enter a tube and compress air that is used to drive a 

15 generator that produces electricity (NRC 2013b). Some of these technologies are undergoing 

16 demonstration testing at commercial scales, but none are currently used to provide baseload 

17 power (BOEM undated).

18 The Electric Power Research Institute (EPRI) conducted a 2011 assessment that identified the 

19 Gulf Coast of Louisiana as having modest potential ocean wave energy resources (EPRI 2011). 

20 However, the infancy of the technologies and the current lack of commercial application support 

21 the conclusion that wave and ocean energy technologies are not reasonable alternatives to 

22 RBS license renewal. Accordingly, the NRC staff does not consider wave and ocean energy to 

23 be a reasonable alternative to RBS license renewal.

24 2.3.8 Municipal Solid Waste

25 Energy recovery from municipal solid waste converts non-recyclable waste materials into usable 

26 heat, electricity, or fuel through combustion (EPA 2014d). The three types of combustion 

27 technologies include mass burning, modular systems, and refuse-derived fuel systems 

28 (EPA 2014c). Mass burning is the method used most frequently in the United States. The heat 

29 released from combustion is used to convert water to steam, which is used to drive a turbine 

30 generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 

31 captured through a filtering system (EPA 2014c). As of 2016, 77 waste-to-energy plants are in 

32 operation in 22 States, processing approximately 30 million tons of waste per year. These 

33 waste-to-energy plants have an aggregate capacity of 2,547 MWe. Although some plants have 

34 expanded to handle additional waste and to produce more energy, no new plants have been 

35 built in the United States since 1995 (EPA 2014d, Michaels 2016). The average 

36 waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can operate 

37 at capacity factors greater than 90 percent (Michaels 2010). Although Louisiana recognizes 

38 waste-to-energy facilities as a potential renewable energy resource, none of these facilities are 

39 currently planned or are in operation in the State (Michaels 2014). Approximately 

40 20 average-sized plants would be necessary to provide the same level of output as RBS.

41 The decision to burn municipal waste to generate energy is usually driven by the need for an 

42 alternative to landfills rather than a need for energy. Given the improbability that additional 

43 stable supplies of municipal solid waste would be available to support 20 new facilities and 

44 given that no such plants currently operate in the Louisiana, the NRC staff does not consider 

45 municipal solid waste combustion to be a reasonable alternative to RBS license renewal.
2-18

1 2.3.9 Petroleum-Fired Power

2 Petroleum-fired electricity generation accounted for approximately 4 percent of Louisiana’s 

3 statewide total in 2015 (EIA 2017a). However, the variable costs and environmental impacts of 

4 petroleum-fired generation tend to be greater than those of natural gas-fired generation. The 

5 historically higher cost of oil has also resulted in a steady decline in its use for electricity 

6 generation, and no growth in capacity using petroleum-fired power plants is forecast through 

7 2040 (EIA 2013a, 2015a). Therefore, the NRC does not consider petroleum-fired generation to 

8 be a reasonable alternative to RBS license renewal.

9 2.3.10 Coal—Integrated Gasification Combined Cycle

10 Integrated gasification combined cycle is a technology that generates electricity from coal. It 

11 combines modern coal gasification technology with both gas-turbine and steam-turbine power 

12 generation. The technology is cleaner than conventional pulverized coal plants because some 

13 of the major pollutants are removed from the gas stream before combustion. An integrated 

14 gasification combined-cycle power plant consists of coal gasification and combined-cycle power 

15 generation. Coal gasifiers convert coal into a gas (synthesis gas, also referred to as syngas), 

16 which fuels the combined-cycle power generating units. Nearly 100 percent of the nitrogen from 

17 the syngas would be removed before combustion in the gas turbines and would result in lower 

18 nitrogen oxide emissions as compared to conventional coal-fired power plants (DOE 2010).

19 Although several smaller integrated gasification combined-cycle power plants have been in 

20 operation since the mid-1990s, more recent large-scale projects using this technology have 

21 experienced a number of setbacks and opposition that have hindered the technology from fully 

22 integrating into the energy market. The most significant roadblock has been the high capital 

23 cost of an integrated gasification combined-cycle power plant as compared to conventional 

24 coal-fired power plants. Both the Duke Energy Edwardsport Generation Station project in 

25 Indiana and the Kemper County integrated gasification combined-cycle project in east-central 

26 Mississippi have experienced cost and schedule overruns. The Kemper County project 

27 suspended work towards startup of the gasifier component in June 2017 (Energy Daily 2017). 

28 Other issues associated with integrated gasification combined cycle include a limited track 

29 record for reliable performance and opposition based on environmental concerns. Based upon 

30 these developments, the NRC staff determined that this technology would not be a reasonable 

31 source of baseload power to replace RBS by the time its license expires in 2025.

32 2.3.11 Fuel Cells

33 Fuel cells oxidize fuels without combustion and therefore without the environmental side effects 

34 of combustion. Fuel cells use a fuel (e.g., hydrogen) and oxygen to create electricity through an 

35 electrochemical process. The only byproducts are heat, water, and carbon dioxide (depending 

36 on the hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 

37 hydrocarbon resources. Natural gas is a typical hydrogen source. 

38 Fuel cells are not economically or technologically competitive with other alternatives for 

39 electricity generation. The U.S. Energy Information Administration estimates that fuel cells may 

40 cost $7,108 per installed kilowatt (total overnight capital costs in 2012 dollars), which is high 

41 compared to other alternative technologies analyzed in this section (EIA 2013b). More 

42 importantly, fuel cell units are likely to be small in size (approximately 10 MW). The world’s 

43 largest fuel cell facility is a 59 MWe plant that came online in South Korea in 2014 

44 (Entergy 2017h, PEI 2017). Using fuel cells to replace the power that RBS provides would be 
2-19

1 extremely costly. It would require the construction of approximately 100 average-sized units 

2 and modifications to the existing transmission system. Given the immature status and high cost 

3 of fuel cell technology, the NRC staff does not consider fuel cells to be a reasonable alternative 

4 to RBS license renewal.

5 2.3.12 Purchased Power

6 It is possible that replacement power may be imported from outside the RBS region of influence. 

7 Although purchased power would likely have little or no measurable environmental impact in the 

8 vicinity of RBS, impacts could occur where the power is generated or anywhere along the 

9 transmission route, depending on the generation technologies used to supply the purchased 

10 power (NRC 2013b). 

11 As discussed in its report, “2015 Integrated Resource Plan,” Entergy is a member of a regional 

12 transmission organization called MISO (Midcontinent Independent System Operator, Inc.) which 

13 manages the flow of power on a grid which stretches from Canada to the Gulf of Mexico. 

14 Entergy controls approximately 10,600 MW of generating capacity in Louisiana, either through 

15 ownership or long-term purchase power contracts (Entergy 2015a). However, Entergy projects 

16 generating capacity shortfalls of approximately 14,000 MW to occur across the MISO region by 

17 2024. In addition, Entergy does not anticipate that excess power will be available for purchase 

18 to replace RBS’s generating capacity (Entergy 2017h).

19 Additionally, purchased power is generally economically adverse because the cost of generated 

20 power historically has been less than the cost of the same power provided by a third party 

21 (NRC 2013b). Power purchase agreements also carry the inherent risk that the contracted 

22 power will not be delivered. 

23 Based on these considerations, the NRC staff determined that purchased power would not be a 

24 reasonable alternative to RBS license renewal.

25 2.3.13 Delayed Retirement

26 The retirement of a power plant ends its ability to supply electricity. Delaying the retirement of a 

27 power plant enables it to continue supplying electricity. A delayed retirement alternative would 

28 consider deferring the retirement of generating facilities within or near the region of influence.

29 Because generators are required to adhere to additional regulations that will require significant 

30 reductions in plant emissions, some power plants may similarly opt for early retirement of older 

31 units rather than incur the cost for compliance. Additional retirements may be driven by low 

32 natural gas prices, slow growth in electricity demand, and requirements of the Mercury and Air 

33 Toxics Standards (EIA 2015a, EPA 2015).

34 Entergy’s, “2015 Integrated Resource Plan,” describes the company’s fleet of power plants as 

35 aging and increasingly susceptible to accelerated deactivation for economic reasons. 

36 Accordingly, Entergy assumes that it will retire nearly 6,000 MWe of its older, gas-fired 

37 generating units within the region of influence by the end of the current planning horizon in 

38 2034. Over this same period, Entergy is projecting it will need to add at least another 

39 8,000 MWe of generating capacity across its service area (Entergy 2017h, 2015a). Therefore, 

40 even if Entergy could delay some of these retirements through maintenance and 

41 refurbishments, it would still be necessary to add additional generating capacity just to meet 

42 projected load growth over this period, and any system capacity retained through delayed 
2-20

1 retirements would likely not be available to replace RBS’s baseload generation. Because of 

2 these conditions, the NRC staff determined that delayed retirement would not be a reasonable 

3 alternative to RBS license renewal.

4 2.4 Comparison of Alternatives

5 In this chapter, the NRC staff considered in depth one alternative to RBS license renewal that 

6 does not replace the plant’s energy generation (the no-action alternative) and four alternatives

7 to license renewal that may reasonably replace RBS’s energy generation. These four power 

8 generation alternatives are (1) new nuclear generation, (2) supercritical pulverized coal 

9 generation, (3) natural gas combined-cycle generation, and (4) a combination of natural gas 

10 combined-cycle generation, biomass generation, and demand-side management. Table 2-2 

11 summarizes the environmental impacts of these five alternatives to RBS license renewal. 

12 Chapter 4 discusses in greater detail the environmental impacts of each alternative.

13 The environmental impacts of the proposed action (issuing a renewed RBS operating license) 

14 would be SMALL for all impact categories except for groundwater resources. Due to 

15 radionuclides released to groundwater, the environmental impact of RBS license renewal to 

16 groundwater resources would be SMALL to MODERATE.

17 Based on the review presented in this draft SEIS, the NRC staff concludes that the 

18 environmentally preferred alternative is the proposed action, recommending that the RBS 

19 operating license be renewed. All other power generation alternatives have impacts in at least 

20 two resource areas that are greater than license renewal, in addition to the environmental 

21 impacts inherent in new construction projects. To make up the lost power generation if the NRC 

22 does not issue a renewed license for RBS (i.e., the NRC takes the no-action alternative), energy 

23 decisionmakers would likely implement one of the four power replacement alternatives 

24 discussed in this chapter. 
2-21

Table 2-2. Summary of Environmental Impacts of the Proposed Action and Alternatives 1 

Impact Area

(Resource)

RBS 

License 

Renewal 

(Proposed 

Action)

No-Action

Alternative

New 

Nuclear

Alternative

Supercritical 

Pulverized 

Coal 

Alternative

Natural Gas 

Combined-Cycle 

Alternative

C

(N

B

D

M

Land Use SMALL SMALL SMALL SMALL to 

MODERATE

SMALL SMA

Visual Resources SMALL SMALL SMALL SMALL SMALL SMA

Air Quality SMALL SMALL SMALL MODERATE SMALL to 

MODERATE

MOD

Noise SMALL SMALL SMALL SMALL SMALL SMA

Geologic Environment SMALL SMALL SMALL SMALL SMALL SMA

Surface Water Resources SMALL SMALL SMALL SMALL to 

MODERATE

SMALL SMA

Groundwater Resources SMALL to 

MODERATE

SMALL SMALL SMALL to 

MODERATE

SMALL SMA

Terrestrial Resources SMALL SMALL SMALL SMALL to 

MODERATE

SMALL to 

MODERATE

SMA

MOD

Aquatic Resources SMALL SMALL SMALL SMALL SMALL SMA

Special Status Species 

and Habitats

SEE 

NOTE(a)

SEE 

NOTE(b)

SEE NOTE(b) SEE NOTE(b) SEE NOTE(b) SEE 

Historic and Cultural 

Resources

SEE 

NOTE(c)

SEE 

NOTE(d)

SEE NOTE(e) SEE NOTE(e) SEE NOTE(e) SEE 

Socioeconomics SMALL SMALL to 

MODERATE

SMALL to 

LARGE

SMALL to 

LARGE

SMALL to 

LARGE

SMA

MOD

Transportation SMALL SMALL SMALL to 

LARGE

SMALL to 

LARGE

SMALL to 

LARGE

SMA

MOD

Human Health SMALL(f) SMALL(f) SMALL(f) SMALL(f) SMALL(f) SMA

Environmental Justice SEE 

NOTE(g)

SEE 

NOTE(h)

SEE NOTE(i) SEE NOTE(i) SEE NOTE(i) SEE 

Waste Management and 

Pollution Prevention

SMALL(j) SMALL(j) SMALL (j) MODERATE SMALL SMA
2-22

Impact Area

(Resource)

RBS 

License 

Renewal 

(Proposed 

Action)

No-Action

Alternative

New 

Nuclear

Alternative

Supercritical 

Pulverized 

Coal 

Alternative

Natural Gas 

Combined-Cycle 

Alternative

C

(N

B

D

M

(a) The NRC staff concludes that the proposed RBS license renewal may affect, but is not likely to adversely affect, the pallid st

proposed action would have no effect on essential fish habitat.

(b) The types and magnitudes of adverse impacts to species listed in the Endangered Species Act of 1973, as amended (16 U.S

seq.); designated critical habitat; and essential fish habitat would depend on shutdown activities, the proposed site, plant desi

as applicable, and on listed species and habitats present when the alternative is implemented. Therefore, the NRC staff cann

particular level of impact for this alternative.

(c) Based on (1) the location of National Register of Historic Places-eligible historic properties within the area of potential effect, 

(3) Entergy’s cultural resource protection plans, (4) the fact that no license renewal-related physical changes or ground-distur

would occur, (5) State Historic Preservation Office input, and (6) cultural resource assessment, license renewal would not adv

known historic properties (Title 36 of the Code of Federal Regulations 800.4(d)(1), “No Historic Properties Affected”).

(d) Until the Post-Shutdown Decommissioning Activities Report is submitted, the NRC staff cannot determine whether land distu

occur outside the existing operational areas after the nuclear plant is shut down.

(e) This alternative would not adversely affect known historic properties.

(f) The chronic effects of electromagnetic fields on human health associated with operating nuclear power and other electricity g

are uncertain.

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

(h) A reduction in tax revenue resulting from the shutdown of RBS could decrease the availability of public services in West Feli

Minority and low-income populations dependent on these services could be disproportionately affected.

(i) Based on the analysis of human health and environmental impacts presented in this SEIS, this alternative would not likely ha

disproportionately high and adverse human health and environmental effects on minority and low-income populations. Howev

determination would depend on the plant design, and operational characteristics of the alternative. Therefore, the NRC staff c

whether this alternative would result in disproportionately high and adverse human health and environmental effects on minor

income populations.

(j) NUREG–2157, “Generic Environmental Impact Statement for Continued Storage of Spent Nuclear Fuel,” (NRC 2014a) discu

environmental impact of spent fuel storage for the timeframe beyond the licensed life for reactor operations.

1 
3-1

1 3 AFFECTED ENVIRONMENT

2 To conduct an environmental review of River Bend Station, Unit 1 (RBS), the U.S. Nuclear 

3 Regulatory Commission (NRC) must first define and describe the environment that could be 

4 affected by the proposed action. For this review, the NRC staff defines the affected 

5 environment as the environment that currently exists at and around RBS. Because existing 

6 conditions are at least partially the result of past construction and operations at the plant, this 

7 chapter presents the nature and impacts of these past and ongoing actions and how they have 

8 shaped the current environment. The effects of ongoing reactor operations at RBS have 

9 become well established, as environmental conditions have adjusted to the presence of the 

10 nuclear power plant. The affected environment for each resource area is presented in 

11 Sections 3.2 to 3.13.

12 3.1 Description of Nuclear Power Plant Facility and Operation

13 The physical presence of RBS buildings and facilities, as well as the plant’s operations, are 

14 integral to creating the environment that currently exists at and around the site. This section 

15 describes RBS buildings; certain nuclear power plant operating systems; and certain plant 

16 infrastructure, operations, and maintenance. 

17 3.1.1 External Appearance and Setting

18 RBS is located approximately 24 miles (mi) (39 kilometers (km)) north-northeast of 

19 Baton Rouge, LA. Baton Rouge, with approximately 228,000 persons, is the largest population 

20 center within a 50-mi radius of RBS. RBS is approximately 3 mi (5 km) south-southeast of 

21 St. Francisville, LA. St. Francisville, with approximately 1,700 persons, is the nearest town to 

22 RBS. RBS is located in the southern portion of West Feliciana Parish on the east bank of the 

23 Mississippi River. Figure 3-1 presents the 50-mi (80-km) area around RBS. The land within a 

24 6-mi radius of the site is primarily rural. (Entergy 2017h)

25 RBS is situated on approximately 3,342 acres (ac) (1,353 hectares (ha)) of 

26 Entergy Louisiana, LLC-owned property. The primary buildings and structures at RBS include 

27 the primary containment structure, the shield building, the auxiliary building, the fuel building, 

28 the control building, the diesel generator building, the auxiliary control building, the radwaste 

29 building, the turbine building, the water treatment building, the condensate demineralizer 

30 regeneration building, the makeup water pump structure, the circulating water pump structure, 

31 the normal service water cooling towers, the ultimate heat sink, the instrument air/service air 

32 building, and four mechanical-draft cooling towers. These buildings and structures lie 

33 approximately 2 mi (3.2 km) from the bank of the Mississippi River at an elevation of 

34 approximately 100 feet (ft) (30 meters (m)) above mean sea level. The station’s four 

35 mechanical draft cooling towers rise 56 ft (17 m) above grade elevation, but these towers are 

36 not visible above the trees to an offsite viewer. The tallest building at the RBS site is the 

37 approximately 270-ft-high (82-m-high) reactor building. A forested areas acts as a visual buffer 

38 between the reactor building and U.S. Highway 61, which passes less than 1 mi (1.6 km) away 

39 from RBS. For that reason, the reactor building is not visible from U.S. Highway 61 

40 (Entergy 2017h).
3-2

1 Source: Entergy 2017h

2 Figure 3-1. River Bend Station 50-mi (80-km) Radius Map 
3-3

1 3.1.2 Nuclear Reactor Systems

2 RBS is a General Electric Type 6 boiling-water reactor (BWR) with a Mark III containment. The 

3 NRC issued the RBS operating license on November 20, 1985, for a reactor core power level of 

4 3,039 megawatts thermal (MWt). In January 2003, the NRC amended the RBS operating 

5 license to increase the reactor core power level to 3,091 MWt (Agencywide Documents Access 

6 and Management System (ADAMS) Accession No. ML030340294). 

7 RBS fuel is low-enriched uranium dioxide (less than 5 percent by weight uranium-235) ceramic 

pellets. The pellets are sealed in tubes made of standard Zircaloy-2TM 8 . RBS refueling occurs 

9 on a 2-year cycle.

10 3.1.3 Cooling and Auxiliary Water Systems

11 RBS uses a closed-cycle (cooling-tower based) heat dissipation system. During normal plant 

12 operations, this heat dissipation system withdraws makeup water from, and discharges cooling 

13 water back to, the Lower Mississippi River (LMR). RBS uses four mechanical draft cooling 

14 towers for condenser cooling.

15 A boiling-water reactor, like the one used at RBS, generates steam directly in the reactor vessel. 

16 The steam passes through moisture separators and steam dryers and then flows to the turbine. 

17 Such systems typically contain only two heat transfer (exchange) loops (NRC 2013b). The 

18 primary loop transports the steam from the reactor vessel directly to the turbine, which 

19 generates electricity. The secondary cooling water loop removes excess heat from the primary 

20 loop in the main condenser. From the condenser, the primary condensate is returned as 

21 feedwater to the reactor; the secondary cooling water loop removes the excess heat and then 

22 routes it to the cooling towers. The cooling towers dissipate the excess heat to the atmosphere. 

23 Water that is not lost to evaporation is either recirculated through the system or discharged as 

24 blowdown (i.e., water that is periodically rinsed from the cooling system to remove impurities 

25 and sediment that may degrade plant performance) to a receiving water body. Water that is lost 

26 to evaporation or that is discharged as blowdown must be replaced with fresh water; this fresh 

27 replacement water is called makeup water (NRC 2013b). Figure 3-2 provides a basic schematic 

28 diagram of a closed-cycle cooling system with mechanical draft cooling towers.

29 RBS uses both public water and onsite groundwater sources. West Feliciana Parish 

30 Consolidated Water District No. 13 supplies water for drinking and other uses at RBS, as further 

31 discussed below. For a more detailed discussion on RBS groundwater use, see Section 3.5.2.2 

32 of this SEIS.

33 Unless otherwise cited for clarity, the NRC drew information about RBS’s cooling and auxiliary 

34 water systems from Entergy’s environmental report (Entergy 2017h) and from the RBS updated 

35 final safety analysis report (UFSAR) (Entergy 2015d). The NRC staff visited RBS in 

36 October 2017 to conduct an environmental site audit (NRC 2017g). Individual plant systems 

37 that interact with the environment are discussed further below.
3-4

1 Source: Modified from NRC 2013b

2 Figure 3-2. Closed-Cycle Cooling System with Mechanical Draft Cooling Towers

3 3.1.3.1 Cooling Tower Makeup Water Supply and Treatment Systems

4 The plant’s cooling tower makeup water system supplies water from the Lower Mississippi River 

5 to the circulating water system (CWS) and to the service water cooling system (SWCS). This

6 makeup water is necessary to compensate for losses resulting from evaporation and drift from 

7 each system’s cooling towers (Entergy 2017h). 

8 The cooling tower makeup water system is composed of three subsystems: (1) two river intake 

9 screens and suction pipelines, (2) the makeup water pump house, and (3) piping from the pump 

10 house to the clarifiers at the plant site. The pump house contains two makeup water pumps, 

11 each with a capacity of 16,000 gallons per minute (gpm) (35.6 cubic feet per second (cfs) or 

about 1.0 cubic meters per second (m3 12 /s)). 

13 Water is withdrawn from the Lower Mississippi River through two 36-in. (91-cm) diameter 

14 suction pipelines and associated intake screens. These submerged intakes are located in a 

15 man-made recession (embayment) on the east bank of the Lower Mississippi River near 

16 Mississippi River Mile (RM) 262 (River Kilometer (RKm) 421.6). The river bank in the 

17 embayment area is also protected against erosion by riprap stone armoring. Figure 3-3 shows 

18 that the two pipelines are about 400 ft (112 m) in length and carry makeup water from the river 

19 intakes to the makeup water pump house. The pipelines are mounted on steel beams atop 

20 steel pilings driven into the stiff clay layer of the river bottom. A covering of riprap and gravel 

21 helps to protect the pipelines from erosion on the upslope portion of the river. The neck-shaped 

22 configuration of the river bank upstream of the man-made embayment serves to minimize 

23 sediment deposition and debris in the vicinity of the intakes.

24 The octagon-shaped river intake screens are 11 ft (3.4 m) wide diagonally and 4 ft (1.2 m) high. 

25 The openings of the wedge-wire-type screens measure 0.75 by 1.5 in. (1.9 by 3.8 cm) resulting 

26 in an average intake flow velocity of less than 0.5 feet per second (fps) (0.15 m/s) 

27 (Entergy 2016f, 2017h). 
3-5

1 Source: Modified from Entergy 2017h 

2 Figure 3-3. River Bend Station Cooling Water Intake and River Discharge Facilities

3 Each screen is also equipped with a hinged panel that operates on differential pressure. This 

4 ensures that debris fouling has no immediate effect on operations as water can flow to the 
3-6

1 makeup water pumps at all times. Additionally, the screens can be backwashed by operating 

2 the second makeup water pump and directing a portion of the combined flow through the 

3 desired intake screen. Backwashing of the screens is normally performed once each day for 

4 30 minutes, but backwashing frequency can vary based on operational needs (Entergy 2015d).

5 Water withdrawn from the river travels through the intake pipelines to the makeup water pump 

6 house where the pipelines converge into a common header into two 24-in. (9.4-cm) diameter 

7 pipelines. Each of these smaller pipelines is connected to a makeup water pump.

8 One makeup water pump is operated under normal conditions with the other in reserve, with 

9 each pump capable of supplying RBS’s total cooling tower makeup water requirement of 

15,300 gpm (34.1 cfs; 0.96 m3

/s), or about 22 million gallons per day (mgd) (83,300 m3 10 /day). In 

11 turn, the makeup water pumps discharge through one 36-in. (14-cm) diameter pipeline that runs 

12 for approximately 2.6 mi (4.2 km) to the RBS facility complex to a splitter box that supplies each 

13 of the two makeup water clarifiers. There, the clarifiers remove suspended solids from the river 

14 water. Each 100-percent capacity clarifier can treat the entire makeup demand for the plant 

15 cooling towers in the event that one clarifier is out of service. A clarifying agent (polyelectrolyte) 

16 is added to the raw water to enhance the removal of suspended sediment. 

The polyelectrolyte is stored in a 5,000 gal (19 m3 17 ) storage tank and fed by three metering 

pumps. An additional 5,000 gal (19 m3 18 ) storage tank and metering system is used to feed

19 sodium hypochlorite to control biofouling. The clarified and treated makeup water is discharged 

20 over a weir into the circulating water flume that serves the circulating water system, as further 

21 discussed in Section 3.1.3.2.

22 Blowdown (bottom sludge) from the clarifiers enters a dilution-mixing tank near the clarifiers. In 

23 the tank, the blowdown sludge is mixed with raw water. This diluted wastewater is then pumped 

24 through the clarifier sludge blowdown pipeline (Figure 3-3), which is a Louisiana Pollutant 

25 Discharge Elimination System (LPDES) permitted outfall (Outfall 006). Section 3.5.1.3 further 

26 discusses the RBS Louisiana Pollutant Discharge Elimination System permit. 

27 3.1.3.2 Circulating Water System and Blowdown Discharge 

28 The circulating water system provides water to the main condenser to quench the steam 

29 discharged from the main turbine. Cooling occurs as heat is rejected from the circulating water 

30 to the atmosphere through the plant’s circulation water cooling towers (shown in Figure 3-5). 

31 Collectively, the circulating water system is comprised of the plant’s main condenser, four 

32 mechanical draft cooling towers, a circulating water pump structure and flume, and four 

33 25-percent capacity circulating (wet-pit type) water pumps and associated piping. Circulating

34 water is pumped from the circulating water pump structure through the main condenser shells 

35 and then back to the top of the cooling towers. Cooled water exits the towers into the open 

36 flume that bisects the two sets of cooling towers and flows back to the circulating water pump 

37 structure. The flume is about 600 ft (183 m) in length and expands gradually in width from 

38 22 ft (6.7 m) at the cooling tower end of the flume to 36 ft (11 m) at the circulating water pump 

39 structure; it has a maximum depth of 21 ft (6.4 m) (Entergy 2015d, 2017h). 

The circulating water system has a design flow rate of 565,000 gpm (1,260 cfs; 35.6 m3 40 /s) of 

41 circulating water. At 100-percent rated power, the temperature rise in the circulating water 

42 passing through the main condenser is 27°F (15°C) and the maximum temperature of the return 

43 water from the cooling towners is 96°F (35.6°C).
3-7

1 Circulating water is chemically treated to minimize scaling, corrosion, and biological fouling. A 

2 sodium hypochlorite and sodium bromide solution is periodically injected into the circulating 

3 water flume to inhibit biological growth in the circulating water system. Alternatively, biofouling 

treatment occurs by injecting treatment granules into the flume water using the Towerbrom® 4 

5 subsystem. Entergy uses sulfuric acid injection to manage the pH of the circulating water so 

6 that scaling and corrosion in the system are minimized. Along with the sulfuric acid injection, 

7 Entergy also uses a corrosion inhibitor and a dispersant to maintain proper water quality. The 

8 Louisiana Department of Environmental Quality (LDEQ) approves all treatment chemicals at 

9 RBS and the State regulates these chemicals under the plant’s Louisiana Pollutant Discharge 

10 Elimination System permit (Permit No. LA0042731). (Entergy 2017h) 

11 3.1.3.3 Normal Service Water System

12 Separate from the circulating water system, the normal service water system (NSWS) provides 

13 cooling water to plant auxiliary system components (such as heat exchangers, chillers, and 

14 coolers) during all modes of plant operation including systems in the turbine, radwaste, auxiliary, 

15 control, standby diesel, and reactor buildings. Section 3.1.3.4 describes how the service water 

16 cooling system cools the normal service water system. 

Three 50-percent capacity pumps (rated at 31,500 gpm (70.2 cfs; 2.0 m3 17 /s)) take suction from 

18 the service water heat exchanger common discharge header/pump suction header and 

19 discharge into the common system supply header. From that point, the header is routed to a 

20 point outside the turbine building where it branches into two supply headers, one to the turbine 

21 building and the second to the other facilities served by the normal service water system. The 

22 nominal flow rate within the system is approximately 50 gpm (189 liters per minute (L/min). 

23 Scaling, corrosion, and biological fouling are controlled in the system through the addition of 

24 various treatment chemicals to the service water (Entergy 2015d, 2017h).

25 3.1.3.4 Service Water Cooling System

26 The service water cooling system provides cooling water to remove heat from the normal 

27 service water system, described above, during normal plant operation and planned unit 

28 outages. In turn, the service water cooling system is cooled by the service water cooling tower. 

29 The service water cooling system uses three pumps with a rated capacity of 31,500 gpm 

(70.2 cfs; 2.0 m3 30 /s) each. Water is pumped from the service water cooling system cooling tower 

31 pump pit. This water is then ultimately conveyed into the system’s heat exchanger supply 

32 header). The common heat exchanger outlet/cooling tower supply header is routed to the 

33 service water cooling system cooling tower. Five risers carry heated water to the top of the 

34 cooling tower where it is cooled before being recirculated. Operation of two pumps is normally 

35 sufficient to handle the heat load with the third pump maintained as a spare. Cooling tower 

operation results in water losses of about 0.38 mgd (1,440 m3 36 /day). Chemical additives are 

37 periodically injected into the service water cooling system cooling tower basin to minimize 

38 scaling, corrosion, and biological fouling within the system (Entergy 2015d, 2017h). 

39 3.1.3.5 Standby Service Water System and Ultimate Heat Sink

40 The normal service water system operates during normal plant operation. In emergencies, the 

41 safety-related standby service water system, in conjunction with the ultimate heat sink, functions 

42 to remove heat from critical plant components to assure safe shutdown and cooldown of the 

43 plant and maintenance of the safe shutdown condition. These components include residual 

44 heat removal heat exchangers, standby diesel generators, containment unit coolers, main 
3-8

1 control room air conditioning chillers, auxiliary building unit coolers, control building unit coolers, 

2 and fuel pool coolers.

3 Primary components of the safety-related standby service water system include two redundant 

4 piping systems, four 50-percent capacity standby pumps, and the standby cooling tower and 

5 associated water storage basin that serves as the ultimate heat sink for RBS (shown in 

6 Figure 3-5). The standby cooling tower is of the counter-flow, induced mechanical draft design. 

The basin holds approximately 6.6 million gallons (25,000 m3 7 ) of usable water, which is 

8 sufficient to provide makeup water for 30 days of post-shutdown operation. Biofouling of the 

9 basin is controlled by a hypochlorite feed system; other biocides and corrosion control agents 

10 may be added to the basin as needed. Makeup water for the ultimate heat sink basin is 

11 supplied by the RBS’s deep groundwater wells. These wells are described in Section 3.5.2.2 of 

12 this SEIS (Entergy 2015d, 2017h).

13 3.1.3.6 Other Water Systems

14 Makeup Water Treatment System

15 Certain in-plant uses and systems at RBS require demineralized (pure) makeup water including 

16 the power conversion system, turbine, reactor plant component cooling systems, the reactor 

17 suppression and spent fuel pools, and other miscellaneous uses. Demineralized water is 

18 produced from raw well water in two treatment trains each comprised of a cation exchange unit, 

19 one vacuum deaerator, two demineralizer forwarding pumps (one for standby operation), one 

20 anion exchange unit, and one mixed bed exchange unit. Each train can produce 

21 150 gpm (570 L/min) of pure water, which is sufficient to meet plant needs. 

22 The plant’s two deep wells (i.e., P-1A and P-1B) provide source water for the treatment units. 

Well water is stored in a 100,000-gal (380-m3 23 ) tank. Transfer pumps convey the raw water from 

24 the storage tank to the treatment units. Demineralized water is conveyed to two 350,000-gal 

(1,320-m3 25 ) demineralized water storage tanks, located adjacent to the RBS Unit 1 turbine 

26 building. From there, demineralized water is fed to supply in-plant uses. (Entergy 2015d, 

27 2017h) 

28 Potable Water System

29 Potable water is supplied to the RBS site by the West Feliciana Parish Consolidated Water 

30 District No. 13, which uses groundwater as its source. Onsite, potable water is furnished to 

31 various areas and buildings for use in bathroom facilities, decontamination showers, emergency 

32 showers, and plant yard fire hydrants (Entergy 2017h).

33 Fire Protection Water System

34 Fire protection water is stored in two storage tanks, each with a working capacity of 265,000 gal 

(1,000 m3 35 ). These tanks are filled automatically by the plant’s shallow well (P-05) at a rate of 

36 800 gpm (3,030 L/min) when water level in the tanks falls 2 ft (0.6 m) below the overflow level. 

37 The plant’s two deep wells can also fill the tanks (Section 3.5.2.2). (Entergy 2015d, 2017h) 

38 3.1.4 Radioactive Waste Management Systems 

39 As a result of normal operations, equipment repairs and replacements, and normal maintenance 

40 activities, nuclear power plants routinely generate both radioactive and nonradioactive wastes. 
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1 Nonradioactive wastes include hazardous and nonhazardous wastes. There is also a class of 

2 waste, called mixed waste, which is both radioactive and hazardous. This section describes the 

3 systems that RBS uses to manage (i.e., treat, store, and dispose of) these wastes. This section 

4 also discusses other waste minimization and pollution prevention measures commonly 

5 employed at nuclear power plants.

6 All nuclear plants were licensed with the expectation that they would release radioactive 

7 material to both the air and water during normal operation. However, NRC regulations require 

8 that gaseous and liquid radioactive releases from nuclear power plants must meet radiation 

9 dose-based limits specified in Title 10 of Code of Federal Regulations (10 CFR) Part 20, 

10 “Standards for Protection Against Radiation,” and the as low as is reasonably achievable 

11 (ALARA) criteria in 10 CFR Part 50, Appendix I, “Numerical Guides for Design Objectives and 

12 Limiting Conditions for Operation to Meet the Criterion ‘As Low as is Reasonably Achievable’ for 

13 Radioactive Material in Light-Water-Cooled Nuclear Power Reactor Effluents.” In other words, 

14 the NRC places regulatory limits on the radiation dose that members of the public can receive 

15 from a nuclear power plant’s radioactive effluents. For this reason, all nuclear power plants use 

16 radioactive waste management systems to control and monitor radioactive wastes.

17 RBS uses liquid, gaseous, and solid waste processing systems to collect and process, as 

18 needed, radioactive materials produced as a byproduct of plant operations. The liquid and 

19 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 

20 discharge into the environment. This is done to assure that the dose to members of the public 

21 from radioactive effluents is reduced to levels that are ALARA in accordance with NRC’s 

22 regulations. The radioactive material removed from the effluents is converted into a solid form 

23 for eventual disposal at a licensed radioactive disposal facility.

24 Entergy has a radiological environmental monitoring program (REMP) to assess the radiological 

25 impact, if any, to the public and the environment from radioactive effluents released during 

26 operations at RBS. The REMP is discussed in Section 3.1.4.5 below.

27 RBS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 

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

29 effluents. These methods are used to assure that radioactive material discharges from the plant 

30 meet NRC and U.S. Environmental Protection Agency regulatory dose standards. The ODCM 

31 also contains the requirements for the REMP (Entergy 2005).

32 3.1.4.1 Radioactive Liquid Waste Management

33 Radioactive liquid wastes at RBS are processed through two subsystems: (1) the major one 

34 being the waste and floor drain collector and (2) the minor one being the phase 

35 separator/backwash subsystem. Both subsystems contain pumps and tanks for collection and 

36 storage of liquid radwaste. However, the major subsystem (the waste and floor drain collector 

37 subsystem) also uses filtration and chemical treatment units. The NRC requires any liquids 

38 discharged from RBS to meet the regulatory requirements found in 10 CFR Part 20 and 

39 Appendix I to 10 CFR Part 50. RBS monitors radioactive liquid discharge from both systems to 

40 assure that activity concentrations do not exceed those regulatory limits.

41 Radioactive liquid wastes entering the waste and floor drain collector subsystem include 

42 influents from the reactor coolant; condensate and feedwater systems; decontamination and 

43 chemistry drains; ultrasonic resin cleaners; the radwaste, reactor, auxiliary, fuel, and turbine 

44 building and shop floor drain sumps; and the decant from the phase separator tanks. 
3-10

1 Radioactivity is removed from the influents by both filtration and ion exchange. Treated liquid 

2 radwaste is then transferred to the recovery sample tanks, where, depending on activity, it is 

3 sent for further reprocessing through the treatment system, storage in the condensate storage 

4 tanks, or discharge through the cooling tower blowdown line. (Entergy 2017h) 

5 The phase separator/backwash tank subsystem collects, decants, and sends filter sludges, 

6 slurries, and spent resins to the radioactive solid waste management system. The system has 

7 two phase separator tanks, and normal operations consist of one tank being in service to allow 

8 settling of the waste before being decanted and sent to the waste and floor drain collector 

9 subsystem. The solids that settle to the bottom of the tank are directly transferred to the 

10 radioactive solid waste management system for processing. The backwash tank collects 

11 backwash from various resin filtration mechanisms at the plant. The filter backwash can be 

12 diverted to the phase separator tanks or is allowed to settle in the backwash tank. Liquid 

13 decanted from the backwash tank is sent to the waste and floor drain collector subsystem, and 

14 any solids that settle to the bottom are sent directly to the radioactive solid waste system for 

15 processing. (Entergy 2017h) 

16 The use of these radioactive waste systems and the procedural requirements in the ODCM 

17 assure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 

18 dose standards.

19 Entergy calculates dose estimates for members of the public using radioactive liquid effluent 

20 release data and aquatic transport models. Entergy’s annual radiological effluent release report 

21 contains a detailed presentation of the radioactive liquid effluents released from RBS and the 

22 resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent release data 

23 from 2012 through 2016 (Entergy 2013b, 2014a, 2015b, 2016g, 2017e). A 5-year period 

24 provides a dataset that covers a broad range of activities that occur at a nuclear power plant, 

25 such as refueling outages, routine operation, and maintenance that can affect the generation of 

26 radioactive effluents. The NRC staff compared the data against NRC dose limits and looked for 

27 indications of adverse trends (i.e., increasing dose levels) over the period of 2012 through 2016. 

28 The following summarizes the calculated doses from radioactive liquid effluents released from 

29 RBS during 2016:

30 • The total-body dose to an offsite member of the public from RBS radioactive liquid

effluents was 1.60×10−4 millirem (mrem) (1.60×10 31 −6 millisievert (mSv)), which is well

32 below the 3 mrem (0.03 mSv) dose criterion in Appendix I to 10 CFR Part 50.

33 • The organ dose (gastrointestinal tract) to an offsite member of the public from RBS

radioactive liquid effluents was 6.32×10−4 mrem (6.32×10 34 −6 mSv), which is well below

35 the 10 mrem (0.1 mSv) dose criterion in Appendix I to 10 CFR Part 50.

36 The NRC staff’s review of RBS’s radioactive liquid effluent control program showed that 

37 radiation doses to members of the public were controlled within NRC’s and EPA’s radiation 

38 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and Title 40, 

39 “Protection of Environment,” of the Code of Federal Regulations (40 CFR) Part 190, 

40 “Environmental Radiation Protection Standards for Nuclear Power Operations.” The NRC staff 

41 observed no adverse trends in the dose levels.

42 Routine plant refueling and maintenance activities currently performed will continue during the 

43 license renewal term. Based on Entergy’s past performance in operating a radioactive waste 

44 system that maintains ALARA doses from radioactive liquid effluents, the NRC staff expects 

45 similar performance during the license renewal term.
3-11

1 3.1.4.2 Radioactive Gaseous Waste Management

2 Radioactive wastes generated at RBS are collected and processed through the gaseous waste 

3 management system. The gaseous waste management system has two trains (A and B) which 

4 consist of a preheater and its associated recombiner, an off-gas condenser and water 

5 separator, a cooler condenser and its associated moisture separator, a pre-filter, a desiccant 

6 dryer, adsorber beds, and an after filter. During normal operations, only one train is in service. 

7 Off-gasses containing radiation traveling through the train undergo total volume reduction, are 

8 held up at various points to allow short-lived radionuclides to decay, are sent through a 

9 high-efficiency particulate absorption (HEPA) filter for some radionuclide removal, and passed 

10 through the adsorption beds where radionuclides such as iodine, xenon, krypton, and their 

11 associated daughter products are captured and allowed to decay. Once past the adsorber 

12 beds, the off-gasses are monitored and sampled for any remaining radioactivity, sent through a 

13 set of HEPA post-filters, and finally exhausted to the atmosphere through the plant exhaust. 

14 (Entergy 2017h).

15 The use of this gaseous radioactive waste system and the procedural requirements in the 

16 ODCM assure that the dose from radioactive gaseous effluents complies with NRC and EPA

17 regulatory dose standards.

18 Entergy calculates dose estimates for members of the public based on radioactive gaseous 

19 effluent release data and atmospheric transport models. Entergy’s annual radioactive effluent 

20 release report contains a detailed presentation of the radioactive gaseous effluents released 

21 from RBS and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive 

22 effluent release data from 2012 through 2016 (Entergy 2013b, 2014a, 2015b, 2016g, 2017e). A 

23 5-year period provides a dataset that covers a broad range of activities that occur at a nuclear

24 power plant such as refueling outages, non-refueling outage years, routine operation, and 

25 maintenance activities that can affect the generation of radioactive effluents. The NRC staff 

26 compared the data against NRC dose limits and looked for indications of adverse trends 

27 (i.e., increasing dose levels) over the period of 2012 through 2016. The following summarizes 

28 the calculated doses from radioactive gaseous effluents released from RBS during 2016:

29 • The air dose at the site boundary from gamma radiation in gaseous effluents from

RBS was 2.66×10-1 millirad (mrad) (2.66×10 30 -3 milligray (mGy), which is well below

31 the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

32 • The air dose at the site boundary from beta radiation in gaseous effluents from RBS

was 2.17×10-1 mrad (2.17×10 33 -3 mGy), which is well below the 20 mrad (0.2 mGy)

34 dose criterion in Appendix I to 10 CFR Part 50.

35 • The dose to an organ (child bone) from radioactive iodine, radioactive particulates,

and carbon 14 from RBS was 4.70 mrem (4.70×10 36 -2 mSv), which is below the 15

37 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.

38 The NRC staff’s review of RBS’s radioactive gaseous effluent control program showed radiation 

39 doses to members of the public that were well below the NRC’s and EPA’s radiation protection 

40 standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190.

41 NRC staff observed no adverse trends in the dose levels.

42 Routine plant refueling and maintenance activities currently performed will continue during the 

43 license renewal term. Based on Entergy’s past performance operating the radioactive waste 
3-12

1 system to maintain ALARA doses from radioactive gaseous effluents, the NRC staff expects 

2 similar performance during the license renewal term.

3 3.1.4.3 Radioactive Solid Waste Management

4 Low-level solid radioactive wastes (LLRW) are processed, packaged, and stored for subsequent 

5 shipment and offsite burial by the solid radwaste system, which is composed of a waste sludge 

6 tank, a waste sludge pump, a waste compactor, and an overhead crane. Solid radioactive 

7 wastes and potentially radioactive wastes include spent resin beads, resin fines, filter sludges, 

8 and other processing media from the liquid radwaste system. 

9 The waste sludge tank is used to hold and transfer solids from the liquid radwaste system for 

10 dewatering, processing, and compaction. The overhead crane is used to move waste 

11 containers from the fill area to the storage area. The compactor is used to reduce the volume of 

12 any compressible dry radioactive wastes. Non-compressible wastes are manually packaged 

13 into appropriate containers. Radioactive solid wastes are stored onsite in the radwaste building, 

14 the low-level radwaste storage facility, or in approved temporary storage facilities. 

15 (Entergy 2017h) 

16 RBS sends LLRW to four licensed processing and disposal sites: (1) EnergySolutions in Clive, 

17 UT, (2) EnergySolutions Bear Creek facility in Oak Ridge, TN, (3) Erwin ResinSolutions in 

18 Erwin, TN, and (4) Waste Control Specialists in Andrews, TX.

19 In 2016, a total of eight LLRW shipments were made from RBS to the above-listed processing 

20 and disposal sites. The total volume and radioactivity of LLRW shipped offsite in 2016 was 

7.84×102 cubic meters (m3

) (2.77×104 cubic feet (ft3)) and 7.12×103 21 curies (Ci) 

(2.63×10 22 8 megabecquerels (MBq)), respectively (Entergy 2017e). Routine plant operation, 

23 refueling outages, and maintenance activities that generate radioactive solid waste will continue 

24 during the license renewal term. The NRC also expects Entergy to continue to generate 

25 radioactive solid waste and ship it offsite for disposal during the license renewal term.

26 3.1.4.4 Radioactive Waste Storage

27 At RBS, low-level radioactive waste is stored temporarily onsite before being shipped offsite for 

28 treatment or disposal at licensed LLRW treatment and disposal facilities. In its environmental 

29 report for its RBS license renewal application, Entergy stated that it also has sufficient existing 

30 capability to store LLRW onsite. Further, Entergy also stated that its long-term needs for 

31 generated LLRW storage (including during the license renewal term) do not require constructing 

32 additional onsite storage facilities. (Entergy 2017h) 

33 RBS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 

34 storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 

35 approved dry cask storage containers onsite. Entergy plans to expand the existing capacity of 

36 the ISFSI by adding an additional concrete pad for dry cask storage. Construction of the new 

37 ISFSI pad is scheduled for 2020 (Entergy 2017c). The installation and monitoring of this facility 

38 is governed by NRC requirements in 10 CFR Part 72, “Licensing Requirements for the 

39 Independent Storage of Spent Nuclear Fuel, High-Level Radioactive Waste, and 

40 Reactor-Related Greater Than Class C Waste.” The River Bend ISFSI will remain in place until 

41 the U.S. Department of Energy (DOE) takes possession of the spent fuel and removes it from 

42 the site for permanent disposal or processing. (Entergy 2017h) 
3-13

1 3.1.4.5 Radiological Environmental Monitoring Program

2 Entergy conducts a REMP to assess the radiological impact, if any, to the public and the 

3 environment from the operations at RBS.

4 The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 

5 radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 

6 groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 

7 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 

8 material, including radon). 

9 In addition to the REMP, RBS has an onsite groundwater protection program designed to 

10 monitor the onsite plant environment for detection of leaks from plant systems and pipes 

11 containing radioactive liquid (Entergy 2016h). Information on the groundwater protection 

12 program is contained in Section 3.5.2 of this SEIS. 

13 The NRC staff reviewed 5 years of annual radiological environmental monitoring data from 2012 

14 through 2016 (Entergy 2013c, 2014b, 2015c, 2016h, 2017f). A 5-year period provides a dataset 

15 that covers a broad range of activities that occur at a nuclear power plant, such as refueling 

16 outages, routine operation, and maintenance that can affect the generation and release of 

17 radioactive effluents into the environment. The NRC staff looked for indications of adverse 

18 trends (i.e., increasing radioactivity levels) over the period of 2012 through 2016. 

19 As discussed in Section 3.5.2, spills of water containing tritium have been detected in the 

20 groundwater on the RBS site in recent years. Entergy monitors the tritium in the groundwater 

21 and continues to define the extent and potential sources of the tritium contamination. Entergy 

22 believes that all detectable tritium contamination is the result of liquid spills within the turbine 

23 building and it has resealed the turbine building floor joints to stop any future leaks. The 

24 direction of groundwater flow will cause tritium in the groundwater to leave the site where the 

25 site boundary meets the Mississippi River. RBS obtains its potable drinking water from the 

26 West Feliciana Parish Consolidated Water District No. 13 Water Supply System, and there are 

27 no offsite, public wells located along the direction of groundwater flow. Therefore, neither RBS 

28 drinking water nor offsite groundwater should come in contact with the tritium contamination in 

29 the groundwater caused by RBS activities. As the groundwater moves towards the Mississippi 

30 River, natural attenuation processes should readily reduce the concentration of tritium within the 

31 groundwater. In addition, because of the river’s large volume, the Mississippi River will greatly 

32 dilute any tritium that reaches the river. Entergy estimates that it is unlikely tritium from these 

33 releases could be detected in the Mississippi River above minimum detection levels. 

34 The groundwater monitoring program at RBS is robust and any future leaks that might occur 

35 during the period of license renewal should be readily detected. If leaks to the groundwater are 

36 stopped before or during the period of license renewal, either active restoration or monitored 

37 natural attenuation could continue to restore onsite groundwater quality. Also, if tritium in the 

38 groundwater should reach the Mississippi River during the period of license renewal above 

39 detectable levels, the river would rapidly dilute those concentrations below detectable levels.

40 The NRC staff’s review of Entergy’s data showed no indication of an adverse trend in 

41 radioactivity levels in the environment. All spills are well monitored, characterized, and actively 

42 remediated. The data showed that there were no significant impacts to the environment from 

43 operations at RBS.
3-14

1 3.1.5 Nonradioactive Waste Management Systems

2 Like any other industrial facility, nuclear power plants generate wastes that are not 

3 contaminated with either radionuclides or hazardous chemicals.

4 RBS has a nonradioactive waste management program to handle its nonradioactive hazardous 

5 and nonhazardous wastes. The waste is managed in accordance with Entergy’s procedures. 

6 RBS has vendor contracts in place to transfer nonradioactive hazardous and nonhazardous 

7 wastes to licensed offsite treatment and disposal facilities. Listed below is a summary of the 

8 types of waste materials generated and managed at RBS.

9 • RBS is classified as a small quantity hazardous waste generator. The amounts of

10 hazardous wastes generated are only a small percentage of the total wastes

11 generated. These wastes consist of paint wastes; spent, off-specification, and

12 shelf-life expired chemicals; and occasional project-specific wastes. (Entergy 2017h).

13 • RBS’s nonhazardous wastes include plant trash and small quantities of medical

14 wastes generated at an onsite medical clinic. Medical wastes generated at the

15 onsite clinic are considered a special classification of wastes and are regulated

16 under the Louisiana Administrative Code (LAC) Title 51, “Public Health—Sanitary

17 Code,” Part XXVII, “Management of Refuse, Infectious Waste, Medical Waste, and

18 Potentially Infectious Biomedical Waste” (LAC 51:XXVII).

19 • Universal wastes include fluorescent lamps, batteries, and devices containing

20 mercury, electronics, and antifreeze. Universal wastes are managed in accordance

21 with Entergy procedures and LAC, Title 33, “Environmental Quality,” Part V,

22 “Hazardous Waste and Hazardous Materials,” standards. Recycled wastes, such as

23 scrap metals, used oils, and certain battery types are managed according to Entergy

24 procedures and Louisiana regulations in LAC 33 Part VII, “Solid Waste.”

25 Entergy operates an onsite sewage treatment plant. The onsite sewage treatment plant treats 

26 sanitary wastewater from all plant locations. Discharge of sanitary wastewater to the 

27 Mississippi River (Outfall 001) or Grant’s Bayou (Outfall 002) is done under Louisiana Pollutant 

28 Discharge Elimination System Permit LA0042731. Since sanitary wastewater is managed 

29 onsite, RBS is required to have personnel certified to do so under LAC, Title 48, “Public 

30 Health—General,” Part V.7303. (Entergy 2017h) 

31 3.1.6 Utility and Transportation Infrastructure 

32 The utility and transportation infrastructure at nuclear power plants typically interfaces with 

33 public infrastructure systems available in the region. Such infrastructure includes utilities, such 

34 as suppliers of electricity, fuel, and water, as well as roads and railroads that provide access to 

35 the site. The following sections briefly describe the existing utility and transportation 

36 infrastructure at RBS. Site-specific information in this section is derived from the environmental 

37 report (Entergy 2017h) unless otherwise cited.

38 3.1.6.1 Electricity

39 Nuclear power plants generate electricity for other users; however, they also use electricity to 

40 operate. Offsite power sources provide power to engineered safety features and emergency 

41 equipment in the event of a malfunction or interruption of power generation at the plant. 

42 Independent backup power sources provide power in the event that power is interrupted from 

43 both the plant itself and offsite power sources. At RBS, one 230-kilovolt (kV) transmission line 
3-15

1 delivers the electrical output of RBS to the regional electric grid at the Fancy Point Substation, 

2 which is on the RBS site. Two 230-kV transmission lines from the same substation supply 

3 offsite power to RBS for normal operation and safe shutdown of the plant.

4 3.1.6.2 Fuel

5 Low-enriched uranium dioxide (UO2) fuel with enrichment not exceeding 5 percent by weight of 

uranium-235 ( 6 235U) fuels the RBS nuclear unit. RBS burns fuel at an average of rate of 47,000 

7 megawatt-days per metric ton of uranium (MWD/MTU), and refueling occurs on a 2-year cycle. 

8 New (i.e., unirradiated) fuel arrives onsite in shipping containers. Upon arrival, RBS personnel 

9 use the fuel handling crane to move the new fuel to fuel storage racks until installation in the 

10 reactor core (Entergy 2015d). Entergy stores spent fuel in a spent fuel pool and an independent 

11 spent fuel storage installation (ISFSI). The ISFSI is designed to store 2,720 spent fuel 

12 assemblies in 40 casks, and Entergy operates the ISFSI under the conditions of a general 

13 license in accordance with 10 CFR Part 72 regulations.

14 In addition to nuclear fuel, RBS requires diesel fuel to operate emergency diesel generators. 

15 Entergy stores diesel fuel for the emergency diesel generators in three diesel fuel oil storage 

16 tanks, each of which has a 50,000-gal (189,000-L) capacity.

17 3.1.6.3 Water

18 In addition to cooling and auxiliary water (described in detail in Section 3.1.3), nuclear power 

19 plants require potable water for sanitary and everyday uses by personnel (e.g., drinking, 

20 showering, cleaning, laundry, toilets, and eye washes). At RBS, the West Feliciana Parish 

21 Consolidated Water District No. 13 Water Supply System supplies potable water to the site 

22 through municipal water main lines.

23 3.1.6.4 Transportation Systems

24 All nuclear power plants are served by controlled access roads. In addition to roads, many 

25 plants also have railroad connections for moving heavy equipment and other materials. Plants 

26 located on navigable waters, such as the Mississippi River, may have facilities to receive and 

27 ship loads on barges.

28 At RBS, the north-south highway US-61 provides primary access to the site via the North 

29 Access Road. Southwest of the RBS site, Louisiana Route 10 (LA-10) Audubon Bridge crosses 

30 the Mississippi River and links Pointe Coupee Parish with West Feliciana Parish. However, no 

31 roads within the RBS site directly connect to LA-10. Section 3.10.6 describes local 

32 transportation systems in more detail.

33 The Illinois Central Gulf Railroad’s Slaughter to Woodville branch is the closest rail line to the 

34 RBS site. It runs approximately 0.5 mi (0.7 km) southwest of the RBS site boundary line 

35 (Entergy 2015d). During RBS construction, a 1.2-mi (1.9-km) rail line spur was constructed to 

36 connect RBS to the rail line, but the spur has since been abandoned, and Entergy has no plans 

37 to reestablish its use.

38 The Mississippi River, upon which RBS is located, is one of the major inland waterway shipping 

39 routes in the United States. The Port of Greater Baton Rouge is the most important regional 

40 shipping port and lies approximately 32 mi (52 km) downstream of RBS. Entergy maintains a 
3-16

1 barge slip in a man-made recession on the east bank of the river near Mississippi River Mile 

2 (RM) 262.

3 Within 10 mi (16 km) of the RBS site, air traffic relies on six private heliports, three private 

4 airfields, and one general aviation airport (False River Regional Airport). The Baton Rouge 

5 Metropolitan Airport, a full-service commercial airport, lies 19 mi (31 km) southeast of RBS.

6 3.1.6.5 Power Transmission Systems

7 One 230-kV transmission line delivers the electrical output of RBS to the regional electric grid. 

8 This line extends from Transformer Yard 1 to the Fancy Point Substation. Two 230-kV 

9 transmission lines supply offsite power to RBS through the same substation for normal 

10 operation and safe shutdown of the plant. These lines connect to RBS through 

11 Transformer Yard 1 and 2A. For license renewal, the NRC (2013b) evaluates as part of the 

12 proposed action the continued operation of those transmission lines that connect the nuclear 

13 power plant to the substation where electricity is fed into the regional power distribution system 

14 and the transmission lines that supply power to the nuclear plant from the grid. In its 

15 environmental report, Entergy states that the lines described above are the only transmission 

16 lines that fit this description. Accordingly, all of the in-scope portions of the transmission lines lie 

17 within the RBS site boundary. Figure 3-4 illustrates the location of the lines.
3-17

1 Source: Entergy 2017h, Figure 2.2-4 

2 Figure 3-4. River Bend Station In-Scope Transmission Lines

3 3.1.7 Nuclear Power Plant Operations and Maintenance 

4 Maintenance activities conducted at RBS include inspection, testing, and surveillance to 

5 maintain the current licensing basis of the facility and to ensure compliance with environmental 

6 and safety requirements. Various programs and activities are currently in place at RBS to 

7 maintain, inspect, and monitor the performance of facility structures, components, and systems. 

8 These activities include in-service inspections of safety-related structures, systems, and 
3-18

1 components, quality assurance and fire protection programs, and radioactive and 

2 nonradioactive water chemistry monitoring. 

3 Additional programs include those implemented to meet technical specification surveillance 

4 requirements and those implemented in response to NRC generic communications. Such 

5 additional programs include various periodic maintenance, testing, and inspection procedures 

6 necessary to manage the effects of aging on structures and components. Certain program 

7 activities are performed during the operation of the units, whereas others are performed during 

8 scheduled refueling outages. Reactor refueling occurs on a 2-year cycle (Entergy 2017h).

9 3.2 Land Use and Visual Resources 

10 RBS lies within a 3,342 ac (1,353 ha) Entergy-owned property in southern West Feliciana 

11 Parish, LA. The site borders the east bank of the Mississippi River and lies 3 mi (5 km) 

12 east-southeast of St. Francisville, LA, and 24 mi (39 km) north-northeast of the city of Baton 

13 Rouge, LA. This section describes land use and visual resources in the affected environment. 

14 3.2.1 Land Use

15 Land uses in the affected area are described below in terms of onsite or offsite land uses. 

16 Onsite land uses are described for the RBS site, and offsite land uses are described within a 

17 6-mi (10-km) radius of the RBS site. The Louisiana coastal zone is also briefly described,

18 although as discussed below, the coastal zone is not affected by the proposed RBS license 

19 renewal.

20 3.2.1.1 Onsite Land Use

21 Entergy currently controls the entirety of the RBS site for power generation; however, areas of 

22 the site are also used for other purposes, including an employee sportsman’s club, recreational 

23 fishing, selective timber harvesting, and occasional ecological studies by State agencies or 

24 other parties. Entergy owns the entire site with the exception of a 1.7-ac (0.7-ha) parcel of land 

25 outside the exclusion area boundary and occupied by the Starhill Microwave Radio Tower. 

26 West Feliciana Parish has zoned the RBS site for industrial use and regulates it as an M-2 

27 General Industry District, a designation applicable to energy generating facilities. 

28 (Entergy 2017h)

29 The principal buildings and structures within the main plant area are located within the northern 

30 portion of the site and include the reactor building, auxiliary building, turbine building, radwaste 

31 building, water treatment facility, site administrative building, circulating water cooling towers, 

32 standby service water cooling tower, ultimate heat sink, and generation support building. The 

33 site also houses an ISFSI adjacent to and immediately south of the previously listed buildings. 

34 A meteorological tower lies to the west, and 230-kV and 500-kV switchyards lie to the south. 

35 The cooling water intake and discharge structures are located in the southeast corner of the 

36 property along the eastern shore of the Mississippi River. Figure 3-5 depicts the layout of the 

37 RBS plant area.

38 Developed land of various use intensities occupies 12.7 percent of the RBS site. Undeveloped 

39 lands on the RBS site fall primarily into four land use/land cover categories: deciduous forest 

40 (24.2 percent of total site area), woody wetlands (22.5 percent), mixed forest (18.6 percent), and 

41 shrub/scrub (13.1 percent) (Entergy 2017h). Table 3-1 lists site land uses and associated 
3-19

1 acreage, and Figure 3-6 depicts the site land use land cover. Sections 3.1 and 3.6 describe the 

2 developed and natural areas of the site in more detail, respectively.

3 Source: Entergy 2017h, Figure 3.0-1 

4 Figure 3-5. River Bend Station Plant Layout
3-20

1 Source: Entergy 2017h, Figure 3.1-1 

2 Figure 3-6. River Bend Station Site Land Use/Land Cover
3-21

1 Table 3-1. River Bend Station Site Land Use/Land Cover by Area

Land Use/Land Cover Area (in acres)(a) Percent

Deciduous forest 796.6 24.2

Woody wetlands 738.6 22.5

Mixed forest 611.6 18.6

Shrub/scrub 430.6 13.1

Developed Land 417.2 12.7

Developed, Open Space 184.1 5.6

Developed, Low Intensity 81.8 2.5

Developed, Medium Intensity 97.2 3.0

Developed, High Intensity 54.0 1.6

Evergreen forest 150.6 4.6

Grassland / herbaceous 43.1 1.3

Pasture / hay 41.4 1.3

Emergent herbaceous wetlands 27.6 0.8

Open water 25.1 0.8

Barren land (rock / sand / clay) 3.8 0.1

Total 3,286.2(b) 100

(a) To convert acres to hectares, divide by 2.4711.

(b) The acreages presented in this table are based on the Multi-Resolution Land

Characteristic Consortium land use/land cover data. Because these data are

presented in pixel format, acreages do not exactly match the RBS site

boundary, and thus, the total acreage presented in this table is slightly different

than the property acreage presented elsewhere in this SEIS.

Source: Entergy 2017h

2 3.2.1.2 Coastal Zone

3 In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.; 

4 CZMA) to encourage and assist States and territories in developing management programs that 

5 preserve, protect, develop, and, where possible, restore the resources of the coastal zone 

6 (i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 

7 may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 

8 Great Lakes waters). Section 307(c)(3)(A) of the Coastal Zone Management Act requires that 

9 applicants for Federal permits whose proposed activities could affect coastal zones certify to the 

10 licensing agency (here, the NRC) that the proposed activity would be consistent with the State’s 

11 coastal management program. The regulations that implement the Coastal Zone Management 

12 Act indicate that this requirement is applicable to renewal of Federal licenses for actions not 

13 previously reviewed by the State (15 CFR 930.51(b)(1)). However, West Feliciana Parish, in 

14 which RBS is located, is not within Louisiana’s designated coastal zone (LDNR 2012); therefore, 

15 a consistency determination is not required for RBS license renewal.
3-22

1 3.2.1.3 Offsite Land Use

2 The area surrounding the RBS site is predominantly rural. Within a 6-mi (10-km) radius of the 

3 site, most land lies within West Feliciana Parish; however, this radius also includes small 

4 portions of East Baton Rouge, East Feliciana, and Pointe Coupee Parishes. The predominant 

5 land use/land cover categories within the radius are wetlands (19.6 percent of land area), 

6 deciduous forest (16.5 percent), pasture/hay (12.1 percent), and shrub/scrub (11.9 percent) 

7 (Entergy 2017h). Developed land of various use intensities accounts for 6.5 percent of land 

8 use/land cover (Entergy 2017h). Table 3-2 characterizes the land uses within a 

9 10-km (6-mi) radius of RBS.

10 Table 3-2. Land Use/Land Cover within a 6-mi (10-km) Radius of River Bend Station

Land Use/Land Cover

Area

(in acres)(a) Percent

Woody wetlands 14,142.3 19.6

Deciduous forest 11,902.6 16.5

Pasture/hay 8,727.7 12.1

Shrub/scrub 8,634.7 11.9

Mixed forest 7,854.8 10.9

Cultivated crops 4,827.3 6.7

Open water 4,786.4 6.6

Developed 4,729.0 6.5

Open space 2,938.5 4.0

Low intensity 989.2 1.4

Medium intensity 422.1 0.6

High intensity 379.2 0.5

Evergreen forest 3,585.5 5.0

Grassland/herbaceous 1,633.3 2.3

Barren land (rock/sand/clay) 928.7 1.3

Emergent herbaceous wetlands 534.4 0.7

Total 72,286.5 100.0

(a) To convert acres to hectares, divide by 2.4711.

Source: Entergy 2017h

11 West Feliciana Parish, in which RBS is located, includes 273,000 ac (110,000 ha) of land. The 

12 Mississippi River forms the parish’s western boundary. According to the West Feliciana Parish 

13 Comprehensive Plan (WFPZC 2008), approximately 9 percent of parish land is developed, 

14 15 percent is in agricultural use, and almost a third is forested. The remaining acreage is 

15 comprised of parks, wetlands, water, brush, and grasslands (WFPZC 2008). The parish’s 

16 agricultural lands are comprised of 93 farms, whose primary agricultural products include corn, 

17 wheat, soybeans, forage, and beef and milk cows (USDA 2012). West Feliciana Parish is one 

18 of the fastest growing parishes in Louisiana (WFPZC 2008). The parish’s Comprehensive Plan 

19 includes policies and actions aimed at developing mixed use sustainable housing and 
3-23

1 commercial areas, emphasizing tourism and ecotourism, attracting new economic development 

2 to the parish in targeted areas, and developing conservation practices to preserve the parish’s 

3 natural resources (WFPZC 2008).

4 A number of parks, historic sites, preserves, and refuges are located near RBS. Approximately 

5 6 mi (10 km) west of the RBS site, Cat Island National Wildlife Refuge consists of 

6 10,473 ac (4,238 ha) of cypress-tupelo swamp and bottomland hardwood forests (FWS 2014a). 

7 Both hunting and fishing are permitted within the refuge, although the refuge is currently closed 

8 to the public due to major flooding in the Baton Rouge area in August 2016 that washed out 

9 several of the refuge’s access roads (FWS 2014a). The refuge is one of the few remaining un10 leveed sections of floodplain along the Lower Mississippi River and, therefore, is subject to 

11 regular inundation by the river. The Mary Ann Brown Preserve lies 6 mi (10 km) northeast of 

12 the RBS site. The preserve contains 100 ac (45 ha) of high-quality, mixed pine and hardwood 

13 forest on the fringes of the Tunica Hills Wildlife Management Area (Nature Conservancy 2017). 

14 Nine parks and State-managed historic sites lie within 6 mi (10 km) of the site: St. Francisville 

15 Recreational Park, Parker Memorial Park, Garden Symposium Park, West Feliciana Sports and 

16 Recreational Park, West Feliciana Parish Railroad Park, Audubon State Historic Site, 

17 Rosedown Plantation State Historic Site, Port Hudson State Historic Site, and Locust Grove 

18 State Historic Site. Figure 3-7 depicts these and other Federal, State, and local lands within a 

19 6-mi (10-km) radius of the RBS site.

20 3.2.2 Visual Resources

21 As described in the previous section, the RBS site is located on the east bank of the Mississippi 

22 River within a rural area of southern Louisiana 24 mi (39 km) north-northeast of the city of Baton 

23 Rouge. The RBS site is heavily wooded and contains several unnamed, intermittent streams 

24 that cross and drain to either Grants Bayou to the east or Alligator Bayou to the west. Several 

25 wooded natural areas lie within a 6-mi (10-km) radius of the site as previously described in 

26 Section 3.2.1.3. Natural features near the site include Thompson Creek to the east and 

27 southeast; the Mississippi River and Bayou Sara to the west and northwest; False River to the 

28 southwest; Wickliffe Creek, Alexander Creek, and Alligator Bayou in the western portion of the 

29 RBS site; Grants Bayou East Fork in the southern part of the RBS property; and oxbow lake 

30 remnants to the south. (Entergy 2017h) 

31 RBS lies approximately 2 mi (3.2 km) from the bank of the Mississippi River at an elevation of 

32 approximately 100 ft (30 km) above mean sea level. The station’s four mechanical-draft cooling 

33 towers rise 56 ft (17 m) above grade elevation but are not visible above the trees to an offsite 

34 viewer. From U.S. Route 61 (US-61), neither the power block nor cooling towers are visible due 

35 to the forested areas, which act as a visual buffer to separate the RBS site from nearby roads. 

36 From the highway entrance, only the RBS Training Center Building, which looks like a typical 

37 office building, is visible. The in-scope transmission lines are contained within the RBS site 

38 boundary and are also not visible to an offsite viewer.
3-24

1 Source: Entergy 2017h, Figure 3.0-5 

2 Figure 3-7. Federal, State, and Local Lands Within a 6-Mi (10-Km) Radius of River Bend 

3 Station

4 3.3 Meteorology, Air Quality, and Noise

5 This section describes the meteorology, air quality, and noise environment in the vicinity of 

6 RBS. 
3-25

1 3.3.1 Meteorology and Climatology

2 The state of Louisiana is characterized by a humid subtropical climate, with long, hot summers 

3 and short, mild winters. The climate of Louisiana is primarily influenced by the Gulf of Mexico. 

4 The warm water temperatures of the Gulf provide warm, moist air particularly to the southern 

5 and coastal regions. In general, temperature and precipitation are more stable in southern 

6 Louisiana as a result of the moderating effect of the Gulf of Mexico. The northern regions of 

7 Louisiana experience more variable changes in temperature and precipitation because of 

8 stronger continental influences. During summer months, rainfall decreases with distance from 

9 the Gulf Coast and during the winter months, this pattern is reversed. RBS is located 

10 approximately 75 miles (120 km) from the Gulf coast. The general climate in this area is humid 

11 subtropical, but is subject to polar influences during the winter (NCDC 2016). Air from the Gulf 

12 of Mexico moderates summer heat, shortens winter cold spells, and provides moisture and 

13 heavy rainfall during all seasons. Thunderstorms are common during the summer months and 

14 hailstorms, tornadoes, and wind storms are common during the spring months. Louisiana is 

15 vulnerable to tropical cyclones (tropical storms and hurricanes) that develop in the Gulf of 

16 Mexico. Tropical cyclones make landfall once every 3 years along southeastern Louisiana, and 

17 the Louisiana coast is vulnerable to severe flooding from these storms 

18 (NOAA 2013b; Frankson et al. 2017).

19 The staff obtained climatological data from the Baton Rouge Ryan Field Airport (KBTR) weather 

20 station. This station is approximately 19 mi (30 km) from RBS and is used to characterize the 

21 region’s climate because of its nearby location and long period of record. Entergy maintains a 

22 meteorological monitoring system composed of a meteorological tower with wind speed, wind 

23 direction, and ambient temperature sensors. Entergy provided meteorological observations 

24 from the RBS site in response to the NRC staff’s request for additional information 

25 (Entergy 2017c). The staff evaluated these data in context with the climatological record from 

26 the Ryan Airport National Weather Service station. 

27 The mean annual wind speed during a 33-year period of record at the KBTR station is 6.3 mph 

28 (10.1 km/h) and the prevailing wind is from the northeast (NCDC 2012, 2013, 2014, 2015 2016). 

29 The mean annual wind speed from RBS’s onsite meteorological tower from 2012–2016 for the 

30 30-foot elevation and 150-foot level sensors are 3.4 mph (5.5 km/h) and 6.9 mph (11.1 km/h),

31 respectively. Annual prevailing wind direction from RBS’s onsite meteorological tower from 

32 2012–2016 for the 30-foot elevation and 150-foot level sensors are from the southeast and 

33 east-southeast, respectively (Entergy 2017c). Entergy has noted the differences in wind 

34 direction between the RBS’s onsite meteorological tower and Ryan Field airport and is in the 

35 process of assessing if trees in the vicinity of RBS’s onsite meteorological tower could 

36 potentially be blocking winds from reaching the tower (Entergy 2017c). 

37 The mean annual temperature for a 30-year period of record (1987–2016) at the KBTR station 

38 is 70.2 °F (21.2 °C) with a mean monthly temperature ranging from a low of 51.9 °C (11.1 °C) in 

39 January to a high of 82.8 °F (28.2 °C) in July (NCDC 2016). The mean annual temperature 

40 from RBS’s onsite meteorological tower for the 2002–2016 timeframe is 66.1 °F (18.9 °C) with a 

41 mean monthly temperature ranging from a low of 48.5 °F in January to a high of 

42 81.3 °F (27.4 °C) in August (Entergy 2017c).

43 Mean total annual precipitation for a 30-year period of record (1987–2016) at the KBTR station 

44 is 61.2 in (115.4 cm) and mean monthly precipitation range is 4.1–6.7 in (10.4–17.0 cm). Mean 

45 total annual precipitation from RBS’s onsite meteorological tower for the 2002–2016 timeframe 
3-26

1 is 64.6 in (164.0 cm) and mean monthly precipitation range is 3.9–6.6 in (9.8–16.8 cm) 

2 (Entergy 2017c). 

3 In the past 65 years (1950–2016), the following number of severe weather events have been 

4 reported in West Feliciana Parish (NCDC 2017):

5 • Hurricane: four events

6 • Tornado: five events

7 • Flood: three events

8 3.3.2 Air Quality

9 Under the Clean Air Act (CAA) of 1963, as amended, 42 U.S.C 7401, et seq., the EPA has set 

10 primary and secondary National Ambient Air Quality Standards (NAAQS, 40 CFR Part 50, 

11 “National Primary and Secondary Ambient Air Quality Standards”) for six common criteria 

12 pollutants to protect sensitive populations and the environment. The National Ambient Air 

13 Quality Standards criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen dioxide 

14 (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). PM is further categorized 

15 by size—PM10 (diameter between 2.5 and 10 micrometers) and PM2.5 (diameter of 2.5 

16 micrometers or less). Table 3-3 presents the National Ambient Air Quality Standards for the six 

17 criteria pollutants.

18 Table 3-3. Ambient Air Quality Standards

Pollutant Averaging Time National Standard Concentration

Carbon Monoxide (CO) 8-hr 9 ppm (primary standard)

1-hr 35 ppm (primary standard)

Lead (Pb) Rolling 3-month average 0.15 μg/m3 

Nitrogen Dioxide (NO2) 1-hr 100 ppb (primary standard)

Annual 53 ppb (primary and secondary 

standard)

Ozone (O3) 8-hr 0.075 ppm (primary and secondary 

standard)

Particulate matter less than 2.5 

μm (PM2.5) 

Annual 12 μg/m3 (secondary)

15 μg/m3 (secondary)

24-hr 35 μg/m3 (primary and secondary 

standard)

Particulate matter less than 10 

μm (PM10)

24-hr 150 μg/m3 (primary and secondary 

standard)

Sulfur Dioxide (SO2) 1-hr 75 ppb (primary standard)

3-hr 0.5 ppm (secondary standard)

Key: ppb = parts per billion; ppm = parts per million; μg/m3 = micrograms per cubic meter. To convert ppb to ppm, 

divide by 1000.

Primary standards provide public health protection, including the health of sensitive populations such as asthmatics,

children, and the elderly. Secondary standards provide public welfare protection, including protection against 

decreased visibility and damage to animals, crops, vegetation, and buildings.

Source: EPA 2017d
3-27

1 The EPA designates areas of attainment and nonattainment with respect to meeting National 

2 Ambient Air Quality Standards. Areas for which there is insufficient data to determine 

3 attainment or nonattainment are designated as unclassifiable. Areas that were once in 

4 nonattainment, but are now in attainment, are called maintenance areas; these areas are under 

5 a 10-year monitoring plan to maintain the attainment designation status. States have primary 

6 responsibility for ensuring attainment and maintenance of the National Ambient Air Quality 

7 Standards. Under Section 110 of the Clean Air Act (42 U.S.C. 7410) and related provisions, 

8 States are to submit, for EPA approval, State implementation plans (SIPs) that provide for the 

9 timely attainment and maintenance of the National Ambient Air Quality Standards. 

10 In Louisiana, air quality designations are made at the parish level. For the purpose of planning 

11 and maintaining ambient air quality with respect to the National Ambient Air Quality Standards, 

12 EPA has developed air quality control regions. Air quality control regions are intrastate or 

13 interstate areas that share a common airshed. RBS is located in West Feliciana Parish, which 

14 is part of the Southern Louisiana Texas Interstate Air Quality Control Region (40 CFR 81.53, 

15 “Southern Louisiana-Southeast Texas Interstate Air Quality Control Region”). This air 

16 quality control region consists of 36 parishes in Louisiana and 15 counties in Texas. With 

17 regard to National Ambient Air Quality Standards, EPA designates the West Feliciana Parish as 

18 unclassifiable/attainment for all criteria pollutants (40 CFR 81.319, “Louisiana”). The nearest 

19 designated nonattainment area for ozone (8-hr National Ambient Air Quality Standards) is East 

20 Baton Rouge and West Baton Rouge, approximately 24 mi (39 km) from RBS. 

21 The Louisiana Department of Environmental Quality regulates air emissions at RBS under a 

22 minor source air permit (Air Permit 3160-00009-04) (LDEQ 2009). The Louisiana Department of 

23 Environmental Quality issued this air permit in July 2009, and the permit will expire in 2019 

24 (Entergy 2017h). Table 3-4 lists permitted air pollutant emission sources and air 

25 permit-specified conditions. In accordance with the minor source air permit and 

26 LAC 33:III.501.C.6, Entergy submits semiannual and annual air emissions reports for RBS to 

27 the Louisiana Department of Environmental Quality. Entergy is in compliance with RBS’s minor 

28 air source permit, and RBS has not received any notices of violation pertaining to the air permit 

29 for the 2011–2015 period (Entergy 2017h, 2017c). 

30 Table 3-4. Permitted Air Emission Sources at River Bend Station

Equipment Air Permit Condition

Standby Diesel Generators (2) Opacity <= 20 percent

PM, NOx, CO, SO2,

VOC emission limit High Pressure Core Spray Diesel Engine

Portable Outage/Maintenance Diesel Engines 

Diesel Oil Storage Tanks (3) VOC emission limit

Gasoline Fuel Storage Tank

Mechanical Draft Cooling Towers (4) PM10 emission limit

Service Water Cooling Tower

Standby Cooling Tower

Air Compressor Opacity <= 20 percent

PM, NOx, CO, SO2,

VOC emission limit

Station Blackout Diesel Generator

Emergency Operations Facility Emergency 

Generator
3-28

Equipment Air Permit Condition

Key: PM = particulate matter, NOx = nitrogen oxides, CO = carbon monoxide, SO2 = sulfur dioxide, VOC = volatile 

organic compounds, VOC limit 

Sources: Entergy 2017h and LDEQ 2009

1 Table 3-5 shows annual emissions from permitted sources at RBS. Diesel generators/engines 

2 and the natural gas emergency generator at RBS are operated intermittently during testing or 

3 during outages as these are intended to be used to supply backup emergency power. 

4 According to the 2014 National Emissions Inventory, estimated annual emissions for West 

5 Feliciana Parish are 29; 1,060; 5,063; 2,933; and 19,732 tons for sulfur dioxide, nitrogen 

6 dioxide, carbon monoxide, particulate matter less than 10 microns, and volatile organic 

7 compounds, respectively (EPA 2017a). RBS air emissions from permitted sources make up 

8 2.0 percent or less of West Feliciana Parish’s total annual emissions. Greenhouse gas 

9 emissions from operation of RBS are discussed in Section 4.15.3 and Section 4.16.8 of this 

10 SEIS.

11 Table 3-5. Estimated Air Pollutant Emissions

Emissions (tons/year)

Year SOx NOx CO PM10 VOCs HAPs

2011 0.4 16 4.0 4.0 2.0 0.01

2012 0.1 9.0 2.4 3.1 1.2 0.01

2013 0.3 14.9 3.8 3.4 1.6 0.01

2014 0.2 2.9 2.3 3.3 1.3 0.01

2015 0.6 20.5 5.1 3.8 1.9 0.02

Key: CO = carbon monoxide, NOx = nitrogen oxides, HAPs = hazardous air pollutants, SOx = sulfur dioxides, 

PM10 = particulate matter less than 10 micrometers, VOC = volatile organic compounds

To convert tons per year to metric tons per year, multiply by 0.90718.

Sources: Entergy 2017h, 2016e

12 The EPA promulgated the Regional Haze Rule to improve and protect visibility in national parks 

13 and wilderness areas from haze, which is caused by numerous, diverse air pollutant sources 

14 located across a broad region (40 CFR 51.308–309). Specifically, 40 CFR 81 Subpart D, 

15 “Identification of Mandatory Class I Federal Areas Where Visibility Is an Important Value,” lists 

16 mandatory Federal areas where visibility is an important value. The Regional Haze Rule 

17 requires States to develop State Implementation Plans to reduce visibility impairment at Class I 

18 Federal Areas. The nearest Class 1 Federal Area is Breton Wilderness Area, approximately 

19 180 miles (290 km), southeast of RBS. Federal land management agencies that administer 

20 Federal Class I areas consider an air pollutant source that is located greater than 

21 50 km (289 miles) from a Class I area to have negligible impacts with respect to Class I areas if 

22 the total SO2, NOX, PM10, and sulfuric acid annual emissions from the source are less than 

23 500 tons per year (70 FR 39104, NRR 2010). Given the distance of the Class I area to RBS 

24 and the air emissions as presented in Table 3-5, there is little likelihood that ongoing activities at 

25 RBS adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) 

26 in any of the Class I areas.
3-29

1 3.3.3 Noise

2 Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 

3 in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 

4 to a reference level equal to a normal person’s threshold of hearing. Most people barely notice 

5 a difference of 3 dB or less. Another characteristic of sound is frequency or pitch. Noise may 

6 be composed of many frequencies, but the human ear does not hear very low or very high 

7 frequencies. To represent noise as closely as possible to the noise levels people experience, 

8 sounds are measured using a frequency-weighting scheme known as the A-scale. Sound levels 

9 measured on this A-scale are given in units of A-weighted decibels (dBA). Table 3-6 presents 

10 common noise sources and their respective noise levels. Noise levels can become annoying at 

11 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 10 dBA sounds 

12 twice as loud (EPA 1981).

13 Table 3-6. Common Noise Sources and Noise Levels

Noise Source Noise Level (dBA)

Human hearing threshold 0

Soft whisper 30

Quiet residential area 40

Dishwasher 55–70

Lawn mower 65–95

Blender 80–90

Ambulance siren, jet plane 120

Source: CHC undated

14 Several different terms are commonly used to describe sounds that vary in intensity over time. 

15 The equivalent sound intensity level (Leq) represents the average sound intensity level over a 

16 specified interval, often 1 hour. The day-night sound intensity level (LDN) is a single value 

17 calculated from hourly Leq over a 24-hour period, with the addition of 10 dBA to sound levels 

18 from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 

19 nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded n percent of the 

20 time during a given period. For example, L90, is the sound level exceeded 90 percent of time 

21 and is considered the background level. 
3-30

There are no Federal regulations1 1 for public exposures to noise. The EPA recommends 

2 day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for outdoors in 

3 residential areas (EPA 1974). However, these are not standards. The Federal Housing 

4 Administration (FHA) has established noise assessment guidelines for housing projects and 

5 finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014). 

6 West Feliciana Parish Code of Ordinances declared unnecessary noises a nuisance; however, 

7 the West Feliciana Parish Code of Ordinances does not set maximum permissible sound levels. 

8 As discussed in Section 3.2.1, the vicinity of the RBS site is rural, sparsely populated, and 

9 heavily wooded. The primary noise source in the vicinity of RBS is vehicular traffic along 

10 U.S. Highway 61. Common noise sources from nuclear power plant operations include

11 transformers, loudspeakers, auxiliary equipment, and worker vehicles (NRC 2013b). Major 

12 noise sources at RBS include transformers, turbine, mechanical draft cooling towers, and the 

13 gun range (Entergy 2017h). The nearest residents are approximately 0.85 miles (1.4 mi) away 

14 from the RBS reactor building. 

15 Ambient sound level surveys were conducted prior to construction (June 1972), during 

16 construction (January 1980), and during the first year (July/August 1986 and February 1987) of 

17 operation of RBS (GSUC 1984b, 1987). Residual sounds levels (L90) at 8 nearby 

18 noise-sensitive receptors in the vicinity of RBS prior to construction in 1972 ranged from 49 to 

19 56 (dBA) (GSUC 1984b); significant noise sources identified included insect noise. During 

20 construction of RBS, residual sounds levels (L90) at seven noise-sensitive receptors in the 

21 vicinity of RBS ranged from 34 to 41 dBA; significant noise sources identified included a paper 

22 mill and highway traffic. Insect noise, unlike the 1972 survey, was absent due to the winter 

23 season. 

24 Daytime and nighttime measurements during the first summer and winter of full-power 

25 operations at RBS were taken at six nearby noise sensitive receptors and two control stations 

26 farther away from RBS; four of the six noise sensitive receptor locations were comparable to 

27 locations at which preoperational measurements were taken. Prevalent noise sources observed 

28 included vehicular traffic, cooling tower fans, river towboat engines, aircraft traffic, and 

29 transformers. Control station sound levels were lower than the noise-sensitive receptor 

1 In 1972, Congress passed the Noise Control Act of 1972 establishing a national policy to 

promote an environment free of noise that impacts the health and welfare of the public. 

However, in 1982 there was a shift in Federal noise control policy to transfer the responsibility of 

regulation of noise to State and local governments. The Noise Control Act of 1972 was never 

rescinded by Congress but remains unfunded (EPA 2017h).
3-31

1 measurements and sound levels were higher in the summer than in the winter (due to insects) 

2 and higher at night than during the day in the summer (GSUC 1987):

3 • Day noise levels (L90) at the six noise-sensitive receptor locations ranged from 34 to

4 50 dBA and at the two control stations ranged from 32 to 39 dBA;

5 • Night noise levels (L90) at the six noise-sensitive receptor locations ranged from 39 to

6 51 dBA and at the two control stations ranged from 27 to 43 dBA.

7 A comparison of operational sound level measurements to preoperation and construction 

8 measurements found both increases and decreases in overall noise levels relative to the 

9 preoperational period. The highest overall increase was 11 dBA and the largest decrease was 

10 8 dBA (GSUC 1987). 

11 RBS received a noise complaint pertaining to nighttime training activities at the RBS firing range 

12 during the 2011–2016 timeframe. However, upon further investigation, Entergy determined that 

13 the nighttime firing range activities were not being conducted during the time specified in the 

14 local resident’s complaint. Therefore, Entergy concluded that the complaint was not related to 

15 RBS operation and related activities (Entergy 2017h, 2017g). Other than this dispositioned 

16 complaint, Entergy has not received noise complaints during the 2011–2016 time period 

17 (Entergy 2017h, 2017c).

18 3.4 Geologic Environment

19 This section describes the geologic environment of the RBS site and vicinity, including 

20 landforms, geology, soils, and seismic conditions.

21 3.4.1 Physiography and Geology

22 The RBS site is located east of the Mississippi River on an upland area. It rises to an average 

23 elevation of approximately 125 ft (38 m) mean sea level (MSL). The upland area is cut by dry 

24 swales and intermittent stream channels (see Figure 3-8). Major drainage features include 

25 Alligator Bayou and Grants Bayou. The main plant buildings are located in an area at an 

26 elevation approximately 95 to 100 ft (29 to 30 m) mean sea level (Entergy 2017h).

27 The rest of the site is located on the flood plain of the Mississippi River, where the elevation of 

28 land surface is approximately 30 to 40 ft (9 to 12 m) mean sea level. This area is located along 

29 the western boundary of RBS (Entergy 2008b, 2017h).

30 The RBS site is built on the Mississippi Delta. This delta is made up of an enormous thickness 

31 of sediment. These sediments occur in layers that dip and thicken toward the Gulf of Mexico. 

32 At the site, these sediments are more than 20,000 ft (6,096 m) thick. (Entergy 2008b) 

33 At RBS, the Mississippi River and its flood plain are underlain by alluvial deposits of sand, silt, 

34 and clay deposited by the Mississippi River. Alluvial deposits of sand, silt, and clay also 

35 underlie the stream channels. The rest of the site is underlain by terrace deposits that formed 

36 during the Pleistocene Epoch (2.5 million to 11,700 years ago, often colloquially known as the 

37 Ice Age). The terrace deposits formed on the flood plain of the ancient Mississippi River. They 

38 occupy upland areas of the site (see Figure 3-9) and are composed of layers of clay, silt, sand, 

39 and gravel.
3-32

1 Two main terraces are identified at the RBS site: the Prairie Allogroup and the Citronelle 

2 Formation. They are similar in makeup and differ primarily in age and areal extent. The Prairie 

3 Allogroup is the younger terrace and was deposited on top of the Citronelle Formation. 

4 However, the Prairie Allogroup is not found in the higher elevations of the site. In these areas, 

5 the Citronelle Formation forms the uppermost terrace unit (Entergy 2008b, 2017h).

6 Most of the terrace deposits are covered by a layer of loess (silt deposited by winds during the 

7 Pleistocene Epoch (last ice age)). At the RBS site, the loess layers are less than 10 ft (3 m) 

8 thick and are found on top of the terrace deposits in the upland areas. The loess is absent on 

9 the Mississippi flood plain and over the alluvial deposits of the stream channels, as in these 

10 areas it has been removed by erosion (Entergy 2008b, 2017h).

11 In the power block area, during plant construction, the terrace deposits were excavated to a 

12 depth of 75 ft (22m). The excavations were partially backfilled with clayey sand engineered fill. 

13 The buildings in the power block area were built into and on the engineered fill (Entergy 2008b).

14 3.4.2 Economic Resources

15 RBS site activities do not significantly prevent access to economically important minerals and 

16 geologic resources in West Feliciana Parish. Economically significant deposits of sand, gravel, 

17 and other mineable resources are not known to exist at the site. No mining or quarrying 

18 operations occur within 5 mi (8 km) of the site (Entergy 2008b). Oil and gas production and 

19 exploration has occurred and may continue to occur across West Feliciana Parish 

20 (LDNR 2017b, USGS 2012). However, there are no active oil or gas wells within 5 mi (8 km) of 

21 the RBS site (Entergy 2008b).

22 The Tuscaloosa Marine Shale underlies the southern half of Louisiana. It underlies West 

23 Feliciana Parish at depths greater than 10,000 ft (3,048 m). Oil and gas has been extracted 

24 from sandstone beds in this shale using conventional technology. However, in West Feliciana 

25 Parish, the shale itself is also being explored to determine if oil and gas can be extracted using 

26 fracking and horizontal drilling technology (GBRBR 2013, Pair 2017, USGS 2017g). While 

27 conducting the environmental review for the RBS license renewal, the NRC staff identified no 

28 fracking and horizontal drilling and exploration activities of the Tuscaloosa Marine Shale within 

29 5 mi (8 km) of RBS (GBRBR 2013). 
3-33

1 Source: Modified from Entergy 2017h

2 Figure 3-8. River Bend Site Topography
3-34

1 Source: Modified from Entergy 2008b

2 Figure 3-9. River Bend Alluvial Stream Deposits

3 3.4.3 Soils

4 Most of the soils at the RBS site can be characterized as silty loams or silty clay loams. Soils 

5 near the Mississippi River are frequently flooded. Soils along the shoreline of the Mississippi 
3-35

1 River are fine sandy loams, while those a little farther away from the river contain more clay and 

2 are either silty clay loams, clay loams, or mucky clay (Entergy 2017h, USDA 2017).

3 Within the site boundary, only one soil type can be classified as prime farmland. However, this 

4 soil type only occurs in small isolated patches. No significant construction activities are planned 

5 for the site over the license renewal period. Should soil disturbing activities take place at the 

6 site, Entergy will manage the potential for soil erosion by following the site’s Storm Water 

7 Pollution Prevention Plan (Entergy 2017h, USDA 2017).

8 3.4.4 Land Subsidence

9 Land subsidence or the gradual sinking of land is a significant issue in southern Louisiana. 

10 Over the millennia, land subsidence was countered by the addition of sediments from the 

11 Mississippi River (Reed and Wilson 2004; Van Kooten 2005; Yuill et al 2009). However, since 

12 the mid-to late 20th century, human activities have impacted natural processes to favor land 

13 subsidence. Processes contributing to land subsidence include aquifer and reservoir 

14 compaction from the extraction of groundwater, oil, and gas and reduced sediment deposition 

15 on the land by the Mississippi River (Reed and Wilson 2004, Van Kooten 2005). The RBS site 

16 is located in an area with a relatively low subsidence rate of 0.07 inch/yr (1.7 mm/yr) 

17 (Zou et al. 2015). Future activities at the site are not expected to increase the current rate of 

18 land subsidence.

19 3.4.5 Seismic Setting

20 The RBS site lies within a region of infrequent and minor seismic activity. There are no major 

21 seismic zones within the state of Louisiana (Entergy 2017h). The State of Louisiana is located 

22 within the geologic tectonic province known as the Gulf Coast Basin. This basin contains 

23 shallow growth faults (normal faults) with decreasing dip with depth. These growth faults trend 

24 for considerable distances and roughly parallel the Louisiana coastline. Fault movement along 

25 these growth faults is driven by a process of gradual creep, as opposed to the sudden breaking 

26 of rock that is associated with earthquakes. As a result, Louisiana is not considered to be 

27 seismically active. Historical earthquakes within Louisiana have occurred infrequently, have 

28 been of low magnitude, and have produced little damage (LGS 2001).

29 The New Madrid Seismic Zone is the most likely area where earthquakes might occur that could

30 affect southern Louisiana (LGS 2001). This 150-mile (240 km) long seismic zone covers parts 

31 of Arkansas, Illinois, Kentucky, Missouri, and Tennessee (MODNR 2014). Historically, some 

32 mild ground shaking in southern Louisiana was reported from large earthquakes originating in 

33 this area (LGS 2001).

34 The NRC evaluates the potential effects of seismic activity on a nuclear power plant in an 

35 ongoing process that is separate from the license renewal process. The NRC requires every 

36 nuclear plant to be designed for site-specific ground motions that are appropriate for its location. 

37 Nuclear power plants, including RBS, are designed and built to withstand site-specific ground 

38 motion based on their location and the potential for nearby earthquake activity. The seismic 

39 design basis is established during the initial siting process, using site-specific seismic hazard 

40 assessments. For each nuclear power plant site, applicants estimate a design-basis ground 

41 motion based on potential earthquake sources, seismic wave propagations, and site responses, 

42 and then account for these factors in the plant’s design. In this way, nuclear power plants are 

43 designed to safely withstand the potential effects of large earthquakes. Over time, the NRC’s 

44 understanding of the seismic hazard for a given nuclear power plant may change as methods of 
3-36

1 assessing seismic hazards evolve and the scientific understanding of earthquake hazards 

2 improves (NRC 2014d). As new seismic information becomes available, the NRC expects that 

3 licensees will evaluate the new information to determine if changes are needed to safety 

4 systems at a plant. The NRC also evaluates new seismic information and independently 

5 confirms that licensee’s actions appropriately consider potential changes in seismic hazards at 

6 the site.

7 3.5 Water Resources

8 This section describes surface water and groundwater resources at and around the RBS site.

9 3.5.1 Surface Water Resources 

10 Surface water encompasses all water bodies that occur above the ground surface, including 

11 rivers, streams, lakes, ponds, and man-made reservoirs or impoundments.

12 3.5.1.1 Surface Water Hydrology

13 Local and Regional Hydrology

14 The Entergy property comprising the RBS plant site is located on the east (left descending) 

15 bank of the Lower Mississippi River centered near Mississippi River River Mile (RM) 262 (River 

Kilometer (RKm) 421.6) above Head of Passes2 16 (as shown in Figures 3-1, 3-3 and 3-10). This 

17 segment of the river is known as the St. Francisville reach (Entergy 2017h). Figure 3-3 shows 

18 that there are only two RBS support structures located in close proximity to the riverbank, the 

19 blowdown control structure and makeup water pump house. All other major plant structures, 

20 including the nuclear island, are located within the RBS facility complex that lies approximately 

21 2 mi (3.2 km) from the river (Figure 3-5). 

22 The Lower Mississippi River–Baton Rouge watershed (hydrologic unit 08070100) encompasses 

23 the RBS property; this watershed is part of the Lower Mississippi River Basin (EPA 2017i, 

24 Entergy 2017h). The Lower Mississippi River–Baton Rouge watershed comprises several 

25 smaller drainages that cross the RBS property, including Alligator Bayou and Grants Bayou 

26 (which is a tributary to Alligator Bayou). As shown in Figure 3-5, Alligator Bayou traverses the 

27 river floodplain and is just to the west of the river’s natural levee. In general, Grants Bayou 

2 The Head of Passes marks the location of the mouth of the Mississippi River. Locations along the main 

river channel are specified in units of river miles, starting with Mississippi River RM 0.0 at Head of Passes 

and Mississippi River RM 953.8 (RKm 1,535) at the mouth of the Ohio River. 
3-37

1 drains the greater RBS property on the east and Alligator Bayou drains the RBS property on the 

2 west. 

3 RBS’s plant drainage ditch system collects runoff and other drainage waters from the RBS plant 

4 site. Most of this collected drainage is then discharged through monitored outfalls to two 

5 south-flowing ditches (known as East and West Creek) (see Section 3.5.1.3). In turn, these 

6 ditches drain toward Grants Bayou, which flows to Alligator Bayou in the river floodplain just 

7 south of the RBS facility complex. Alligator Bayou then flows to Thompson Creek which has a 

8 confluence with the Lower Mississippi River at a point about 7 mi (11 km) downstream of the 

9 RBS embayment area (Entergy 2015d, 2017h). 

10 Other than the drainage systems and tributary streams referenced above, there are no ponds or 

11 lakes within the RBS site, but there are about 7.3 ac (3 ha) of freshwater ponds elsewhere on 

12 the RBS property (Entergy 2017h). Otherwise, the only other water bodies on the RBS site 

13 include the 600-ft-long (183-m) circulating water flume (see Section 3.1.3.2) and two sets of 

14 open aeration and sedimentation lagoons located at the sanitary wastewater treatment plant in 

15 the southeastern corner of the RBS facility complex.

16 The Mississippi River is most relevant to RBS operations. It comprises the largest river system 

17 in the United States. The mainstem of the river runs for 2,340 mi (3,766 km) from its 

18 headwaters in northern Minnesota to the Gulf of Mexico, and drains a total area of about 

19 1,250,000 square miles (3,240,000 square kilometers) (Kammerer 1990; Entergy 2017h). The 

20 Lower Mississippi River encompasses the approximately 980-mi (1,600-km) long segment of 

21 the river that flows south from the confluence of the Ohio River in Illinois to Head of Passes in 

22 Louisiana, where the mainstem of the river branches off into the Gulf of Mexico 

23 (Alexander et al. 2012; Entergy 2017h). 

24 Along the St. Francisville reach of the Lower Mississippi River adjoining the RBS property, the 

25 width of the river ranges from approximately 1,700 ft (520 m) at the downstream edge of the 

26 property at Mississippi River RM 260 (RKm 418) (near LA Route 10 and the Audubon Bridge) to 

27 approximately 4,300 ft (1,300 m) at the northwest edge near Mississippi River RM 264 

28 (RKm 425). The maximum depth of the river along the reach is about 100 ft (30 m) based on an 

29 average annual water level elevation of 20.4 ft (6.2 m) MSL (Entergy 2017h). 

30 River flow and water level varies substantially throughout the year. Previous studies indicate 

31 that the flow velocity averages 3.88 fps (1.18 m/s) in the St. Francisville reach (Entergy 2017h). 
3-38

1 Source: Modified from Entergy 2017h

2 Figure 3-10. Hydrologic Features of the Lower Mississippi River Basin Near River Bend 

3 Station
3-39

1 River System Management and Flood Control

2 The Mississippi River System is closely managed and heavily engineered for flood control and 

3 navigation. Federal authority for coordinating the management of the river system lies with the 

4 Mississippi River Commission (MRC). Six districts of the U.S. Army Corps of Engineers 

5 implement the Mississippi River Commission’s plans (Alexander et al. 2012). 

6 Engineered features in the Lower Mississippi River basin include a levee system along the 

7 mainstem of the river and its tributaries in the alluvial plain, floodways to divert excess flow from 

8 the river, and channel improvements such as revetments and dikes to direct channel flow and to 

9 prevent migration of channels (Entergy 2017h; USACE 2017b). In total, the Lower Mississippi 

10 River has over 3,500 mi (5,630 km) of levees to prevent flooding during times of high discharge. 

11 Levee construction has reduced the river’s natural floodplain by approximately 90 percent 

12 (Alexander et al. 2012). Additional engineered features include cutoffs to shorten the river and 

13 to reduce flood heights and various other flood control structures. Specifically, excess river flow 

14 in the St. Francisville reach of the Lower Mississippi River is managed by flow diversions into 

15 the Atchafalaya River through the Old River Control Structure located upstream of the site 

16 (Figure 3-10). The USACE also performs dredging to increase the flow capacity of river 

17 channels to reduce flood potential (Entergy 2015d, 2017h; USACE 2017b). 

18 In relation to the RBS site, man-made levees are nearly continuous on the west bank of the 

19 Lower Mississippi River, and on the east bank the levees alternate with high bluffs from Cairo, 

20 IL to Baton Rouge, LA (see Figure 3-10). A low-water navigation channel measuring 9 ft (2.7 m) 

21 deep and 300 ft (91 m) wide is maintained by dredging and dikes between Cairo and Baton 

22 Rouge (Entergy 2017h). 

23 The location of the RBS plant site on elevated ground northeast of the Lower Mississippi River 

24 lower floodplain reduces the potential for riverine or stream flooding of the plant site. The 

25 USACE has established the Mississippi River Project Design Flood level at the site as 54.5 ft 

26 (16.6 m) mean sea level (MSL). The estimated recurrence interval for this flood is greater than 

27 100 years (i.e., less than 1 percent chance per year) (Entergy 2015d, 2017h). The postulated 

28 probable maximum flood (PMF) elevation of the Lower Mississippi River is 60 ft (18.3 m) MSL 

29 (Entergy 2015d). 

30 The RBS facility is located at a higher elevation than these flood levels. At the RBS facility 

31 complex, grade elevation averages 95 ft (30 m) MSL. RBS safety-related equipment lies at a 

32 minimum elevation of 98ft (29.9m) MSL, or is otherwise located in buildings protected from 

33 floodwaters. 

34 The Federal Emergency Management Agency (FEMA) has delineated the flood hazard areas 

35 along the Lower Mississippi River and near the RBS site. The RBS facility complex and 

36 associated power block is located more than 1 mi (1.6 km) from areas mapped as Zone A 

37 (areas of 100-year flood) associated with the Lower Mississippi River floodplain. FEMA 

38 designates the RBS complex as lying in Zone C, which represents areas of minimal flooding. 

39 East of the river, the only other areas mapped as lying within the 100-year floodplain are 

40 associated with the drainage ways and tributaries to local streams including Grants Bayou just 

41 to the east of the RBS site area (Entergy 2017h; FEMA 1979). Within the RBS facility complex, 

42 a tributary to Grants Bayou on the west side of the plant complex (known as West Creek), has 

43 been reconfigured and channelized to confine it within a 2,850-ft (870-m) long geotextile and 

44 concrete-lined (i.e., FabriformTM) channel. This modification was performed to minimize 
3-40

1 potential flooding during extreme rainfall events, including the probable maximum flood 

2 (Entergy 2015d, 2017h). 

3 As shown in Figure 3-3, there are only two RBS support structures located within the lower 

4 floodplain of the Lower Mississippi River (i.e., the blowdown control structure and makeup water 

5 pump house), neither of which is a safety-related structure. Nevertheless, in order to protect the 

6 pumps and motors from floodwaters, the structure is built to withstand flooding. The entrance to 

7 the pump house lies above the surface of the ground at an elevation of 60.5 ft (18.4 m) 

8 (Entergy 2015d). This is about the same elevation as the probable maximum flood and higher 

9 than the Mississippi River Project Design Flood Level.

10 Flow Characteristics of the Lower Mississippi River

11 In its environmental report, Entergy states that the annual mean flow of the Lower Mississippi 

River near the RBS site is 514,080 cfs (14,520 m3 12 /s) for the period of record 1965–2015. This 

13 estimate is based on data from the Tarbert Landing, MS station (Entergy 2017h). The ER also 

14 reports that the lowest recorded flow for the Lower Mississippi River was 111,000 cfs 

(3,140 m3 15 /s) for the period of record. This station (USGS station no. 07295100) is operated 

16 jointly by the U.S. Geological Survey and the U.S. Army Corps of Engineers and is located near 

17 Mississippi River RM 306.3 (RKm 492.9), approximately 44 RM (71 RKm) upstream of RBS 

18 (USGS 2014a). The available flow data is based on daily, instantaneous discharge and river 

19 stage measurements. 

20 The U.S. Geological Survey also operates a gauging station at Baton Rouge (Gauging Station

21 No. 07374000) at Mississippi River RM 229.6 (RKm 369.5), approximately 32 RM (51 RKm) 

22 downstream of RBS. Flows measured at this gauging station are generally representative of 

23 surface water withdrawals that RBS and other facilities make from the St. Francisville reach of 

24 the Lower Mississippi River. For water years 2005 through 2016, the mean annual discharge at 

Baton Rouge is 547,373 cfs (15,463 m3 25 /s). For water year 2016, the mean discharge was 

654,100 cfs (18,477 m3 26 /s) (USGS 2017i). The lowest daily mean flow is 141,000 cfs 

(3,980 m3

/s), and the 90 percent exceedance flow is 235,500 cfs (6,650 m3 27 /s) for the period of 

28 record (USGS 2016). The 90 percent exceedance flow is an indicator value of hydrologic 

29 drought. It signifies a streamflow that is equaled or exceeded 90 percent of the time as 

30 compared to the average flow for the period of record. 

31 Due to the operation of the Old River Control Structure, river flow-by at the RBS site would not 

be expected to fall below 100,000 cfs (2,800 m3 32 /s) (Entergy 2015d, 2017h). Based on average 

33 monthly flow over the relatively short period of record at the station, October is the low-flow 

34 month and May is the high-flow month (USGS 2016). 

35 3.5.1.2 Surface Water Use

36 As described in Section 3.1.3, RBS withdraws surface water from the Lower Mississippi River 

37 for the plant circulating water system and service water cooling system. Heated cooling water 

38 from the main condenser along with other comingled effluents from auxiliary systems are 

39 discharged back to the river principally through RBS Outfall 001 in accordance with Entergy’s 

40 Louisiana Pollutant Discharge Elimination System permit (LDEQ 2017f) (see Figure 3-3). 

41 RBS’s maximum (hypothetical) surface water withdrawal rate from the Lower Mississippi River 

is 32,000 gpm (71.3 cfs; 2.0 m3

/s). This rate is equivalent to about 46.1 mgd (174,500 m3 42 /day) 

43 and assumes two-pump operation with valves open at 100 percent. However, current (nominal) 
3-41

1 plant operation only requires one pump with the second makeup pump serving as a backup 

(see Section 3.1.3.1). Thus, RBS’s design intake flow is defined as 23 mgd (87,100 m3 2 /day). 

3 Consumptive use due to drift and evaporation from the circulating water system and service 

water cooling system cooling towers is about 17.7 mgd (67,000 m3 4 /day) based on design 

5 maximum (Entergy 2017h). This reflects a design consumptive use rate of approximately 

6 77 percent.

7 Table 3-7 summarizes RBS’s surface water withdrawals for the period 2012–2016. Based on 

8 the NRC staff’s review of Entergy’s reported surface water withdrawals, RBS withdraws an 

average of 17.7 mgd (67,000 m3 9 /day) of water. This is equivalent to an average withdrawal rate 

of approximately 27.4 cfs (0.77 m3 10 /s). Return discharges (mainly consisting of cooling tower 

blowdown) to the river have averaged 3.9 mgd (14,800 m3 11 /day), which is equivalent to an 

average discharge rate of about 6 cfs (0.17 m3 12 /s). The difference between withdraw and 

discharge (i.e., 21.4 cfs (0.6 m3

/s); approximately 13.8 mgd (52,200 m3 13 /day)) generally reflects 

14 consumptive use through cooling tower evaporation, drift, and other losses. In total, these 

15 operational data indicate a consumptive use rate averaging 78 percent. 

16 Table 3-7. Annual River Bend Station Surface Water Withdrawals and Return Discharges 

17 to the Mississippi River

Year Withdrawals (mgd)(a) Discharges (mgd)(a,b) Consumptive Use (mgd)(c)

2012 17.3 3.9 13.4

2013 17.8 4.0 13.8

2014 18.0 4.0 14.0

2015 17.2 3.8 13.4

2016 18.1 3.9 14.2

Average 17.7 3.9 13.8

Note: All reported values are rounded. To convert million gallons per day (mgd) to cubic feet per second (cfs), 

multiply by 1.547. 

(a) Values are the mean of monthly surface water withdrawals and monitored discharges, based on circulating water

flow metering and discharge recorder measurements or estimating methods.

(b) Based on monitored effluent from Outfall 001 including contributions from other previously monitored sources via

internal outfalls.

(c) Calculated as the difference between withdrawal and discharge.

Source: Entergy 2017b

18 RBS surface water withdrawals are not currently subject to any water appropriation, allocation, 

19 or related permitting requirements, and no general permitting system exists for surface water 

20 withdrawals from the Mississippi River (Entergy 2017h). The Louisiana Department of Natural 

21 Resources does coordinate a surface water resources management program that includes the 

22 establishment of cooperative agreements with water users for the withdrawal of surface water 

23 from the State's water bodies (LDNR 2017a). Nevertheless, Entergy’s Louisiana Pollutant 

24 Discharge Elimination System permit (LDEQ 2017f) for RBS does limit the maximum design 

capacity of the cooling water intake to no greater than 46 mgd (174,000 m3 25 /day).
3-42

1 3.5.1.3 Surface Water Quality and Effluents

2 Water Quality Assessment and Regulation

3 In accordance with Section 303(c) of the Federal Water Pollution Control Act (i.e., Clean Water 

4 Act of 1972, as amended (CWA) (33 U.S.C. 1251 et seq.), States have the primary 

5 responsibility for establishing, reviewing, and revising water quality standards for the Nation’s 

6 navigable waters. Such standards include the designated uses of a water body or water body 

7 segment, the water quality criteria necessary to protect those designated uses, and an anti8 degradation policy with respect to ambient water quality. As set forth under Section 101(a) of 

9 the Clean Water Act, water quality standards are intended to restore and maintain the chemical, 

10 physical, and biological integrity of the Nation’s waters and to attain a level of water quality that 

11 provides for the protection and propagation of fish, shellfish, and wildlife and provides for human 

12 recreation in and on the water. The Federal EPA reviews state promulgated water quality 

13 standards to ensure they meet the goals of the Clean Water Act and Federal water quality 

14 standards regulations (40 CFR Part 131, “Water Quality Standards”).

15 The Louisiana Department of Environmental Quality (LDEQ) promulgates surface water quality 

16 standards in Louisiana. Designated use categories include: (1) agriculture, (2) drinking water 

17 supply, (3) fish and wildlife propagation, (4) outstanding natural resource waters, (5) oyster 

18 propagation, (6) primary contact recreation, and (7) secondary contact recreation. All surface 

19 waters of the State are designated and protected for recreational uses and for the preservation 

20 and propagation of desirable species of aquatic biota (i.e., aquatic animal or plant life) and 

21 indigenous species of wildlife. The State also considers the use and value of water for public 

22 water supplies, agriculture, industry, and other purposes, as well as navigation, in setting 

23 standards (LAC 33:IX.1111). 

24 The mainstem of the Lower Mississippi River from the Old River Control Structure to Monte 

25 Sano Bayou near Baton Rouge (Lower Mississippi River segment 070201), that encompasses 

26 the shoreline of Entergy’s property and RBS, is designated for the following uses: primary 

27 contact recreation, secondary contact recreation, fish and wildlife propagation, and drinking 

28 water supply (Entergy 2017h; LAC 33:IX.1111). River waters must normally meet the specified 

29 numeric criteria for chlorides (75 mg/L), sulfate (120 mg/L), dissolved oxygen (5 mg/L), pH 

30 range (6 to 9 units), bacteria (not to exceed a fecal coliform density of 400/100 mL), maximum 

31 temperature (32 °C (90 °F)), and total dissolved solids (400 mg/L) (LAC 33:IX.1111).

32 Section 303(d) of the Federal Clean Water Act requires states to identify all “impaired” waters 

33 for which effluent limitations and pollution control activities are not sufficient to attain water 

34 quality standards in such waters. Similarly, Clean Water Act Section 305(b) requires states to 

35 assess and report on the overall quality of waters in their State. States prepare a Clean Water 

36 Act Section 303(d) list that comprises those water quality limited stream segments that require 

37 the development of total maximum daily loads (TMDLs) to assure future compliance with water 

38 quality standards. The list also identifies the pollutant or stressor causing the impairment, and 

39 establishes a priority for developing a control plan to address the impairment. The total 

40 maximum daily loads specify the maximum amount of a pollutant that a waterbody can receive 

41 and still meet water quality standards. Once established, total maximum daily loads are often 

42 implemented through watershed-based programs administered by the State, primarily through 

43 the National Pollutant Discharge Elimination System (NPDES) permit program, pursuant to 

44 Section 402 of the Clean Water Act, and associated point and nonpoint source water quality 

45 improvement plans and associated best management practices (BMPs). States are required to 

46 update and resubmit their impaired waters list every 2 years. This process ensures that 
3-43

1 impaired waters continue to be monitored and assessed by the State until applicable water 

2 quality standards are met. 

3 The 2016 Louisiana Water Quality Integrated Report includes Louisiana’s Clean Water Act 

4 Section 303(d) list, which the EPA approved on February 10, 2017 (LDEQ 2017g). According to 

5 the State’s revised 2016 report, the 85-RM (137-RKm) long Lower Mississippi River segment 

6 (water body segment LA070301) that adjoins the RBS site property fully supports the 

7 designated uses for secondary contact recreation, fish and wildlife propagation, and drinking 

8 water supply. However, this river segment is impaired for primary contact recreation due to 

9 fecal coliform bacteria. Similarly, Thompson Creek (water body segment 20202), which may 

10 receive stormwater runoff and other effluents from RBS, is also impaired for primary contact 

11 recreation due to fecal coliform bacteria (LDEQ 2017a). 

12 National Pollutant Discharge Eliminating System Permitting Status and Plant Effluents 

13 To operate a nuclear power plant, NRC licensees must comply with the Clean Water Act, 

14 including associated requirements imposed by EPA or the State, as part of the National 

15 Pollutant Discharge Elimination System (NPDES) permitting system under Section 402 of the 

16 Clean Water Act. The Federal National Pollutant Discharge Elimination System permit program 

17 addresses water pollution by regulating point sources (i.e., pipes, ditches) that discharge

18 pollutants to waters of the United States. NRC licensees must also meet state water quality 

19 certification requirements under Section 401 of the Clean Water Act. The EPA or the State, not 

20 the NRC, sets the limits for effluents and operational parameters in plant-specific NPDES 

21 permits. Nuclear power plants require a valid NPDES permit and a current Section 401 Water 

22 Quality Certification. NRC operating licenses are subject to conditions deemed imposed by the 

23 Clean Water Act as a matter of law. The NRC does not duplicate the EPA’s or a delegated 

24 State agency’s water quality reviews.

25 In August 1996, the EPA authorized the State of Louisiana to assume NPDES program 

26 responsibility and general permit authority in Louisiana (EPA 2017e). The LDEQ administers 

27 the NPDES program as the Louisiana Pollutant Discharge Elimination System (LPDES). The 

28 State’s regulations for administering the NPDES program are contained in Louisiana 

29 Administrative Code (LAC), Title 33, IX., Chapter 23 (LAC 33:IX.23). Like NPDES permits, 

30 Louisiana Pollutant Discharge Elimination System (LPDES) permits (called water discharge

31 permits in Louisiana) are generally issued on a 5-year cycle. 

32 RBS is authorized to discharge various wastewater (effluent) streams consisting of cooling 

33 tower blowdown, site stormwater, and miscellaneous process flows under LPDES Permit 

34 No. LA0042731) (LDED 2017a). The LDEQ renewed Entergy’s permit on September 15, 2017, 

35 based on Entergy’s submittal of a renewal application in May 2016 (Entergy 2016d). The permit 

36 is valid until October 30, 2022.

37 RBS’s LPDES permit specifies the monitoring requirements for effluent chemical and thermal 

38 quality and for stormwater discharges. The plant’s LPDES permit authorizes discharge from 

39 15 outfalls including 7 internal outfalls (internal monitoring points) for effluents to primary 

40 Outfall 001 and one internal outfall (No. 104) to stormwater Outfall 004. Table 3-8 summarizes 

41 the contributing industrial processes and associated effluent (wastewater) streams, including 

42 stormwater runoff, discharged through RBS’s outfalls. Where appropriate, Table 3-8 identifies 

43 relevant information or notable changes in RBS’s permitted wastewater and stormwater 

44 discharges or proposed permit modifications observed by the NRC staff based on a review of 

45 Entergy’s 2016 LPDES permit renewal application. 
3-44

1 Table 3-8. Louisiana Pollutant Discharge Elimination System Permitted Outfalls, River 

Bend Station (a) 2 

Outfall

Average Flow

(mgd) Description(a,b)

001(c) 3.88 Continuous discharge of cooling tower blowdown and previously monitored 

effluent from internal outfalls. Discharge to Mississippi River

101(c,d) 0.020 Intermittent discharge of low-level radioactive low-volume wastewater from the 

liquid radwaste wastewater treatment system and maintenance wastewaters; 

during maintenance activities, discharge may occur to Outfall 001 via the 

cooling tower flume rather than the common discharge header.

201(c,d) 0.020 Intermittent discharge of treated sanitary wastewater, low volume wastewaters, 

and maintenance wastewaters. During maintenance activities on the common 

discharge header, previously monitored effluent from Outfall 201 may be 

routed to Outfall 002

301(c) 0(e) Intermittent discharge of mobile metal (chemical and nonchemical) cleaning 

wastewater generated from cleaning of internal components of plant equipment

401(c,d) 0 Intermittent discharge of low-volume wastewater treatment systems; during 

maintenance activities, outfall may discharge via the cooling tower flume rather 

than the common discharge header. During maintenance, reverse osmosis 

reject from the makeup water polishing system may be discharged via 

Outfall 401 rather than Outfall 003 

501(c,d) 0.104 Intermittent discharge of low-volume wastewaters, including but not limited to, 

wastewaters from the mobile standby service water reverse osmosis filtration 

unit, standby cooling tower reject, and other low-volume wastewaters

601(c,d) 0 Intermittent discharge of low-volume wastewater, including but not limited to, 

wastewaters from the filter backwash from service water polishing and 

feed-and-bleed from the service water system and other low-volume 

wastewaters

701(c) NA(f) Intermittent discharge of low-level radioactive water from the groundwater

remediation project. During maintenance, outfall may discharge to Outfall 001 

via the cooling tower flume 

002(c) 0.096 Stormwater runoff from the industrial materials storage area, the low-level 

waste storage building area, the clarifier area, and the sanitary wastewater

treatment plant area; intermittent discharge of air conditioning condensate, 

potable water, clarified river water, well water, and maintenance wastewaters; 

low volume wastewaters including but not limited to bearing cooling water. 

Discharge to Grant’s Bayou via plant drainage system

003(c) 0.127 Stormwater runoff from the reactor building, turbine building, services building, 

clarifiers, cooling tower area, main transformer yard, and auxiliary transformer 

yards; intermittent discharge of maintenance wastewaters including but not 

limited to flushing of piping systems and vessels (including Fire Protection 

Water Supply System and Automatic Sprinkler System); low volume 

wastewaters; air conditioning condensate; de minimis quantities of cooling 

tower drift/mist. Discharge to East Creek and then to Grant’s Bayou 

004(c) 0.467 Stormwater runoff from the office areas, warehouse areas, materials storage 

areas, and equipment/vehicle maintenance areas; intermittent discharge of 

maintenance wastewaters including flushing of piping systems and vessels, air 

conditioning condensate, and potable water. Discharge to West Creek and 

then to Grant’s Bayou 

104 0(e) Intermittent discharge of exterior vehicle washwater to Outfall 004
3-45

Outfall

Average Flow

(mgd) Description(a,b)

005(c) 0.074 Stormwater runoff from the cooling tower yard and intermittent discharge of air 

conditioning condensate, and de minimis quantities of cooling tower drift/mist; 

discharge to Grant’s Bayou via plant drainage system

006 0.085 Intermittent discharge of clarifier underflow; discharge to Mississippi River via 

the clarifier sludge blowdown pipeline

007 0 Intermittent discharge of hydrostatic test wastewater. No discharge has 

occurred since 2011 (Entergy 2016d)

Note: To convert million gallons per day (mgd) to cubic feet per second (cfs), multiply by 1.547. 

(a) Summarized from LPDES Permit No. LA0042731 (LDEQ 2017f), except as noted.

(b) Based on flow for 2014–2015 as cited in Entergy’s LPDES renewal application (Entergy 2016d).

(c) Outfall also permitted to receive hydrostatic test wastewater from a mobile unit (designated as Outfall 007).

(d) NPDES permit internal monitoring point prior to Outfall 001.

(e) There have been no discharges from this outfall since 1999 (Entergy 2016d).

(f) Temporary groundwater remediation skid has been abandoned but Internal Outfall 701 has been retained

(LDEQ 2017f).

Source: Entergy 2016d; LDEQ 2017f. 

1 The location of RBS’s outfalls are shown in Figure 3-11; Figure 3-3 also provides a more

2 detailed view of Outfall 001 at the discharge location to the Lower Mississippi River. 

3 As specified in the LPDES permit for each RBS outfall, Entergy is required to perform effluent 

4 monitoring and report measurement and analytical sampling results to the LDEQ for various 

5 parameters such as flow rate, discharge temperature, available chlorine, total organic carbon 

6 (TOC), chemical oxygen demand (COD), total suspended solids (TSS), fecal coliform, oil and 

7 grease, pH, and various metals. The LDEQ requires that effluent monitoring results for RBS’s 

8 LPDES-permitted outfalls be reported in discharge monitoring reports (DMRs) submitted 

9 through an electronic portal, generally on a monthly basis (Entergy 2017h; LDEQ 2017f). 

10 For the primary plant outfall to the Lower Mississippi River (Outfall 001), Entergy conducts 

11 compliance monitoring at an aboveground vacuum-breaker (air-relief valve) chamber along the 

12 buried blowdown pipeline prior to discharge to the Lower Mississippi River (Figure 3-3). As 

13 observed by the NRC staff, the monitoring location is equipped with continuous flow and 

14 temperature recorders (Entergy 2016d).

15 The RBS LPDES permit allows for the use of water treatment chemicals including those used 

16 for raw water treatment in the clarifiers and in other plant subsystems (Section 3.1.3). These 

17 include flocculants, biocides, corrosion inhibitors, and other compounds that are added to 

18 maintain acceptable water and component quality. The LPDES permit includes a condition 

19 requiring Entergy to notify the LDEQ of any proposed changes to the water treatment chemicals 

20 used at RBS. Additionally, the permit requires Entergy to perform routine whole effluent aquatic 

21 toxicity testing during periods when chlorination is being conducted or when biocide or other 

22 potentially toxic substances may be present in plant effluents. At a minimum, the LPDES permit 

23 requires Entergy to perform annual toxicity testing on the discharge from Outfall 001 

24 (LDEQ 2017f). 
3-46

1 Entergy also maintains a zebra mussel monitoring and control program for monitoring the 

2 occurrence and relative densities of zebra mussels in the Lower Mississippi River, raw water 

3 influent to the RBS clarifier system and effluent, and the clarifier internals. When zebra mussels 

4 are suspected or confirmed, Entergy conducts inspection and sampling, as appropriate, of adult 

5 populations in the Lower Mississippi River near the intake piping. Entergy then performs 

6 cleaning of intake screens and piping as necessary (Entergy 2017h). For control of biofouling 

7 and specifically for the use of chlorine in controlling zebra mussels, RBS’s LPDES permit 

8 imposes an effluent limit on Outfall 001 for total residual (free available) chlorine (LDEQ 2017f). 
3-47

1 Source: Modified from Entergy 2017h

2 Figure 3-11. Louisiana Pollutant Discharge Elimination System Permitted Outfalls, River 

3 Bend Station
3-48

1 As for thermal discharge regulation, Entergy’s LPDES permit imposes a monthly average 

2 temperature limit of 105 °F (40.6 °F) and a daily maximum temperature of 110 °F (43.3 °F) on 

3 the combined effluent from Outfall 001 to the Lower Mississippi River. As previously described 

4 in Section 3.1.3.2, the maximum temperature rise of the circulating water passing through the 

5 RBS main condenser is 27 °F (15 °C) and the maximum temperature of the return water from 

6 the cooling towers is 96 °F (35.6 °C). Discharge temperature is continuously monitored by a 

7 recorder and plant monitoring computer located in the RBS control room. As the monitoring 

8 location for Outfall 001 on the blowdown pipeline is more than 1 mi (1.6 Km) from the discharge 

9 point, the effluent temperature would likely be less before reaching the river. There have been 

10 no exceedances of LPDES thermal limits at RBS over the last 5 years (2012–2016) 

11 (Entergy 2017h). 

12 Outfalls 002, 003, 004, and 005 at RBS predominantly receive stormwater runoff collected by 

13 the plant drainage system (Table 3-8). As specified in the LPDES permit, Entergy collects and 

14 analyzes samples for such parameters as total organic carbon, chemical oxygen demand, total 

15 suspended solids, oil and grease, and pH level. The results are reported on discharge

16 monitoring reports submitted to the LDEQ (Entergy 2017h; LDEQ 2017f). 

17 As also required by the LPDES permit, Entergy is required to develop, maintain, and implement 

18 a Storm Water Pollution Prevention Plan (SWPPP) for RBS that identifies potential sources of 

19 pollution reasonably expected to affect the quality of stormwater, and best management 

20 practices that will be used to prevent or reduce pollutants in stormwater discharges. Entergy’s 

21 Storm Water Pollution Prevention Plan for RBS identifies potential sources of pollution that 

22 could affect stormwater, groundwater, or surface water quality. The plan also includes 

23 procedural practices, controls, and inspections for preventing or reducing pollutants in 

24 stormwater discharges (Entergy 2013a). The LDEQ found during its March 2016 compliance 

25 review relating to Entergy’s LPDES renewal application that Entergy was performing annual 

26 stormwater inspections at RBS as required (LDEQ 2017e).

27 There is no direct discharge of sanitary effluent to surface waters from RBS. Sanitary drains 

28 collect waste from across the RBS facility complex via gravity feed and lifting stations before 

29 being conveyed to the onsite sanitary wastewater treatment plant. The facility has a total 

treatment capacity of 65,000 gallons (250 m3 30 ) per day and is located in the southeastern corner 

31 of the RBS facility complex and south of the clarifiers. 

32 Two parallel treatment trains process the incoming waste via aeration lagoons, sedimentation 

33 ponds, rock filter basins, a gravity sand filter, and an ultraviolet disinfection unit for final 

34 treatment. Train 1 is dedicated to the radiologically active portion of the plant inside the 

35 protected area. Sludge from this system may need to be dried, compressed, and stored as 

36 low-level waste (Entergy 2015d, 2017h). As a safeguard, waste from sinks and drains within 

37 the plant containing waste that is known to be or is potentially contaminated with chemicals or 

38 radioactivity are physically separated from the sanitary drains. Such drains are piped directly to 

39 the liquid radwaste system rather than to the sanitary system (Entergy 2015d). 

40 Train 2 provides treatment of the larger demands of the outlying plant support structures. 

41 Sludge from this system can be disposed of in any permitted municipal landfill. In total, the 

42 facility can accommodate 20 years of sludge accumulation in the sedimentation ponds 

43 (Entergy 2015d, 2017h). To date, Entergy has not needed to perform any sludge removal. As 

44 required by State regulation, Entergy has certified wastewater plant operators (Entergy 2017h).
3-49

1 Treated effluent from the sanitary plant is normally pumped to the clarifier sludge blowdown

2 pipeline (Section 3.1.3.1). This discharge point is regulated and monitored as Internal 

3 Outfall 201 under the RBS LPDES permit (Figure 3-11). 

4 RBS is also subject to the requirements of EPA’s oil pollution prevention regulation 

5 (40 CFR 112, “Oil Pollution Prevention”), and Entergy has developed and implemented a Spill 

6 Prevention, Control, and Countermeasure (SPCC) Plan. The SPCC Plan for RBS 

7 (Entergy 2016f) identifies and describes the procedures, materials, equipment, and facilities that 

8 are utilized at the site to minimize the frequency and severity of oil spills as required by the 

9 regulation.

10 With respect to potential impacts to water resources from ongoing RBS operations, Entergy

11 reports that it has received no Federal or State notices of violation associated with RBS 

12 activities during the period 2012 through October 2017, including any associated with the plant’s 

13 LPDES permit (Entergy 2017h, 2017c). The NRC staff’s review of records maintained by the 

14 LDEQ through its Electronic Document Management System also revealed no notices of 

15 violation over the last 5-year period. However, the NRC staff did find Entergy was the subject of 

16 a LDEQ Administrative Order issued in February 2013 for RBS’s tritium-contaminated 

17 groundwater remediation project (LDEQ 2013). This order established interim effluent 

18 limitations and monitoring requirements (pending issuance of RBS’s renewed LPDES permit) 

19 and authorized the discharge of contaminated groundwater to Internal Outfall 101 after being 

20 sampled for radioactivity in a temporary storage tank. Section 3.5.2.3 details groundwater 

21 quality and ongoing remediation activities at RBS.

22 In addition, the NRC staff reviewed LPDES permit discharge monitoring reports records 

23 submitted to the LDEQ, compliance summaries contained in Entergy’s ER, and compliance 

24 documentation provided by Entergy in response to the NRC’s requests for additional information 

25 (Entergy 2017h, 2017c). While Entergy has had a number of LPDES permit noncompliance or 

26 exceedance events over the last 5 years, the NRC staff found that they have generally been of 

27 minor significance and/or procedural or administrative in nature. One apparent trend is that a 

28 majority of the events are attributable to operations at the sanitary wastewater treatment plant. 

29 Other Surface Water Resources Permits and Approvals

30 Section 401 of the Clean Water Act (33 U.S.C. 1251 et seq.) requires an applicant for a Federal 

31 license to conduct activities that may cause a discharge of regulated pollutants into navigable 

32 waters to provide the licensing agency with water quality certification from the State. This 

33 certification implies that discharges from the project or facility to be licensed will comply with 

34 Clean Water Act requirements and will not cause or contribute to a violation of State water 

35 quality standards. If the applicant has not received Section 401 certification, the NRC cannot 

36 issue a license unless that State has waived the requirement. The NRC recognizes that some 

37 NPDES-delegated states explicitly integrate their Section 401 certification process with NPDES 

38 permit issuance. 

39 On October 25, 1974, the State of Louisiana issued its opinion that operational discharges from 

40 RBS would not violate state water quality standards and certified that the operation complied 

41 with Section 21(b) of the Federal Water Quality Improvement Act of 1970. Gulf States Utilities 

42 Company, the original owner and operator of RBS, also requested Section 401 certification for 

43 RBS from the State. On December 13, 1974, the Louisiana Stream Control Commission 

44 informed Gulf States that the State intended to take no action on Gulf States’ request. The NRC 
3-50

1 deemed this inaction to constitute a waiver of the certification requirements under the provisions 

2 of Section 401 of the Clean Water Act (NRC 1985). 

3 RBS’s current LPDES permit does not explicitly convey water quality certification under 

4 Section 401 of the Clean Water Act for ongoing operations. In support of license renewal, 

5 Entergy requested that the State provide documentation of continued certification and 

6 compliance with respect to Section 401 of the Clean Water Act. LDEQ responded to Entergy’s 

7 request by letter dated September 8, 2017. In summary, LDEQ informed Entergy that: (1) no 

8 new or additional water quality certification is necessary in support of Entergy’s license renewal 

9 application; (2) LDEQ deems that the certification issued by the Louisiana Stream Control 

10 Commission on October 25, 1974, is valid for RBS license renewal; and (3) LDEQ deems the 

11 currently issued LPDES permit for RBS to be a certification obtained pursuant to paragraph (1) 

12 of 33 U.S.C. Section 1341(a) (i.e., the Clean Water Act) with respect to the operation of RBS, 

13 Unit 1 (LDEQ 2017c). The NRC staff concludes that the LDEQ’s letter to Entergy provides the 

14 necessary certification to support operating license renewal.

15 The discharge of dredged or fill material to surface waters or wetlands is regulated under 

16 Section 404 of the Clean Water Act. Entergy performs annual maintenance dredging of a 

17 portion of the Lower Mississippi River to remove accumulated sediments from the vicinity of 

18 RBS’s submerged intake screens. The dredged material is deposited back into the deeper 

19 portions of the river. Entergy and its contractors conduct all dredging activities in accordance 

20 with the provisions of a U.S. Army Corp of Engineers, New Orleans District general permit for 

21 maintenance dredging (Entergy 2017h). This general permit (GP-23) is issued pursuant to 

22 Section 404 of the Clean Water Act and Section 10 permit of the Rivers and Harbors 

23 Appropriation Act of 1899. The Army Corps of Engineers issued a new permit to Entergy in 

24 August 2017. Special conditions attached to the permit include a number of measures to 

25 reduce environmental impacts to waterways, historic properties, and endangered species that 

26 may occur in the project area. The new permit is valid through April 2022 (USACE 2017a). 

27 3.5.2 Groundwater Resources

28 This section describes the current groundwater resources at the RBS site and in the site vicinity.

29 3.5.2.1 Aquifer Descriptions

30 In West Feliciana Parish, freshwater is found in aquifers (water with a chloride concentration of 

31 250 mg/L or less) at depths to about 300 to 600 ft (91-183 m) mean sea level. As the aquifers 

32 dip to the south, near the southern boundary of the parish, fresh water can be found as deep at 

33 2,000 ft (610 m) mean sea level (Figure 3-12). Below these depths, aquifers generally contain 

34 saltwater (i.e., water with a chloride concentration greater than 250 mg/L) (USGS 2014b).

35 The source of groundwater in the aquifers of West Feliciana Parish is primarily from 

36 precipitation with some aquifers obtaining water from overlying aquifers or from rivers. Water is 

37 removed (discharged) from the aquifers by wells, evapotranspiration, and by discharge into 

38 rivers, or into underlying aquifers USGS 2014b). These aquifers primarily consist of beds of 

39 unconsolidated sand, which generally thicken and dip to the south (Figure 3-12). Individual 

40 aquifers generally are at least 75 ft (23 m) thick and can be more than 200 ft (61 m) thick. They 

41 are commonly separated by confining beds primarily made of clay and silt that have low 

42 permeability and do not readily transmit groundwater. Their thickness ranges from 100 ft to 

43 much as 500 ft (152 m) (USGS 2014b).
3-51

1 In West Feliciana Parish, the Mississippi River Alluvial Aquifer occurs within the Mississippi 

2 River flood plain. The land surface forms its upper surface. It is generally flat, with no 

3 discernible dip (USGS 2014b).

4 Source: Modified from USGS 2014b

5 Figure 3-12. West Feliciana Parish Generalized North-to-South Hydrogeologic Cross 

6 Section

7 Outside of the flood plain, beds of sand and gravel within terrace deposits form another surficial 

8 aquifer (USGS 2014b). This aquifer is the Upland Terrace aquifer. Layers of loess 

9 (wind-deposited silt) blanket the top of the aquifer. The loess deposits in West Feliciana Parish 

10 extend 30 to 40 mi (48 to 64 km) east of the Mississippi River (Entergy 2008b). The aquifer dips 

11 and thickens to the south (Figure 3-12) (USGS 2014b). It is approximately 75 ft (23 m) thick in 
3-52

1 West Feliciana Parish and increases to about 400 ft (129 m) at Baton Rouge, LA 

2 (Entergy 2008b).

3 The Upland Terrace Aquifer is underlain by the Evangeline and Jasper equivalent aquifer 

4 systems (Figure 3-12). Aquifers within the Evangeline and Jasper equivalent systems have 

5 been named for the depths at which they are found in the Baton Rouge area. The Evangeline 

6 equivalent aquifer system that underlies West Feliciana Parish consists of from shallowest to 

7 deepest, the “800-foot,” “1,000-foot,” “1,200-foot,” “1,500-foot,” and “1,700-foot” sands of the 

8 Baton Rouge area (USGS 2014b). The Evangeline equivalent aquifer system is underlain by 

9 the Jasper equivalent aquifer system. This system is made up of the “2,000-foot,” “2,400-foot,” 

10 and “2,800-foot” sands of the Baton Rouge area.

11 This naming convention represents the approximate depths these aquifers are found in the 

12 Baton Rouge area. Since the aquifers dip towards the south, north of Baton Rouge these 

13 aquifers occur at shallower and shallower depths. Therefore, beneath RBS, they are found at 

14 shallower depths than their names suggest.

15 The Baton Rouge area represents the approximate downgradient extent of the Upland Terrace 

16 Aquifer and the Evangeline and Jasper equivalent aquifers that contain freshwater. This is 

17 because an east-west trending fault (called the Baton Rouge fault) acts as a barrier to 

18 groundwater flow. Prior to groundwater development in the 1940s, freshwater in the aquifers 

19 flowed southward toward the fault. It then flowed upward and discharged at the land surface in 

20 springs in Baton Rouge. As a result, aquifers located north of the fault contain freshwater, while 

21 the same aquifers located south of the fault contain saltwater (Entergy 2008b, USGS 2013).

22 At RBS, the Mississippi River Alluvial Aquifer is within the Mississippi River flood plain. It is 

23 made up of alluvial deposits of sand, silt, clay and gravel that were deposited by the Mississippi 

24 River. The aquifer is approximately 150 ft (46 m) thick and is found beneath and on both sides 

25 of the river.

26 The Upland Terrace Aquifer occurs adjacent to and east of the Mississippi River Alluvial Aquifer. 

27 It is overlain by loess over most of the site. The Upland Terrace Aquifer is composed of layers 

28 of clay, silt, sand, and gravel. In the area of the RBS power block, the Upland Terrace Aquifer is 

29 about 100 ft (30 m) thick and about 200 ft (61 m) thick where it comes into contact with the 

30 Mississippi River Alluvial Aquifer. While not an aquifer, the structural fill in the power block area 

31 is capable of holding and acting as a pathway for groundwater. It is composed of clayey sand 

32 and is surrounded by and underlain by the Upland Terrace Aquifer (Entergy 2008b, 2017h). 

33 Figure 3-13 contains a west-east cross section across RBS that shows the Mississippi River 

34 Alluvial Aquifer, the Upland Terrace Aquifer, and the structural fill.

35 In the RBS power block area, the Upland Terrace Aquifer is underlain by a thick clay unit that is 

36 more than 200 ft (61 m) thick. Beneath this clay unit are four sand units that taken together total 

37 270 ft (82 m) in thickness. These sands are the “1000-Foot,” “1,200-Foot,” and “1,500-Foot” 

38 sand aquifers of the Evangeline equivalent aquifer (Entergy 2008b) (Figures 3-12 and 3-14). 

39 These sands are hydraulically isolated from the Upland Terrace Aquifer by the thick overlying 

40 clay unit. However, in some areas near the Mississippi River Alluvial Aquifer at RBS, this 

41 overlying clay unit might be thin or absent (Entergy 2008b).

42 At RBS, the “1000-Foot,” “1,200-foot,” and “1,500 foot” sand aquifers are underlain by 

43 approximately 300 ft (92 m) of clay. Two sand aquifers underlie this clay. The total thickness of 

44 the two sands is approximately 90 ft (27 m). One of these sands is the “1,700-foot” sand of the 
3-53

1 Evangeline equivalent aquifer system and the other is the “2,000-foot” sand of the Jasper 

2 equivalent aquifer system (Entergy 2008b) (Figures 3-12 and 3-14). 

3 These two sands are underlain by 270 ft (83 m) of clay, which is underlain by the “2,400-foot” 

4 and “2,800-foot” sands of the Jasper equivalent aquifer. The combined thickness of the two 

5 sands is 210 ft (64 m). At RBS these are the deepest aquifers that contain fresh water, as 

6 deeper aquifers contain salt water (Entergy 2008b) (Figures 3-12 and 3-14).
3-54

1 Source: Modified from Entergy 2008b and 2017h

2 Figure 3-13. West-East Cross Section of Upland Terrace and Mississippi River Aquifers 

3 at River Bend Site
3-55

1 Source: Modified from Entergy 2008b

2 Figure 3-14. Aquifers Beneath the Power Block Area That Contain Freshwater
3-56

1 3.5.2.2 Groundwater Movement

2 Beneath the flood plain of the Mississippi River at RBS, the Mississippi River Alluvial Aquifer 

3 and the Upland Terrace Aquifer are hydrologically connected. In the power block area, the 

4 structural fill is surrounded by and hydrologically connected to the Upland Terrace Aquifer (see 

5 Figure 3-13). Near the Mississippi River, where the overlying clay units are thin or absent; the 

6 “1000-foot,” “1,200-foot,” and “1,500-foot” sand aquifers of the Evangeline equivalent aquifer 

7 may also be hydrologically connected to the Mississippi River Alluvial Aquifer (Entergy 2008b, 

8 2017h).

9 At RBS, the water table is found in both the Mississippi River Alluvial Aquifer and the Upland 

10 Terrace Aquifer. It is also found in the structural fill material that surrounds and underlies 

11 structures in the power block. The groundwater in the Mississippi River Alluvial Aquifer and the 

12 structural fill is found under unconfined conditions. Groundwater in the Upland Terrace Aquifer 

13 is also unconfined except beneath discontinuous clay layers at depth or beneath thick surficial 

14 deposits of silt and clay close to its contact with the Mississippi River Alluvial Aquifer. The 

15 groundwater in all deeper aquifers exists under confined conditions (Entergy 2008b, 2017h).

16 Changes in the water levels of the Mississippi River can cause corresponding changes in 

17 Mississippi River Alluvial Aquifer groundwater levels. Water level changes in the Mississippi 

18 River can also cause changes in water levels in the Upland Terrace Aquifer and the “1000-foot,” 

19 “1,200-foot,” and “1,500-foot” sand aquifers of the Evangeline equivalent aquifer system where 

20 they are hydraulically connected to the Mississippi River Alluvial Aquifer.

21 As the Mississippi River Alluvial Aquifer is found both beneath and on both sides of the 

22 Mississippi River, regional groundwater flow in the Mississippi River Alluvial Aquifer is generally 

23 southward, in line with the flow direction of the river. In addition, when the height of river water 

24 levels cause the head of the Mississippi River to exceed the head in the Mississippi River 

25 Alluvial Aquifer, or in any other aquifers hydrologically connected to the river; water from the 

26 river would flow into those aquifers. Conversely, when the opposite occurs, groundwater would 

27 flow into the river. It is under these conditions, when the head in aquifers that are hydrologically 

28 connected to the river exceed river heads, that groundwater from RBS would leave the site and 

29 enter the river.

30 At RBS, groundwater flow in the Upland Terrace Aquifer is southwestward from the power block 

31 area and towards the Mississippi River where it flows into the Mississippi River Alluvial Aquifer 

32 (Figures 3-15 and 3-16). The Mississippi River is so large that it is very unlikely groundwater in 

33 the Mississippi River Alluvial Aquifer on one side of the river would reach the other side of the 

34 river. In effect, the Mississippi River itself would act as a boundary preventing groundwater 

35 flowing out of the Upland Terrace Aquifer and the Mississippi River Alluvial Aquifer at RBS from 

36 reaching groundwater on the other side of the river.
3-57

1 Source: Modified from Entergy 2017h

2 Figure 3-15. Direction of Groundwater Flow in the Upland Terrace Aquifer at the River 

3 Bend Site
3-58

1 Source: Modified from Entergy 2008b and 2017h

2 Figure 3-16. Cross Section Depicting Groundwater Flow through the Upland Terrace 

3 Aquifer into the Mississippi River Aquifer and then into the Mississippi 

4 River
3-59

1 Beneath RBS, groundwater in the Evangeline and Jasper equivalent aquifers flows south or 

2 southwest towards water wells in the Baton Rouge area. Withdrawal of groundwater from wells 

3 in the Baton Rouge area is large enough that it is lowering water levels in the Evangeline and 

4 Jasper equivalent aquifers over a large area of West and East Feliciana Parish. 

5 (Entergy 2008b, 2017h, USGS 2004, 2014, 2015, 2017k, 2017h).

6 3.5.2.3 Groundwater Use

7 Potable water (i.e., drinking water) is supplied to RBS by the West Feliciana Parish 

8 Consolidated Water District No. 13 Water Supply System (Entergy 2017h). While many of the 

9 neighbors that surround RBS have wells, they also primarily obtain their drinking water from the 

10 same parish water supply system (Entergy 2017h).

11 Other than RBS-owned water wells, there are no water wells within the RBS site boundary.

12 Outside of the site boundary and east of the Mississippi River, 46 wells are located within a 

13 2-mile band around the RBS property boundary. Of these wells, one well is screened into the

14 Mississippi River Alluvial Aquifer, 21 wells are screened into the Upland Terrace Aquifer, and 24 

15 wells are screened into the Evangeline and Jasper equivalent aquifers (Entergy 2017h) 

16 (Figure 3-17).

17 Five onsite wells extract groundwater at RBS (Figure 3-17). Four wells produce water for use 

18 by RBS operations and one well extracts water for the cleanup of groundwater contamination. 

19 Two wells (wells P-1A and P-1B) are screened within the “2,800-foot” sand at a total depth of 

20 approximately 1,800 ft (549 m). These two wells are used to supply water for general site 

21 purposes, including plant makeup water. A third well (Well BP-1) is screened in the “1,200-foot” 

22 sand and is 500 ft (152 m) deep. Groundwater from this well is used for various maintenance 

23 and construction activities and dust suppression. The fourth well (Well P-05) is screened within 

24 the Upland Terrace Aquifer at depths of 84 to 124 ft (26 to 38 m). This well is capable of 

25 pumping 800 gpm (3,028 L/m). Water from this well is used for fire protection. The fifth well is a 

26 monitoring well (MW-125) screened within the Upland Terrace Aquifer. This well is periodically 

27 pumped to remediate tritium-contaminated water. Based on 5 years of data (2011–2015), 

28 annual average water withdrawals from the five wells listed above was 9.9 mgy (37 million L/yr), 

29 equivalent to a rate of 18.8 gpm (71 L/min). Of this volume, the two wells completed in the 

30 “2,800-foot” sand of the Jasper equivalent aquifer system produced 83 percent of the site’s well 

31 water (Entergy 2017h).

32 3.5.2.4 Groundwater Quality at RBS

33 The Mississippi River Alluvial Aquifer, the Upland Terrace Aquifer, and the Evangeline and 

34 Jasper equivalent aquifer systems are all part of the Southern Hills Regional Aquifer System. 

35 The EPA designated this system as a sole source aquifer. It encompasses a large area in the 

36 States of Louisiana and Mississippi (Figure 3-18). A sole source aquifer, as defined by the 

37 EPA, is an aquifer that supplies at least 50 percent of the drinking water for its service area. 

38 Further, it is an aquifer where no reasonably available alternative drinking water sources exist 

39 should the aquifer become contaminated. Under the EPA Sole Source Aquifer program, EPA 

40 can designate an aquifer as a sole source of drinking water and establish a review area for it. 

41 Within the review area, EPA evaluates proposed projects that will receive Federal funding. The 

42 purpose of EPA's evaluation is to ensure that these proposed projects do not contaminate the 

43 sole source aquifer. Proposed projects that are funded entirely by State, local, or private 

44 concerns are not subject to EPA review (Entergy 2008b, 2017h; EPA 2017f, 2017g).
3-60

1 Source: Modified from Entergy 2017h

2 Figure 3-17. Registered Water Wells Within a 2-Mile Band Around River Bend Station 

3 Property Boundary
3-61

1 Source: Modified from Entergy 2017h

2 Figure 3-18. Areal Extent of Southern Hills Regional Aquifer System

3 The water quality in the Mississippi River Alluvial Aquifer is very hard and exceeds the EPA

4 Secondary Maximum Contaminant Levels for drinking water for iron and manganese. Water in 

5 the Upland Terrace Aquifer is generally soft and low in dissolved solids. Water in the 

6 Evangeline equivalent aquifer system is soft and generally does not exceed the EPA Secondary 
3-62

1 Maximum Contaminant Levels for drinking water for pH and chloride, iron, and dissolved solids 

2 concentrations. Water in the Jasper equivalent aquifer system is soft and generally does not 

3 exceed the EPA Secondary Maximum Contaminant Levels for drinking water for color, pH, and 

4 iron, manganese, and dissolved solids concentrations (USGS 2014b).

5 Activities at RBS that involve the use of chemicals are typically associated with painting, 

6 cleaning parts/equipment, refueling onsite vehicles/generators, fuel oil and gasoline storage, 

7 and the storage and use of water-treatment additives. Chemical spills at RBS have been minor 

8 in nature and have been remediated. No chemical spills have required a regulatory agency to 

9 issue a notice of violation (Entergy 2017h).

10 All radionuclides in surface water bodies at RBS are below minimum detectible levels. Other 

11 than tritium, concentrations of all other radionuclides in groundwater beneath RBS are below 

12 minimum detectable levels (Entergy 2017a). Tritium is a hydrogen atom with an atomic mass of 

13 three (NRC 2006) that usually binds with oxygen to form a water molecule. A water molecule 

14 that contains tritium will behave in the environment just like a water molecule that does not 

15 contain tritium (NRC 2006).

16 Tritium emits a weak form of radiation—a low-energy beta particle similar to an electron. This 

17 radiation does not travel very far in air and cannot penetrate the skin. If tritium enters the body, 

18 it disperses quickly and is uniformly distributed throughout the soft tissues. If ingested, the 

19 human body excretes half of tritium ingested within approximately 10 days (NRC 2006). 

20 Additional information is available in NRC 2006 on tritium and radiation protection limits, and 

21 drinking water standards.

22 Nuclear power plants routinely and safely release dilute concentrations of water containing 

23 tritium. These authorized releases are closely monitored by the plant operator, reported to the 

24 NRC, and made available to the public on the NRC’s Web site (NRC 2017k). At RBS, water 

25 containing tritium is diluted to authorized levels and then released to the Mississippi River. The 

26 large volume of water in the river further dilutes the concentration of tritium in the river water to 

27 very low concentrations.

28 In recent years, spills of water containing tritium have made it into the groundwater within the 

29 structural fill that surrounds and underlies structures in the power block. From there it has 

30 moved into the Upland Terrace Aquifer. No tritium above minimum detectable activities has 

31 been found in any surface water bodies or offsite wells. In addition, no tritium above minimum 

32 detectable activities has been found in any deeper aquifers. This is likely to remain the case for 

33 any deeper aquifers beneath the Upland Terrace Aquifer, as the Upland Terrace Aquifer is 

34 underlain by thick clay units that act as barriers to the vertical movement of groundwater 

35 (Figures 3-13 and 3-14) (Entergy 2017h, 2017g).

36 It is important to note that while the structural fill around the power block buildings has been 

37 contaminated with tritium, the structural fill is not an aquifer. The Upland Terrace Aquifer is the 

38 only known aquifer to have been contaminated with tritium.

39 The following is a list of RBS spills and associated actions relating to the release of radioactive 

40 materials to groundwater. The radiological impacts resulting from the release of radionuclides 

41 into groundwater at the RBS site are described in Section 4.5.1.2 of this SEIS. 

42 • In 2008, a break in a blowdown pipe from the cooling towers resulted in the release

43 of water to the ground and the nearby stormwater drainage system. The water
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1 reached the Mississippi River and Grant’s Bayou via the stormwater drainage system 

2 and through Outfall 003. No tritium was detected above minimum detectible activity 

3 in Grant’s Bayou or in groundwater. However, tritium was detected at a 

4 concentration of 28,043 pCi/l in Outfall 003. Any tritium that made it to the 

5 Mississippi River would have been greatly diluted to very low levels (Entergy 2017h).

6 • In 2011 and 2012, a plume of tritium in the power block area was discovered and the

7 extent of contamination was investigated and defined. The plume is located in the

8 structural fill and the underlying Upland Terrace Aquifer. The source of the

9 contamination is currently believed to be from equipment leaks and previous spills

10 within the turbine building seeping through degraded floor joints. These joints were

11 resealed in 2016 (Entergy 2017h).

12 • In 2012, an equipment failure caused water containing low concentrations of tritium

13 (4,260 pCi/L)) to leak into the ground near the wastewater treatment plant

14 (Entergy 2017h).

15 • In 2013, an estimated 380 gallons (1,438 L) of water overflowed from a condensate

16 storage tank sump in the power block area. Tritium concentrations in the overflow

17 were 1,135,000 pCi/L (Entergy 2017h).

18 • In 2014, an equipment failure caused water containing low concentrations of tritium

19 (4,580 pCi/L)) to leak into the ground near a temporary blowdown pipeline gate valve

20 (Entergy 2017h).

21 • In 2014, water containing tritium was determined to be leaking from the liquid

22 radwaste system pipeline that conveyed liquid to the circulating water blowdown pit

23 south of the nuclear island. Entergy abandoned the line in 2012 and replaced it with

24 a temporary aboveground line, but the abandoned line still contained some water.

25 Groundwater samples contained tritium at concentrations of 28,270 pCi/L

26 (Entergy 2017h, 2017c). A corrective action plan was instituted that included (1)

27 filling the abandoned buried portion of the pipeline with a solid material to

28 permanently seal it and (2) installing a new liquid radwaste pipeline; including a new

29 engineered trench for the buried portion to facilitate future maintenance and

30 inspection. Entergy plans to complete the project by the end of 2017

31 (Entergy 2017c).

32 • In 2015, 60,000 gallons (227,125 L) of water containing tritium spilled from the

33 condensate demineralizer system inside the turbine building. As may have

34 happened in 2011 and 2012, some of this water may have seeped through degraded

35 floor joints in the turbine building and into the underlying structural fill material. As

36 previously mentioned, to prevent the possibility of future leaks the turbine building,

37 floor joints were resealed in 2016 (Entergy 2017h).

38 In response to these releases, in 2016, the NRC issued Entergy a non-cited violation for 

39 violation of 10 CFR 20.1406(c) because between 2013 through 2015, the licensee failed to 

40 conduct operations to minimize the introduction of residual radioactivity into the groundwater at 

41 the site. The NRC determined the finding to be of very low safety significance because while 

42 the issue involved radioactive material control, it did not involve transportation or public 

43 exposure in excess of 0.005 rem. The licensee has documented this finding in its corrective 

44 action program (NRC 2016c). The extent of groundwater contamination from these releases 

45 and the corrective actions taken are described in the following discussion.
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1 Source: Modified from Entergy 2017h

2 Figure 3-19. Wells Used to Monitor the Groundwater at the River Bend Site

3 The groundwater monitoring program at RBS includes 95 monitor wells (Entergy 2017h) 

4 (Figure 3-19). With the exception of a few wells installed in the Mississippi Alluvial Aquifer, all of 

5 them are completed either in the structural fill of the power block or the Upland Terrace Aquifer. 
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1 Deeper aquifers are monitored via the onsite production wells (Entergy 2017h, 2017g). Entergy 

2 participates in the Industry Ground Water Protection Initiative NEI-07-07 (NEI 2007). Since 

3 2008, the NRC staff has been monitoring implementation of this initiative at licensed nuclear 

4 reactor sites. The initiative identifies actions to improve management and response to 

5 instances in which the inadvertent release of radioactive substances may result in low but 

6 detectible levels of nuclear power plant-related radioactive materials in subsurface soils and 

7 water. The initiative identifies those actions necessary for the implementation of a timely and 

8 effective groundwater protection program along with acceptance criteria to demonstrate that the 

9 objectives have been met.

10 Tritium has been detected in the groundwater in a small area within the power block area 

11 located just west of and next to the radwaste and turbine buildings (Figure 3-20). Tritium in this 

12 area has been detected both in the groundwater of the structural fill and in the underlying 

13 Upland Terrace Aquifer. In Quarter 3 of 2017, the maximum value reported for tritium in the fill 

14 was 740,000 pCi/L (monitor well MW-158). In the same quarter, beneath the fill within the 

15 Upland Terrace Aquifer, the maximum reported value was 223,000 pCi/L (monitor well MW-155, 

16 Quarter 3, 2017) (Entergy 2017h, 2017g, 2017c).

17 Tritium has also been detected within the Upland Terrace Aquifer a short distance west of the 

18 power block area (Entergy 2017h, 2017g). Tritium concentrations in this area are much lower 

19 than the values found in the fill and Upland Terrace Aquifer near the radwaste and turbine 

20 buildings. In Quarter 3 of 2017, the maximum value reported in this area was 54,900 pCi/L 

21 (monitor well MW-110) (Entergy 2017h, 2017g, 2017c).

22 To better characterize the impacts on the groundwater as a resource, it is helpful to compare 

23 the concentrations of the radionuclides in the groundwater of the Upland Terrace Aquifer to EPA

24 maximum contaminant levels (MCL). For tritium, EPA has established a maximum contaminant 

25 level of 20,000 pCi/L (EPA 2002b, NRC 2006). Spills into the groundwater within the Upland 

26 Terrace Aquifer have exceeded the maximum contaminant level for tritium. In November 2016, 

27 the highest tritium concentration within the Upland Terrace Aquifer in the area directly beneath 

28 the power block area exceeded the maximum contaminant level by a factor of 11. At the same 

29 time, the highest concentration within the Upland Terrace Aquifer in the area just west of the 

30 power block area exceeded the maximum contaminant levels by a factor of 2.8. Although the 

31 MCLs were exceeded, there was no impact to drinking water due to the absence of any drinking 

32 water wells down-gradient of the spills. This is discussed further in Chapter 4 of this SEIS.

33 Entergy monitors the tritium in the groundwater and continues to define the extent of 

34 groundwater contamination and any potential sources of contamination. Entergy believes that 

35 all detectable tritium contamination within the fill and Upland Terrace Aquifer is the result of 

36 liquid spills within the turbine building. As previously mentioned, in 2016, Entergy resealed the 

37 turbine building floor joints to stop any future leaks. However, it is too early to conclude that 

38 Entergy has identified and stopped all sources of tritium contamination.

39 Entergy has actively remediated contaminated groundwater by periodically pumping 

40 groundwater from the area next to the radwaste building. The contaminated water was then 

41 placed into storage tanks. There, water was added to reduce the concentration in the tanks. 

42 When the water in the tanks was within acceptable Louisiana Department of Environmental 

43 Quality and NRC regulatory limits; it was discharged to the Mississippi River (Entergy 2017h) 

44 (LDEQ 2013). Once in the river, the tritium concentrations were further diluted by the water in 

45 the river to extremely low levels that were very likely below laboratory detection limits 

46 (Entergy 2017h).
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1 Source: Modified from Entergy 2017h 

2 Figure 3-20. Groundwater Tritium Concentrations as of November 2015 at the River Bend 

3 Site
3-67

1 Entergy is also remediating the contaminated groundwater by using monitored natural 

2 attenuation (Entergy 2017h). Monitored natural attenuation is a methodology endorsed by EPA

3 that, depending on site-specific circumstances, is used to reduce or attenuate the concentration 

4 of contaminates in groundwater (EPA 1999b). Natural attenuation relies on natural processes 

5 such as dilution, sorption, evaporation, radioactive decay, and chemical reactions with natural 

6 substances. The natural attenuation process that will reduce tritium concentrations in 

7 groundwater are most likely to be the processes of dilution and radioactive decay.

8 The direction of groundwater flow in the structural fill and the Upland Terrace Aquifer is 

9 southwestward toward the Mississippi River Aquifer and from there into the Mississippi River. 

10 Following this direction of flow, groundwater only leaves the RBS property when it flows into the 

11 Mississippi River. Using monitored natural attenuation, the tritium in the groundwater near the 

12 power block would move with the groundwater over the approximately 2-mile distance until it 

13 exits the site boundary at the Mississippi River.

14 Tritium has a half-life of 12.3 years. This means that after 12.3 years, half of the tritium will be 

15 gone. Radioactive decay will decrease the concentration of tritium in the groundwater. Within 

16 the Upland Terrace Aquifer, the distance along the groundwater path from the power block area 

17 to the Mississippi River is approximately 2 miles. It is estimated that it would take 8.9 to 12.5 

18 years for the tritium in the Upland Terrace Aquifer to reach the Mississippi River 

19 (Entergy 2017c), by which time approximately 39 to 50 percent of the tritium will have decayed 

20 away.

21 As tritium in the groundwater moves away from the power block area, its concentration in the 

22 Upland Terrace Aquifer will decrease. The Upland Terrace Aquifer is a water table aquifer. 

23 When precipitation events occur, some of the water from the rain or from runoff, will seep into 

24 the underlying aquifer and make its way down to the water table. The addition of this water will 

25 dilute the concentration of tritium in the groundwater. In addition, as individual water molecules 

26 move between the clay, silt, and sand particles that make up the Upland Terrace Aquifer; water 

27 molecules containing tritium will spread through the aquifer and mix with water molecules that 

28 do not contain tritium. This will cause the concentration of the tritium in the groundwater to 

29 decrease as the tritium-containing water mixes with water that does not contain tritium.

30 As the groundwater in the Upland Terrace Aquifer moves towards the river, biological processes 

31 are also likely to reduce the concentration of tritium in the aquifer. The land between the power 

32 block and the river is largely made up of a dense forest. Trees in this forest will withdraw 

33 groundwater from the Upland Terrace Aquifer. Tree roots cannot distinguish between a water 

34 molecule containing tritium and one that does not. Therefore, it is likely that some of the tritium 

35 in the groundwater will be removed by the trees. Tritium removed by the trees will likely be 

36 incorporated into the tree for a while before it is lost to atmosphere, with a small fraction 

37 organically bound to the structure of the tree until the tritium decays away.

38 As groundwater containing tritium flows beneath the flood plain of the Mississippi River, 

39 occasional flooding of the land surface by the river would add additional water to the underlying 

40 aquifer. This in turn would dilute and reduce tritium concentrations in the aquifer.

41 When the height of the water in the Mississippi River causes the river head to exceed the head 

42 in adjacent aquifers, river water would very likely move into the Upland Terrace and Mississippi 

43 River aquifers. This would dilute the tritium in the groundwater, reducing its concentrations in 

44 these aquifers near the river.
3-68

1 All of the processes described above will reduce the concentration of tritium in the groundwater

2 before it moves into the Mississippi River. After it moves into the river, its concentration would 

3 be greatly reduced by the large volume of water flowing in the river. The impacts from 

4 groundwater consumption and from the releases of radionuclides into the groundwater are 

5 described in Section 4.5.1.2 of this SEIS.

6 3.6 Terrestrial Resources

7 This section describes the terrestrial resources of the affected environment, including the 

8 surrounding ecoregion, species, and vegetative communities present on the RBS site, and 

9 important species and habitats potentially present on or near the RBS site.

10 3.6.1 River Bend Station Ecoregion

11 The RBS site overlaps with the edges of two ecoregions: the Mississippi Alluvial Plains

12 ecoregion and Mississippi Valley Loess ecoregion (NHEERL 2011). The Mississippi Alluvial 

13 Plain ecoregion consists of a long thin band that begins in southern Illinois (at the confluence of 

14 the Ohio River with the Mississippi River); extends south through parts of Missouri, Tennessee, 

15 Arkansas, Mississippi, and Louisiana; and ends at the Gulf of Mexico (Wiken et al. 2011). The 

16 Mississippi Valley Loess ecoregion stretches from the Ohio River in western Kentucky, extends 

17 south to Louisiana, and ends just east of the Mississippi River (Wiken et al. 2011).

18 The climate of both ecoregions is mild, humid subtropical, and the terrain is mostly broad, flat 

19 alluvial plain with river terraces, swales, and levees (Wiken et al. 2011). In the Mississippi 

20 Valley Loess ecoregion, thick deposits of loess sediment (wind-blown silt) in hills and ridges is a 

21 distinguishing feature (Wiken et al. 2011). Prior to European settlement, both ecoregions were 

22 dominated by bottomland deciduous forest; however, much of the forested habitat has been 

23 cleared for agricultural use. Virgin cypress stands were typically 400 to 600 years old at the 

24 time of European settlement, but over the last century, most of these trees have been logged, 

25 and few individual trees over 200 years old remain in either ecoregion (Sharitz and 

26 Mitsch 1993). Wiken et al. (2011) reports that the Mississippi Alluvial Plain is one of the most 

27 altered ecoregions in the United States. Today, over 90 percent of the landscape has been 

28 converted to cropland (Weakley et al. 2016). Primary crops include soybeans, cotton, corn, 

29 rice, wheat, pasture, and sugarcane (Wiken et al. 2011). Of the two ecoregions, the Mississippi 

30 Valley Loess ecoregion has seen less development and remains a mosaic of forest, pine 

31 plantations, pasture, and cropland (Wiken et al. 2011).

32 Existing forests communities are distinctly segregated by the extent of the hydroperiod, or 

33 seasonal pattern of water inundation. The hydroperiod determines the amount of oxygen and 

34 moisture available to a given forest community. The most intact habitats are confined to the 

35 wettest areas, which are difficult to cultivate or alter for other economic purposes 

36 (Weakley et al. 2016). Common forest communities include (in decreasing flood duration) river 

37 swamp forest, lower hardwood swamp forest, backwater and flats forest, and upland transitional 

38 forest (Weakley et al. 2016). River swamp forests contain bald cypress (Taxodium distichum) 

39 and water tupelo (Nyssa aquatica) (Wiken et al. 2011). Hardwood swamp forests include water 

40 hickory (Carya aquatic), red maple (Acer rubrum), green ash (Faxinus pennsylvanica), and river 

41 birch (Betula nigra) (Wiken et al. 2011). Seasonally flooded areas of higher elevation contain 

42 these species as well as sweetgum (Liquidambar styraciflua), sycamore (Platanus occidentalis), 

43 laurel oak (Quercus laurifolia), Nuttall oak (Q. texana), and willow oak (Q. phellos) 

44 (Wiken et al. 2011). Common herbs include butterweed (Senecio glabellus), jewelweed 

45 (Impatiens capensis), and royal fern (Osmunda regalis), and woody vines include poison ivy 
3-69

1 (Toxicodendron radicans), greenbriers (Smilax spp.), and trumpet-creeper (Campsis radicans) 

2 (Weakley et al. 2016).

3 Common wildlife include white-tailed deer (Odocoileus virginianus), black bear (Ursus 

4 americanus), bobcat (Lynx rufus), coyote (Canis latrans), gray fox (Urocyon cinereoargenteus), 

5 northern raccoon (Procyon lotor), eastern fox squirrel (Sciurus niger), eastern cottontail 

6 (Sylvilagus floridanus), swamp rabbit (Sylvilagus aquaticus), American beaver 

7 (Castor canadensis), wild turkey (Meleagris gallopavo), cormorants (Phalacrocorax spp.), egrets 

8 (Egretta spp.), herons, mourning dove (Zenaida macroura), wood thrush (Hylocichla mustelina), 

9 yellow-throated vireo (Vireo flavifrons), various migratory waterfowl, and American alligators 

10 (Alligator mississippiensis).

11 3.6.2 River Bend Station Site Surveys, Studies, and Reports

12 This section summarizes the wildlife and vegetation surveys, studies, and reports that have 

13 been conducted on and near the RBS site in chronological order.

14 Preoperational Wildlife and Habitat Surveys (1972–1977)

15 In the 1970s, Gulf States Utilities Company commissioned several wildlife and habitat surveys 

16 of the RBS site prior to construction and operation of the nuclear power plant. In 1972, a 

17 vegetative survey of the site identified 16 distinct forest communities and 34 meadows and 

18 pastures. Small mammal trappings were conducted between the summer of 1974 through the 

19 summer of 1977 within several of the site’s natural habitats, including upland mixed 

20 shrub-grasslands, upland hardwood forests, disturbed upland areas, and mature bottomland 

21 hardwood forest. Avian surveys were conducted in 1972, 1973, and 1974 and included a mist 

22 net survey in bottomland hardwood forest areas, a breeding bird census in the loess bluff forest 

23 region of the site, and a winter bird census in meadows and more open-type habitats. 

24 Methodology and results of these surveys are described in the environmental report for RBS 

25 operation (GSUC 1984).

26 Ecological Asset Value Development Report (2002)

27 In 2002, the Electric Power Research Institute team performed a site-specific assessment of 

28 ecological asset development opportunities on the RBS site. During the assessment, the team 

29 considered the ecological assets that are present or could potentially be developed on the RBS 

30 site, evaluated how the current regulatory and market climate would affect development of the 

31 identified ecological assets, and recommended specific ecological asset projects for Entergy to 

32 consider pursuing further. As part of the assessment, the team collected soil samples, 

33 conducted vegetation surveys, and evaluated the potential for the site to provide habitat for 

34 threatened, endangered, or rare species.

35 Vegetation Surveys (2006–2007)

36 Between December 2006 and November 2007, Entergy commissioned vegetation surveys of 

37 the RBS site in connection with the River Bend Station, Unit 3 combined license application. 

38 Entergy documented the results of these vegetation surveys in its environmental report for the 

39 combined license application (Entergy 2008a). Surveyors identified seven vegetative 

40 communities within the site’s natural areas, including upland palustrine wetlands and four types 

41 of bottomland forest. Additionally, surveyors documented wildlife present on the site through 

42 direct observation and indirect evidence (e.g., scat and tracks).
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1 3.6.3 River Bend Station Site

2 As described in Section 3.2, RBS lies within a 3,342-ac (1,353-ha) Entergy-owned property on 

3 the east bank of the Mississippi River within a rural area of southern Louisiana 24 mi (39 km) 

4 north-northeast of the city of Baton Rouge. Site-specific information in this section is derived 

5 from the environmental report (Entergy 2017h) unless otherwise cited.

6 The site primarily consists of two basic forest types: bottomland hardwood and swamp/cypress. 

7 Upland bluffs on the site are part of the Tunica Hills region and represent the southernmost 

8 reaches of the loess bluffs. A natural levee lies along the bank of the Mississippi River that has 

9 been hardened with riprap partially colonized by trees and shrubs. Between the natural levee 

10 and upland bluffs lies bottomland forest and alluvial floodplain habitat of variable drainage. This 

11 area of the site also contains a large bird rookery used by snowy egret (Egretta thula), blue 

12 heron (Ardea herodias), night heron (Nycticorax nyticorax), and other wading and water birds. 

13 The RBS site contains approximately 2,869 ac (1,161 ha) (87 percent) of undeveloped natural 

14 areas consisting of the following land use/land cover types: deciduous forest, woody wetlands, 

15 mixed forest, shrub/scrub, evergreen forest, grasslands, pasture, emergent herbaceous 

16 wetlands, open water, and barren land (see Table 3-1 and Figure 3-6). Most of the RBS site 

17 has been logged or cultivated in the past, which accounts for the lack of mature trees and the 

18 overall reduced plant diversity found throughout the site. Logging likely begun on the site as 

19 early as the 1820s and continued through the 1950s. The non-forested areas have all been 

20 previously disturbed and include mowed lawns, maintained transmission line corridors, and a 

21 few areas that were previously cleared and are now in the early stages of succession and 

22 dominated by planted grasses and invasive shrubs. The principal plant communities on the site 

23 include several types of bottomland forest communities, upland forest, upland forest palustrine 

24 wetland, and upland fields. The following subsections describe these communities in more 

25 detail. Unless otherwise noted, the descriptions of these vegetative communities that follow are 

26 derived from Entergy’s environmental report (2017h).

27 Bottomland Forest

28 Bottomland forest occupies approximately 19 percent of the RBS site and is primarily composed 

29 of three community types: bald cypress/tupelo gum bottomland forest, tupelo gum/hackberry 

30 bottomland forest, and hachberry/boxelder/ash bottomland forest. 

31 Areas of bald cypress/tupelo gum bottomland forest are regularly to permanently inundated. 

32 Bald cypress and tupelo (Nyssa spp.) are the dominant species, and some red maple 

33 (Acer rubrum) and green ash (Fraxinus pennsylvanica) are also present. Buttonbush 

34 (Cephalanthus spp.) is a fairly common shrub in open canopy areas, and watermeal 

35 (Wolffia spp.) and duckweed (Lemna spp.) occur in areas where there are permanent stands of 

36 water.

37 Tupelo gum/hackberry bottomland forest occurs in low-lying, poorly drained flats in close 

38 proximity to bald cypress. Tupelo gum and sugarberry (Celtis laevigata) are the dominant 

39 species, but red maple, green ash, and oaks (Quercus spp.) are also present. The herbaceous 

40 layer varies depending on how recently an area has been subject to inundation, scouring, or 

41 prolonged drought.

42 Hackberry/boxelder/ash bottomland forest occurs in areas of slightly higher elevation with better 

43 drainage, although this community is also subject to periodic flooding. The canopy in these 
3-71

1 areas is dominated by sugarberry, box elder (Acer negundo), and green ash, but a number of 

2 other species are present as well including cottonwood (Populus deltoides), black willow 

3 (Salix nigra), oak, and sweetgum. The understory is brushy and includes tree saplings, grapes 

4 (Vitis spp.), and briars (Smilax spp.).

5 Upland Forest

6 Upland forests dominate the loess plain areas of the RBS site. These areas include a mixture 

7 of species such as tulip tree (Liriodendron tulipifera), water oak (Quercus nigra), Shumard's oak 

8 (Q. shumardii), red mulberry (Morus rubra), sweetgum, and pines (Pinus spp.). The understory 

9 varies widely depending on the level of previous disturbance and how recently disturbance 

10 occurred. Areas to the east of Powell Station Road have little ground cover or support 

11 non-native shrubs and vines, such as privet (Ligustrum spp.), barberry (Berberis thunbergii), 

12 and Japanese honeysuckle (Lonicera japonica). Upland forests west of Powell Station Road 

13 are slightly more mature and denser ground cover is more common. In these areas, non-native 

14 shrubs and vines as well as Christmas fern (Polystichum acrostichoides), may-apple 

15 (Podophyllum peltatum), snakeroot (Sanicula spp.), Virginia snakeroot (Aristolochia

16 serpentaria), and rattlesnake fern (Botrychium virginianum) form the understory.

17 Upland Forest Palustrine Wetland

18 Approximately 4 ac (1.6 ha) of wetlands lie immediately west of Powell Station Road. The area 

19 is primarily composed of inundated emergent wetlands with rushes, sedges, and forbs 

20 surrounded by wetland forest with scattered bald cypress, sweetgum, and water oak.

21 Upland Fields

22 Much of the upland fields on the site were upland forest prior to being cleared for RBS 

23 construction in the mid-1980s for equipment laydown. These areas are now dominated by 

24 broomsedge bluestem (Andropogon virginicus), Bermuda grass (Cynodon dactylon), panic 

25 grasses (Dichanthelium spp.), and weedy forbs such as hop-clover (Trifolium dubium). Many of 

26 the uplands fields are occasionally or regularly mowed.

27 Wildlife at the RBS Site

28 As described in Section 3.6.2, the RBS site was surveyed for wildlife prior to construction and 

29 again in 2006 and 2007 during preparation of the RBS Unit 3 combined license application. The 

30 site supports a wide variety of amphibians, reptiles, birds, and mammals due to its diversity of 

31 habitats.

32 Entergy (2017h) reports that the site supports as many as 79 amphibians and reptiles (26 frogs 

33 and salamanders, 9 lizards, 29 snakes, and 15 turtles), including the American alligator, bullfrog 

34 (Rana catesbeiana), eastern spadefood toad (Scaphiopus holbrookii), southern leopard frog 

35 (R. sphenocephala), eastern garter snake (Thamnophis scripta elegans), southern copperhead 

36 (Agkistrodon contortrix contortrix), and western cottonmouth (A. piscivorus leucostoma).

37 The Lower Mississippi River is part of the Mississippi Flyway, a major bird migratory route that 

38 extends from the Gulf of Mexico across the continental United States and into Canada. Thus, 

39 the RBS region is a pass over area for semiannual migrations of neotropical birds as well as 

40 seasonal migrations of waterfowl. Additionally, the site provides permanent and winter habitat 

41 for a number of waterfowl. Based on preconstruction surveys, approximately 177 bird species 
3-72

1 occur on the RBS site. Forest community birds include year round and seasonal residents such 

2 as the American robin (Turdus migratorius), blue jay (Cyanocitta cristata), white-eyed vireo 

3 (Vireo griseus), red-bellied woodpecker (Sphyrapicus thyriideus), and Carolina wren 

4 (Thryomanes ludovicianus). Bottomland forest and wetland areas support water-dependent 

5 birds, including the great blue heron (Ardea herodias), belted kingfisher (Ceryle alcyon), 

6 redwinged blackbird (Agelaius phoeniceus), and great egret (Ardea alba). Birds of prey include 

7 turkey vulture (Cathartes aura), Cooper's hawk (Accipiter cooperii), great horned owl (Bubo 

8 virginianus), red-tailed hawk (Buteo jamaicensis), and short-eared owl (Asio flammeus). 

9 Additionally, the bald eagle (Haliaeetus leucocephalus) occasionally transits the site. Game 

10 birds include the mourning dove, northern bobwhite (Colinus virginianus), wild turkey (Meleagris 

11 gallopavo), and wood duck (Aix sponsa), all of which are year-round residents.

12 As many as 44 mammal species are likely to occur on the RBS site, and these include 

13 white-tailed deer, coyote, northern raccoon, eastern cottontail, eastern fox squirrel, gray fox, and 

14 American beaver.

15 Table 3-9 includes a more comprehensive list of common wildlife that likely occur on or near the 

16 RBS site.

17 Table 3-9. Common Wildlife Occurring on or in the Vicinity of the River Bend Station Site

Species(a) Common Name

Amphibians

Bufo woodhousei Woodhouse’s toad

Hyla crucifer peeper

Pseudacris nigrita southern chorus frog

Rana catesbeiana bullfrog

Rana sphenocephala southern leopard frog

Scaphiopus holbrookii eastern spadefoot toad

Birds(b)

Accipiter cooperii cooper’s hawk

Anas americana American wigeon

Anas crecca green-winged teal

Anas discors blue-winged teal

Anas platyrhynchos mallard

Anas strepera gadwall

Ardea alba great egret

Ardea herodias great blue heron

Bubo virginianus great horned owl

Bubulcus ibis cattle egret

Bucephala albeola bufflehead

Butorides virescens green heron

Cardinalis cardinal

Ceryle alcyon belted kingfisher
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Species(a) Common Name

Charadrius vociferus killdeer

Coragyps atratus black vulture

Corvus brachyrhynchos common crow

Cyanocitta cristata blue jay

Fulica americana American coot

Gallinago common snipe

Haliaeetus leucocephalus bald eagle

Hirundo rustica barn swallow

Lophodytes cucullatus hooded merganser

Nycticorax black-crowned night heron

Passer domesticus house sparrow

Petrochelidon pyrrhonota cliff swallow

Phalacrocorax auritus double-crested cormorant

Picoides pubescens downy woodpecker

Scolopax minor American woodcock

Strix varia barred owl

Sturnella magna eastern meadowlark

Sturnus vulgaris European starling

Thryomanes ludovicianus Carolina wren

Turdus migratorius American robin

Zenaida macroura mourning dove

Mammals

Canis latrans coyote

Castor canadensis American beaver

Cryptotis parva least shrew

Dasypus novemcinctus nine-banded armadillo

Didelphis virginiana Virginia opossum

Eptesicus fuscus big brown bat

Lynx rufus bobcat

Mephitis striped skunk

Mustela vison North American mink

Myocastor coypus nutria

Odocoileus virginianus white-tailed deer

Ondatra zibethicus common muskrat

Oryzomys palustris marsh rice rat

Procyon lotor northern raccoon

Sciurus carolinensis eastern gray squirrel

Sciurus niger eastern fox squirrel

Sigmodon hispidus hispid cotton rat

Sylvilagus aquaticus swamp rabbit
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Species(a) Common Name

Sylvilagus floridanus eastern cottontail

Urocyon cinereoargenteus gray fox

Vulpes red fox

Reptiles

Agkistrodon contortriix southern copperhead

Agkistrodon piscivorus leucostoma western cottonmouth

Alligator mississippiensis American alligator

Crotalus horridus canebrake rattlesnake

Elaphe guttata corn snake

Nerodia erythrogaster flavigaster yellow-bellied water snake

Sternotherus odoratus stinkpot

Thamnophis scripta elegans eastern garter snake

(a) Table adapted from Entergy 2017h, Table 3.6-1.

(b) With the exception of the European starling, house sparrow, northern

bobwhite, and wild turkey, all bird species listed in this table are

protected under the Migratory Bird Treaty Act of 1918, as amended

(16 U.S.C. §§ 703–712).

Source: Entergy 2017h

1 3.6.4 Important Species and Habitats

2 The Louisiana Natural Heritage Program (LNHP) within the Louisiana Department of Wildlife 

3 and Fisheries (LDWF) oversees the State’s Threatened and Endangered Species Conservation 

4 Program as described in Part IV, “Threatened and Endangered Species,” of Title 56 of the 

5 Louisiana Revised Statutes. The Revised Statutes give the Louisiana Natural Heritage Program 

6 the authority to list species as State-threatened or endangered; to issue regulations necessary 

7 and advisable to provide for conservation of such species; and to prohibit the export, take, 

8 possession, sale, or transport of such species. 

9 As part of the Threatened and Endangered Species Conservation Program, the Louisiana 

10 Natural Heritage Program maintains a database of rare, threatened, and endangered species of 

11 plants and animals and natural communities in the State. Table 3-10 identifies the plants, 

12 animals, and natural communities listed in the Louisiana Natural Heritage Program’s database 

13 as occurring in West Feliciana Parish. The table also includes habitat associations for each 

14 species. Entergy (2008a, 2017h) reports that none of the species identified in Table 3-10 have 

15 been identified as occurring on the RBS site.

16 The Louisiana Department of Wildlife and Fisheries also oversees Louisiana’s Natural Areas 

17 Registry Program, a voluntary program that encourages private landowners to conserve 

18 biologically unique lands. For an area to qualify for the registry, it must contain one or more of 

19 the following: habitat for native plants or animals with rare or declining populations within 

20 Louisiana, plant communities that are characteristic of the native vegetation of Louisiana, or 

21 outstanding natural features such as old growth forests or wetlands. By joining the registry, 

22 landowners commit to protect the area and its unique natural elements to the best of their 

23 abilities, notify the program representative of any threats to the area or the plants and animals 

24 within, and notify the program representative of an intent to sell or transfer ownership of the 
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1 area (LDWF 2017c). In 2004, the Louisiana Department of Wildlife and Fisheries designated 

2 the River Bend Natural Area, a 550-ac (223-ha) portion of the RBS site, as a Louisiana Natural 

3 Area because it contains very species-rich, upland hardwood forests (Entergy 2017h, 2017c; 

4 LDWF 2006) (see Figure 3-21). The site was eligible for registry as a natural area due to its 

5 unusual topography, which includes deep, fertile, wind-blown loessial deposits that have eroded 

6 over thousands of years to form a characteristic highly dissected landscape of high, narrow 

7 ridges, steep slopes, deep ravines, and intermittent-to-permanent streams (LDWF 2006). Relic 

8 populations of numerous species more common in the Appalachian Mountains, Ozarks, and 

9 areas northward may still occur in the natural area and in the broader Tunica Hills region today 

10 (LDWF 2006).

11 Table 3-10. Important Terrestrial Species and Habitats in West Feliciana Parish

Species(a) Common Name

State 

Rank(b)

Global 

Rank(c)

State 

Status(d)

Federal 

Status(e) Habitat Associations

Important Animals

Brachycerus flavus yellow brachycercus 

mayfly

S2 G4 — — Clear creeks and medium 

rivers.

Haliaeetus 

leucocephalus 

bald eagle S3 G5 SE FD Cypress trees near open 

water; open lakes and 

rivers.

Helmitheros 

vermivorus

worm-eating warbler S3 G5 — — Steep slopes of eastern 

deciduous forests with 

dense understories.

Mustela frenata long-tail weasel S3 G5 — — Brushland, and open 

areas such as woodlands, 

marshes, swamps, field 

edges and riparian 

grasslands near water.

Plethodon websteri Webster's salamander S1 G3 SP — Moist hardwood forest 

bordering rocky streams.

Seiurus motacilla Louisiana waterthrush S3–S4 G5 — — Open-banked, fast- or 

slow-moving streams with 

steep to moderate 

gradients, in forested 

watersheds or swampy 

areas with standing water.

Setophaga ruticilla American redstart S3 G5 — — Open wooded habitats 

dominated by deciduous 

trees.

Sorex longirostris southeastern shrew S2 G5 — — Moist or wet areas in 

damp forests or bordering 

swamps, marshes and 

rivers as well as upland 

shrubby or wooded 

habitats.

Spilogale putorius eastern spotted skunk S1 G5 — — Forested and well covered 

brushy areas and prairie 

outcrops.
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Species(a) Common Name

State 

Rank(b)

Global 

Rank(c)

State 

Status(d)

Federal 

Status(e) Habitat Associations

Ursus americanus 

luteolus

Louisiana black bear S3 G5 ST FD Large tracts of heavily 

wooded bottomland 

hardwoods and swamps.

Important Plants

Actaea pachypoda white baneberry S2 G5 — — Partially shaded areas of 

deciduous and mixed 

forests with dense thickets 

and well-drained, acidic 

soil.

Asarum canadense Canada wild-ginger S1 G5 — — Shaded areas of 

deciduous forest with rich, 

mesic soils.

Celastrus scandens climbing bittersweet S1 G5 — — Full sun to shade in rich, 

mesic soils of southern 

mesophytic forests, salt 

dome hardwood forests, 

and high sites in 

bottomland hardwoods.

Chamaelirium 

luteum

fairy wand S2–S3 G5 — — Shady sesic acidic sandy 

loam soils in hardwood 

slope and mixed 

hardwood-loblolly pine 

forests.

Circaea lutetiana 

spp. canadensis

Enchanter's 

nightshade

S2 G5 — — Areas of dappled sun to 

medium shade, mesic 

conditions, and rich loamy 

soil with abundant organic 

matter.

Deparia 

acrostichoides

silvery glade fern S2 G5 — — Shaded, moist areas of 

mesic wooded valleys, 

rocky canyon bottoms, and 

wooded ravine slopes.

Diplazium 

pycnocarpon

glade fern S2 G5 — — Shady, rich wooded 

ravines.

Dryopteris 

ludoviciana

south shield wood-fern S2 G4 — — Shady bottomland 

hardwood forests, rich 

ravines in loess hills, 

prairie terrace loess 

flatwoods, and forested 

seeps.

Frasera 

caroliniensis

Carolina gentian SH G5 — — Upland savannas, upland 

woodlands, wooded 

slopes, limestone and 

sandstone glades, 

woodland openings, and 

small meadows in upland 

wooded areas.

Heuchera 

americana

American alumroot S2 G5 — — Partial shade to full sun in 

rich woods and rocky 

outcrops.
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Species(a) Common Name

State 

Rank(b)

Global 

Rank(c)

State 

Status(d)

Federal 

Status(e) Habitat Associations

Hexalectris spicata crested coral-root S2 G5 — — Partial shade in mesic to 

dry soils of forests over 

sandstone or limestone 

substrate.

Magnolia 

pyramidata

pyramid magnolia S2 G4 — — Partial shade in dense, 

rich wooded bluffs and 

ravines on the edges of 

water bodies and swamps.

Pachysandra 

procumbens

Allegheny-spurge S2 G4–G5 — — Shady areas in rich woods 

with limestone substrate.

Panax 

quinquefolius

American ginseng S1 G3–G4 — — Cool areas of rich woods 

with alkaline loessial 

deposits.

Physalis carpenteri Carpenter's 

ground-cherry

S1 G3 — — Loess bluffs of the Tunica 

Hills region.

Platythelys 

querceticola

low erythrodes S1 G3–G5 — — Shady areas of mesic 

hardwood forests, 

floodplains, and swamps.

Ponthieva 

racemosa

shadow-witch orchid S2 G4–G5 — — Shady swamps and moist 

woodlands.

Saxifraga 

virginiensis

Virginia saxifrage SH G5 — — Sunny cliffs, ledges, and 

rocky talus areas and 

slopes.

Schisandra glabra scarlet woodbine S3 G3 — — Shady areas of southern 

mesophytic forests, 

hardwood slope forests, 

and mixed 

hardwood-loblolly pine 

forests.

Silphium 

perforliatum

Carpenter's square S1 G5 — — Sunny areas of wet to 

mesic woods and prairies.

Triphora 

trianthophora

nodding pogonia S2 G3–G4 — — Rich humus, leaf mold, 

and rotten logs of 

hardwood and coniferous 

forests, rich woods along 

streams, edges of 

swamps, floodplain 

forests, and mountain 

slopes.

Important Natural Communities

batture S3 G4–G5 — — Slopes between natural 

levee crests and major 

streams or rivers with 

semi-permanently 

inundated soils.
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Species(a) Common Name

State 

Rank(b)

Global 

Rank(c)

State 

Status(d)

Federal 

Status(e) Habitat Associations

cypress-tupelo 

swamp

S4 G3–G5 — — In regularly to permanently 

inundated areas along 

rivers and streams and in 

blackswamp depressions 

and swales.

hackberry-American 

elm-green ash 

forest

S4 G4–G5 — — Along upper floodplain 

terraces of large and small 

alluvial rivers; on ridges, 

flats, and sloughs; and in 

upland ravine bottoms.

overcup oak-water 

hickory forest

S4 G4 — — On the edges of swamps 

and bayous in poorly 

drained areas and within 

silty-clay flats in first 

bottoms and terraces of 

larger streams and rivers.

small stream forest S2 G3 Along small river and large 

creeks with silt-loam soils 

and brief periods of 

seasonal flooding.

southern 

mesophytic forest

S2 G1–G2 — — In the Tunica Hills region 

of Louisiana in areas with 

deep, fertile, alkaline 

loessial deposits and 

streams with intermittent to 

continuous flow.

(a) Entergy (2008a, 2017h) reports that none of these species were recorded as present on the RBS site during

surveys performed in conjunction with the proposed River Bend Station, Unit 3 combined license application. (b) S1 = critically imperiled in Louisiana because of extreme rarity (5 or fewer known extant populations); S2 =

imperiled in Louisiana because of rarity (6 to 20 known extant populations); S3 = rare and local throughout the state

or found locally in a restricted region of the state (21 to 100 known extant populations); S4 = apparently secure in

Louisiana with many occurrences (100 to 1000 known extant populations); SH = historical occurrence in Louisiana

but no recent records verified within the last 20 years; a range in state rank (e.g., S2-S3) indicates the limits of

uncertainty.

(c) G1 = critically imperiled globally because of extreme rarity (5 or fewer known extant populations); G2 = imperiled

globally because of rarity (6 to 20 known extant populations); G3 = either very rare and local throughout its range or

found locally in a restricted (21 to 100 known extant populations); G4 = apparently secure globally, though it may be

quite rare in parts of its range, especially at the periphery (100 to 1000 known extant populations); a range in

global rank (e.g., G3–G5) indicates the limits of uncertainty.

(d) SE = State-endangered, taking or harassment of these species is a violation of State law; ST = State-threatened,

taking or harassment of these species is a violation of State law; SP = possession of species prohibited; — = not

State-listed.

(e) FE = Federally endangered under the Endangered Species Act of 1973, as amended (ESA); FT = Federally

threatened under the ESA; FD = Previously listed, but delisted from the ESA; — = not Federally listed under the

ESA.

Sources: Entergy 2008a, 2017h; FWS 2017a; LNHP 2017
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1 3.6.5 Invasive and Non-Native Species

2 The University of Georgia Center for Invasive Species and Ecosystem Health reports 

3 209 invasive species in West Feliciana Parish (UGA 2016). Entergy (2017h) describes the 

4 prominent terrestrial invasive species on or near the RBS site to likely include broomsedge 

5 bluestem (Andropogon virginicus), Chinese privet (Ligustrum sinense), bigleaf periwinkle (Vinca 

6 major), eastern saltbush (Baccharis halimifolia), Japanese honeysuckle (Lonicera japonica), 

7 kudzu (Pueraria montana var. lobata), McCartney rose (Rosa bracteata), poison ivy 

8 (Toxicodendron radicans), sweet joe-pye weed (Eutrochium purpureum), and feral hogs (Sus 

9 scrofa). Entergy (2017h) has not implemented any management programs or procedures 

10 specifically related to invasive species because no invasive species have interfered with plant 

11 operation.
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1 Source: Entergy 2017h, Figure 3.1-3 

2 Figure 3-21. RBS Site Natural Areas

3 3.7 Aquatic Resources

4 The aquatic communities of interest for the RBS site occur in the Lower Mississippi River. The 

5 Mississippi River makes up the southwest boundary of the RBS site, and it supplies makeup 

6 water to RBS’s cooling system. The Mississippi River also receives the plant’s cooling system 

7 blowdown. Earlier in this chapter, Section 3.1.3 describes the cooling system in detail, and 
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1 Section 3.5.1 describes the surface water characteristics of the Mississippi River and other 

2 onsite waterbodies.

3 The sections below describe the environmental changes within the Lower Mississippi River, the 

4 aquatic habitats and species within the Lower Mississippi River near RBS, the aquatic habitats 

5 and species of other onsite aquatic resources, State-listed aquatic species near RBS, and 

6 non-native species that occur near RBS. 

7 3.7.1 Environmental Changes in the Lower Mississippi River

8 The Mississippi River has historically fluctuated between a meandering river that erodes 

9 sediments on the river bank to create curves or bends, to a braided river that consists of several 

10 river channels separated by small islands. During the most recent glacial retreat, the Lower 

11 Mississippi River returned to a meandering river. A rivers meanders as it erodes the outer bank 

12 and then deposits the sediment on the inner bank, which results in a diverse set of habitats such 

13 as extensive floodplains, deep backwaters, oxbow lakes, and other shallow-water habitats. 

14 These waterbody features often provide high-quality habitats for aquatic biota (animal and plant 

15 life) due to the structural complexity and low flows that support spawning, feeding, and refuge 

16 from large predators. These diverse habitats support high biological richness with an abundance 

17 of fish and invertebrate species that occur within the Mississippi River. (Baker et al. 1991) 

18 The Mississippi River has a long history of humans using the river as a mode of transportation 

19 and subsequently modifying much of the high-quality, shallow-water habitats associated with a 

20 meandering river (Baker et al. 1991). For example, beginning in the 1800s, human 

21 modifications to allow for ship traffic along the Mississippi River and to minimize flooding events 

22 changed the relative abundance and types of habitats, access to fish migratory routes, flow 

23 patterns, and river channelization. For over 300 years, humans have built levees along the 

24 Mississippi River to control flooding. By 1844, levees were nearly continuous along the 

25 Mississippi River up to its confluence with the Arkansas River (Baker et al. 1991). As of 2005, 

26 nearly 3,000 km (1,864 mi) of levees lined the Lower Mississippi River, and an additional 

27 1,000 km (621 mi) of levees lined its tributaries (Brown et al. 2005). Levees decrease the 

28 frequency of flooding events, during which aquatic biota can move between the Mississippi 

29 River and floodplain habitats. The flow of aquatic resources from floodplain habitats into the 

30 river is one reason that the Lower Mississippi is so rich in species diversity.

31 Beginning in 1824, the U.S. Government removed snags, such as trees or tree roots, from the 

32 river. Snags provide natural habitat for invertebrates that require a firm attachment site and 

33 offer fish and other aquatic biota places to hide. In addition, revetments, which are fortifications 

34 built to prevent erosion and river meandering, have increased the availability of hard-surface 

35 habitats but decreased the availability of soft-surface river bank habitats. Approximately 

36 50 percent of the banks of the Lower Mississippi River are covered by revetments, such as 

37 timber, wooden or wire fences, rocks, and tires (Baker et al. 1991; Brown et al. 2005). 

38 However, such revetments do not provide as high a quality structure for aquatic organisms as 

39 naturally occurring tree roots. 

40 In addition, the U.S. Army Corps of Engineers (USACE) has artificially created cutoffs that 

41 shortened the length of the river by cutting across a point bar or neck of a meander. 

42 Baker et al. (1991) estimates that artificially created cutoffs have shortened the length of the 

43 Lower Mississippi River by 25 to 30 percent, or approximately 500 km (310 mi). Cutoffs can 

44 also increase the river speed and erosion of river banks (Baker et al. 1991). 
3-82

1 In addition to physical changes, runoff from over 40 percent of the conterminous 48 States 

2 drains into the Mississippi River. Land use changes over time have increased the concentration 

3 of industrial, chemical, and sediment inputs into the river. Farming practices currently include 

4 the use of fertilizers, pesticides, and herbicides, which wash into the Mississippi River, 

5 especially after large rain events (Brown et al. 2005). Plowed fields, as compared to forested 

6 areas, also increase the amount of sediments entering the Mississippi River. 

7 Currently, the USACE continues to dredge, install river bank revetments and levees, and 

8 regulate upstream reservoirs to minimize the historical movements of the river and create a 

9 relatively stable channel.

10 3.7.2 Lower Mississippi River

11 The Lower Mississippi River can be divided into two distinct sections: (1) the upper section 

12 ranging from Cairo, IL to Baton Rouge, LA and (2) the lower section from Baton Rouge, LA to 

13 the Gulf of Mexico. The lower section of the Lower Mississippi River has been more heavily 

14 modified by human activity. For example, a 12-m (39-ft) channel is maintained in the lower 

15 section to promote navigation, levees occur along both sides of the rivers, revetments have 

16 replaced natural habitats along much of the riverside, large meander loops are infrequent, and 

17 floodplains are rare (Baker et al. 1991). Similarly, deep channels, which do not provide 

18 high-quality habitat, comprise 85 percent of the lower section’s aquatic habitat as compared to 

19 55 percent of the upper section’s aquatic habitat (Baker et al. 1991). The aquatic habitats and 

20 biota in the Lower Mississippi River near RBS are discussed below. 

21 3.7.2.1 Aquatic Habitats near RBS

22 Four types of aquatic habitats occur near RBS: the channel, revetments, natural steep river 

23 banks, and seasonally inundated floodplains along the river levee. 

24 The Channel

25 The channel near RBS is characterized by deep water, high current speeds, high levels of 

26 suspended solids, high turbidity, high levels of nutrients, low-algal biomass, and uniform bottom 

27 habitat consisting of sand and/or gravel (Baker et al. 1991; Entergy 2008a, 2017h). The 

28 channel typically supports the lowest amount of biological richness because of the lack of 

29 structure to hide from predators and high levels of suspended solids that prevents primary 

30 producers at the base of the food chain from having access to sunlight in order to make food, 

31 develop, and grow. In addition, high current speeds limit biological productivity because mobile 

32 organisms must expend additional energy to move, hover feeding is not possible, and sessile 

33 organisms (those that are attached to a base and generally immobile) may not be able to stay 

34 attached to hard surfaces. Furthermore, these conditions do not provide suitable habitat for 

35 spawning. 

36 The intake structure and barge slip are located within a man-made, shallow-cut embayment that 

37 is most similar to a lotic sandbar (a sandbar surrounded by fast moving water), or channel 

38 habitat. The bottom substrate primarily consists of coarse sand and sandy mud. The area is 

39 regularly disturbed due to maintenance dredging and high turbidity levels, which prohibit the 

40 growth of high-quality benthic habitats such as mussel beds or submerged aquatic vegetation. 

41 (Entergy 2008a, 2017h).
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1 Revetments

2 Revetments are river banks that are usually cleared and lined with human-modified materials to 

3 prevent erosion (Baker et al. 1991). Within the vicinity of RBS, revetments made of rocks and 

4 concrete structures line most of the banks on the outer bends of the river, and wings or dikes 

5 line the inside bends to prevent erosion. Near the discharge structure, riprap (rocks piled on top 

6 of one another) and small boulders line parts of the man-made embayment (Entergy 2008a). 

7 Revetments provide a hard substance that support the growth of macroinvertebrates. However, 

8 for fish, revetments provide a lower habitat quality than natural river banks because revetments 

9 lack the structure and refuges provided by fallen trees and brush typically found along river 

10 banks. 

11 Steep River Banks

12 Steep river banks occur on the sides of river bends where the main channel current flows 

13 against them (Baker et al. 1991). The fast flow of the Lower Mississippi River often increases 

14 erosion along the river bank. Areas of upstream flow, or eddies, are common along the river 

15 bank and may provide an important refuge of slower-moving water for some fish species. Near 

16 RBS, fallen trees and brush, such as willow seedlings (Salix spp.) and cockleburs (Xanthium 

17 strumarium), alongside the river provide an important high-quality habitat for fish and substrate 

18 for macroinvertebrates to attach to and grow (Entergy 2008a, 2017h). Some vegetation is only 

19 covered by water intermittently, and therefore, only provides refuge during periods of flooding. 

20 The closest natural steep bank to the intake embayment is approximately 70 feet (21 meters)

21 away. (Entergy 2008a, 2017h). 

22 Floodplains

23 Floodplains are one of the most biologically important habitats in the Lower Mississippi River as 

24 the shallow water and habitat structure from trees and plants support use as spawning grounds, 

25 nursery habitats, refuges from predators, and foraging grounds. Seasonally inundated 

26 floodplains near RBS contain some areas of forested wetlands and isolated sloughs. Alligator 

27 and Grants bayous also regularly flood into the forested wetlands and isolated sloughs 

28 (Entergy 2008a). 

29 3.7.2.2 Aquatic Communities in the Lower Mississippi River

30 Human activities, such as river channelization, artificial revetments, levee construction, polluted 

31 land runoff, and the influx of municipal and industrial water effluents, have degraded the quality 

32 of the aquatic habitat surrounding RBS. These modifications have resulted in poor spawning 

33 habitats, high turbidity, high concentrations of total suspended solids, high current velocities, 

34 and fluctuating water levels near RBS, and therefore, have influenced the relatively low 

35 biological productivity, as described below (Baker et al. 1991, Entergy 2008a, 2017h). 

36 Plankton

37 Plankton are small organisms that float or drift in rivers and other water bodies. Plankton are a 

38 primary food source for many fish, and other animals, and consist of bacteria, protozoans, 

39 certain algae, tiny crustaceans such as copepods, and many other organisms. High turbidity 

40 (small suspended particles that make the water murky) and fluctuating water levels near RBS 

41 limit primary production for plankton that are dependent upon light for growth, such as 

42 phytoplankton and periphyton (GSUC 1984, Entergy 2008a, 2017h). Low levels of primary 
3-84

1 production may also limit the growth of zooplankton and other organisms that feed upon 

2 phytoplankton and periphyton. Therefore, the Lower Mississippi River is considered a 

3 detritus-based system, which is typical for large rivers. 

4 Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 

5 the base of aquatic food webs by producing biomass from inorganic compounds and sunlight. 

6 As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 

7 recycling of nutrients and minerals.

8 Studies conducted in the 1970s before RBS began operations documented extremely low 

9 concentrations of phytoplankton near RBS, likely due to the high suspended sediment load 

10 which blocks light from entering the water and prevents photosynthesis, and therefore growth, of 

11 phytoplankton (GSUC 1984, Entergy 2008a). Phytoplankton density was highest in areas of 

12 slower river currents, such as along the western riverbank, as compared to the main channel 

13 (Entergy 2008a). Diatoms dominated collections (GSUC 1984, Entergy 2008a). 

14 Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past, often called 

15 blue-green algae), heterotrophic microbes, other small organisms, and detritus that attach to 

16 submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 

17 source of nutrients to many bottom-feeding organisms.

18 Preoperational studies in the 1970s documented more than 115 taxa of planktonic algae 

19 (NRC 1985). Cynobacteria were most dominant during summer months (GSUC 1984, 

20 Entergy 2008a). 

21 Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water 

22 column. They include small invertebrates (e.g. copepods) and ichthyoplankton (fish eggs and 

23 larvae). Zooplankton are important trophic links between primary producers 

24 (e.g., phytoplankton and periphyton) and carnivores (e.g., fish). In the Lower Mississippi River, 

25 most fish spawn in backwaters with slower currents, and few spawn within the rapidly flowing 

26 channel portions of the river. 

27 Preoperational studies from 1974–1977 documented 140 invertebrate taxa and 45 species of 

28 larval fish near RBS (GSUC 1984, Entergy 2008a). For invertebrates, rotifers (a phylum of 

29 mostly microscopic, wheel-shaped animals) dominated collections from the main channel and 

30 river banks, whereas copepods, water fleas, and hydroid fragments (fragments of class 

31 Hydrozoa animals in their hydroid life stage) dominated collections near the intake and 

32 discharge structures (GSUC 1984, Entergy 2008a). In general, rotifers dominated most 

33 collections and organism density was higher along the shoreline as compared to the main 

34 channel. 

35 For larval fish, preoperational studies showed that species diversity peaked in late spring and 

36 early summer, which corresponds to the spawning period for common fish within the Lower 

37 Mississippi River. The most commonly collected larval fish species included freshwater drum 

38 (Aplodinotus grunniens), gizzard shad (Dorosoma cepedianum), and threadfin shad 

39 (D. petenense) (GSUC 1984, Entergy 2008a). Entergy (2017g) suggested that most 

40 zooplankton originated in backwaters or shallow habitats and then drifted towards the RBS site. 

41 Similar to other types of taxa, larval fish were denser along the river banks as compared to the 

42 river channel.
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1 Fish

2 Between 100 to 200 fish species are known to occur within the Lower Mississippi River 

3 (Baker et al. 1991). Prior to RBS operations, Gulf States Utilities Company documented 88 fish 

4 species in surveys conducted near RBS from 1972–1977 (GSUC 1984, Entergy 2008a). 

5 Entergy has not conducted fish surveys near RBS since operations began. In order to gather 

6 additional data regarding fish populations near RBS since 1977, the NRC staff reviewed survey 

7 data that was recorded in the online database, FishNet (2014). This database is a collaborative 

8 effort by natural history museums and biodiversity institutions to compile fish survey data. The 

9 database included fish surveys within the vicinity of RBS from 1973, 1976, 1978, 1979, 2000, 

10 and 2001. The NRC staff notes that the surveys used different methodologies, sampling 

11 locations, sampling protocols, and equipment. Therefore, additional species may occur near 

12 RBS that have not been captured in a survey due to the various survey methods and sampling 

13 regimes. Table 3-11 describes fish species that have been observed during two time periods: 

14 1970–1980 and 2000–2017. 

15 The fish survey data indicate that a variety of fish occur near RBS, with species diversity highest 

16 during spring and summer, especially during high-flow periods. Flooding events likely provide a 

17 hydrological connection for species that occur in backwaters and floodplains to migrate into the 

18 Mississippi River. Common fish species near RBS include gizzard shad, threadfin shad, 

19 blacktail shiner (Cyprinella venusta), river shiner (Notropis blennius), white crappie (Pomoxis 

20 annularis), river carpsucker (Carpiodes carpio), goldeye (Hiodon alosoides), common carp 

21 (Cyprinus carpio), Mississippi silverside (Menidia audens), inland silverside (Menidia beryllina), 

22 and silver chub (Macrhybopsis storeriana) (Table 3-11). Common commercially important fish 

23 species include blue catfish (Ictalurus furcatus), channel catfish (Ictalurus punctatus), flathead 

24 catfish (Pylodictis olivaris), bigmouth buffalo (Ictiobus cyprinellus), smallmouth buffalo (Ictiobus 

25 bubalus), and freshwater drum (LDWF 2017a; Entergy 2008a, 2017g). 

26 Table 3-11. Historical and Recent Fish Species Recorded near River Bend Station

Species Common Name

Survey Year(s)

1970–1980(a) 2000–2017(b)

Acipenseridae

Scaphirhynchus platorynchus shovelnose sturgeon X X

Amiidae

Amia calva bowfin X

Anguillidae

Anguilla rostrata American eel X

Atherinidae

Labidesthes sicculus brook silverside X

Menidia audens Mississippi silverside X

Menidia beryllina inland silverside X

Menidia peninsulae tidewater silverside X X 

Catostomidae

Carpiodes carpio river carpsucker X X

Ictiobus bubalus smallmouth buffalo X

Centrarchidae
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Species Common Name

Survey Year(s)

1970–1980(a) 2000–2017(b)

Lepomis cyanellus green sunfish X

Lepomis humilis orangespotted sunfish X X

Lepomis macrochirus bluegill X X

Lepomis megalotis longear sunfish X X

Micropterus punctulatus spotted bass X

Micropterus salmoides largemouth bass X X

Pomoxis annularis white crappie X X

Pomoxis nigromaculatus black crappie X X

Clupeidae

Alosa chrysochloris skipjack herring X

Dorosoma cepedianum gizzard shad X X

Dorosoma petenense threadfin shad X X

Cyprinidae

Cyprinella lutrensis red shiner X X

Cyprinella venusta blacktail shiner X X

Cyprinus carpio common carp X X

Hybognathus argyritis Western silvery minnow X

Hybognathus nuchalis Mississippi silvery 

minnow

X X

Luxilus chrysocephalus striped shiner X

Macrhybopsis aestivalis speckled chub X

Macrhybopsis hyostoma shoal chub X X

Macrhybopsis storeriana silver chub X X

Notemigonus crysoleucas golden shiner

Notropis atherinoides emerald shiner X X

Notropis blennius river shiner X X

Notropis buchanani ghost shiner X

Notropis longirostris longnose shiner X

Notropis lutrensis red shiner X

Notropis shumardi silverband shiner X X

Notropis texanus weed shiner X

Notropis volucellus mimic shiner X X

Opsopoeodus emiliae pugnose minnow X

Pimephales vigilax bullhead minnow X X

Fundulidae

Fundulus blairae lowland topminnow X

Hiodontidae

Hiodon alosoides goldeye X X

Hiodon tergisus mooneye X

Ictaluridae

Ameiurus melas black bullhead X

Ictalurus furcatus blue catfish X X
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Species Common Name

Survey Year(s)

1970–1980(a) 2000–2017(b)

Ictalurus punctatus channel catfish X X

Pylodictis olivaris flatheaded catfish X

Lepisosteidae

Lepisosteus oculatus spotted gar X

Lepisosteus platostomus shortnose gar X

Moronidae

Morone chrysops white bass X X

Morone mississippiensis yellow bass X X

Morone saxatilis striped bass X

Muglildae

Mugil cephalus striped mullet X X

Percidae

Percina caprodes common logperch X

Percina shuamardi river darter X

Percina vigil saddleback darter X

Stizostedion canadense sauger X

Poeciliidae

Gambusia affinis mosquitofish X X

Sciaenidae

Aplodinotus grunniens freshwater drum X X

Syngnathidae

Syngnathus scovelli Gulf pipefish X

(a) GSUC 1984

FishNet 2014: Surveys conducted by the following:

• J.V. Conner, Sabins & DeMont in 1973 along bank of the Mississippi River at River Mile 263;

• Suttkus, Beckham, Conner, Heath & Levine in 1976 along bank of the Mississippi River at River Mile 263.7;

• R.D. Suttkus, Conner & Rohmann in 1978 along bank of the Mississippi River at River Mile 262.5;

• R.D. Suttkus & Conner in 1978 and 1979 along bank of the Mississippi River at River Miles 262.6, 262.8,

263, 264, 264.8;

(b) Entergy 2008a

FishNet 2014: Surveys conducted by the following:

• Bart, Rios, Coste & Galloway in 2000 at St. Francisville on the west bank across from boat launch and on

the east bank across from an industrial plant;

• Rios, Todaro & Coste in 2000 and 2001 at St. Francisville on the west bank across from boat launch and

the east bank across from an industrial plant,

• Todaro, Rios, Coste, & Marik in 2001 at St. Francisville on the east bank across from an industrial plant

Sources: GSUC 1984; Entergy 2008a; FishNet 2014

1 Invertebrates

2 Preoperational studies identified more than 70 taxa of benthic (bottom dwelling) invertebrates at 

3 the RBS site (GSUC 1984, Entergy 2008a). Density of benthic invertebrates near RBS was 

4 highest along the shoreline portions of the river where their preferred habitat (e.g., soft organic 

5 mud and low flows) often occurs. Density of benthic invertebrates was lowest along the channel 

6 where fast currents, scouring, and shifting bottom surfaces prevent sessile macroinvertebrates 
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1 from attaching to hard surfaces in order to grow. Similarly, density was generally lowest in the 

2 spring, when flows were highest and mostly likely to disturb bottom habitats, causing some 

3 organisms to detach from hard surfaces or become exposed or smothered. 

4 At least 200 macroinvertebrate species occur in the Lower Mississippi River 

5 (Harrison and Morse 2012). In preoperational surveys, the most common benthic taxa near 

6 RBS were aquatic worms (Oligochaetes) and mayfly larvae: oligochaetes or worms comprised 

7 58 percent of the total number of organisms in benthic samples and mayfly larvae comprised 

8 30 percent of the benthic samples near RBS (GSUC 1984, Entergy 2008a). The three most 

9 common genera of macroinvertebrates included river shrimp (Macrobrachium sp.), crayfish 

10 (Procambarus spp.), and grass shrimp (Palaemonetes spp.). 

11 Ohio River shrimp (Macrobrachium ohione) commonly occur near RBS. This species is often 

12 used as bait for recreational fisheries and is an important prey species for many larger, 

13 predatory fish in the Lower Mississippi River (Entergy 2008a, 2017g). Ohio River shrimp often 

14 depend upon submerged aquatic vegetation or other submerged structures as habitat to provide 

15 refuge from predators. 

16 3.7.3 Other Onsite Aquatic Resources

17 3.7.3.1 Alligator Bayou

18 Alligator Bayou is a small intermittent stream that flows through the western portion of the RBS 

19 property. The Mississippi River and Thompson Creek periodically flood into Alligator Bayou, 

20 providing the bayou with additional water flow and nutrients. Productivity, or the density and 

21 diversity of aquatic fish and invertebrates, peaks in the bayou after flooding events. Alligator 

22 Bayou is an important habitat for aquatic fish and invertebrates due to the availability of slower 

23 currents and natural substrates. For example, woody debris (e.g., woody stumps and roots) 

24 provide a source of refuge for mobile organisms to hide and a hard surface for some immobile 

25 organisms to attach and grow. Similarly, dense stands of rooted, aquatic vegetation grow in the 

26 bayou and are an important refuge for juvenile salamanders, fish, crayfish, and a variety of other 

27 aquatic species. Alligator Bayou is also an important spawning ground and nursery area for fish 

28 eggs and larvae (Entergy 2008a). 

29 Gulf States Utilities Company identified more than 150 taxa of invertebrates and 64 species of 

30 fish in Alligator Bayou from 1972 through 1977 (GSUC 1984). Dominant benthic organisms in 

31 the bayou included aquatic oligochaetes and dipteran (mainly midge and phantom midge) 

32 larvae. Crayfish were the most abundant macrocrustacean and are an important prey item for 

33 reptiles, amphibians, fish, birds, and mammals. (GSUC 1984; Entergy 2008a) 

34 3.7.3.2 Grants Bayou

35 Grants Bayou is an intermittent stream and a tributary of Alligator Bayou. Flows tend to be 

36 continuous in the winter and spring, but aquatic life is limited due to the intermittent flow and 

37 lack of ability to maintain populations during dry periods. Historical studies documented 

38 23 fish species within Grants Bayou. Studies conducted before RBS began operations 

39 indicated that the most common species included gizzard shad, shiners, minnows, mosquitofish, 

40 sunfish, bluegill, and largemouth bass (GSUC 1984; Entergy 2008a).
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1 3.7.3.3 Onsite Ponds

2 In addition to these streams, 19 small ponds exist on the RBS site. Three of the ponds naturally 

3 occurred on site prior to RBS construction, although the rest were man made. Aquatic biota

4 within the ponds are limited and dominated by submerged, emergent, and floating plants.

5 3.7.4 State-Ranked Species

6 Four aquatic State-ranked species occur within West Feliciana Parish (Table 3-12; 

7 LDFW 2017b). Louisiana’s Natural Heritage Program ranked three of the species, central 

8 stoneroller (Campostoma anomalum), bluntface shiner (Cyprinella camura), and rainbow darter

9 Etheostoma caeruleum, as “S2,” which indicates that these species are imperiled in Louisiana 

10 due to rarity (6 to 20 known extant populations) or because these species are very vulnerable to 

11 extirpation. State-ranked species are not afforded protection under Title 56 of the Louisiana 

12 Revised Statutes or relevant rules and regulations adopted by the Louisiana Wildlife and 

13 Fisheries Commission and the Secretary of the Department of Wildlife and Fisheries 

14 (LDFW 2017b). Pallid sturgeon (Scaphirhynchus albus) is a Federally listed endangered 

15 species and is discussed further in Section 3.8.

16 Table 3-12. State-Ranked and Protected Species in West Feliciana Parish

Species Common Name(a)

Designation

State Rank State Status Federal Status

Campostoma anomalum central stoneroller S2

Cyprinella camura bluntface shiner S2

Etheostoma caeruleum rainbow darter S2

Scaphirhynchus albus pallid sturgeon S1 E E

S2= imperiled in Louisiana because of rarity (6 to 20 known extant populations) or because of some factor(s) 

making it very vulnerable to extirpation.

S1= critically imperiled in Louisiana because of extreme rarity (5 or fewer known extant populations) or because of 

some factor(s) making it especially vulnerable to extirpation.

E= Endangered

Source: LDWF 2017b, 2017d

17 Central stoneroller is a relatively widespread freshwater fish that occurs in rivers and streams 

18 with riffles, runs, or pools with gravel or rubble substrates. This species has a large range within 

19 central and eastern North America, including the Great Lakes basin, Mississippi River 

20 watershed, and the Hudson Bay rivershed. Although this species is considered imperiled in 

21 Louisiana, NatureServe (2016) did not identify any major threats to populations within North 

22 America. Central stoneroller is often used as a bait fish and it has been introduced and is 

23 considered invasive in parts of Connecticut, New York, and New Mexico (USGS 2017a). Adult 

24 central stoneroller fish consume a relatively large amount of prey items, including detritus, 

25 filamentous algae, diatoms, and small aquatic insects (Gagnon 2011). 

26 Bluntface shiner is a relatively widespread freshwater fish that occurs in clear streams with 

27 moderate-to-fast currents over sand or gravel substrates. This species has a large range within 

28 central and eastern North America, including the Great Lakes, Mississippi River, and the 

29 Hudson River basins. Although this species is considered imperiled in Louisiana, NatureServe 
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1 (2016) does not identify any major threats to populations within North America. Prey items 

2 include detritus, diatoms, inorganic material, and green and blue-green algae that are often 

3 found on the surfaces of rocks on the river or stream bed (NatureServe 2016).

4 Rainbow darter is a relatively widespread freshwater fish that occurs in creeks, streams, and 

5 small-to-medium rivers with riffles and gravel or rubble substrates. This species has a large 

6 range within central and eastern North America, including the Great Lakes and Mississippi River 

7 basins. Although this species is considered imperiled in Louisiana, NatureServe (2016) does 

8 not identify any major threats to populations within North America. Rainbow darter is 

9 considered invasive in parts of the Hudson River drainage area in New York (USGS 2017d). 

10 Adults and juveniles prey on aquatic insects, especially aquatic insect larvae (USGS 2017d; 

11 NatureServe 2016). 

12 Entergy (2017h; 2008a) was not aware of any known occurrences of State-listed or 

13 State-ranked fish or mussel species at or near the RBS site. The NRC staff reviewed the 

14 Fishnet database, which as described above, is a collaborative effort by natural history 

15 museums and biodiversity institutions to compile fish survey data. The NRC did not identify any 

16 known occurrence of State-listed or State-ranked fish species on or near the RBS site and the 

17 adjacent portion of the Mississippi River (Fishnet 2014). 

18 3.7.5 Non-Native and Nuisance Species

19 Several species of aquatic plants, fish, and invertebrates have been introduced within the Lower 

20 Mississippi River. Many of these species become an ecological concern if they outcompete 

21 native species for space, prey, or other limited resources. Water hyacinth (Eichhornia 

22 crassipes) are invasive aquatic plants that grow rapidly on the surface of the Mississippi River, 

23 especially in backwater areas (USGS 2017c). These plants can outcompete native species by 

24 fundamentally changing water quality parameters and habitat structure as they reduce available 

25 space on the surface of the river and reduce the available oxygen and light levels for native 

26 species within the Mississippi River (Toft et al. 2003; McFarland et al. 2004). These physical 

27 effects can lead to a decline in oxygen and light-sensitive species, as well as 

28 trophic-level cascades where by the decline of a predator may increase the population of its 

29 prey or vice versa. For example, Toft et al. (2003) documented trophic level changes after the 

30 introduction of water hyacinth whereby predators of oxygen and light-sensitive species 

31 decreased and prey of oxygen and light-sensitive species increased. 

32 Common carp, which come from coastal areas of the Caspian and Aral Seas, inhabit the 

33 Mississippi River near RBS (Entergy 2017h; USGS 2017b). Common carp tend to grow quickly 

34 and outcompete native fish species in consuming prey items such as aquatic plants, plankton, 

35 and benthic invertebrates. Common carp also degrade water-quality conditions by increasing 

36 turbidity and uprooting submerged aquatic vegetation during active feeding sessions 

37 (USGS 2017b). 

38 In addition to fish, non-native invertebrate species have been introduced and have established 

39 substantial populations within the Mississippi River. Asian clams (Corbicula manilensis) and 

40 zebra mussels (Dreissena polymorpha) occur near RBS (Entergy 2008a). Asian clams are 

41 native to western Asia, parts of Africa, and the Mediterranean. Entergy (2008a; 2017h) has 

42 documented a limited number of Asian clams near RBS. Zebra mussels are native to the Black 

43 and Caspian seas and were introduced into the Great Lakes within the ballast water of 

44 freighters around 1988. Since that time, zebra mussels have spread throughout the Great 

45 Lakes and Mississippi River. Zebra mussels attach to hard surfaces in order to grow. When 
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1 attached to underwater piping or other structures related to the intake system, these organisms 

2 can cause biofouling. Due to the regular occurrence of zebra mussels near RBS, Entergy 

3 (2008a; 2017h) has implemented a zebra mussel monitoring and control program that includes 

4 inspecting and/or sampling adult populations near the intake, and cleaning the intake screens 

5 and adjacent piping when necessary.

6 3.8 Special Status Species and Habitats

7 This section addresses species and habitats that are federally protected under the Endangered 

8 Species Act of 1973 (16 U.S.C. § 1531 et seq.) (ESA) and the Magnuson–Stevens Fishery 

9 Conservation and Management Reauthorization Act, as amended (16 U.S.C. §§ 1801–1884) 

10 (MSA). The NRC has direct responsibilities under the Endangered Species Act and 

11 Magnuson–Stevens prior to taking a Federal action such as the proposed RBS license renewal. 

12 The terrestrial and aquatic resource sections of this report (Sections 3.6 and 3.7, respectively) 

13 discuss species and habitats protected by other Federal acts and the State of Louisiana under 

14 which the NRC does not have direct responsibilities.

15 3.8.1 Species and Habitats Protected Under the Endangered Species Act

16 The U.S. Fish and Wildlife Service and the National Marine Fisheries Service jointly administer 

17 the Endangered Species Act. The U.S. Fish and Wildlife Service manages the protection of, 

18 and recovery effort for, listed terrestrial and freshwater species, and the National Marine 

19 Fisheries Service manages the protection of and recovery effort for listed marine and 

20 anadromous species. This section describes the action area and considers separately those 

21 species that could occur in the action area under the jurisdictions of each Service.

22 3.8.1.1 Action Area

23 The implementing regulations for Section 7(a)(2) of the Endangered Species Act define 

24 “action area” as all areas affected directly or indirectly by the Federal action and not merely the 

25 immediate area involved in the action (50 CFR 402.02, “Definitions”). The action area 

26 effectively bounds the analysis of federally listed species and critical habitats because only 

27 species and habitats that occur within the action area may be affected by the Federal action.

28 For the purposes of the Endangered Species Act analysis in this SEIS, the NRC staff considers 

29 the action area to be the 3,342-ac (1,353-ha) RBS site and the Mississippi River from the RBS 

30 intake at Mississippi River Mile (RM) 262 downstream to the region where Outfall 001 

31 discharges to the Mississippi River at RM 262.4. Outfall 001 continuously discharges cooling 

32 tower blowdown at an average rate of 3.88 million gallons per day (MGD) (0.17 cubic meters 

per second (m3 33 /s)) (LDEQ 2017f). The action area also encompasses the relatively small area 

34 of the thermal plume. Entergy (2008a) has estimated that the Mississippi River would 

35 experience temperatures elevated above 90 °F (32 °C) over a surface area of approximately 

36 54 ft by 5 ft (16.5 m by 1.5 m) during summer months at worst-case scenario operational 

37 conditions from the combined operation of RBS and the previously proposed River Bend 

38 Station, Unit 3 had it been built. Sections 3.2 and 3.6 describe the RBS site land use and 

39 terrestrial resources, and Section 3.7 describes aquatic resources. Section 4.7.1.3 describes 

40 the RBS thermal plume and associated Louisiana Pollutant Discharge Elimination System 

41 (LPDES) permit limitations on thermal effluent in more detail. Section 3.1.3 describes the RBS 

42 intake and discharge, and Section 3.5.1 describes the characteristics of the Mississippi River 

43 within the vicinity of RBS.
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1 The NRC staff recognizes that while the action area is stationary, federally listed species can 

2 move in and out of the action area. For instance, a migratory fish species could occur in the 

3 action area seasonally as it travels up or down the Mississippi River past RBS. Thus, in its 

4 analysis, the NRC staff considers not only those species known to occur directly within the 

5 action area, but those species that may passively or actively move into the action area. The 

6 staff then considers whether the life history of each species makes the species likely to move 

7 into the action area where it could be affected by the proposed RBS license renewal.

8 The following sections first discuss species under U.S. Fish and Wildlife Service’s jurisdiction 

9 followed by those under the National Marine Fisheries Service’s jurisdiction.

10 3.8.1.2 Species and Habitats Under U.S. Fish and Wildlife Service’s Jurisdiction

11 The NRC staff used U.S. Fish and Wildlife Service’s Environmental Conservation Online 

12 System (ECOS) Information for Planning and Conservation (IPaC) tool to determine species 

13 that may be present in the RBS action area. The ECOS IPaC tool identified one federally listed 

14 species under U.S. Fish and Wildlife Service’s (2017a) jurisdiction as potentially occurring in the 

15 action area: the pallid sturgeon (Scaphirhynchus albus). No proposed species, candidate 

16 species, or proposed or designated critical habitat occurs within the action area (FWS 2017a).

17 Pallid Sturgeon (Scaphirhynchus albus)

18 On September 6, 1990, U.S. Fish and Wildlife Service listed the pallid sturgeon as endangered 

19 wherever found (55 FR 36641). The U.S. Fish and Wildlife Service has not designated critical 

20 habitat for the species. Overfishing, curtailment of range, habitat destruction and modification, 

21 altered flow regimes, water quality issues, and lack of recruitment are the primary factors that 

22 have contributed to this species’ decline (55 FR 36641; FWS 2014c). Unless otherwise noted, 

23 information about this species is derived from the U.S. Fish and Wildlife Service’s (2014c) 

24 revised recovery plan.

25 The pallid sturgeon is a benthic, riverine fish with a flattened shovel-shaped snout and a long, 

26 slender, and armored peduncle (the tapered portion of the body that terminates at the tail). 

27 Adults can reach lengths of 1.8 m (6 ft). The species is similar in appearance to the more 

28 common shovelnose sturgeon (Scaphirhynchus platorynchus), which is federally listed as 

29 threatened due its similarity of appearance to the pallid sturgeon.

30 The pallid sturgeon is native to the Mississippi River Basin, including the Mississippi River, 

31 Missouri River, and their major tributaries (i.e., the Platte, Yellowstone, and Atchafalaya Rivers). 

32 Historically, the range of the species encompassed about 3,515 continuous river miles in these 

33 rivers and its tributaries within Montana, North Dakota, South Dakota, Nebraska, Iowa, Kansas, 

34 Missouri, Kentucky, Tennessee, Arkansas, Louisiana, and Mississippi. The present known 

35 range spans the length of the historical range but consists of disconnected reaches of these 

36 rivers as a result of damming and other obstructions to fish passage.

37 Pallid sturgeon can reach ages of 60 years or more. Females reach maturity at 15 to 20 years, 

38 and males reach maturity at approximately 5 years. Females spawn at intervals of every 

39 2 to 3 years. Mature females in the upper reaches of the Missouri River produce 150,000 to 

40 170,000 eggs, while females in the southern extent of the range typically produce significantly 

41 fewer eggs (43,000 to 58,000 eggs). Females spawn adjacent to or over coarse substrate such 

42 as boulder, gravel, or cobble or in bedrock within deeper water with relatively fast, converging 
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1 flows. Incubation is approximately 5 to 7 days, and newly hatched larvae are pelagic and drift 

2 downstream in currents for 11 to 13 days.

3 Habitat requirements for pallid sturgeon larvae and young-of-the-year are unknown due to low 

4 populations of spawning adults and poor recruitment across the species’ range. However, 

5 requirements may be similar to other Scaphirhynchus species. Scaphirhynchus

6 young-of-the-year in the Middle Mississippi River are often found in channel border and 

7 island-side channel habitats with low velocities (1 m/s or 0.33 feet per second), moderate 

8 depths (2 to 5 m or 6.6 to 16.4 ft), and sand substrate.

9 Adults prefer bottom habitats of large river systems. Juveniles and adults are almost always 

10 observed in flowing portions of main channels in the upper reaches of the specie’s range, in 

11 channel border habitats, and in inundated floodplain habitats with flowing water in the more 

12 channelized Lower Mississippi River. Pallid sturgeon are most often associated with sandy and 

13 fine bottom substrates, and individuals exhibit a selection propensity for sand over mud, silt, or 

14 vegetation. Across their range, individuals have been documented in waters of varying depths 

15 and velocities that range from 0.58 m to greater than 20 m (1.9 to greater than 65 ft) and 

16 velocities of less than 1.5 m/s (less than 4.9 feet per second (fps)) and an average of 0.58 m/s 

17 to 0.88 m/s (1.9 fps to 2.9 fps). Pallid sturgeon have been collected from a variety of turbidity 

18 conditions, including highly altered systems with low turbidity and relatively natural systems with 

19 seasonally high turbidity.

20 In their first year of life (Age-0), pallid sturgeon eat zooplankton, larvae of mayflies 

21 (Ephemeroptera) and midge (Chironomidae), and small invertebrates. Juveniles and adults eat 

22 fish and aquatic insect larvae. As the pallid sturgeon increases in size, its diet trends toward 

23 piscivory. The majority of the pallid sturgeon’s adult diet consists of fish from the Cyprinidae, 

24 Sciaenidae, and Clupeidae families, although diet varies by season and location 

25 (Hoover et al. 2007). Pallid sturgeon in the Lower Mississippi River belong to the Coastal Plain 

26 Management Unit (CPMU), which includes the Lower Mississippi River from the confluence of 

27 the Ohio River (in Illinois) to the Gulf of Mexico in Louisiana. Prior to 1990, when the U.S. Fish 

28 and Wildlife Service listed it under the Endangered Species Act, pallid sturgeon collections on 

29 the Lower Mississippi River were rare, so the historical baseline population size is 

30 undocumented (FWS 2013). From 1990 to 2013, over 1,100 pallid sturgeon have been 

31 captured in the Coastal Plain Management Unit, of which 500 were collected from the Lower 

32 Mississippi River (FWS 2013). Although there remains no estimate of the Lower Mississippi 

33 River population size, current data suggest a substantial population when compared to fishing 

34 effort, fish species composition, and rarity of marked recaptures (FWS 2013). The International 

35 Union for Conservation of Nature and Natural Resources estimates the total population of pallid 

36 sturgeon throughout its entire range to be as few as 6,000 to as many as 21,000 individuals 

37 (Krentz 2004).

38 Pallid sturgeon are not currently known to spawn in the Mississippi River main channel 

39 (FWS and NMFS 2009) and, therefore, eggs and larvae would not occur in the RBS action area. 

40 Researchers have captured larval pallid sturgeon at several locations well upstream of RBS 

41 between the confluence of the Ohio River (Ohio River RM 0) and Vicksburg, MS 

42 (Mississippi River RM 437) (FWS 2013). However, the NRC staff did not identify any studies or 

43 reports that indicate the occurrence of pallid sturgeon larvae as far downstream as the RBS 

44 action area.

45 As reported in NRC’s (2017a) biological evaluation for the proposed license renewal of 

46 Waterford Steam Electric Station, Unit 3, juvenile pallid sturgeon were collected in the 1970s 
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1 during impingement and entrainment studies associated with energy-generating facilities 

2 downstream of RBS. Between January 1976 and January 1977, one juvenile was impinged 

3 over the course of a Clean Water Act (CWA) Sections 316(a) and 316(b) impingement and 

4 entrainment study associated with Willow Glen Power Station, which lies approximately 61 RM 

5 downstream of RBS at Mississippi River RM 201 (ENSR 2007). Adult pallid sturgeon have 

6 been captured in the Mississippi River throughout Louisiana according to capture and telemetry 

7 records by the U.S. Army Engineer Research and Development Center, the U.S. Army Corps of 

8 Engineers, and the U.S. Fish and Wildlife Service (2013). The southernmost collection of pallid 

9 sturgeon has been at Mississippi River RM 95.5 (FWS 2013).

10 In order to gather additional data regarding the occurrence of pallid sturgeon in the RBS action 

11 area, the NRC staff reviewed survey data recorded within FishNet, a collaborative online 

12 database that includes data from natural history museums and biodiversity institutions, as 

13 described in Section 3.7.2 of this report. The database includes 78 recorded collections of pallid 

14 sturgeon in Louisiana from 1973, 1991, 1998, 2001, 2002, 2004, and 2005 (MMNS 2017). 

15 However, all collections were within Concordia, Tensas, and Madison Parishes, all of which are 

16 well upstream (roughly 150 RM or more) of RBS.

17 Based on the limited data available on pallid sturgeon occurrences in the Lower Mississippi 

18 River discussed above, the NRC conservatively assumes that pallid sturgeon juveniles and 

19 adults may occur in the RBS action area, although such occurrences are likely occasional to 

20 rare. Larval pallid sturgeon and eggs, however, are unlikely to occur in the RBS action area 

21 based on available capture and spawning records, all of which are well upstream of RBS.

22 3.8.1.3 Species and Habitats under National Marine Fisheries Service’s Jurisdiction

23 The NRC staff did not identify any federally listed, proposed, or candidate species or critical 

24 habitats (proposed or designated) under National Marine Fisheries Service’s jurisdiction with the 

25 potential to occur in the action area.

26 3.8.2 Species and Habitats Protected under the Magnuson–Stevens Act

27 The National Marine Fisheries Service has not designated essential fish habitat within the 

28 Mississippi River. Therefore, this section does not contain a discussion of any species or 

29 habitats protected under the Magnuson–Stevens Act.

30 3.9 Historic and Cultural Resources

31 This section describes the cultural background and the historic and cultural resources found at 

32 RBS and in the surrounding area. The National Historic Preservation Act of 1966, as amended 

33 (NHPA) (54 U.S.C. 300101 et seq.), requires Federal agencies to consider the effects of their 

34 undertakings on historic properties. Renewing the operating license of a nuclear power plant is 

35 an undertaking that could potentially affect historic properties. Historic properties are defined as 

36 resources included on, or eligible for inclusion on, the National Register of Historic Places 

37 (NRHP). The criteria for eligibility are listed in the Title 36, “Parks, Forest, and Public Property,” 

38 of the Code of Federal Regulations (36 CFR) 60.4, “Criteria for Evaluation,” and include 

39 (1) association with significant events in history, (2) association with the lives of persons

40 significant in the past, (3) embodiment of distinctive characteristics of type, period, or 

41 construction, and (4) sites or places that have yielded, or are likely to yield, important 

42 information.
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1 In accordance with 36 CFR 800.81, “Use of the NEPA Process for Section 106 Purposes,” the 

2 NRC complies with the obligations required under National Historic Preservation Act 

3 Section 106 through its process under the National Environmental Policy Act of 1969, as 

4 amended (NEPA) (42 U.S.C. 4321 et seq.). In the context of National Historic Preservation Act, 

5 the area of potential effect for a license renewal action is the RBS site and its immediate 

6 environs. RBS is located within the 3,300-acre (1,350-ha) Entergy Louisiana, LLC property. 

7 This property constitutes the area of potential effect and consists primarily of wetlands, 

8 agriculture, and developed areas. These land areas may be impacted by maintenance and 

9 operations activities during the license renewal term. The area of potential effect may extend 

10 beyond the immediate RBS environs if Entergy’s maintenance and operations activities affect 

11 offsite historic properties. This is irrespective of land ownership or control.

12 In accordance with the provisions of the National Historic Preservation Act, the NRC is required 

13 to make a reasonable effort to identify historic properties within the area of potential effect. If 

14 the NRC finds that either there are no historic properties within the area of potential effect or the 

15 undertaking (license renewal) would have no effect on historic properties, the NRC provides 

16 documentation of this finding to the State historic preservation officer. In addition, the NRC 

17 notifies all consulting parties, including Indian tribes, and makes this finding public (through the 

18 NEPA process) prior to issuing the renewed operating license. Similarly, if historic properties 

19 are present and could be affected by the undertaking, the NRC is required to assess and 

20 resolve any adverse effects in consultation with the State historic preservation officer and any 

21 Indian Tribe that attaches religious and cultural significance to identified historic properties. The 

22 Louisiana Office of Cultural Development is responsible for administering Federal and 

23 State-mandated historic preservation programs to identify, evaluate, register, and protect 

24 Louisiana’s archaeological and historical resources. Within this office, the Division of Historic 

25 Preservation and the Division of Archaeology jointly comprise the State historic preservation 

26 officer (LOCD 2011, 2017).

27 3.9.1 Cultural Background

28 This section contains a brief description of the history of human occupation of the RBS area 

29 using the following chronologic cultural sequence (Entergy 2017h): 

30 • Paleo-Indian Period (8,000+ years before present)

31 • Archaic Period (8,000 years before present to 3,500 years before present)

32 • Woodland Period (3,500 years before present to AD 1,200)

33 • Mississippi Period (AD 1200 to 1450)

34 • Protohistoric and European Contact (AD 1450 to 1700)

35 • Historic Era (AD 1700 to present)

36 The Paleo-Indian Period is generally characterized by highly mobile bands of hunters and 

37 gatherers hunting small and large game animals (e.g., giant armadillo, mammoth, and dire wolf) 

38 and gathering plants. Paleo-Indian sites are not common in Louisiana because these nomadic 

39 people left very few artifacts at any one location. Paleo-Indian groups who may have been 

40 living near RBS would have exploited the rich riverine resources. However, because over time 

41 the sea level has risen and the course of the Mississippi River has shifted, many Paleo-Indian 

42 coastal remains are now either submerged, washed away, or deeply buried under silt. A typical 

43 Paleo-Indian archaeological site might consist of an isolated Clovis stone point (a distinctive 

44 fluted spearhead) or knife characteristic of the period. A few such points have been found in the 

45 parishes north of Lake Pontchartrain (Neuman and Hawkins 2013; Entergy 2017h).
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1 The Archaic Period represents a continuation of the hunter and gatherer subsistence economy 

2 practiced during the Paleo-Indian Period. In contrast to their predecessors, these groups 

3 generally remained longer in each camp and limited their roaming to several favored campsites 

4 within a smaller geographical range. Archaeological sites in southeast Louisiana from this 

5 period tend to be located predominantly along coastal and inland waters, and they are 

6 characterized by well-developed shell middens (refuse heaps), large numbers of milling 

7 implements and fishing tools, and evidence of earthen mounds (Neuman and Hawkins 2013; 

8 Entergy 2017h).

9 The Woodland Period experienced a transition from earlier hunting and gathering cultures to 

10 one characterized by village settlements, food production, pottery manufacturing, and shell and 

11 earthen mound building. The Woodland Period in Louisiana lasted from approximately 

12 3,500 years before present to AD 1200, and included several distinct occupations, including the 

13 Poverty Point, Tchefuncte, Marksville, Troyville, and Coles Creek cultures. During the 

14 Woodland Period, Louisiana Indians likely traded with members of the highly influential 

15 Hopewell Culture that was centered in the Ohio and Illinois river valleys, as evidenced by their 

16 use of similarly-fashioned burial mounds, pottery, pipes, and ornamental objects. 

17 Archaeological sites from this period indicate an increased use of habitation areas for longer 

18 periods of time than those that predate this period, but they are not considered to have been 

19 permanently occupied. (Neuman and Hawkins 2013, Entergy 2017h) 

20 The Mississippi Period is characterized by major changes in settlement, subsistence patterns, 

21 and social structure. Large, highly centralized chiefdoms with permanent settlement sites 

22 supported by numerous satellite villages emerged during this period. The platform mound, a 

23 new ceremonial earthen mound, appeared in association with these permanent settlements. 

24 Platform mounds, burial mounds, and fortified defensive structures were often constructed in 

25 clusters in settlements of this period. Mississippian Period subsistence relied heavily on maize 

26 agriculture, as well as on hunting and gathering. Long-distance trading increased and craft 

27 specialists produced highly specialized lithic (stone or chipped stone) and ceramic artifacts, 

28 beadwork, and shell pendants. Mississippian Culture spread rapidly through the major river 

29 valleys of the Southeast. In the Lower Mississippi Valley of Louisiana, the Mississippian culture 

30 is believed to have encountered and merged with the resident Plaquemine Culture, thought to 

31 be descendants of the earlier Troyville/Coles Creek occupations. Over time, the Plaquemine 

32 adopted distinctive Mississippian customs and techniques for making pottery and other 

33 ceremonial objects. Louisiana peoples that may have descended from the Mississippian 

34 Culture include those who speak the Tunican, Chitimachan, and Muskogean languages, 

35 whereas those that may have descended from the Plaquemine Culture include the Taensa and 

36 Natchez (Neuman and Hawkins 2013; Entergy 2017h).

37 In 1682, French explorers—led by Robert de La Salle—travelling downriver on the Mississippi 

38 River were the first Europeans to lay claim to southeast Louisiana. These European explorers 

39 encountered several native villages established along the Mississippi River, including the 

40 Bayagoula/Mugulasha, Ouacha, Chaouacha, Chitimacha, Ofogula, Okelousa, Tunica and 

41 Houma. Diseases carried by the European explorers spread rapidly through these native 

42 groups and killed many of their members, resulting in significant changes to their way of life. 

43 Attempts at colonization of the area by the French were unsuccessful until 1699. (Neuman and 

44 Hawkins 2013; Entergy 2016a, 2017h) 

45 The Historic Era in Louisiana can be characterized by three major settlement periods, each 

46 under different sovereign rule. During the French Colonial Period (AD 1700 to 1763), most 

47 settlers in the French colony of Louisiana were of French or French-Canadian descent, although 
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1 large numbers of Germans and Swiss also settled along the Mississippi River. In 1762, France 

2 secretly ceded Louisiana to Spain as part of the Treaty of Fontainebleau, leading to the Spanish 

3 Colonial Period (AD 1763 to 1803). Spain saw the colony as a means to limit British 

4 expansionism in the area, and it was during this time that vegetable and indigo production came 

5 to prominence in the region, to eventually be replaced by sugarcane and cotton production. 

6 Control over Louisiana was transferred back to France by way of treaty in 1800, who in turn sold 

7 the territory to the United States in 1803 as part of the Louisiana Purchase. Early in the ensuing

8 American Period (AD 1803 to present), plantations harvesting sugarcane, rice, and cypress 

9 timber dominated the economy and culture of the area. Following the Civil War and the 

10 abolition of slavery, sugar production fell dramatically as plantations struggled to maintain 

11 sufficient labor supplies. Chinese, Portuguese, Italian, and German immigrant labor was used 

12 to augment the African-American workers who chose to remain. 

13 During the 20th century, agricultural cultivation and timbering enterprises began to give way to 

14 the establishment of large petrochemical industrial complexes and marine terminals along both 

15 banks of the Mississippi River (Entergy 2016a, 2017h). 

16 3.9.2 Historic and Cultural Resources at River Bend Station

17 Historic and cultural resources in the vicinity of RBS include prehistoric era and historic era 

18 archaeological sites, historic districts, and buildings, as well as any site, structure, or object that 

19 may be considered eligible for listing on the National Register of Historic Places. Historic and 

20 cultural resources also include traditional cultural properties that are important to a living 

21 community of people for maintaining their culture. “Historic property” is the legal term for a 

22 historic or cultural resource that is included on, or eligible for inclusion on, the National Register 

23 of Historic Places. 

24 Construction of the existing RBS facility likely disturbed any historic and archaeological 

25 resources that may have been located within its footprint. However, much of the surrounding 

26 area remains largely undisturbed. Although no comprehensive Phase I cultural resources 

27 survey has been completed for the entire 3,300-acre Entergy Louisiana, LLC property, several 

28 cultural resources studies of the RBS site were conducted between 1971 and 2007 

29 (Entergy 2017h). In addition, Entergy conducted a literature review of archaeological sites in 

30 the vicinity of RBS in 2015. The results of these studies indicate that there are more than 

31 100 known historic and cultural resources within a 6-mi (10-km) radius of RBS. Twenty-five of 

32 these resources are either National Register of Historic Places-listed, eligible for listing on the 

33 register, or have the equivalent eligibility or potential eligibility under national heritage or legacy 

34 commission designations, and are therefore considered historic properties within the context of 

35 National Historic Preservation Act (DOI 2017; Entergy 2017h). These include 14 aboveground 

36 properties, the nearest of which is Star Hill Plantation located approximately 1 mi (1.6 km) 

37 northeast of RBS (Entergy 2017h).

38 3.10 Socioeconomics

39 This section describes current socioeconomic factors that have the potential to be directly or 

40 indirectly affected by changes in operations at RBS. RBS and the communities that support it 

41 can be described as a dynamic socioeconomic system. The communities supply the people, 

42 goods, and services required to operate the nuclear power plant. Power plant operations, in 

43 turn, supply wages and benefits for people and dollar expenditures for goods and services. The 
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1 measure of a community’s ability to support RBS operations depends on its ability to respond to 

2 changing environmental, social, economic, and demographic conditions.

3 3.10.1 Power Plant Employment

4 The socioeconomic region of influence (ROI) is defined by the areas where RBS workers and 

5 their families reside, spend their income, and use their benefits, thus affecting the economic 

6 conditions of the region. Entergy employs a permanent workforce of approximately 680 workers 

7 (Entergy 2017h). Approximately 90 percent of RBS workers reside in five Louisiana parishes 

8 and one county in Mississippi (see Table 3-13). The remaining workers are spread among 

9 25 parishes and counties in Louisiana and 9 other States, with numbers ranging from 

10 1 to 17 workers per parish or county (Entergy 2017h). Table 3-13 presents geographic 

11 distribution of the Entergy workforce at RBS across five parishes and one county. Because 

12 approximately 69 percent of RBS workers reside in East Baton Rouge and West Feliciana 

13 parishes, the most significant socioeconomic effects of plant operations are likely to occur in 

14 those two parishes. The focus of the impact analysis, therefore, is on the socioeconomic 

15 impacts of continued RBS operations on East Baton Rouge and West Feliciana parishes.

16 Table 3-13. Residence of Entergy Employees by Parish or County

Parish or County Number of Employees Percentage of Total

Total 680 100.00

Louisiana

East Baton Rouge 339 49.85

East Feliciana 38 5.59

Livingston 47 6.91

Pointe Coupee 20 2.94

West Feliciana 127 18.68

Mississippi

Wilkinson 42 6.18

Other parishes and counties 67 9.85

Source: Entergy 2017h

17 Entergy purchases goods and services to facilitate RBS operations. Although Entergy procures 

18 specialized equipment and services from a wider region, it acquires some proportion of the 

19 goods and services used in plant operations from within the socioeconomic region of influence. 

20 These transactions fuel a portion of the local economy by sustaining jobs and generating 

21 income from the purchases of goods and services.

22 Refueling outages occur on a 2-year cycle and historically have lasted approximately 

23 25 to 30 days. During refueling outages, site employment typically increases by an additional 

24 700 to 900 temporary workers (Entergy 2017h). Outage workers come from all regions of the 

25 country; however, for the purpose of analysis, the majority of outage workers are expected to 

26 come from Louisiana.
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1 3.10.2 Regional Economic Characteristics

2 This section presents information on employment and income in the RBS socioeconomic region 

3 of influence.

4 3.10.2.1 Regional Employment and Income

5 From 2010 to 2016, the labor force in the RBS region of influence increased 5.2 percent to just 

6 over 239,000 persons. In addition, the number of employed persons increased by 7.9 percent, 

7 to approximately 227,000 persons. Consequently, from 2010–2016, the number of unemployed 

8 people in the region of influence decreased by nearly 29 percent to just over 12,000 persons, or 

9 about 5.0 percent of the total 2016 workforce—down from 7.6 percent in 2010 (BLS 2017).

10 According to the U.S. Census Bureau’s (USCB’s) 2011–2015 American Community Survey 

11 5-Year Estimates, the educational, health, and social services industry represented the largest

12 employment sector in the socioeconomic region of influence (approximately 25 percent) 

13 followed by retail trade (approximately 12 percent). These are followed by the arts, 

14 entertainment, recreation, accommodation, and food services industry and the professional, 

15 scientific, management, administrative, and waste management services industry at 

16 approximately 11 percent each. A list of employment by industry in each parish of the region of 

17 influence is provided in Table 3-14.

18 Table 3-14. Employment by Industry in the River Bend Station Region of Influence 

19 (2011–2015, 5-Year Estimates)

Industry

East Baton 

Rouge 

Parish

West 

Feliciana 

Parish Total Percent

Agriculture, forestry, fishing, hunting, and mining 2,486 162 2,648 1.2

Construction 16,024 570 16,594 7.5

Manufacturing 15,812 448 16,260 7.4

Wholesale Trade 4,640 22 4,662 2.1

Retail Trade 25,758 381 26,139 11.9

Transportation, warehousing, and utilities 9,028 342 9,370 4.2

Information 4,072 80 4,152 1.9

Finance, insurance, 

real estate, rental, and leasing 12,332 170 12,502 5.7

Professional, scientific, management, 

administrative, and waste management services 22,898 351 23,249 10.5

Educational, health, and social services 54,772 1,198 55,970 25.4

Arts, entertainment, recreation, accommodation, 

and food services 23,154 283 23,437 10.6

Other services (except public administration) 11,535 174 11,709 5.3

Public administration 13,002 840 13,842 6.3

Total Employed Civilian Workers 215,513 5,021 220,534 -

Source: USCB 2017c
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1 Estimated income information for the RBS socioeconomic region of influence (USCB 2011–

2 2015 American Community Survey 5-Year Estimates) is presented in Table 3-15.

3 Table 3-15. Estimated Income Information for the River Bend Station Socioeconomic 

4 Region of Influence (2011–2015, 5-Year Estimates)

East Baton 

Rouge Parish

West Feliciana 

Parish Louisiana

Median household income (dollars)(a) 49,285 56,685 45,047

Per capita income (dollars)(a) 27,944 22,122 24,981

Families living below the poverty level (percent) 13.3 12.4 15.2

People living below the poverty level (percent) 19.6 16.0 19.8

(a) In 2015 inflation-adjusted dollars

Source: USCB 2017c

5 3.10.2.2 Unemployment

6 According to the USCB’s 2011–2015 American Community Survey 5-Year Estimates, the 

7 unemployment rates in East Baton Rouge Parish and West Feliciana Parish were 

8 7.6 and 8.5 percent, respectively. Comparatively, the unemployment rate in the State of 

9 Louisiana during this same time period was 8.1 percent (USCB 2017c).

10 3.10.3 Demographic Characteristics

11 According to the 2010 Census, an estimated 126,900 people lived within 20 mi (32 km) of RBS, 

12 which equates to a population density of 101 persons per square mile (Entergy 2017h). This 

13 translates to a Category 3 population density using the license renewal GEIS (NRC 1996) 

14 measure of sparseness which is defined as “60 to 120 persons per square mile within 20 miles.” 

15 An estimated 953,086 people live within 50 miles (80 kilometers) of RBS with a population 

16 density of 121 persons per square mile (Entergy 2017h). With two cities within a 50-mile radius 

17 having populations greater than 100,000 persons, this translates to a Category 3 density, using 

18 the license renewal GEIS (NRC 1996) measure of proximity (one or more cities with 100,000 

19 persons within 50 miles). Therefore, RBS is located in a “medium” population area based on 

20 the license renewal GEIS sparseness and proximity matrix.

21 Table 3-16 shows population projections and percent growth from 1980 to 2060 in the two22 parish RBS region of influence. Over the last several decades, East Baton Rouge Parish has 

23 experienced an increasing population yet declining growth rate. In contrast, West Feliciana 

24 Parish has experienced widely fluctuating growth rates. Based on State of Louisiana and 

25 estimated forecasts, the population in East Baton Rouge Parish is projected to decrease at a 

26 moderate rate while the population of West Feliciana Parish is projected to decrease at a high 

27 rate. These projections reflect a trend of population decline that began in the aftermath of 

28 Hurricane Katrina in late 2005.
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1 Table 3-16. Population and Percent Growth in River Bend Station Socioeconomic Region 

2 of Interest Parishes 1980–2010, 2015 (Estimated), and 2020–2060 (Projected)

Year

East Baton Rouge Parish West Feliciana Parish

Population

Percent 

Change Population

Percent 

Change

Recorded 

1980 366,191 – 12,186 –

1990 380,105 3.8 12,915 6.0

2000 412,852 8.6 15,111 17.0

2010 440,171 6.6 15,625 3.4

Estimated 2015 444,690 1.0 15,415 -1.3

Projected 

2020 426,380 -3.1 15,120 -3.2

2030 421,500 -1.1 14,260 -5.7

2040 416,620 -1.2 13,400 -6.0

2050 411,740 -1.2 12,540 -6.4

2060 406,860 -1.2 11,680 -6.9

Sources: Decennial population data for 1970–2010 and estimated 2015 (USCB 2017a); projections for 

2020–2030 by State of Louisiana, Division of Administration (No Date); 2040–2060 calculated.

3 The 2010 Census demographic profile of the two-parish ROI population is presented in 

4 Table 3-17. According to the 2010 Census, minorities (race and ethnicity combined) comprised 

5 approximately 53 percent of the total two-parish population. The largest minority populations in 

6 the region of influence were Black or African American (approximately 45 percent) followed by 

7 Hispanic, Latino, or Spanish origin of any race (approximately 4 percent).

8 Table 3-17. Demographic Profile of the Population in the River Bend Station Region of 

9 Influence in 2010

East Baton 

Rouge Parish

West Feliciana 

Parish

Region of 

Influence

Total Population 440,171 15,622 455,796

Race (Percent of Total Population, Not Hispanic or Latino)

White 47.0 51.2 47.1

Black or African American 45.1 46.3 45.2

American Indian and Alaska Native 0.2 0.1 0.2

Asian 2.8 0.2 2.7

Native Hawaiian and Other Pacific Islander 0.0 0.0 0.0

Some other race 0.1 0.0 0.1

Two or more races 1.1 0.5 1.1

Hispanic, Latino, or Spanish Ethnicity of Any Race

Hispanic or Latino 16,274 251 16,525

Percent of total population 3.7 1.6 3.6

Minority Population (Including Hispanic or Latino Ethnicity)

Total minority population 233,507 7,623 241,130
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East Baton 

Rouge Parish

West Feliciana 

Parish

Region of 

Influence

Percent minority 53.0 48.8 52.9

Source: USCB 2017a

1 According to the Census Bureau’s 2011–2015 American Community Survey 5-Year Estimates, 

2 minority populations in the region of influence have increased by approximately 7,000 persons 

3 since 2010 and now comprise approximately 54 percent of the population (see Table 3-18). 

4 The largest increase occurred in the Black or African American population (which grew by 

5 nearly 3,000 persons since 2010, an increase of approximately 1.4 percent). The next largest 

6 increase in minority population was in the Asian population, which grew by approximately 1,900 

7 persons, or approximately 16 percent, since 2010.

8 Table 3-18. Demographic Profile of the Population in the River Bend Station Region of 

9 Influence, 2011–2015, 5-Year Estimates

East Baton 

Rouge Parish

West Feliciana 

Parish ROI

Total Population 444,690 15,415 460,105

Race (percent of total population, Not-Hispanic or Latino)

White 45.9 51.7 46.1

Black or African American 45.3 45.7 45.4

American Indian and Alaska Native 0.1 0.3 0.1

Asian 3.2 0.0 3.8

Native Hawaiian and Other Pacific 

Islander

0.0 0.0 0.0

Some other race 0.2 0.0 0.2

Two or more races 1.4 0.7 1.4

Hispanic, Latino, or Spanish Ethnicity of Any Race

Hispanic or Latino 17,142 232 17,374

Percent of total population 3.9 1.5 3.8

Minority Population (Including Hispanic or Latino Ethnicity)

Total minority population 240,645 7,443 248,088

Percent minority 54.1 48.3 53.9

Source: USCB 2017e

10 3.10.3.1 Transient Population

11 Within 50 mi (80 km) of RBS, colleges, tourism and recreational opportunities attract daily and 

12 seasonal visitors who create a demand for temporary housing and services. In 2017, 

13 approximately 39,000 students attended colleges and universities within 50 mi (80 km) of RBS 

14 (NCES 2018a).

15 Based on the Census Bureau’s 2011–2015 American Community Survey 5-Year Estimates 

16 (USCB 2017b), approximately 21,100 seasonal housing units are located within 50 mi (80 km) 
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1 of RBS. Of those, 3,850 housing units are located in the socioeconomic region of influence. 

2 Table 3-19 presents information about seasonal housing for the parishes located all or partly 

3 within 50 mi (80 km) of RBS.

4 Table 3-19. 2011–2015 5-Year Estimated Seasonal Housing in Parishes or Counties 

5 Located Within 50 mi (80 km) of River Bend Station 

Parish or County Total Housing Units

Vacant Housing Units: for 

Seasonal, Recreation, or 

Occasional Use Percent

Total 667,196 21,115 3.2

Louisiana

Ascension 43,255 468 1.1

Assumption 10,470 634 6.1

Avoyelles 18,157 1,054 5.8

Catahoula 4,901 674 13.8

Concordia 9,418 756 8.0

East Baton Rouge 190,343 3,197 1.7

East Feliciana 8,138 404 5.0

Iberia 30,002 345 1.1

Iberville 12,914 461 3.6

Lafayette 96,468 947 1.0

Livingston 52,888 1,146 2.2

Pointe Coupee 11,257 1,244 11.1

St. Helena 5,163 431 8.3

St. Landry 36,047 1,611 4.5

St. Martin 22,390 1,109 5.0

Tangipahoa 51,938 1,096 2.1

West Baton Rouge 9,873 30 0.3

West Feliciana 5,214 653 12.5

Mississippi

Adams 14,622 951 6.5

Amite 6,636 854 12.9

Franklin 4,157 452 10.9

Pike 17,898 1,194 6.7

Wilkinson 5,047 1,404 27.8

Parishes within 50 mi (80 km) of RBS with at least one block group located within the 50-mi (80-km) radius.

Note: ROI parishes are in bold italics.

Source: USCB 2017b

6 3.10.3.2 Migrant Farm Workers

7 Migrant farm workers are individuals whose employment requires travel to harvest agricultural 

8 crops. These workers may or may not have a permanent residence. Some migrant workers 
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1 follow the harvesting of crops, particularly fruit, throughout rural areas of the United States. 

2 Others may be permanent residents living near RBS who travel from farm to farm harvesting 

3 crops.

4 Migrant workers may be members of minority or low-income populations. Because they travel 

5 and can spend a significant amount of time in an area without being actual residents, migrant 

6 workers may be unavailable for counting by census takers. If uncounted, these minority and 

7 low-income workers would be underrepresented in the decennial Census population counts.

8 The U.S. Department of Agriculture’s National Agricultural Statistics Survey conducts the 

9 Census of Agriculture every 5 years. This results in a comprehensive compilation of agricultural 

10 production data for every county and parish in the Nation. Beginning with the 2002 Census of 

11 Agriculture, farm operators were asked whether or not they hired migrant workers—defined as a 

12 farm worker whose employment required travel—to do work that prevented the workers from 

13 returning to their permanent place of residence the same day. 

14 Information about both migrant and temporary farm labor (working less than 150 days) can be 

15 found in the 2012 Census of Agriculture. Table 3-20 presents information on migrant and 

16 temporary farm labor within 50 mi (80 km) of RBS. 

17 Table 3-20. Migrant Farm Workers and Temporary Farm Labor in Parishes or Counties 

18 Located Within 50 mi (80 km) of RBS (2012)

County or Parish(a)

Number of 

Farms with 

Hired Farm 

Labor(b)

Number of Farms 

Hiring Workers for 

Less Than

150 Days(b)

Number of Farm 

Workers Working 

for Less Than 

150 Days(b)

Number of Farms 

Reporting 

Migrant Farm 

Labor(b)

Total 2,915 2,175 6,108 187

Louisiana

Ascension 49 34 158 6

Assumption 51 34 182 14

Avoyelles 346 274 604 19

Catahoula 150 100 250 1

Concordia 172 118 352 5

East Baton Rouge 101 82 167 0

East Feliciana 122 98 241 2

Iberia 108 75 482 20

Iberville 69 37 216 13

Lafayette 148 99 299 7

Livingston 82 74 (c) 3

Pointe Coupee 152 113 447 21

St. Helena 92 76 190 1

St. Landry 348 245 596 31

St. Martin 100 72 235 22

Tangipahoa 257 195 561 9

West Baton Rouge 37 23 104 5

West Feliciana 60 37 103 3
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County or Parish(a)

Number of 

Farms with 

Hired Farm 

Labor(b)

Number of Farms 

Hiring Workers for 

Less Than

150 Days(b)

Number of Farm 

Workers Working 

for Less Than 

150 Days(b)

Number of Farms 

Reporting 

Migrant Farm 

Labor(b)

Mississippi

Adams 48 33 74 0

Amite 145 131 590 3

Franklin 38 31 (c) 0

Pike 156 127 257 2

Wilkinson 84 67 (c) 0

(a) Parishes within 50 mi (80 km) of RBS with at least one block group located within the 50-mi (80-km) radius.

(b) Table 7. Hired farm Labor – Workers and Payroll: 2012.

(c) Withheld to avoid disclosing data for individual farms.

Note: ROI parishes are in bold italics.

Source: 2012 Census of Agriculture – Parish Data (NASS 2014)

1 According to the 2012 Census of Agriculture, approximately 6,110 farm workers were hired to 

2 work for less than 150 days and were employed on 2,175 farms within 50 mi (80 km) of RBS. 

3 The parish with the highest number of temporary farm workers (604 workers on 274 farms) was 

4 Avoyelles Parish, LA (NASS 2014). Approximately 187 farms, in the 50-mi (80-km) radius of 

5 RBS reported hiring approximately 1,300 migrant workers in the 2012 Census of Agriculture. 

6 St. Landry Parish had the highest number of farms (31) reporting migrant farm labor 

7 (NASS 2014).

8 3.10.4 Housing and Community Services

9 This section presents information regarding housing and local public services, including 

10 education and water supply.

11 3.10.4.1 Housing

12 Table 3-21 lists the total number of occupied and vacant housing units, vacancy rates, and 

13 median values of housing units in the region of influence. Based on the Census Bureau’s 

14 2011–2015 American Community Survey 5-year estimates (USCB 2017d), there were 

15 approximately 196,000 housing units in the region of influence, of which over 173,000 were 

16 occupied. The median values of owner-occupied housing units in the region of influence range 

17 from $170,500 in East Baton Rouge Parish to $188,200 in West Feliciana Parish. The vacancy 

18 rate also varied slightly between the two parishes, from 2.0 percent in East Baton Rouge Parish 

19 to 2.6 percent in West Feliciana Parish (USCB 2017d).

20 Table 3-21. Housing in the River Bend Station Region of Influence (2011–2015, 

21 5-Year Estimate)

East Baton Rouge 

Parish 

West Feliciana 

Parish

Region of 

Influence

Total housing units 190,343 5,214 195,557

Occupied housing units 169,120 3,911 173,031
3-106

East Baton Rouge 

Parish 

West Feliciana 

Parish

Region of 

Influence

Total vacant housing units 21,223 1,303 22,526

Percent total vacant 11.1 25.0 11.5

Owner occupied units 100,963 2,974 103,937

Median value (dollars) 170,500 188,200 171,006

Owner vacancy rate (percent) 2.0 2.6 2.0

Renter occupied units 68,157 937 69,094

Median rent (dollars/month) 842 822 842

Rental vacancy rate (percent) 8.8 12.7 8.9

Source: USCB 2017d

1 3.10.4.2 Education

2 West Feliciana Parish has one public school district in which there are a total of four schools. 

3 During the 2014–2015 school year, the district enrolled approximately 2,100 students 

4 (NCES 2018b).

5 3.10.4.3 Public Water Supply

6 West Feliciana Parish Water District 13 is the main public water service provider for parish 

7 residents and relies on groundwater as its source. It also provides potable water to RBS. 

8 Table 3-22 shows that demand on the West Feliciana Parish Water District 13 is approximately 

9 at 35.0 percent capacity. West Feliciana Parish has sufficient water service capabilities to meet 

10 the needs of the public. (Entergy 2017h) 

11 Baton Rouge Water Company is the main public water provider in East Baton Rouge Parish and 

12 relies on groundwater as its source and serves a population of over 500,000. The system is at 

13 approximately 68 percent capacity. The Baton Rouge Water Company has plans to add an 

14 additional well and is investigating drilling additional wells to increase capacity. (Entergy 2017h) 

15 Table 3-22 lists the largest public water suppliers in East Baton Rouge Parish and West 

16 Feliciana Parish and provides information regarding the water source and population served for 

17 those suppliers. Currently, there is excess capacity in the major public water systems.

18 Table 3-22. Public Water Supply Systems in East Baton Rouge Parish and West Feliciana 

19 Parish

Public Water System Source

Design 

Capacity

(mgd)

Average 

Production

(mgd)

Demand 

(percent of 

capacity)

Population

Served(a)

East Baton Rouge Parish

Baton Rouge Water Company Groundwater 98.38 66.54 67.6 526,710

City of Baker Groundwater 5.8 1.54 26.6 13,855

City of Zachary Groundwater 9 2.5 27.8 22,728
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Public Water System Source

Design 

Capacity

(mgd)

Average 

Production

(mgd)

Demand 

(percent of 

capacity)

Population

Served(a)

West Feliciana Parish

West Feliciana Consolidated 

Waterworks 

(Water District 13)

Groundwater 3.25 1.14 35.0 10,956

Town of St. Francisville Groundwater 4 0.1 2.5 2,304

(a) Safe Drinking Water Search for the State of Louisiana (EPA 2018).

Sources: Entergy 2017h, EPA 2018

1 3.10.5 Tax Revenues

2 Entergy pays annual property taxes to West Feliciana Parish based on the assessed value of 

3 RBS. The State of Louisiana calculates a total entity or unit value for regulated utilities in the 

4 state, including Entergy Louisiana, LLC, and does not value RBS separately. The total 

5 assessment of Entergy Louisiana, Inc.-owned property in Louisiana in 2016 was approximately 

6 $1,122 million (LTC 2017, page 9). The taxable assessed value of Entergy Louisiana, LLC 

7 property in West Feliciana Parish in 2015 was approximately $180 million (WFP 2016, page 59). 

8 Entergy Louisiana, LLC does not receive separate tax invoices from West Feliciana Parish for 

9 power plants. In 2016, Entergy Louisiana, LLC paid approximately $14.2 million in property 

10 taxes to West Feliciana Parish (see Table 3-23).

11 Total property tax revenues for West Feliciana Parish, including parish and local taxes, were 

12 approximately $22.5 million in 2016. The two largest programs receiving parish funds were 

13 schools (which received approximately $9.9 million) and law enforcement (which received 

14 approximately $4 million). This was followed by the parish improvement funds program, which 

15 received about $2.5 million (LTC 2017, page 106). In 2016, Entergy Louisiana, LLC payments 

16 to West Feliciana Parish in property taxes represented roughly 63 percent of the total parish 

17 property tax revenues. Entergy anticipates that the company's assessed value and tax rates 

18 will continue to fluctuate; however, Entergy does not expect there to be notable or significant 

19 changes to future property tax payments during the license renewal period. 

20 Other significant payments made by Entergy Louisiana, LLC to agencies and parishes for RBS

21 are listed in Table 3-24. 

22 Table 3-23. Entergy Louisiana, LLC Property Tax Payments, 2011–2016

Year

Entergy Louisiana, LLC

Property Taxes

(in millions of dollars)

West Feliciana Parish 

Revenues

(in millions of dollars)

Percent of Parish 

Revenue

2011 15.6 21.5 73

2012 15.4 21.7 71

2013 14.3 21.4 67

2014 14.6 21.6 68

2015 14.4 21.8 66

2016 14.2 22.5 63

Source: Entergy 2017h, Entergy 2017c
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1 Table 3-24. Entergy Louisiana, LLC Annual Support Payments to Agencies and Parishes

Agency

Payment

(in dollars) Purpose

Federal Emergency Management 

Agency 524,814 Federal Radiological Emergency 

Preparedness program fee

East Feliciana, West Feliciana, East 

Baton Rouge, West Baton Rouge, 

and Pointe Coupee Emergency 

Management Offices

215,000 Radiological emergency preparedness 

program support fees, with East Baton 

Rouge Parish receiving $15,000 for 

maintaining the RBS reception centers

Louisiana Department of 

Environmental Quality 432,696 Radiological emergency preparedness fees

Governor’s Office of Homeland

Security & Emergency Management 62,158

Radiological emergency preparedness 

program support fee including radiological 

instrument calibration

Mississippi Emergency Management 

Agency 46,200

Operation and support of 24 hour 

radiological emergency preparedness 

hotline fee, and some limited radiological 

emergency preparedness support

Source: Entergy 2017c

2 3.10.6 Local Transportation

3 The primary access to RBS is from US-61 via the North Access Road. At the North Access 

4 Road plant entrance, a dedicated turn lane was included in construction of the northbound 

5 portion of US-61, along with the installation of traffic lights for controlling traffic flow. A second 

6 road with access to the plant from US-61 is the two-lane paved highway LA-965, located 

7 northwest of RBS in West Feliciana Parish. Transportation studies show that use of this road is 

8 minimal in comparison to US-61, and traffic volume has fluctuated very little over the years. The 

9 most recent traffic volume recorded for LA-965 west of US-61 was an average annual daily 

10 traffic count of 545 vehicles. Southwest of the RBS property boundary, the recently completed 

11 LA-10 Audubon Bridge crosses the Mississippi River and links Pointe Coupee Parish with West 

12 Feliciana Parish. No roads within RBS directly access LA-10. An average annual daily traffic 

13 count of 3,066 was taken in 2012 on LA-10 east of the bridge. No average annual daily traffic 

14 counts of a later date were available for West Feliciana Parish recorded mile-point locations. 

15 (Entergy 2017h) 

16 Table 3-25 lists one US highway (US-61) and three State roads (LA-10, LA-965, and LA-966) 

17 near RBS. The table also shows Louisiana Department of Transportation & Development 

18 (LaDOTD) average annual daily traffic volumes recorded at several mile marker points for each 

19 highway or road. The average annual daily traffic values represent traffic volumes for a 24-hour 

20 period factored by both day of week and month of year.
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1 Table 3-25. Louisiana State Routes in the Vicinity of River Bend Station: 2016 Average 

2 Annual Daily Traffic Count

Roadway and Location Mile Marker

Average Annual Daily Traffic 

and Average Daily Traffic

US-61

Northwest of RBS (West Feliciana) 105.72 15,628

Southeast of RBS (East Feliciana) 99.08 13,236(a)

LA-10

Northwest of RBS (West Feliciana) 150.44 2,729

Northwest of RBS (West Feliciana) 149.62 3,478

Southwest of RBS (West Feliciana) 140.15 3,066(b)

LA-965

Northwest of RBS (West Feliciana) 2.06 675

Northwest of RBS (West Feliciana) 2.65 2,311

East of RBS (West Feliciana) 16.201 2,624

LA-966

Northeast of RBS (West Feliciana) 0.34 852

(a) AADT represents traffic volume in 2015

(b) AADT represents traffic volume in 2012

Source: LaDOTD 2018

3 3.11 Human Health

4 Like any industrial facility or nuclear power plant, operations at RBS produce human health risks 

5 for both workers and members of the public. This section describes human health risks from 

6 the operation of RBS.

7 3.11.1 Radiological Exposure and Risk

8 Operation of a nuclear power plant involves the use of nuclear fuel to generate electricity 

9 through the fission process through which uranium atoms are split, resulting in the production of 

10 heat which is used to produce steam to drive the plant’s turbines and the creation of radioactive 

11 byproducts. As required by NRC regulations at 10 CFR 20.1101,”Radiation Protection 

12 Programs,” Entergy has a radiation protection program designed to protect onsite personnel 

13 (including employees and contractor employees), visitors, and offsite members of the public 

14 from radiation and radioactive material at RBS.

15 The radiation protection program is extensive and includes, but is not limited to the following:

16 • Organization and Administration (e.g., a radiation protection manager who is

17 responsible for the program and who ensures trained and qualified workers for the

18 program)

19 • Implementing Procedures

20 • ALARA Program to minimize dose to workers and members of the public

21 • Dosimetry Program (i.e., measure radiation dose of plant workers)
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1 • Radiological Controls (e.g., protective clothing, shielding, filters, respiratory

2 equipment, and individual work permits with specific radiological requirements)

3 • Radiation Area Entry and Exit Controls (e.g., locked or barricaded doors, interlocks,

4 local and remote alarms, personnel contamination monitoring stations)

5 • Posting of Radiation Hazards (i.e., signs and notices alerting plant personnel of

6 potential hazards)

7 • Recordkeeping and Reporting (e.g., documentation of worker dose and radiation

8 survey data)

9 • Radiation Safety Training (e.g., classroom training and use of mockups to simulate

10 complex work assignments)

11 • Radioactive Effluent Monitoring Management (i.e., controlling and monitoring

12 radioactive liquid and gaseous effluents released into the environment)

13 • Radioactive Environmental Monitoring (e.g., sampling and analysis of environmental

14 media, such as air, water, vegetation, food crops, direct radiation, and milk to

15 measure the levels of radioactive material in the environment that may impact human

16 health)

17 • Radiological Waste Management (i.e., controlling, monitoring, processing, and

18 disposing of radioactive solid waste)

19 Regarding radiation exposure to RBS personnel, the NRC staff reviewed the data contained in 

20 NUREG–0713, Volume 37, “Occupational Radiation Exposure at Commercial Nuclear Power 

21 Reactors and Other Facilities 2015: Forty-Eighth Annual Report” (NRC 2017i). The forty-eighth 

22 annual report was the most recent annual report available at the time of this environmental 

23 review. It summarizes the NRC’s Radiation Exposure Information and Reporting System 

24 database’s occupational exposure data through 2015. Nuclear power plants are required by 

25 10 CFR 20.2206, “Reports of Individual Monitoring,” to report their occupational exposure data 

26 to the NRC annually. Radiological doses associated with RBS license renewal are discussed 

27 further in Chapter 4 of this SEIS.

28 NUREG–0713 calculates a 3-year average collective dose per reactor for workers at all nuclear 

29 power reactors licensed by the NRC. The 3-year average collective dose is one of the metrics 

30 that the NRC uses in the Reactor Oversight Program to evaluate the applicant’s ALARA 

31 program. Collective dose is the sum of the individual doses received by workers at a facility 

32 licensed to use radioactive material over a 1-year time period. There are no NRC or EPA

33 standards for collective dose. Based on the data for operating boiling-water reactors like the 

34 one at RBS, the average annual collective dose per reactor was 120 person-rem. In 

35 comparison, RBS had a reported annual collective dose per reactor of 111 person-rem.

36 In addition, as reported in NUREG–0713, for 2015, no worker at RBS received an annual dose

37 greater than 2.0 rem (0.02 sievert (Sv)), which is less than half of the NRC occupational dose 

38 limit of 5.0 rem (0.05 Sv) in 10 CFR 20.1201, “Occupational Dose Limits for Adults.”

39 Offsite dose to members of the public is discussed in Section 3.1.4 of this SEIS. 

40 3.11.2 Chemical Hazards

41 State and Federal environmental agencies regulate the use, storage, and discharge of 

42 chemicals, biocides, and sanitary wastes. Such environmental agencies also regulate how 

43 facilities like RBS manage minor chemical spills. Chemical and hazardous wastes can 

44 potentially impact workers, members of the public, and the environment. 
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1 Entergy currently controls the use, storage, and discharge of chemicals and sanitary wastes at 

2 RBS in accordance with its chemical control procedures, waste-management procedures, and 

3 RBS site-specific chemical spill prevention plans. Entergy monitors and controls discharges of 

4 chemical and sanitary wastes through RBS’s Louisiana Pollutant Discharge Elimination System

5 permit process. These plant procedures, plans, and processes are designed to prevent and 

6 minimize the potential for a chemical or hazardous waste release and, in the event of such a 

7 release, minimize impact to workers, members of the public, and the environment 

8 (Entergy 2017h). 

9 During the period of extended operation. NRC staff expects that Entergy will minimize chemical 

10 hazard impact by implementing good industrial hygiene practices as required by permits and 

11 Federal and State regulations.

12 3.11.3 Microbiological Hazards

13 Large nuclear power plants are usually built next to a body of water such as a lake, river, or 

14 ocean, which provides a source of cooling water and accepts heat discharge from the plant. For 

15 RBS, that body of water is the Mississippi River. The thermal effluents, or heated discharge, of 

16 nuclear power plants (like RBS) that discharge into a river can potentially promote the growth of 

17 certain thermophilic, or heat-loving, microorganisms that are linked to adverse human health 

18 effects. Microorganisms of particular concern include several types of bacteria (Legionella spp., 

19 Salmonella spp., Shigella spp., and Pseudomonas aeruginosa) and the free-living amoeba 

20 Naegleria fowleri. 

21 The public can be exposed to the thermophilic microorganisms like Salmonella, Shigella, 

22 P. aeruginosa, and N. fowleri during swimming, boating, or other recreational uses of

23 freshwater. If a nuclear power plant’s thermal effluent enhances the growth of thermophilic 

24 microorganisms, recreational water users near the plant’s discharge could experience an 

25 elevated risk of exposure to these microorganisms. In addition, nuclear plant workers can be 

26 exposed to the bacteria Legionella spp. when performing maintenance activities on plant cooling 

27 systems by inhaling cooling water vapors (because these vapors are often within the optimum 

28 temperature range for Legionella growth). 

29 3.11.3.1 Thermophilic Microorganisms of Concern

30 Salmonella typhimurium and S. enteritidis

31 These are two species of enteric bacteria (bacteria that live in human or animal intestines) that 

32 cause salmonellosis, an infection that can cause diarrhea, vomiting, fever, and abdominal 

33 cramps. This disease is more common in summer than winter (CDC 2015b). Salmonellosis is 

34 transmitted through contact with contaminated human or animal feces, contact with 

35 contaminated water, contact with food or infected animals, or contamination in laboratory 

36 settings (CDC 2015b). These bacteria grow at temperatures ranging from 77 to 113 °F (25 to 

37 45 °C), have an optimal growth temperature around the human body temperature of 98.6 °F 

38 (37 °C), and can survive extreme temperatures as low as 41 °F (5°C) and as high as 122 °F 

39 (50 °C) (Oscar 2009). Research studies examining the persistence of Salmonella spp. outside 

40 of a host found that the bacteria can survive for several months in water and in aquatic 

41 sediments (Moore et al. 2003). From 1990–2016, the annual number of reported Salmonella

42 spp. cases within the State of Louisiana has ranged from 531 to 1,548 cases, for an average of 

43 1,000 cases per year (LDH 2016b). CDC data indicate that no outbreaks or cases of 

44 waterborne Salmonella infection from recreational waters have occurred in the United States 
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1 from 2006 through 2017 (CDC 2017d). During that time period, all CDC-reported Salmonella

2 outbreaks were caused by consumption of contaminated produce, meats, or prepared foods; 

3 contact with contaminated animals; or exposure in a laboratory (CDC 2017d).

4 Shigella spp

5 Shigellosis infections are caused by the transmission of Shigella spp. from person to person 

6 through contaminated feces and unhygienic handling of food. Those infected may experience 

7 diarrhea, fever, and stomach cramps. Like salmonellosis, infections are more common in 

8 summer than in winter (CDC 2017e). The bacteria grow at temperatures between 77 and 99 °F 

9 (25 and 37 °C) and can survive temperatures as low as 41 °F (5 °C) (PHAC 2010). From 

10 1990–2016, the annual number of reported Shigella spp. cases within the State of Louisiana 

11 has ranged from 128 to 645, for an average of 367 cases per year (LDH 2016c). CDC reports 

12 (2004, 2006, 2008, 2011, 2014b, 2015a) indicate that less than a dozen shigellosis outbreaks 

13 have been attributed to lakes, reservoirs, and other recreational waters in the past 10 available 

14 data years (2001 through 2012). 

15 Pseudomonas aeruginosa

16 Pseudomonas aeruginosa can be found in soil, hospital respirators, water, and sewage and on 

17 the skin of healthy individuals. It is most commonly linked to infections transmitted in healthcare 

18 settings. Infections from exposure to P. aeruginosa in water can lead to development of mild 

19 respiratory illnesses in healthy people (CDC 2014a). These bacteria have an optimal growth 

20 temperature of 98.6 °F (37 °C) and can survive in temperatures as high as 107.6 °F (42 °C) 

21 (Todar 2004). The Louisiana Department of Health (undated) reported no cases of 

22 Pseudomonas aeruginosa from 1990 through 2017. 

23 Naegleria fowleri

24 The free-living amoeba Naegleria fowleri prefers warm freshwater habitats. This microorganism 

25 can cause human primary amoebic meningoencephalitis—an almost always fatal brain 

26 infection. The infection occurs when N. fowleri penetrates the nasal tissue through direct 

27 contact with contaminated water from warm lakes, rivers, hot springs, or municipal sources 

28 (i.e., tap water) and migrates to the brain tissues (CDC 2017c). This free-swimming amoeba 

29 species is rarely found in water temperatures below 95 °F (35 °C), and infections rarely occur at 

30 those temperatures (Tyndall et al. 1989). The N. fowleri-caused disease, primary amoebic 

31 meningoencephalitis, is rare in the United States. During the 53-year period from 1962 through 

32 2015, the CDC (2017b) confirmed an average of seven cases each year of primary amoebic 

33 meningoencephalitis. Of all cases recorded over that same period, the CDC reports that four 

34 cases occurred in Louisiana (CDC 2017b). The Louisiana Office of Public Health (2013) 

35 determined that the three most recent cases, two cases in 2011 and one case in 2013, were not 

36 attributed to rivers, lakes, and other recreational waters. No cases of primary amoebic 

37 meningoencephalitis in Louisiana have ever been attributed to the Mississippi River or 

38 recreational surface water use (Entergy 2017d). 

39 Legionella spp. 

40 Legionella spp. infections result in legionellosis (commonly called Legionnaires’ disease), which 

41 manifests as a dangerous form of pneumonia or an influenza-like illness. Legionellosis 

42 outbreaks are often associated with complex water systems housed inside buildings or 

43 structures, such as cooling towers (CDC 2017a). Legionella spp. thrive in aquatic environments 
3-113

1 as intracellular parasites of protozoa and are only infectious in humans through inhalation 

2 contact from an environmental source (CDC 2017a). Stagnant water between 95 and 115 °F 

3 (35 and 46 °C) tends to promote growth in Legionella spp., although the bacteria can grow at 

4 temperatures as low as 68 °F (20 °C) and as high as 122 °F (50 °C) (OSHA 1999). From 

5 1990–2016, the annual number of reported Legionella spp. cases within the State of Louisiana 

6 has ranged from 1 to 61, for an average of 15 cases per year (LDH 2016a). 

7 3.11.4 Electromagnetic Fields

8 Based on its evaluation in the GEIS for license renewal (NUREG-1437), the NRC has not found 

9 electric shock resulting from direct access to energized conductors or from induced charges in 

10 metallic structures to be a problem at most operating plants. Generally, the NRC staff also does 

11 not expect electric shock from such sources to be a human health hazard during the license 

12 renewal term. However, a site-specific review is required to determine the significance of the 

13 electric shock potential along the portions of the transmission lines that are within the scope of 

14 this SEIS. Transmission lines that are within the scope of the NRC’s license renewal 

15 environmental review are limited to: (1) those transmission lines that connect the nuclear plant 

16 to the substation where electricity is fed into the regional distribution system and (2) those 

17 transmission lines that supply power to the nuclear plant from the grid (NRC 2013b).

18 As discussed in Section 3.1.6.5 of this SEIS, the only transmission lines that are in scope for 

19 RBS license renewal are onsite. Specifically, these onsite, in-scope transmission lines are (1) a 

20 line to the on-site Fancy Point Substation that delivers the electrical output of the plant, and 

21 (2) two lines from the Fancy Point Substation to the plant that deliver offsite power for normal

22 operation and safe shutdown of the plant (Entergy 2017h). Therefore, there is no potential 

23 shock hazard to offsite members of the public from these on-site transmission lines. As 

24 discussed in Section 3.11.5 of this SEIS, RBS maintains an occupational safety program, which 

25 includes protection from acute electrical shock, and is in accordance with Occupational Safety 

26 and Health Administration regulations.

27 3.11.5 Other Hazards

28 This section addresses two additional human health hazards: (1) physical occupational hazards 

29 and (2) electric shock hazards.

30 Nuclear power plants are industrial facilities that have many of the typical occupational hazards 

31 found at any other electric power generation utility. Nuclear power plant workers may perform 

32 electrical work, electric power line maintenance, repair work, and maintenance activities and 

33 may be exposed to some potentially hazardous physical conditions (e.g., falls, excessive heat, 

34 cold, noise, electric shock, and pressure).

35 The Occupational Safety and Health Administration (OSHA) is responsible for developing and 

36 enforcing workplace safety regulations. Congress created OSHA by enacting the Occupational 

37 Safety and Health Act of 1970, as amended (29 U.S.C. 651 et seq.) to safeguard the health of 

38 workers. With specific regard to nuclear power plants, plant conditions that result in an 

39 occupational risk, but do not affect the safety of licensed radioactive materials, are under the 

40 statutory authority of OSHA rather than the NRC as set forth in a memorandum of 

41 understanding (53 FR 43950) between the NRC and OSHA. Occupational hazards are reduced 

42 when workers adhere to safety standards and use appropriate protective equipment; however,

43 fatalities and injuries from accidents may still occur. RBS maintains an occupational safety 

44 program for its workers in accordance with OSHA regulations (Entergy 2017h).
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1 3.12 Environmental Justice

2 Under Executive Order (EO) 12898 (59 FR 7629), Federal agencies are responsible for 

3 identifying and addressing, as appropriate, disproportionately high and adverse human health 

4 and environmental impacts on minority and low-income populations. Independent agencies, 

5 such as the NRC, are not bound by the terms of EO 12898 but are, as stated in 

6 paragraph 6-604 of the executive order, “requested to comply with the provisions of [the] order.”

7 In 2004, the Commission issued the agency’s “Policy Statement on the Treatment of 

8 Environmental Justice Matters in NRC Regulatory and Licensing Actions” (69 FR 52040), which 

9 states, "The Commission is committed to the general goals set forth in EO 12898, and strives to 

10 meet those goals as part of its NEPA review process."

11 The Council on Environmental Quality (CEQ) provides the following information in 

12 Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 1997):

13 Disproportionately High and Adverse Human Health Effects. 

14 Adverse health effects are measured in risks and rates that could result in latent 

15 cancer fatalities, as well as other fatal or nonfatal adverse impacts on human 

16 health. Adverse health effects may include bodily impairment, infirmity, illness, or 

17 death. Disproportionately high and adverse human health effects occur when the 

18 risk or rate of exposure to an environmental hazard for a minority or low-income 

19 population is significant (as employed by NEPA) and appreciably exceeds the 

20 risk or exposure rate for the general population or for another appropriate 

21 comparison group (CEQ 1997).

22 Disproportionately High and Adverse Environmental Effects. 

23 A disproportionately high environmental impact that is significant (as employed 

24 by NEPA) refers to an impact or risk of an impact on the natural or physical 

25 environment in a low-income or minority community that appreciably exceeds the 

26 environmental impact on the larger community. Such effects may include 

27 ecological, cultural, human health, economic, or social impacts. An adverse 

28 environmental impact is an impact that is determined to be both harmful and 

29 significant (as employed by NEPA). In assessing cultural and aesthetic

30 environmental impacts, impacts that uniquely affect geographically dislocated or 

31 dispersed minority or low-income populations or American Indian tribes are 

32 considered (CEQ 1997).

33 This environmental justice analysis assesses the potential for disproportionately high and 

34 adverse human health or environmental effects on minority and low-income populations that 

35 could result from the operation of RBS during the period of extended operation. In assessing 

36 the impacts, the following definitions of minority individuals, minority populations, and 

37 low-income population were used (CEQ 1997):

38 Minority Individuals

39 Individuals who identify themselves as members of the following population 

40 groups: Hispanic or Latino, American Indian or Alaska Native, Asian, Black or 

41 African American, Native Hawaiian or Other Pacific Islander, or two or more 
3-115

1 races, meaning individuals who identified themselves on a Census form as being 

2 a member of two or more races, for example, White and Asian.

3 Minority Populations

4 Minority populations are identified when (1) the minority population of an affected 

5 area exceeds 50 percent or (2) the minority population percentage of the affected 

6 area is meaningfully greater than the minority population percentage in the 

7 general population or other appropriate unit of geographic analysis.

8 Low-income Population

9 Low-income populations in an affected area are identified with the annual 

10 statistical poverty thresholds from the Census Bureau’s Current Population 

11 Reports, Series P60, on Income and Poverty.

12 Minority Population

13 According to the Census Bureau’s 2010 Census data, approximately 42 percent of the 

14 population residing within a 50-mi (80-km) radius of RBS identified themselves as minority 

15 individuals. The largest minority populations were Black or African American (approximately 

16 37 percent) and Hispanic, Latino, or Spanish origin of any race (approximately 3 percent) 

17 (USCB 2017a).

18 According to the CEQ definition, a minority population exists if the percentage of the minority 

19 population of an area (e.g., census block group) exceeds 50 percent or is meaningfully greater 

20 than the minority population percentage in the general population. Therefore, census block 

21 groups within the 50 mi (80 km) radius of RBS were considered minority population block 

22 groups if the percentage of the minority population in the block group exceeded 42 percent, the 

23 percent of the minority population within the 50-mi (80-km) radius of RBS.

24 As shown in Figure 3-22, minority population block groups (race and ethnicity) are clustered 

25 north around Woodville, MS, east around Jackson, LA; west around New Roads, LA; and 

26 southeast of RBS in Baton Rouge, LA. Based on this analysis, RBS is not located in a minority 

27 population block group.

28 According to 2010 Census data, minority populations in the socioeconomic region of influence 

29 (East Baton Rouge and West Feliciana parishes) comprised approximately 53 percent of the 

30 total two-parish population (see Table 3-17). Figure 3-22 shows predominantly minority 

31 population block groups, using 2010 Census data for race and ethnicity, within a 50-mile 

32 (80-kilometer) radius of RBS. According to the Census Bureau’s 2011–2015 American 

33 Community Survey 5-Year Estimates (USCB 2017e), since 2010, minority populations in the 

34 region of influence increased by approximately 7,000 persons and now comprise 54 percent of 

35 the population (see Table 3-18).

36 Low-Income Population

37 The Census Bureau’s 2011–2015 American Community Survey (ACS) data identifies 

38 approximately 19 percent of individuals residing within a 50-mi (80-km) radius of RBS as living 

39 below the Federal poverty threshold in 2015 (USCB 2017c). The 2015 Federal poverty 

40 threshold was $24,257 for a family of four.
3-116

1 Figure 3-23 shows the location of predominantly low-income population block groups within a 

2 50-mile (80-kilometer) radius of RBS. Census block groups were considered low-income

3 population block groups if the percentage of individuals living below the Federal poverty 

4 threshold within the block group exceeded 19 percent, the percent of the individuals living below 

5 the Federal poverty threshold within the 50-mi (80-km) radius of RBS.

6 As shown in Figure 3-23, low-income population block groups are clustered north around 

7 Woodville, MS, east around Jackson, LA; west around New Roads, LA; and southeast of RBS in 

8 Baton Rouge, LA. Based on this analysis, RBS is not located in a low-income population block 

9 group.

10 According to the Census Bureau’s 2011–2015 American Community Survey 5-Year Estimates, 

11 15.2 percent of families and 19.8 percent of people in Louisiana were living below the Federal 

12 poverty threshold and the median household and per capita incomes for Louisiana were 

13 $45,047 and $24,981, respectively (USCB 2017c). In the socioeconomic region of influence 

14 (East Baton Rouge and West Feliciana parishes), people living in East Baton Rouge Parish 

15 have higher median household and per capita incomes ($49,285 and $27,944, respectively) 

16 than the State averages, with fewer families and people (13.3 percent and 19.6 percent, 

17 respectively) living below the poverty level. In addition, people living in West Feliciana Parish 

18 also have higher median household and per capita incomes ($56,685 and $22,122, 

19 respectively) than the State averages, with 12.4 percent of families and 16.0 percent of persons 

20 living below the official poverty level (USCB 2017c).
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1 Source: USCB 2017a

2 Figure 3-22. 2010 Census—Minority Block Groups Within a 50-mi (80-km) Radius of River 

3 Bend Station
3-118

1 Source: USCB 2017c

2 Figure 3-23. 2011–2015, American Community Survey 5-Year Estimates—Low-Income 

3 Block Groups Within a 50-mi (80 km) Radius of River Bend Station
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1 3.13 Waste Management and Pollution Prevention

2 Like any nuclear power plant, RBS produces both radioactive and nonradioactive waste. This 

3 section describes waste management and pollution prevention at RBS.

4 3.13.1 Radioactive Waste 

5 As discussed in Section 3.1.4 of this SEIS, RBS uses liquid, gaseous, and solid waste

6 processing systems to collect and treat, as needed, radioactive materials produced as a 

7 byproduct of plant operations. Radioactive materials in liquid and gaseous effluents are 

8 reduced prior to being released into the environment so that the resultant dose to members of 

9 the public from these effluents is well within NRC and EPA dose standards. Radionuclides that 

10 can be efficiently removed from the liquid and gaseous effluents prior to release are converted 

11 to a solid waste form for disposal in a licensed disposal facility.

12 3.13.2 Nonradioactive Waste

13 Waste minimization and pollution prevention are important elements of operations at all nuclear 

14 power plants. Licensees are required to consider pollution prevention measures as dictated by 

15 the Pollution Prevention Act (Public Law 101-508) and the Resource Conservation and 

16 Recovery Act of 1976, as amended (Public Law 94-580) (NRC 2013b).

17 As described in Section 3.1.5, RBS has a nonradioactive waste management program to handle 

18 nonradioactive waste in accordance with Federal, State, and corporate regulations and 

19 procedures. RBS maintains a waste minimization program that uses material control, process 

20 control, waste management, recycling, and feedback to reduce waste.

21 RBS has a Stormwater Pollution Prevention Plan (SWPPP) that identifies potential sources of 

22 pollution that may affect the quality of stormwater discharges from permitted outfalls. The 

23 SWPPP also describes best management practices for reducing pollutants in stormwater 

24 discharges and assure compliance with the site’s Louisiana Pollutant Discharge Elimination

25 System permit. 

26 RBS also has a Spill Prevention, Control and Countermeasure (SPCC) plan (Entergy 2016f) to 

27 monitor areas within the site that have the potential to discharge oil into or upon navigable 

28 waters, as per regulations in 40 CFR Part 112, “Oil Pollution Prevention.” The SPCC plan 

29 identifies and describes the procedures, materials, equipment, and facilities that Entergy uses to 

30 minimize the frequency and severity of oil spills. 

31 RBS is subject to EPA reporting requirements in 40 CFR 110, “Discharge of Oil,” pursuant to 

32 Section 311(b)(4) of the Federal Water Pollution Control Act. Under these regulations, RBS 

33 must report to the National Response Center any discharges of oil if the quantity may be 

34 harmful to the public health or welfare or the environment. From 2011 through mid-2017, RBS 

35 reported no oil discharges that triggered the reporting requirements in 40 CFR 110. RBS is also 

36 subject to the reporting provisions of the Louisiana Administrative Code, Title 33, Part I, 

37 Chapter 39, “Notification Regulations and Procedures for Unauthorized Discharges.” This 

38 reporting provision requires RBS to report the release to the environment of 

39 42 gallons (1 barrel or 159 liters) of oil or more to the Louisiana Department of Public Safety and 

40 the Louisiana Department of Environmental Quality. From 2012 through mid-2017, RBS 

41 reported one spill that triggered this 42-gallon notification requirement. In October 2016, an 

42 estimated 60 gallons (227 liters) of hydraulic fluid from a service truck's hydraulic oil reservoir 
3-120

1 leaked onto the ground. Entergy used sorbents (insoluble materials for picking up and retaining 

2 liquid) to absorb visible puddles, cleaned the area, and placed the fluid in drums for disposal. 

3 (Entergy 2017h, Entergy 2017c)
4-1

1 4 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS

2 4.1 Introduction

3 In this chapter, the NRC staff evaluates the environmental consequences of issuing a renewed 

4 license authorizing an additional 20 years of operation for River Bend Station, Unit 1 (RBS). 

5 The NRC staff’s evaluation of environmental consequences will include the following: 

6 1) impacts associated with continued operations similar to those that have occurred

7 during the current license term

8 2) impacts of various alternatives to the proposed action, including a no-action

9 alternative (not issuing the renewed license) and replacement power alternatives

10 (new nuclear, supercritical pulverized coal, natural gas combined-cycle, and a

11 combination of natural gas, biomass, and energy conservation programs)

12 3) impacts from the termination of nuclear power plant operations and decommissioning

13 after the license renewal term (with emphasis on the incremental effect caused by an

14 additional 20 years of reactor operation)

15 4) impacts associated with the uranium fuel cycle

16 5) impacts of postulated accidents (design-basis accidents and severe accidents)

17 6) cumulative impacts of the proposed action of issuing a renewed license for RBS

18 7) resource commitments associated with the proposed action, including unavoidable

19 adverse impacts, the relationship between short-term use and long-term productivity,

20 and irreversible and irretrievable commitment of resources

21 8) new and potentially significant information on environmental issues related to the

22 impacts of operation during the renewal term

23 In this chapter, the NRC also compares the environmental impacts of license renewal with those 

24 of the no-action alternative and replacement power alternatives to determine whether the 

25 adverse environmental impacts of license renewal are not so great that it would be 

26 unreasonable to preserve the option of license renewal for energy-planning decisionmakers. 

27 Chapter 2 of this supplemental environmental impact statement (SEIS) describes in detail the 

28 attributes of the agency’s proposed action (i.e., license renewal of River Bend Station, Unit 1) 

29 and the no-action alternative. Chapter 2, Section 2.2.2 further describes the NRC staff’s 

30 process for developing a range of reasonable alternatives to the proposed action including the 

31 replacement power alternatives that the staff selected for detailed analysis in this chapter, 

32 including supporting assumptions and data relied upon. As noted in Chapter 2, Table 2-1, the 

33 site location for various replacement power alternatives would be adjacent to RBS. Chapter 2, 

34 Table 2-2, summarizes the environmental impacts of the proposed action and alternatives to the 

35 proposed action.

36 The affected environment (i.e., environmental baseline) for each resource area considered, and 

37 against which the potential environmental impacts of the alternatives are measured, is 

38 described in Chapter 3. As documented in Chapter 3, the effects of ongoing reactor operations 

39 at RBS have become well established as environmental conditions have adjusted to and reflect 

40 the presence of the nuclear power plant. 

41 This SEIS documents the NRC staff’s environmental review of the RBS license renewal 

42 application and supplements the information provided in NUREG–1437, “Generic Environmental 

43 Impact Statement for License Renewal of Nuclear Plants” (GEIS) (NRC 2013b). The GEIS 

44 identifies 78 issues (divided into Category 1 and Category 2 issues) to be evaluated for the 

45 proposed action in the license renewal environmental review process. Section 1.4 of this SEIS 
4-2

1 provides an explanation of the criteria for Category 1 issues (generic to all nuclear power plants) 

2 and Category 2 issues (specific to individual nuclear power plants) as well as the definitions of 

3 SMALL, MODERATE, and LARGE impact significance.

4 For Category 1 issues, the NRC staff can rely on the analysis in the GEIS unless otherwise 

5 noted. Table 4-1 lists the Category 1 (generic) issues that apply to River Bend Station, Unit 1 

6 (RBS) during the proposed license renewal period. For these issues, the NRC staff did not 

7 identify any new and significant information during its review of the applicant’s environmental 

8 report, the site audits, or the scoping period that would change the conclusions presented in the 

9 GEIS. Therefore, there are no impacts related to these issues beyond those already discussed 

10 in the GEIS, and accordingly, these issues are not addressed further in this SEIS. The staff’s 

11 process for evaluating new and significant information is described in Section 4.14. 

12 Table 4-1. Applicable Category 1 (Generic ) Issues for River Bend Station 

Issue GEIS Section Impact

Land-Use 

Onsite land use 4.2.1.1 SMALL

Offsite land use 4.2.1.1 SMALL

Visual Resources

Aesthetic Impacts 4.2.1.2 SMALL

Air Quality

Air quality impacts (all plants) 4.3.1.1 SMALL

Air quality effects of transmission lines 4.3.1.1 SMALL

Noise

Noise Impacts 4.3.1.2 SMALL

Geologic Environment

Geology and soils 4.4.1 SMALL

Surface Water Resources

Surface water use and quality (non-cooling system impacts) 4.5.1.1 SMALL

Altered current patterns at intake and discharge structures 4.5.1.1 SMALL

Altered salinity gradients 4.5.1.1 SMALL

Scouring caused by discharged cooling water 4.5.1.1 SMALL

Discharge of metals in cooling system effluent 4.5.1.1 SMALL

Discharge of biocides, sanitary wastes, and minor chemical 

spills

4.5.1.1 SMALL

Effects of dredging on surface water quality 4.5.1.1 SMALL

Temperature effects on sediment transport capacity 4.5.1.1 SMALL

Groundwater Resources

Groundwater contamination and use (non-cooling system 

impacts)

4.5.1.2 SMALL

Groundwater use conflicts (plants that withdraw less than 100 

gallons per minute [gpm])

4.5.1.2 SMALL

Groundwater quality degradation resulting from water 

withdrawals

4.5.1.2 SMALL
4-3

Issue GEIS Section Impact

Exposure of terrestrial organisms to radionuclides 4.6.1.1 SMALL

Cooling tower impacts on vegetation (plants with cooling 

towers)

4.6.1.1 SMALL

Bird collisions with plant structures and transmission lines 4.6.1.1 SMALL

Transmission line ROW management impacts on terrestrial 

resources

4.6.1.1 SMALL

Electromagnetic fields on flora and fauna (plants, agricultural 

crops, honeybees, wildlife, livestock)

4.6.1.1 SMALL

Aquatic Resources

Impingement and entrainment of aquatic organisms (plants 

with cooling towers)

4.6.1.2 SMALL

Entrainment of phytoplankton and zooplankton (all plants) 4.6.1.2 SMALL

Thermal impacts on aquatic organisms (plants with cooling 

towers)

4.6.1.2 SMALL

Infrequently reported thermal impacts (all plants) 4.6.1.2 SMALL

Effects of cooling water discharge on dissolved oxygen, gas 

supersaturation, and eutrophication

4.6.1.2 SMALL

Effects of nonradiological contaminants on aquatic organisms 4.6.1.2 SMALL

Exposure of aquatic organisms to radionuclides 4.6.1.2 SMALL

Effects of dredging on aquatic resources 4.6.1.2 SMALL

Effects on aquatic resources (non-cooling system impacts) 4.6.1.2 SMALL

Impacts of transmission line ROW management on aquatic 

resources

4.6.1.2 SMALL

Losses from predation, parasitism, and disease among 

organisms exposed to sublethal stresses

4.6.1.2 SMALL

Socioeconomics

Employment and income, recreation and tourism 4.8.1.1 SMALL

Tax Revenues 4.8.1.2 SMALL

Community services and education 4.8.1.3 SMALL

Population and housing 4.8.1.4 SMALL

Transportation 4.8.1.5 SMALL

Human Health

Radiation exposures to the public 4.9.1.1.1 SMALL

Radiation exposures to plant workers 4.9.1.1.1 SMALL

Human health impact from chemicals 4.9.1.1.2 SMALL

Microbiological hazards to plant workers 4.9.1.1.3 SMALL

Physical occupational hazards 4.9.4.1.5 SMALL

Postulated accidents

Design-basis accidents 4.9.1.2 SMALL

Waste Management

Low-level waste storage and disposal 4.11.1.1 SMALL

Onsite storage of spent nuclear fuel 4.11.1.2 SMALL

Offsite radiological impacts of spent nuclear fuel and highlevel waste disposal4.11.1.3 (a) 

Mixed waste storage and disposal 4.11.1.4 SMALL

Terrestrial Resources
4-4

Issue GEIS Section Impact

Nonradioactive waste storage and disposal 4.11.1.4 SMALL

Uranium Fuel Cycle

Offsite radiological impacts—individual impacts from other 

than the disposal of spent fuel and high-level waste

4.12.1.1 SMALL

Offsite radiological impacts—collective impacts from other 

than the disposal of spent fuel and high-level waste

4.12.1.1 (b)

Nonradiological impacts of the uranium fuel cycle 4.12.1.1 SMALL

Transportation 4.12.1.1 SMALL

Termination of Nuclear Power Plant Operations and Decommissioning

Termination of plant operations and decommissioning 4.12.2.1 SMALL

(a) The environmental impact of this issue for the time frame beyond the licensed life for reactor

operations is

contained in NUREG–2157 (NRC 2014).

(b) There are no regulatory limits applicable to collective doses to the general public from fuel cycle facilities. The

practice of estimating health effects on the basis of collective doses may not be meaningful. All fuel cycle

facilities are designed and operated to meet the applicable regulatory limits and standards. The Commission

concludes that the collective impacts are acceptable. The Commission concludes that the impacts would not

be sufficiently large to require the National Environmental Policy Act (NEPA) conclusion, for any plant, that the

option of extended operation under Title 10 of the Code of Federal Regulations (10 CFR) Part 54,

“Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” should be eliminated.

Accordingly, while the Commission has not assigned a single level of significance for the collective impacts of

the uranium fuel cycle, this issue is considered Category 1.

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 and NRC 2013b

1 The NRC staff analyzed the Category 2 (site-specific) issues applicable to RBS during the 

2 proposed license renewal period and assigned impacts to these issues as shown in Table 4-2.

3 Table 4-2. Applicable Category 2 (Site-Specific) Issues for the River Bend Station Site 

Issue GEIS Section Impact(a)

Surface Water Resources

Surface water use conflicts (plants with cooling ponds or 

cooling towers using makeup water from a river)

4.5.1.1 SMALL

Groundwater Resources

Groundwater use conflicts (plants with closed-cycle cooling 

systems that withdraw makeup water from a river) 

4.5.1.2 SMALL

Radionuclides released to groundwater 4.5.1.2 SMALL to MODERATE

Terrestrial Resources

Effects on terrestrial resources (noncooling system impacts) 4.6.1.1 SMALL

Water use conflicts with terrestrial resources (plants with 

cooling ponds or cooling towers using makeup water from a 

river)

4.6.1.1 SMALL

Aquatic Resources

Water use conflicts with aquatic resources (plants with 

cooling ponds or cooling towers using makeup water from a 

river)

4.6.1.2 SMALL
4-5

Issue GEIS Section Impact(a)

Threatened, endangered, and protected species and 

essential fish habitat

4.6.1.3 may affect, but is not 

likely to adversely affect 

the pallid sturgeon

Historic and Cultural Resources

Historic and cultural resources 4.7.1 would not adversely 

affect known historic 

properties

Human Health

Microbiological hazards to the public (plants with cooling 

ponds or canals or cooling towers that discharge to a river)

4.9.1.1.1 SMALL

Chronic effects of electromagnetic fields(b) 4.9.1.1.1 Uncertain Impact

Electric shock hazards 4.9.1.1.1 SMALL

Postulated Accidents

Severe accidents 4.9.1.2 SMALL

Environmental Justice

Minority and low-income populations 4.10.1 no disproportionately 

high and adverse 

human health and 

environmental effects

Cumulative Impacts

Cumulative Impacts 4.13 Not applicable

(a) Impact determinations for Category 2 issues based on findings described in Sections 4.2 through 4.13 for the

proposed action.

(b) This issue was not designated as Category 1 or 2 and is discussed in Section 4.11.1 below.

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 and NRC 2013b

1 4.2 Land Use and Visual Resources

2 This section describes the potential land use and visual resources impacts of the proposed 

3 action (license renewal) and alternatives to the proposed action.

4 4.2.1 Proposed Action

5 As identified in Table 4-1, the impacts of all generic land use or visual resource issues would be 

6 SMALL. Table 4-2 does not identify any site-specific (Category 2) land use or visual resource 

7 issues.

8 4.2.2 No-Action Alternative

9 4.2.2.1 Land Use

10 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

11 shut down on or before the expiration of the current facility operating license (August 29, 2025). 

12 Under this alternative, land uses would remain similar to those that would occur under the 

13 proposed license renewal except that land could be converted to other uses sooner if RBS were 

14 to shut down in 2025 instead of operating for an additional 20 years. The GEIS (NRC 2013b) 

15 notes that land use impacts could occur in other areas beyond the immediate nuclear plant site 

Special Status Species and Habitats
4-6

1 as a result of the no-action alternative if new power plants are built to replace lost power 

2 generating capacity. However, such impacts would likely be experienced no matter which 

3 alternative occurs. The NRC staff concludes that the no­action alternative is unlikely to 

4 noticeably alter or have more than minor effects on land use. Thus, the NRC staff concludes 

5 that the impacts of the no-action alternative on land use during the proposed license renewal 

6 term would be SMALL.

7 4.2.2.2 Visual Resources

8 Shutdown of RBS would not significantly change the visual appearance of the site. The most 

9 notable visual change would be the elimination of condensate plumes that, under certain 

10 meteorological conditions, are visible emerging from RBS’s mechanical draft cooling towers. 

11 The NRC staff concludes that the impacts of the no-action alternative on visual resources would 

12 be SMALL.

13 4.2.3 Replacement Power Alternatives: Common Impacts

14 4.2.3.1 Land Use

15 Each replacement power alternative would entail construction and operation of a new energy 

16 generating facility on the existing Entergy property and would result in qualitatively similar 

17 impacts to land use. Construction would require the permanent commitment of land for the new 

18 plant, plant intake and discharge structures, water treatment facilities, and cooling towers. 

19 Other construction-related land use impacts would include land clearing, excavations, drilling of 

20 monitoring wells, and the installation of temporary support facilities. Material laydown areas and 

21 onsite concrete batch plants could also result in temporary land use changes. Entergy would 

22 site any new plant on an area of the RBS site that it had previously excavated to support a 

23 planned second nuclear unit (the second unit was never built). Using this previously excavated 

24 land would minimize land use changes. The existing RBS transmission lines and structures 

25 would adequately support each replacement power alternative, and the existing RBS intake and 

26 discharge structures could also support these alternatives with some modifications, all of which 

27 would minimize land use impacts. Clearing and conversion of some land could occur 

28 depending on the specific siting of buildings and infrastructure within the site footprint.

29 Operation of any new plant would not result in additional land use impacts on the site beyond 

30 those identified during construction. However, replacement power alternatives could alter offsite 

31 land uses during the operational period as a result of mining, extraction, or waste disposal 

32 activities associated with each plant’s particular type of fuel.

33 4.2.3.2 Visual Resources

34 Construction of any of the replacement power alternatives would require clearing, excavation, 

35 and the use of construction equipment. Because the Entergy property is situated such that 

36 trees hide it from view from offsite, these temporary visual impacts would be minimal in the 

37 context of the area’s existing aesthetics, and construction machinery and activities would blend 

38 into the adjacent skyline. Additionally, a tree buffer lies between the RBS site and U.S. Highway 

39 61 (US-61) such that construction activities are unlikely to be visible to travelers on nearby 

40 roads. Construction of any new plant would not be visible from any sensitive viewing areas, 

41 such as cultural resources or historic properties. Painting structures, ducts, pipes, and tanks a 

42 blue-gray color, as Entergy has done at RBS, would allow these features to blend into the 

43 concrete of the existing site structures and further reduce any visual impacts. For offsite 
4-7

1 infrastructure associated with a new plant, such as pipelines, use of construction equipment 

2 may create short-term visual impacts during the construction period depending on the location 

3 of the infrastructure and visibility in the context of the surrounding landscape.

4 During operation, visual impacts of any of the replacement power alternatives would be similar 

5 in type and magnitude to those assessed for the proposed RBS license renewal, which would 

6 be SMALL as identified in Table 4-1. New cooling towers and their associated plumes would be 

7 the most obvious visual impact and would likely be visible farther from the site than other 

8 buildings and infrastructure. Because of their height, the cooling towers may require aircraft 

9 warning lights, which would be visible at night. A new coal plant would visibly emit smoke from 

10 smoke stacks when operating. However, as previously discussed, any new plant would be 

11 located on the RBS site, where tall structures and plumes are not visible offsite due to the 

12 continuous tree line surrounding the site. Therefore, any changes would blend in with the 

13 existing viewshed.

14 4.2.4 New Nuclear Alternative

15 4.2.4.1 Land Use

16 The NRC staff did not identify any impacts for the new nuclear alternative beyond those 

17 discussed in the impacts common to all replacement power alternatives. However, the impacts 

18 to land use could be slightly more intense for the new nuclear alternative compared to RBS 

19 license renewal due to the larger land area requirement. Thus, there is more potential for this 

20 alternative to require the conversion of land from nonindustrial uses to industrial use. For 

21 instance, under a new nuclear alternative, landscaped or natural areas adjacent to currently 

22 developed areas may be cleared and permanently occupied by plant buildings and 

23 infrastructure. Nevertheless, such impacts would be minimal given that Entergy previously 

24 cleared an area of the site for an additional nuclear unit that it did not build. Also, Entergy would 

25 use some existing buildings and infrastructure for the new nuclear plant. The NRC staff 

26 concludes that the impacts to land use from construction and operation of a new nuclear 

27 alternative would be SMALL.

28 4.2.4.2 Visual Resources

29 The NRC staff did not identify any impacts for the new nuclear alternative beyond those 

30 discussed in the impacts common to all alternatives. The NRC staff concludes that impacts of 

31 constructing and operating a new nuclear alternative on visual resources would be SMALL.

32 4.2.5 Supercritical Pulverized Coal Alternative

33 4.2.5.1 Land Use

34 In addition to the impacts common to all replacement power alternatives, the supercritical 

35 pulverized coal alternative (coal alternative) would require a significant amount of land for coal 

36 mining. Such impacts would be partially offset by the elimination of land used for uranium

37 mining to supply fuel to RBS but would still likely result in noticeable impacts to land use during 

38 the coal plant’s operational period. The NRC staff concludes that the impacts of constructing 

39 and operating a coal alternative on land use would be SMALL during construction and SMALL 

40 to MODERATE during operation.
4-8

1 4.2.5.2 Visual Resources

2 The NRC staff did not identify any impacts for the new coal plant beyond those discussed in the 

3 impacts common to all replacement power alternatives given the current industrial nature of the 

4 RBS site. The NRC staff concludes that impacts of constructing and operating a coal alternative 

5 on visual resources would be SMALL.

6 4.2.6 Natural Gas Combined-Cycle Alternative

7 4.2.6.1 Land Use

8 In addition to the impacts common to all replacement power alternatives, the natural gas 

9 combined-cycle alternative (natural gas alternative) would require the construction a new gas 

10 pipeline to connect the plant to an existing pipeline that lies approximately 2 mi (3.2 km) east of 

11 the site. An area of 25 ac (10 ha) of land would be required to create the right-of-way for this 

12 pipeline, which would create minor land use impacts. Because of the abundance of natural gas 

13 being transported through a nearby pipeline, the use of additional offsite land during the 

14 operational period for gas extraction is unlikely. The NRC staff concludes that impacts of 

15 constructing and operating a natural gas alternative on land use would be SMALL.

16 4.2.6.2 Visual Resources 

17 The NRC staff did not identify any impacts for the natural gas alternative beyond those 

18 discussed in the impacts common to all replacement power alternatives. The NRC staff 

19 concludes that impacts of constructing and operating a natural gas alternative on visual 

20 resources would be SMALL.

21 4.2.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

22 Demand-Side Management)

23 4.2.7.1 Land Use

24 The NRC staff did not identify any impacts for the natural gas and biomass portions of the 

25 combination alternative beyond those discussed in the impacts common to all replacement 

26 power alternatives and those described for the natural gas alternative. The demand-side 

27 management portion of the combination alternative, which would account for approximately 

28 11 percent of the combination alternative’s power generation, would not require any new 

29 construction or otherwise result in land use changes. Thus, there would be no land use impacts 

30 associated with this portion of the alternative. Although the biomass component would require 

31 offsite land use for the cultivation of energy crops (fuel), land use impacts associated with the 

32 production of crops is already occurring and would be the same regardless of whether crops are 

33 used as feedstock for electricity generation, for food, or for some other purpose. The NRC staff 

34 concludes that the overall impacts of implementing the combination alternative on land use 

35 would be SMALL.

36 4.2.7.2 Visual Resources

37 The NRC staff did not identify any impacts for the natural gas and biomass portions of the 

38 combination alternative beyond those discussed in the impacts common to all replacement 

39 power alternatives and those described for the natural gas alternative. The demand-side 

40 management portion of the combination alternative would not result in any visual impacts. The 
4-9

1 NRC staff concludes that impacts of implementing the combination alternative on visual 

2 resources would be SMALL.

3 4.3 Air Quality and Noise

4 This section describes the potential air quality and noise impacts of the proposed action (license 

5 renewal) and alternatives to the proposed action.

6 4.3.1 Proposed Action

7 4.3.1.1 Air Quality

8 As identified in Table 4-1, the impacts of all generic air quality issues would be SMALL. 

9 Table 4-2 does not identify any site-specific (Category 2) air quality issues for RBS. 

10 4.3.1.2 Noise

11 As identified in Table 4-1, the impacts of all generic noise issues would be SMALL. Table 4-2 

12 does not identify any site-specific (Category 2) noise issues for RBS. 

13 4.3.2 No-Action Alternative

14 4.3.2.1 Air Quality

15 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

16 shut down on or before the expiration of the current facility operating license. When the plant 

17 stops operating, there would be a reduction in air pollutant emissions from activities related to 

18 plant operation, such as use of combustion sources (diesel generators, engines), use of cooling 

19 towers, and vehicle traffic. Activity from these air emission sources would not cease, but 

20 emissions would be lower. Therefore, the NRC staff concludes that if emissions decrease, the 

21 impact on air quality from shutdown of RBS would be SMALL. 

22 4.3.2.2 Noise

23 When the plant stops operating, there will be a reduction in noise from activities related to plant 

24 operation, including noise from the turbine generator, onsite gun range, and vehicle traffic 

25 (e.g., workers, deliveries). As activity from noise sources is reduced, NRC staff expects the 

26 impact on ambient noise levels is expected to be less than current operations of RBS; therefore, 

27 the NRC staff concludes that the impacts of the no-action alternative on noise would be SMALL. 

28 4.3.3 Replacement Power Alternatives: Air Quality and Noise Common Impacts

29 4.3.3.1 Air Quality 

30 Construction of a power station would result in temporary impacts on local air quality. Air 

31 emissions would be intermittent and would vary based on the level and duration of specific 

32 activities throughout the construction phase. During the construction phase, the primary 

33 sources of air emissions would consist of engine exhaust and fugitive dust emissions. Engine 

34 exhaust emissions would be from heavy construction equipment and commuter, delivery, and 

35 support vehicular traffic traveling to and from the facility as well as within the site. Fugitive dust 

36 emissions would be from soil disturbances by heavy construction equipment (e.g., earthmoving, 

37 excavating, and bulldozing); vehicle traffic on unpaved surfaces; concrete batch plant 
4-10

1 operations; and wind erosion to a lesser extent. Various mitigation techniques and best 

2 management practices (BMPs) (e.g., watering disturbed areas, reducing equipment idle times, 

3 and using ultra-low sulfur diesel fuel) could be used to minimize air emissions and to reduce 

4 fugitive dust. Air emissions include criteria pollutants (particulate matter, nitrogen oxides, 

5 carbon monoxide, and sulfur dioxide), volatile organic compounds (VOCs), hazardous air 

6 pollutants (HAPs), and greenhouse gases (GHGs). Small quantities of volatile organic 

7 compounds and hazardous air pollutants would be released from equipment refueling, onsite 

8 maintenance of the heavy construction equipment, and other construction-finishing activities as 

9 well as from cleaning products, petroleum-based fuels, and certain paints.

10 The impacts on air quality as a result of operation of a power station will depend on the energy 

11 technology (i.e., fossil-fuel based or nuclear). Fossil-fuel based power plants result in larger 

12 amounts of air emissions than nuclear power plants. Worker vehicles, auxiliary power 

13 equipment, and mechanical draft cooling tower operation will result in additional emissions.

14 4.3.3.2 Noise

15 Construction of a power station is similar to construction of any large industrial project in that all 

16 involve many noise-generating activities. In general, noise emissions vary with each phase of 

17 construction, depending on the level of activity, the mix of construction equipment for each 

18 phase, and site-specific conditions. Several factors, including source-receptor configuration, 

19 land cover, meteorological conditions (e.g., temperature, relative humidity, and vertical profiles 

20 of wind and temperature), and screening (e.g., topography, and natural or man-made barriers), 

21 affect noise propagation to receptors. Typical construction equipment, such as dump trucks, 

22 loaders, bulldozers, graders, scrapers, air compressors, generators, and mobile cranes, would 

23 be used, and pile-driving and blasting activities would take place. Other noise sources include 

24 commuter, delivery, and support vehicular traffic traveling to and from the facility and within the 

25 site. However, noise from vehicular traffic related to constructing a replacement power

26 alternative would be intermittent and similar to current RBS noise levels from vehicular traffic. 

27 During the construction phase, a variety of construction equipment would be used for varying 

28 durations. Noise levels from construction equipment at 50 ft (15 m) distance are typically in the 

29 85- to 100-dBA range (DoT 2006); however, noise levels attenuate rapidly with distance. For

30 instance, at a 0.9 mi (1.4-km) distance from construction equipment with a sound strength of 

31 85 dBA, noise levels drop to 45 dBA (GSU 2016). Given the approximate distance of noise 

32 sensitive receptors to the site of the replacement power alternatives (0.85 mi (1.4 km)), the NRC 

33 staff does not expect noise to be noticeable from construction equipment.

34 Noise from replacement power alternative plant operation will result from both continuous onsite 

35 sources, such as mechanical draft cooling towers, transformers, turbines, and other auxiliary 

36 equipment, as well as offsite sources, such as vehicular traffic (e.g., employee commuting, 

37 delivery, and support). Offsite noise as a result of vehicles would be intermittent and similar to 

38 current RBS noise levels from vehicular traffic. Similarly, noise sources and levels during 

39 operation of replacement power alternatives would be similar to existing RBS conditions. 

40 4.3.4 New Nuclear Alternative

41 4.3.4.1 Air Quality

42 Air emissions and sources would include those identified in Section 4.3.3.1. Because air 

43 emissions from construction activities would be limited, local, and temporary, the NRC staff 
4-11

1 concludes that the associated air quality impacts from construction of a new nuclear alternative 

2 would be SMALL.

3 Operation of a new nuclear generating plant would result in air emissions similar in magnitude to 

4 those of RBS. Sources of air emissions will include stationary combustion sources (e.g., diesel 

5 generators and auxiliary boilers), mechanical draft cooling towers, and mobile sources 

6 (e.g., worker vehicles, onsite heavy equipment, and support vehicles). In general, most 

7 stationary combustion sources at a nuclear power plant would operate only for limited periods, 

8 often during periodic maintenance testing. A new nuclear power plant would need to secure a 

9 permit from the Louisiana Department of Environmental Quality for air pollutants associated with 

10 its operations (e.g., criteria pollutants, volatile organic compounds, hazardous air pollutants, and 

11 greenhouse gases). The NRC staff expects the air emissions for combustion sources from a 

12 new nuclear plant to be similar to those currently being emitted from RBS (see Section 3.2.1). 

13 Therefore, NRC staff expects emissions to fall far below the threshold for major sources 

14 (100 tons (91 MT) per year) and the threshold for mandatory greenhouse gas reporting 

15 (27,558 tons (25,000 MT) per year of carbon dioxide equivalents (CO2eq)). Additional air 

16 emissions would result from the 680 employees commuting to and from the new nuclear facility. 

17 The NRC staff does not expect air emissions from operation of a new nuclear alternative to 

18 contribute to National Ambient Air Quality Standard violations. The NRC staff concludes that 

19 the impacts of operation of a new nuclear alternative on air quality would be SMALL.

20 4.3.4.2 Noise

21 Noise sources for a new nuclear alternative would include those identified above under 

22 Section 4.3.3.2. Based on the temporary nature of construction activities, distance of 

23 noise-sensitive receptors from the site, consideration of noise attenuation from the construction 

24 site, and good noise control practices, the NRC staff concludes that the potential noise impacts 

25 of construction activities from a new nuclear alternative would be SMALL. Noise sources and 

26 levels during operation of a new nuclear alternative would be similar to existing RBS conditions. 

27 Therefore, the NRC staff concludes that noise impacts from operation of a new nuclear 

28 alternative would be SMALL.

29 4.3.5 Supercritical Pulverized Coal Alternative

30 4.3.5.1 Air Quality

31 Air emissions and sources for construction of the coal alternative would include those identified 

32 above under Section 4.3.3.1. Since air emissions from construction activities would be limited, 

33 local, and temporary, the NRC staff concludes that the associated air quality impacts from 

34 construction would be SMALL.

35 The staff estimated air emissions for operating the coal alternative using air emission factors 

36 developed by the U.S. Department of Energy’s (DOE’s) National Energy Technology Laboratory 

37 (NETL 2010a) for a supercritical pulverized coal power plant that is equipped with low nitrogen 

38 oxide burners and over-fire air to control nitrogen oxides, wet limestone forced-oxidation 

39 scrubbers to control sulfur dioxide, and a monoethanolamine (MEA)-based solvent process to 

40 remove carbon dioxide from the flue gas. Assuming a total gross capacity of 1,200 MW and 

41 capacity factor of 0.85, the NRC staff estimates the following air emissions for the coal units: 

42 • sulfur dioxide (SO2)—140 tons (127 MT) per year

43 • nitrogen oxides (NOx)—4,030 tons (3,655 MT) per year
4-12

1 • particulate matter (PM10)—770 tons (698 MT) per year

2 • carbon monoxide (CO)—90 tons (81 MT) per year

3 • mercury (Hg)—0.07 tons (0.06 MT) per year

4 • carbon dioxide equivalent (CO2eq)—1.30 million tons (1.18 million MT) per year

5 Operation of the mechanical draft cooling tower would result in additional particulate matter 

6 emissions over the values presented above. Indirect criteria emission sources will include up to 

7 300 worker vehicles commuting to and from the coal facility and particulate matter as result of 

8 coal mining. A new coal plant would qualify as a major-emitting industrial facility and would be 

9 subject to a New Source Review (NSR) and Title V, “Permits,” permitting requirements under 

10 the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7651 et seq.). These permitting 

11 requirements ensure that the plant operator minimizes air emissions and does not substantially 

12 degrade the local air quality. Additionally, various Federal and State regulations aimed at 

13 controlling air pollution would affect a coal plant. 

14 Based on the NRC staff’s air emission estimates listed above, criteria pollutant emissions and 

15 greenhouse gas emissions from a coal alternative would be noticeable and significant. Carbon 

16 dioxide emissions would be much larger than the threshold in the U.S. Environmental Protection 

17 Agency’s Greenhouse Gas Tailoring Rule, and nitrogen oxide and particulate matter emissions 

18 would exceed the threshold for major sources. As a result of the significant criteria air 

19 emissions (nitrogen oxides and particulate matter) and greenhouse gas emissions, the NRC 

20 staff concludes that the air quality impacts associated with operation of a coal alternative would 

21 be MODERATE.

22 4.3.5.2 Noise

23 Noise sources would include those identified above under Section 4.3.3.2. Both onsite and 

24 offsite noise sources would be intermittent and short term, lasting only through the duration of 

25 plant construction. Based on the temporary nature of construction activities, distance of noise 

26 sensitive receptors from the site, consideration of noise attenuation from the construction site, 

27 and good noise control practices, the NRC staff concludes that the potential noise impacts of 

28 construction activities from a coal alternative would be SMALL. 

29 In addition to the onsite and offsite noise sources discussed above under Section 4.3.3.2 as 

30 common to all replacement power alternatives, intermittent noise would result from delivery of 

31 coal via the Mississippi River to the facility to support operation of a coal power plant. However, 

32 noise levels from onsite and offsite sources would be similar to existing conditions since noise 

33 sources would be similar to those resulting from operation of RBS and waterborne commerce 

34 on the Mississippi River. Therefore, the NRC staff concludes that noise impacts from operation 

35 of a coal alternative would be SMALL.

36 4.3.6 Natural Gas Combined-Cycle Alternative

37 4.3.6.1 Air Quality

38 Air emissions and sources for construction of the natural gas alternative would include those 

39 identified above under Section 4.3.3.1. There would also be additional air emissions resulting 

40 from construction of a new or upgraded pipeline that will connect to existing natural gas supply 

41 lines east of the site. Air emissions would be localized, intermittent, and short lived, and 

42 adherence to well-developed and well-understood construction best management practices 

43 would mitigate air quality impacts. Therefore, the NRC staff concludes that construction-related 
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1 impacts on air quality from a natural gas alternative would be of relatively short duration and 

2 would be SMALL.

3 Operation of a natural gas plant would result in emissions of criteria pollutants and greenhouse

4 gases. The sources of air emissions during operation include gas turbines through heat 

5 recovery steam generator stacks. The staff estimated air emissions for the natural gas 

6 alternative using emission factors developed by the U.S. Department of Energy’s National 

7 Energy Technology Laboratory (NETL 2010a). Assuming a total gross capacity of 1,200 MW 

8 and capacity factor of 0.87, the NRC staff estimates the following air emissions for the natural 

9 gas units:

10 • sulfur oxides—14 tons (12 metric tons (MT)) per year

11 • nitrogen oxides—305 tons (277 MT) per year

12 • carbon monoxide—30 tons (27 MT) per year

13 • PM10—22 tons (20 MT) per year

14 • carbon dioxide equivalents (CO2eq)—3.9 million tons (3.6 million MT) per year

15 Operation of the mechanical draft cooling towers and up to 180-worker vehicles would also 

16 result in additional criteria emissions above those presented in the list. Operation of a new 

17 natural gas plant would qualify as a major-emitting industrial facility and would be subject to a 

18 New Source Review and Title V air permitting requirements under the Clean Air Act of 1970, as 

19 amended (42 U.S.C. 7651 et seq.), to ensure that air emissions are minimized and that the local 

20 air quality is not substantially degraded. Additionally, various Federal and State regulations 

21 aimed at controlling air pollution would affect a natural gas alternative.

22 Based on the NRC staff’s air emission estimates, nitrogen oxide and greenhouse gas emissions 

23 from a natural gas plant would be noticeable and significant. Carbon dioxide emissions would 

24 be much larger than the threshold in EPA’s Greenhouse Gas Tailoring Rule, and nitrogen oxide 

25 emissions would exceed the threshold for major sources. The NRC staff concludes that the 

26 overall air quality impacts associated with operation of a natural gas alternative would be 

27 SMALL to MODERATE.

28 4.3.6.2 Noise

29 In addition to the onsite and offsite noise sources discussed above under Section 4.3.3.2, 

30 construction of pipelines to support operation of a natural gas alternative would result in 

31 additional offsite noise. However, construction activities would be temporary and intermittent. 

32 In consideration of noise attenuation with distance and good noise control practices, the NRC 

33 staff concludes that the potential noise impacts of construction activities from a natural gas

34 alternative would be SMALL. During the operation phase, noise sources from a natural gas 

35 alternative would include those discussed above as well as offsite mechanical noise from 

36 compressor stations and pipeline blowdowns. The majority of noise-producing equipment 

37 (e.g., mechanical draft cooling towers, turbines, pumps) would be located inside the power 

38 block, and the NRC staff does not anticipate noise levels to be significantly greater than noise 

39 levels at RBS. Therefore, NRC staff concludes that operation-related noise impacts from the 

40 natural gas alternative would be SMALL.
4-14

1 4.3.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

2 Demand-Side Management)

3 4.3.7.1 Air Quality

4 Air quality impacts would result primarily from construction and operation of natural gas and 

5 biomass-fired portions of this combination alternative. The NRC staff does not anticipate air 

6 quality impacts from the demand-side management component of the combination alternative. 

7 Air emissions and sources for construction of the natural gas and biomass-fired portions of this 

8 combination alternative would include those identified above under Section 4.3.3.1. Air 

9 emissions from construction would be localized and intermittent, and well-understood 

10 construction best management practices would mitigate air quality impacts. Therefore, the NRC 

11 staff concludes that construction-related impacts on air quality from the natural gas and 

12 biomass-fired portions of the combination alternative would be SMALL.

13 Air emissions associated with the operation of the natural gas portion of the combination 

14 alternative are similar to those associated with the natural gas alternative. However, emissions 

15 associated with the natural gas portion of the combination alternative are reduced proportionally 

16 because the electricity output of the natural gas unit under the combination alternative is 

17 66 percent of that of the natural gas only alternative. Operation of the four biomass-fired units 

18 would result in emissions from the conversion of the fuel feedstock (crops, forest and crop 

19 residue, wood waste, and municipal solid waste) into a gas that will primarily consist of carbon 

20 monoxide and carbon dioxide. Emissions from biomass-fired plants depend on the type of 

21 biomass feedstock and gasification technology (Ciferno and Marano 2002; NREL 2003). 

22 The NRC staff estimates the following air emissions for the natural gas and biomass-fired 

23 portions of the combination alternative based on emission factors developed by the 

24 U.S. Department of Energy’s National Energy Technology Laboratory and the National Renewal

25 Energy Laboratory (NETL 2010a; NREL 1997):

26 • sulfur oxides—80 tons (73 metric tons (MT)) per year

27 • nitrogen oxides—1,600 tons (1,450 MT) per year

28 • carbon monoxide—7,240 tons (6,570 MT) per year

29 • PM10—365 tons (332 MT) per year

30 • carbon dioxide equivalents (CO2eq)—4.7 million tons (4.2 million MT) per year

31 Operation of the mechanical draft cooling towers and up to 210-worker vehicles would also 

32 result in additional criteria emissions above those presented in the list. New natural gas and 

33 biomass-fired units would qualify as major-emitting industrial facilities and would be subject to a 

34 New Source Review and the Federal and State regulations aimed at controlling air pollution. 

35 Based on the air emission estimates shown above, the NRC staff expects that nitrogen oxide, 

36 carbon monoxide, and greenhouse gas emissions from the natural gas and biomass portions of 

37 the combination alternative would be noticeable and significant. Carbon dioxide emissions 

38 would be much larger than the threshold in EPA’s Greenhouse Gas Tailoring Rule, and nitrogen 

39 oxide and carbon monoxide emissions would exceed the threshold for major sources. The NRC 

40 staff concludes that the overall air quality impacts associated with operation of the combination 

41 alternative would be MODERATE.
4-15

1 4.3.7.2 Noise

2 The onsite and offsite construction-related noise sources for the natural gas portion of the 

3 combination alternative would be similar to those for construction of the natural gas alternative 

4 discussed above under Section 4.3.6.2. The construction-related noise sources for the biomass 

5 portion of the combination alternative would include those discussed above and would be 

6 intermittent and temporary. Given the distance of noise sensitive receptors from the site, the 

7 NRC staff concludes that the potential noise impacts of construction activities from the biomass 

8 portion of this alternative would be SMALL. Therefore, the NRC staff concludes that 

9 construction impacts from the combination alternative would be SMALL. 

10 The NRC staff does not anticipate noise impacts from the demand-side management

11 component of the combination alternative. Offsite and onsite noise sources from operation of 

12 the natural gas and biomass portions of the combination alternative would include those 

13 identified above. Noise levels during operation of the natural gas and biomass portions of this 

14 combination alternative would be similar to existing conditions associated with noise from RBS 

15 operations since the noise sources are similar. Therefore, noise impacts from operation of the 

16 combination alternative would not be noticeable and would be SMALL. 

17 4.4 Geologic Environment

18 This section describes the potential geology and soils impacts of the proposed action (license 

19 renewal) and alternatives to the proposed action.

20 4.4.1 Proposed Action

21 As identified in Table 4-1, the impacts of the single geologic environment issue (geology and 

22 soils) would be SMALL. Table 4-2 does not identify any site-specific (Category 2) geologic 

23 environment issues. 

24 4.4.2 No-Action Alternative

25 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

26 shut down on or before the expiration of the current facility operating license. There would not 

27 be any impacts to the geology and soils at the RBS site with shutdown of the facility. With the 

28 shutdown of the facility, no additional land would be disturbed. Therefore, impacts on geology 

29 and soil resources from the no-action alternative would be SMALL.

30 4.4.3 Replacement Power Alternatives: Common Impacts

31 During construction for all the replacement power alternatives, sources of aggregate material, 

32 (such as crushed stone, sand, and gravel) would be required to construct buildings, foundations, 

33 roads, and parking lots. The NRC staff presumes that these resources would likely be obtained 

34 from commercial suppliers using local or regional sources. Land clearing during construction 

35 and installation of power plant structures and impervious surfaces would expose soils to erosion 

36 and alter surface drainage. Best management practices would be implemented in accordance 

37 with applicable permitting requirements so as to reduce soil erosion. These practices would 

38 include the use of sediment fencing, staked hay bales, check dams, sediment ponds, and riprap 

39 aprons at construction and laydown yard entrances; mulching and geotextile matting of 

40 disturbed areas; and rapid reseeding of temporarily disturbed areas. Removed soils and any 

41 excavated materials would be stored onsite for redistribution such as for backfill at the end of 
4-16

1 construction. Construction impacts would be temporary and localized. Therefore, the common 

2 impacts of construction on geology and soil resources would be SMALL.

3 During operations for all the replacement power alternatives, no additional land would be 

4 disturbed. Therefore, the NRC staff concludes that the common impacts of operations on 

5 geology and soil resources would be SMALL.

6 4.4.4 New Nuclear Alternative

7 The NRC staff did not identify any impacts to the geologic environment for the new nuclear 

8 alternative beyond those discussed above as common to all replacement power alternatives. 

9 Therefore, NRC staff concludes that the impacts to geology and soil resources from 

10 construction and operation of a new nuclear alternative would be SMALL.

11 4.4.5 Supercritical Pulverized Coal Alternative

12 The NRC staff did not identify any impacts to the geologic environment for the coal alternative 

13 beyond those discussed above as common to all replacement power alternatives. Therefore, 

14 NRC staff concludes that the impacts to geology and soil resources from construction and 

15 operation of a coal alternative would be SMALL. 

16 4.4.6 Natural Gas Combined-Cycle Alternative

17 The NRC staff did not identify any impacts to the geologic environment for the natural gas 

18 alternative beyond those discussed above as common to all replacement power alternatives. 

19 Therefore, NRC staff concludes that the impacts to geology and soil resources from 

20 construction and operation of a natural gas alternative would be SMALL.

21 4.4.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

22 Demand-Side Management)

23 The NRC staff did not identify any geologic impacts for the combination alternative beyond 

24 those discussed above. Therefore, NRC staff concludes that the impacts to geology and soil 

25 resources from construction and operation of a combination alternative would be SMALL.

26 4.5 Water Resources

27 This section describes the potential surface water and groundwater resources impacts of the 

28 proposed action (license renewal) and alternatives to the proposed action.

29 4.5.1 Proposed Action

30 4.5.1.1 Surface Water Resources

31 As identified in Table 4-1, the impacts of all generic surface water resources issues would be 

32 SMALL. Table 4-2 identifies the one site-specific (Category 2) issue related to surface water 

33 resources applicable to RBS during the license renewal term. This issue is analyzed below.
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1 Category 2 Issue Related to Surface Water Resources: Surface Water Use Conflicts (Plants 

2 with Cooling Ponds or Cooling Towers Using Makeup Water from a River)

3 For nuclear power plants using cooling towers or cooling ponds supplied with makeup water 

4 from a river, the potential impact on the flow of the river and water availability to meet the 

5 demands of other users is a Category 2 issue. Category 2 issues require a plant-specific 

6 assessment. 

7 In evaluating the potential impacts resulting from surface water use conflicts associated with 

8 license renewal, the NRC staff uses as its baseline the resource conditions described in 

9 Section 3.5.1. These baseline conditions encompass the defined hydrologic (flow) regime of the 

10 surface water(s) that are potentially affected by continued operations, as well as the magnitude 

11 of surface water withdrawals for cooling and other purposes (as compared to any applicable 

12 appropriation and permitting standards). The baseline also considers other downstream uses 

13 and users of surface water.

14 The mean annual discharge of the Lower Mississippi River measured at the U.S. Geological 

15 Survey (USGS) gage at Baton Rouge, LA, is 547,373 cubic feet per second (cfs) (15,463 cubic 

meters per second (m3

/s)). RBS withdraws an average of 27.4 cfs (0.77 m3 16 /s), equivalent to 

17.7 mgd (67,000 m3 17 /day), of water from the St. Francisville reach of the Lower Mississippi 

River. Consumptive use averages 21.4 cfs (0.6 m3

/s), or about 13.8 mgd (52,200 m3 18 /day). This 

19 consumptive use is equivalent to about 0.004 percent of the Lower Mississippi River’s mean 

20 annual discharge (flow).

21 In addition to considering average flow conditions, the NRC staff also evaluated the impacts of 

22 continued RBS operations on low-flow conditions in the Mississippi River Basin and the Lower 

23 Mississippi River. At the Baton Rouge gaging station, the lowest daily mean flow observed to 

date is 141,000 cfs (3,980 m3 24 /s) recorded on October 31, 2012, and the 90 percent exceedance 

flow is approximately 235,500 cfs (6,650 m3 25 /s) for the station’s period of record. The 90 percent 

26 exceedance flow is an indicator value for hydrologic drought.

27 Due to the operation of the Old River Control Structure, river flow past the RBS site would not 

be expected to fall below 100,000 cfs (2,800 m3 28 /s) in the future given current hydrologic 

29 conditions in the river basin.

30 Compared to the established indicators of low-flow conditions as recorded at Baton Rouge 

31 (i.e., lowest daily mean and 90-percent exceedance flows), RBS’s current consumptive water 

use (i.e., 21.4 cfs (0.6 m3 32 /s)) represents a 0.015 and a 0.009-percent reduction, respectively, in 

33 the flow of the river downstream of the RBS property. The NRC staff finds these hydrologic 

34 effects to be negligible. Further, Entergy states that RBS’s consumptive water use would not be 

35 expected to increase during the license renewal term (Entergy 2017h).

36 In conclusion, the NRC staff’s review indicates that consumptive water use associated with RBS 

37 operations would continue to have no substantial impact on downstream water availability. 

38 RBS’s surface water withdrawals and relatively low rate of consumptive use of river flow from 

39 the Lower Mississippi River are unlikely to measurably impact downstream water availability or 

40 instream uses of surface water within the St. Francisville reach of the river during the license 

41 renewal term. Thus, operation of RBS during the license renewal term is not expected to result 

42 in a water use conflict on the Lower Mississippi River. In total, the NRC staff concludes that the 

43 potential impacts on surface water resources and downstream water availability from RBS’s 
4-18

1 continued withdrawals and consumptive water use during the license renewal term would be 

2 SMALL. 

3 4.5.1.2 Groundwater Resources

4 As identified in Table 4-1, the impacts of all generic groundwater resources issues would be 

5 SMALL. Table 4-2 identifies two site-specific (Category 2) issues related to groundwater 

6 resources applicable to RBS during the license renewal term. These issues are analyzed 

7 below.

8 Groundwater Use Conflicts (Plants with Closed-Cycle Cooling Systems That Withdraw Makeup 

9 Water from a River)

10 This issue evaluates the potential for water withdrawals from a river to cause groundwater use 

11 conflicts with other users. It is concerned with the potential for the consumptive use of river to 

12 lower the water level in aquifers hydrologically connected to the river. If water levels in aquifers 

13 hydrologically connected to the river decrease, this could reduce the availability of water in the 

14 aquifers. This issue is most concerned with impacts during low flows when the extraction of 

15 river water could have a more noticeable impact on water levels in aquifers hydrologically 

16 connected to the river.

17 The consumption of Mississippi River water by RBS should have no discernible impact on the 

18 availability of groundwater supplies. Dewatering of aquifers hydrologically connected to the 

19 Mississippi River would occur if the head in the river dropped below the heads in aquifers 

20 hydrologically connected to the river. As described in Section 4.5.1.1, the probable minimum 

21 flow rate of the Mississippi River at RBS during the operating life of the station is not anticipated 

to be less than 100,000 cfs (2,800 m3 22 /s). During this low flow period, RBS would consume 

23 0.02 percent of the flow in the Mississippi River (Entergy 2017h). This would have little if any 

24 effect on river water levels and therefore significant dewatering of connected aquifers as a result 

25 of river water consumption should not occur. Therefore, the NRC staff concludes that the 

26 impact on groundwater resources as a result of Mississippi River water consumption is SMALL.

27 Radionuclides Released to Groundwater

28 The issue of “radionuclides released to groundwater” looks at the potential contamination of 

29 groundwater from the release of radioactive liquids from plant systems into the environment. 

30 Section 3.5.2.4 of this SEIS contains a description of RBS groundwater quality and 

31 radionuclides RBS has released into groundwater.

32 As discussed in Section 3.5.2.4, the quality of offsite groundwater and surface water supplies 

33 has not been impacted by radiological contamination of onsite groundwater and should continue 

34 to be unaffected over the period of license renewal. NRC staff has concluded that over the 

35 period of extended operation, groundwater contamination will likely remain onsite.

36 Tritium contamination exists in the Upland Terrace Aquifer beneath and immediately to the west 

37 of the RBS power block area. Thick clay units beneath the Upland Terrace Aquifer keep any 

38 radiological contamination within the Upland Terrace Aquifer from moving deeper into 

39 underlying aquifers.

40 Entergy believes all of the tritium contamination currently found within the Upland Terrace 

41 Aquifer is the result of liquid spills that occurred within the turbine building. Entergy has taken 
4-19

1 corrective actions and resealed turbine building floor joints to stop any future leaks. However, it 

2 is too early for the NRC staff to conclude that Entergy has identified and stopped all of the 

3 sources of the tritium leaks.

4 Potable water at RBS is supplied by the West Feliciana Parish Consolidated Water District 

5 No. 13 Water Supply System. The direction of groundwater flow within the Upland Terrace 

6 Aquifer will cause tritium in the groundwater to leave the site where the site boundary meets the 

7 Mississippi River. No offsite, private or public wells are located along the direction of 

8 groundwater flow. Therefore, neither RBS drinking water nor offsite groundwater should come 

9 in contact with the tritium contamination in the groundwater caused by RBS activities.

10 As groundwater moves through the Upland Terrace Aquifer towards the Mississippi River, 

11 natural attenuation processes should readily reduce the concentration of tritium within the 

12 groundwater. Any tritium-containing groundwater moving into the Mississippi River will be 

13 diluted and reduced in concentration by the large volume of water in the river. In addition, 

14 Entergy estimates that it is unlikely that the concentration of tritium from RBS releases would be 

15 above minimum detection levels in the river (Entergy 2017h).

16 The groundwater monitoring program at RBS is robust and has detected radionuclide leaks into 

17 the groundwater. Any large leaks that might occur during the period of license renewal should 

18 be readily detected. If leaks to the groundwater are stopped before or during the period of 

19 license renewal, onsite groundwater quality could be restored through either active restoration 

20 or monitored natural attenuation.

21 The onsite impacts on groundwater quality at RBS are currently detectible within the Upland 

22 Terrace Aquifer and are sufficient to alter noticeably, but not to destabilize, important attributes 

23 of this resource. If Entergy has not identified and stopped all of the sources of the tritium leaks, 

24 and if tritium continues to leak into the groundwater during the period of license renewal, the 

25 impact on groundwater quality in this aquifer during the license renewal period could be 

26 MODERATE. However, with the elimination of radionuclide leaks to groundwater, either 

27 through active remediation activities or monitored natural attenuation, the impact on 

28 groundwater quality could be SMALL. Based on this information, the NRC staff concludes that 

29 the impact of radionuclides released to groundwater at RBS during the license renewal term 

30 could range from SMALL to MODERATE.

31 4.5.2 No-Action Alternative

32 4.5.2.1 Surface Water Resources

33 Surface water withdrawals and the rate of consumptive water use would greatly decrease and 

34 would eventually cease after RBS is shut down. Wastewater discharges would be reduced 

35 considerably. As a result, shutdown would reduce the overall impacts on surface water use and 

36 quality. Stormwater runoff would continue to be discharged from the plant site to ditches and 

37 receiving waters. Overall, the impact of the no-action alternative on surface water resources 

38 would remain SMALL.

39 4.5.2.2 Groundwater Resources

40 With the cessation of operations, there should be a reduction in onsite groundwater

41 consumption and little or no additional impacts on groundwater quality. Therefore, the NRC 
4-20

1 staff concludes that the impact of the no-action alternative on groundwater resources would be 

2 SMALL.

3 4.5.3 Replacement Power Alternatives: Common Impacts

4 4.5.3.1 Surface Water Resources

5 Construction

6 Construction activities associated with replacement power alternatives may cause temporary 

7 impacts to surface water quality by increasing sediment loading to waterways. Construction 

8 activities may also impact surface water quality through pollutants in stormwater runoff from 

9 disturbed areas and excavations, spills and leaks from construction equipment, and any dredge

10 and fill activities. These sources could potentially affect downstream surface water quality. 

11 Potential hydrologic impacts would vary depending on the nature and acreage of land area 

12 disturbed and the intensity of excavation work. 

13 Nevertheless, all site construction activities would have to be conducted under a Louisiana 

14 Department of Environmental Quality-issued Louisiana Pollutant Discharge Elimination System 

15 (LPDES) general permit for stormwater discharges from large construction sites (i.e., 5 ac (2 ha) 

16 or more) (LAC 33:IX.2515; LDEQ 2017d). This general permit requires the development and 

17 implementation of a stormwater pollution prevention plan including use of appropriate best 

18 management practices for waste management, water discharge, stormwater pollution 

19 prevention, soil erosion control, site stabilization techniques, and spill prevention practices to 

20 prevent or minimize any surface water quality impacts during construction.

21 In addition, to minimize hydrologic impacts and to maximize the use of existing infrastructure, 

22 Entergy (2017h) assumes that thermoelectric power generating replacement power alternatives

23 (i.e., new nuclear, coal, natural gas, and biomass-fired units) would use the existing RBS 

24 surface water intake and discharge infrastructure (after making necessary modifications and 

25 refurbishment). The NRC further assumes that the builders of these facilities would use the 

26 existing RBS mechanical draft cooling towers or construct new cooling towers as necessary on 

27 previously disturbed land. Any necessary dredge-and-fill operations in waterways or wetlands 

28 would be conducted under a permit from the U.S. Army Corps of Engineers (USACE) and 

29 State-equivalent permits requiring the implementation of applicable best management practices 

30 to minimize associated impacts. 

31 For all replacement power alternatives, water would be required for potable and sanitary use by 

32 the construction workforce and for concrete production, equipment cleaning, dust suppression, 

33 soil compaction, and other miscellaneous uses depending on the replacement power 

34 alternative. In its environmental report, Entergy (2017h) assumes that there would be no direct 

35 use of surface water during construction. The project builder could obtain construction water 

36 from the municipal water utility (i.e., West Feliciana Parish Consolidated Water District No. 13) 

37 via a service connection or possibly truck the water to the point of use from the local utility. 

38 Alternatively, the builder could also use onsite groundwater to support construction. 

39 Operation

40 The thermoelectric power generating components of the replacement power alternatives would 

41 use mechanical draft cooling towers operating in a closed-cycle configuration. Makeup water 

42 would be obtained from the Lower Mississippi River. Power plants using closed-cycle cooling 
4-21

1 systems with cooling towers withdraw substantially less water for condenser cooling than a 

2 thermoelectric power plant using a once-through system. However, the relative percentage of 

3 consumptive water use is greater in closed-cycle plants because of evaporative and drift losses 

4 during cooling tower operation (NRC 2013b). Any surface water withdrawals would be subject 

5 to applicable State water appropriation and registration requirements (see Section 3.5.1.2). In 

6 addition, closed-cycle cooling systems typically require chemical treatment. Specifically, cooling 

7 towers commonly require biocide injections to control biofouling and other chemical additives for 

8 corrosion control in plant systems (NRC 2013b). For example, RBS currently requires such 

9 additives for proper operation. Residual concentrations of these chemical additives would be 

10 present in the cooling tower blowdown discharged to receiving waters, such as the Lower 

11 Mississippi River, under all thermoelectric power alternatives.

12 Nevertheless, any chemical additions would be accounted for in the operation and permitting of 

13 liquid effluents. All effluent discharges from the thermoelectric power generating components 

14 under these replacement power alternatives would be subject to Louisiana Pollutant Discharge 

15 Elimination System permit requirements for the discharge of wastewater and industrial 

16 stormwater to waters of the United States. Effluent limitations and monitoring requirements 

17 imposed under the permits would ensure compliance with applicable State ambient water 

18 quality standards.

19 To prevent and respond to accidental non-nuclear releases to surface waters, facility operations 

20 under all alternatives would be conducted in accordance with a spill prevention, control, and 

21 countermeasures plan; stormwater pollution prevention plan; or equivalent plans and associated 

22 best management practices and procedures.

23 4.5.3.2 Groundwater Resources

24 Construction

25 During construction for all the replacement power alternatives, construction water might be 

26 obtained from onsite groundwater or from the local water utility. There is also likely to be a need 

27 for groundwater dewatering during excavation and construction. Pumped groundwater removed 

28 from excavations would be discharged in accordance with appropriate State and local permits. 

29 The application of best management practices in accordance with a State-issued Louisiana 

30 Pollutant Discharge Elimination System general permit, including an appropriate waste 

31 management, water discharge, and stormwater pollution prevention plan as well as spill 

32 prevention practices, would prevent or minimize groundwater quality impacts during 

33 construction. These groundwater impacts would be short lived. Therefore, the NRC staff 

34 concludes that the common impacts from construction on groundwater resources would be 

35 SMALL.

36 Operation

37 During operations for all the replacement power alternatives, the NRC staff assumes that 

38 potable water would be obtained from a local water service company rather than from onsite 

39 groundwater. Any groundwater withdrawals would be subject to applicable State water 

40 appropriation and registration requirements. Effluent discharges would be subject to Louisiana 

41 Pollutant Discharge Elimination System permit requirements for the discharge of wastewater

42 and industrial stormwater as described in Section 4.5.3.1. Therefore, the NRC staff concludes 

43 that the common impacts from operations on groundwater resources would be SMALL.
4-22

1 4.5.4 New Nuclear Alternative

2 4.5.4.1 Surface Water Resources

3 The hydrologic and water quality assumptions and implications for construction and operations 

4 as described in Sections 4.5.3.1 as common to all replacement power alternatives also apply to 

5 this alternative, except as noted below.

6 Potential surface water resources impacts could be greatest under the new nuclear alternative 

7 due to the larger land area required for construction of the new nuclear unit and deep 

8 excavation work required for the nuclear island. The NRC staff also estimates that groundwater

9 dewatering of deep excavations could be necessary. Nevertheless, the dewatering would not 

10 be expected to impact offsite surface water bodies, and water pumped from excavations would 

11 be managed and discharged in accordance with Louisiana Department of Environmental Quality 

12 requirements and would not be expected to affect offsite surface water quality.

13 Operation of a single AP1000 pressurized-water reactor using closed-cycle cooling would 

require approximately 25 mgd (38.7 cfs; 1.09 m3 14 /s) of surface water, with consumptive use of 

22 mgd (34 cfs; 0.96 m3 15 /s). This would be comparable to RBS’s design withdrawal and 

consumptive use rates of 23 mgd (35.6 cfs; 1.0 m3

/s) and 17.7 mgd (27.4 cfs; 0.77 m3 16 /s), 

17 respectively. Thus, consumptive water use under the new nuclear alternative would be 

18 negligible compared to the mean annual flow of the Lower Mississippi River. It would similarly 

19 represent a very small percentage (i.e., 0.02 percent or less) of potential low-flow conditions, as 

20 discussed in Section 4.5.1.1. 

21 Based on this analysis, the NRC staff concludes that the overall impacts on surface water

22 resources from construction and operations under the new nuclear alternative would be SMALL. 

23 4.5.4.2 Groundwater Resources

24 The NRC staff did not identify any impacts on groundwater resources for the new nuclear 

25 alternative beyond those discussed above as common to all replacement power alternatives. 

26 Therefore, NRC staff concludes that the impacts on groundwater resources from construction 

27 and operation of a new nuclear power plant would be SMALL.

28 4.5.5 Supercritical Pulverized Coal Alternative

29 4.5.5.1 Surface Water Resources

30 Impacts on surface water resources associated with this alternative would be similar to but 

31 potentially more than those under the new nuclear alternative. This is attributable to the smaller 

32 amount of land required for construction of the coal plant’s power block, but increased potential 

33 for runoff and leachate from onsite coal and ash piles. Otherwise, the same hydrologic and 

34 water quality assumptions and implications for construction and operations as described in 

35 Section 4.5.3.1 also apply to this alternative, except as noted.

36 Under the coal alternative, there would be the potential for hydrologic and water quality impacts 

37 to occur from the construction or refurbishment of the barge facilities that would be used to 

38 transport coal to the site location. Management of runoff and leachate from coal and ash 

39 storage facilities would require additional regulatory oversight and would present an additional 

40 risk to surface water resources during operations. Nevertheless, as described in 
4-23

1 Section 4.5.3.1, water quality impacts would be regulated under appropriate Louisiana 

2 Department of Environmental Quality-issued Louisiana Pollutant Discharge Elimination System 

3 permits, both for construction and operational impacts. U.S. Army Corps of Engineers permits 

4 would regulate construction in waterways and wetlands.

5 The coal facility would require more makeup water for operations than the new nuclear 

6 alternative but maintain similar consumptive water use, estimated at 20 mgd (30.9 cfs; 

0.87 m3 7 /s). Consumptive water use for coal facility operations would constitute a very small 

8 percentage (i.e., about 0.02 percent) of river flow under potential low-flow conditions, as 

9 referenced in Section 4.5.1.1. The potential for water use conflicts would be negligible. 

10 Based on the potential for additional hydrologic alteration and potential water quality impacts 

11 from new construction and coal and ash handling and management, the NRC staff concludes 

12 that impacts on surface water resources from construction and operations of a coal alternative 

13 would range from SMALL to MODERATE.

14 4.5.5.2 Groundwater Resources

15 With the exception of an increased potential for runoff and leachate from onsite coal and ash 

16 piles to degrade groundwater resources, the NRC staff did not identify any impacts on 

17 groundwater resources for the coal alternative beyond those discussed above as common to all 

18 replacement power alternatives. Therefore, NRC staff concludes that the impacts from 

19 construction and operation of a coal alternative on groundwater resources would be SMALL to 

20 MODERATE. 

21 4.5.6 Natural Gas Combined-Cycle Alternative

22 4.5.6.1 Surface Water Resources

23 The NRC staff expects that direct impacts on surface water resources from constructing a 

24 natural gas alternative would be much smaller than those from constructing either a new nuclear 

25 or coal facility because the natural gas facility requires less extensive excavation and 

26 earthwork. Otherwise, the same hydrologic and water quality assumptions and implications for 

27 construction and operations described in Sections 4.5.3.1 as common to all replacement power

28 alternatives also apply to the natural gas alternative, except as noted below. 

29 Construction of a natural gas facility may result in some additional, temporary impacts to surface 

30 water quality due to the need to construct new gas pipelines to service the facility. Some 

31 stream or wetlands crossings or subcrossings could be necessary. However, water quality 

32 impacts would be regulated under a Louisiana Department of Environmental Quality-issued 

33 LPDES general permit and the U.S. Army Corps of Engineers permits regulate construction in 

34 waterways and wetlands. The use of modern pipeline construction techniques, such as 

35 horizontal directional drilling, would further minimize the potential for hydrologic and water 

36 quality impacts.

37 For natural gas facility operations, cooling-water demand and consumptive water use would be 

38 substantially less than for new nuclear and coal plants. Consumptive water use under the 

natural gas alternative (estimated at 5.7 mgd (8.8 cfs; 0.25 m3 39 /s)) would be negligible compared 

40 to potential low-flow conditions of the Lower Mississippi River, as referenced in Section 4.5.1.1. 

41 The potential for water use conflicts would also be negligible. 
4-24

1 For the natural gas alternative, the NRC staff concludes that the overall impacts on surface 

2 water resources from construction and operations would be SMALL.

3 4.5.6.2 Groundwater Resources

4 The NRC staff did not identify any impacts on groundwater resources for the natural gas 

5 alternative beyond those discussed above as common to all replacement power alternatives. 

6 Therefore, the NRC staff concludes that the impacts from natural gas alternative construction 

7 and operation on groundwater resources would be SMALL.

8 4.5.7 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and 

9 Demand-Side Management)

10 4.5.7.1 Surface Water Resources

11 Construction of a natural gas plant and four biomass-fired units would have similar but 

12 somewhat greater potential water resources impacts than construction of a natural gas facility 

13 alone because the combination facilities would disturb a larger combined land area. Otherwise, 

14 the same hydrologic and water quality assumptions and implications for construction and 

15 operations described in Sections 4.5.3.1 as common to all replacement power alternatives also 

16 apply to the combination alternative, except as noted below.

17 Makeup water demand and consumptive water use for operation of the combination facility units 

18 would be similar to but somewhat greater than that for the natural gas alternative alone. 

19 However, the consumptive water use for the natural gas and biomass components of the 

combination alternative (estimated at 5.8 mgd (9.0 cfs; 0.25 m3 20 /s)) would still be negligible 

21 compared to potential low-flow conditions of the Lower Mississippi River, as referenced in 

22 Section 4.5.1.1.

23 The NRC staff does not expect implementation of the demand-side management component of 

24 this combination alternative to result in incremental impacts on surface water use and quality. In 

25 consideration of this information, the NRC staff concludes that the overall impacts on surface 

26 water resources from construction and operation of a combination alternative would be SMALL.

27 4.5.7.2 Groundwater Resources

28 The NRC staff did not identify any impacts for the combination alternative beyond those 

29 discussed above as common to all replacement power alternatives. Therefore, the NRC staff 

30 concludes that the impacts to groundwater resources from construction and operation of a 

31 combination alternative would be SMALL.

32 4.6 Terrestrial Resources

33 This section describes the potential terrestrial resources impacts of the proposed action (license 

34 renewal) and alternatives to the proposed action.

35 4.6.1 Proposed Action

36 As identified in Table 4-1, the impacts of all generic terrestrial resource issues would be SMALL. 

37 Table 4-2 identifies two RBS site-specific (Category 2) issues related to terrestrial resources 

38 during the license renewal term. These issues are analyzed below. 
4-25

1 4.6.1.1 Category 2 Issue Related to Terrestrial Resources: Effects on Terrestrial Resources 

2 (Non-cooling System Impacts)

3 According to the GEIS, non-cooling system impacts on terrestrial resources can include those 

4 impacts that result from landscape maintenance activities, stormwater management, elevated 

5 noise levels, and other ongoing operations and maintenance activities that would occur during 

6 the renewal period on and near a plant site.

7 Landscape Maintenance Activities 

8 Entergy’s (2017h) landscape maintenance practices primarily consist of grass cutting and weed 

9 control within developed or previously disturbed areas of the site. Transmission line 

10 rights-of-way cover approximately 8 ac (3.2 ha) of the Entergy property. Although vegetation is 

11 sparse in these areas because the lines cross the RBS industrial area, Entergy applies 

12 herbicide spot treatments on a 2-year cycle to control undesirable brush and woody vegetation.

13 Herbicide application volumes typically range from 10 to 25 gallons per brush acre, and all 

14 chemicals are applied according to label directions and manufacturer recommendations by 

15 licensed companies with qualified applicators. Approximately 87 percent (2,869 ac (1,161 ha)) 

16 of the RBS site remains as undeveloped, uncultivated natural areas (see Table 3-1 in 

17 Section 3.2.1.1). Entergy does not actively maintain these areas and has no plans to disturb 

18 any undeveloped areas as part of the proposed license renewal.

19 Stormwater Management

20 Stormwater runoff from impervious surfaces can change the frequency or duration of inundation 

21 and soil infiltration within neighboring terrestrial habitats. Effects may include erosion, altered 

22 hydrology, sedimentation, and other changes to plant community characteristics. Runoff may 

23 contain sediments, contaminants from road or parking surfaces, or herbicides. RBS’s Louisiana 

24 Pollutant Discharge Elimination System permit allows Entergy to discharge stormwater from four 

25 outfalls. Collection and discharge of excess stormwater to the Mississippi River minimizes the 

26 amount of excess runoff that terrestrial habitats would receive and the associated effects. 

27 Additionally, the Louisiana Pollutant Discharge Elimination System permit requires Entergy to 

28 maintain a stormwater pollution prevention plan (SWPP), which identifies potential sources of 

29 pollutants that could affect stormwater discharges and identifies best management practices 

30 that Entergy uses to reduce pollutants in stormwater discharges to ensure compliance with 

31 applicable conditions of the permit. The best management practices include procedures to 

32 minimize and respond to spills and leaks, handle industrial materials and wastes that can be 

33 readily mobilized by contact with stormwater, and minimize erosion and sedimentation, among 

34 other activities. Entergy further monitors areas with potential for spills of oil or other regulated 

35 substances under its Spill Prevention Control and Countermeasures Plan. Collectively, these 

36 measures ensure that the effects to terrestrial resources from pollutants carried by stormwater 

37 would be minimized during the proposed license renewal term.

38 Noise

39 The GEIS (NRC 2013b) indicates that elevated noise levels from transformers and cooling 

40 towers could disrupt wildlife behavioral patterns or cause animals to avoid such areas.

41 However, limited wildlife occurs in areas of the site with elevated noise levels due to the 

42 developed nature of the site, associated lack of high-quality habitat, and regular presence of 

43 human activity. Wildlife that does occur in developed areas has already adapted to the 

44 conditions of the site and is tolerant of disturbance. Therefore, noise associated with the 
4-26

1 continued operation of transformers and cooling towers during the proposed license renewal 

2 term is unlikely to create noticeable impacts on terrestrial resources.

3 Other Operations and Maintenance Activities

4 Operational and maintenance activities that Entergy (2017h) might undertake during the license 

5 renewal term include maintenance and repair of plant infrastructure such as roadways, piping 

6 installations, fencing, and security-related structures. These activities would likely be confined 

7 to previously disturbed areas of the site. Entergy anticipates performing no refurbishment

8 during the license renewal period. 

9 Entergy (2017h) maintains procedures to ensure that environmentally sensitive areas are 

10 adequately accounted for and protected during operational and maintenance activities and 

11 project planning. The procedures direct Entergy personnel to obtain appropriate local, State, or 

12 Federal permits (or some combination of the three) prior to beginning work; implement best 

13 management practices to protect wetlands, natural heritage areas, and sensitive ecosystems; 

14 and consult the appropriate agencies wherever federally or State-listed species may be 

15 affected. Additionally, RBS’s Environmental Protection Plan contained in Appendix B of the 

16 facility operating license requires Entergy to prepare an environmental evaluation for any 

17 construction or operational activities which may significantly affect the environment (NRC 1985). 

18 If such an evaluation indicates than an activity involves an unreviewed environmental question, 

19 the RBS Environmental Protection Plan requires that Entergy obtain approval from the NRC 

20 prior to performing the activity (NRC 1985). The renewed license, if issued, would include an 

21 environmental protection plan with identical or similar requirements.

22 Conclusion

23 Based on the NRC staff’s independent review, the staff concludes that the landscape 

24 maintenance activities, stormwater management, elevated noise levels, and other ongoing 

25 operations and maintenance activities that Entergy might undertake during the renewal term 

26 would primarily be confined to already disturbed areas of the RBS site. These activities would 

27 neither have noticeable effects on terrestrial resources nor would they destabilize any important 

28 attribute of the terrestrial resources on or in the vicinity of the RBS site. Accordingly, the NRC 

29 staff concludes that non-cooling system impacts on terrestrial resources during the license 

30 renewal term would be SMALL.

31 4.6.1.2 Water Use Conflicts with Terrestrial Resources (Plants with Cooling Ponds or Cooling 

32 Towers Using Makeup Water from a River)

33 Water use conflicts occur when the amount of water needed to support terrestrial resources is 

34 diminished as a result of agricultural, municipal, or industrial uses; droughts; or a combination of 

35 these factors.

36 Section 4.5.1.1 addresses surface water use conflicts and concludes that the potential impacts 

37 on surface water resources and downriver water availability from RBS’s consumptive water use 

38 during the license renewal term would be SMALL because of RBS’s very low consumptive use

39 relative to river flow. The State of Louisiana also imposes water withdrawal restrictions through 

40 the Louisiana Pollutant Discharge Elimination System permit to further ensure adequate 

41 instream and downstream flows. Section 4.7.1.1 addresses water use conflicts with aquatic 

42 resources and determines that RBS consumes a very small amount of the Mississippi River’s 

43 flow each year (about 0.004 percent of the Lower Mississippi River’s mean annual discharge) 
4-27

1 and that the impacts of water use conflicts would be SMALL for aquatic resources. The NRC 

2 staff finds no other impacts that terrestrial or riparian habitats or species would experience 

3 beyond those discussed in Sections 4.5.1 or 4.7.1. Accordingly, the NRC staff concludes that 

4 the impacts of water use conflicts on terrestrial resources from the proposed license renewal 

5 would be SMALL.

6 4.6.2 No-Action Alternative

7 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

8 shut down on or before the expiration of the current facility operating license. Some impacts on 

9 terrestrial resources, such as cooling tower drift, would cease following reactor shutdown. 

10 Some impacts may continue to exist at a reduced level, for example impacts on noise and 

11 impacts associated with herbicide application and landscape maintenance depending on the 

12 level at which Entergy continues to maintain landscaped areas. Other impacts on terrestrial 

13 resources would be the same as if the plant were operating, such as the potential for bird 

14 collisions with plant structures and transmission lines. Thus, shutdown itself is unlikely to 

15 noticeably alter or have more than minor effects on terrestrial resources. The NRC staff 

16 concludes that the impacts of the no-action alternative on terrestrial resources during the 

17 proposed license renewal term would be SMALL.

18 4.6.3 Replacement Power Alternatives: Common Impacts

19 Each replacement power alternative would entail construction and operation of a new energy 

20 generating facility on Entergy’s existing RBS site and would result in qualitatively similar impacts 

21 to terrestrial resources. During construction, the use of the existing site would allow Entergy to 

22 maximize existing buildings and infrastructure. Entergy would site any new plant on an area of 

23 the RBS site that Entergy previously excavated for a planned second nuclear unit that was 

24 never built. Reusing this excavated site would minimize impacts to wetlands and other 

25 terrestrial habitats. However, the exact level of disturbance to terrestrial habitats and biota

26 would depend on the amount of land required for each alternative and the specific siting of 

27 buildings and infrastructure within the site footprint. The existing transmission lines and 

28 structures would be adequate to support each alternative, and the existing RBS intake and 

29 discharge structures could be used with some modifications, all of which would minimize 

30 terrestrial habitat disturbances. Clearing of some plant communities within the construction 

31 footprint would likely occur. Wildlife in these areas would be displaced but could relocate to 

32 neighboring natural areas. Some habitat loss or fragmentation, loss of food resources, and 

33 altered behavior due to noise and other construction-related disturbances would be possible. 

34 Erosion and sedimentation from clearing, leveling, and excavating land could affect adjacent 

35 riparian and wetland habitats. Implementation of appropriate best management practices and 

36 revegetation following construction would minimize such impacts. 

37 In the GEIS (NRC 2013b), the NRC staff concludes that impacts to terrestrial resources from 

38 operation of nuclear and fossil-fueled plants would be similar and would include cooling tower 

39 salt drift, noise, bird collisions with plant structures and transmission lines, impacts connected 

40 with herbicide application and landscape management, and potential water use conflicts 

41 connected with cooling-water withdrawals. The fossil-fueled alternatives would generate air 

42 emissions of greenhouse gases, such as nitrogen oxides and carbon dioxide, all of which would 

43 contribute cumulatively to climate change. Climate change is associated with migratory mis44 synchronizations; loss of coastal, riparian, and wetland terrestrial habitats to sea level rise and 

45 storm surges; and increased susceptibility to insect infestations and pathogens, among other 

46 effects. Additional impacts to terrestrial resources during the operational period could occur as 
4-28

1 a result of offsite mining, extraction, or waste disposal activities associated with each plant’s 

2 particular type of fuel.

3 4.6.3.1 New Nuclear Alternative

4 The NRC staff did not identify any impacts on terrestrial resources from the new nuclear 

5 alternative beyond those discussed in the impacts common to all replacement power

6 alternatives. However, the common impacts could be slightly more intense for the new nuclear 

7 alternative compared to RBS license renewal due to the larger land area requirement that could 

8 result in increased erosion and potential introduction of sediments to riparian habitats. 

9 Nonetheless, because of the short-term nature of the construction activities, use of existing 

10 infrastructure, and implementation of best management practices, the direct impacts to 

11 terrestrial resources would be minimal. Therefore, NRC staff concludes that the impacts to 

12 terrestrial resources from construction and operation of a new nuclear alternative would be 

13 SMALL.

14 4.6.3.2 Supercritical Pulverized Coal Alternative

15 In addition to the impacts to terrestrial resources common to all alternatives, operation of the 

16 coal alternative would require coal deliveries, cleaning, and storage, which would create noise, 

17 dust, and loss of habitat. Limestone preparation and storage would create dust and runoff that 

18 could affect soil and vegetation. Air emissions from the coal plant could create acid 

19 precipitation, which can injure foliage, leach nutrients from the soil, and contribute to decreased 

20 biodiversity over time. Disposal of combustion wastes could result in habitat loss and potential 

21 seepage of trace and other elements into soils. The NRC staff concludes that impacts on 

22 terrestrial resources of constructing and operating a coal alternative would be SMALL during 

23 construction and SMALL to MODERATE during operation. The anticipated range in impacts 

24 during the operational period is due to the variable impacts that air emissions and coal mining 

25 could have on terrestrial resources.

26 4.6.3.3 Natural Gas Combined-Cycle Alternative

27 The impacts on terrestrial resources common to all alternatives would be less intense for the 

28 natural gas alternative as compared to the new nuclear, coal, and combination alternatives 

29 because the natural gas alternative would disturb the least amount of land. However, the 

30 natural gas alternative would require construction of a gas pipeline, which could result in the 

31 loss, modification, or fragmentation of terrestrial habitat. The natural gas alternative would 

32 require 25 ac (10 ha) of land for a right-of-way to connect the new plant to an existing gas 

33 pipeline approximately 2 mi (3.2 km) east of the site. The NRC staff concludes that impacts of 

34 constructing and operating a natural gas alternative on terrestrial resources would be SMALL to 

35 MODERATE during both construction and operation. The anticipated range in impacts is due to 

36 the variable impacts that gas pipeline construction could have on sensitive habitats (if those 

37 habitats are in or near the pipeline’s right-of-way) as well as the variable impacts of air 

38 emissions during the operational period.

39 4.6.3.4 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and Demand-Side 

40 Management)

41 The NRC staff did not identify any impacts to terrestrial resources for the natural gas and 

42 biomass portions of the combination alternative beyond those discussed in the impacts common 

43 to all replacement power alternatives and those described for the natural gas only alternative. 
4-29

1 The demand-side management portion of the combination alternative, which would account for 

2 approximately 11 percent of the combination alternative’s power generation, would not require 

3 any new construction or otherwise result in impacts to terrestrial resources. Thus, impacts to 

4 terrestrial resources from the demand-side management portion of the alternative would be 

5 negligible. The NRC staff concludes that impacts of implementing the combination alternative 

6 on terrestrial resources would be SMALL to MODERATE during construction and operation. 

7 The anticipated range in impacts is due to the variable impacts that gas pipeline construction 

8 could have on sensitive habitats (if the habitat is in or near the right-of-way) as well as the 

9 variable impacts of air emissions during the operational period.

10 4.7 Aquatic Resources

11 This section describes the potential aquatic resources impacts of the proposed action (license 

12 renewal) and alternatives to the proposed action.

13 4.7.1 Proposed Action

14 As identified in Table 4-1, the impacts of all generic aquatic resource issues would be SMALL. 

15 Table 4-2 identifies one aquatic resource site-specific (Category 2) issue applicable to RBS 

16 during the license renewal term. This issue is analyzed below.

17 4.7.1.1 Water Use Conflicts with Aquatic Resources (Plants with Cooling Ponds or Cooling 

18 Towers Using Makeup Water from a River)

19 Water use conflicts occur when the amount of water needed to support aquatic resources is 

20 diminished as a result of demand for agricultural, municipal, or industrial use or decreased water 

21 availability due to droughts, or a combination of these factors.

22 The mean annual discharge of the Lower Mississippi River measured at the U.S. Geological 

23 Survey (USGS) gage at Baton Rouge, LA, is 547,373 cubic feet per second (cfs) (15,463 cubic 

meters per second (m3 24 /s)), as described in Section 4.5.1.1. RBS withdraws an average of 

27.4 cfs (0.77 m3

/s), equivalent to 17.7 mgd (67,000 m3 25 /day), of water from the St. Francisville 

reach of the Lower Mississippi River. Consumptive use averages 21.4 cfs (0.6 m3 26 /s), or about 

13.8 mgd (52,200 m3 27 /day). This consumptive use is equivalent to about 0.004 percent of the 

28 Lower Mississippi River’s mean annual discharge (flow). 

29 The amount of Mississippi River water RBS consumes is minor in comparison to the flow of 

30 water past the plant (0.004 percent), and therefore RBS does not consume an amount that 

31 would be harmful to aquatic biota during low flow conditions. The NRC staff did not identify any 

32 information that indicates that the Mississippi River biota are affected by the loss of river water 

33 consumed by RBS’s makeup water withdrawals. The NRC staff concludes that water use 

34 conflicts would not occur from the proposed license renewal or would be so minor that the 

35 effects on aquatic resources would be undetectable. Thus, the NRC staff concludes that the 

36 impacts of water use conflicts on aquatic resources during the license renewal term would be 

37 SMALL.
4-30

1 4.7.2 No-Action Alternative

2 If RBS were to cease operating, impacts to aquatic ecology would decrease or stop following 

3 reactor shutdown. Some withdrawal of water from the 

4 Mississippi River would continue during the shutdown 

5 period as the fuel is cooled, although the amount of 

6 water withdrawn would decrease over time. The 

7 reduced demand for cooling water would substantially 

8 decrease the effects of impingement, entrainment, 

9 thermal effluents, and other impacts to aquatic biota. 

10 These effects likely would stop following the removal 

11 of fuel from the reactor core and shutdown of the 

12 spent fuel pool. Given the small area of the thermal 

13 plume in the Mississippi River under normal operating 

14 conditions, effects from cold shock are unlikely. 

15 Thus, the NRC staff concludes that the impacts of the no-action alternative on aquatic resources 

16 during the proposed license renewal term would be SMALL.

17 4.7.3 Replacement Power Alternatives: Common Impacts

18 Construction:

19 Construction activities for a new replacement power plant and mechanical draft cooling tower 

20 could degrade water quality of nearby waterbodies, such as bayous, streams, or the 

21 Mississippi River, through erosion and sedimentation; result in loss of habitat through wetland 

22 filling; or result in direct mortality of aquatic organisms from dredging or other in-water work. 

23 Because of the short-term nature of construction activities, degradation of habitat quality would 

24 be relatively localized and temporary. Loss of habitat could be minimized by siting a plant far 

25 from bayous, streams, and other onsite aquatic resources, as well as using the existing RBS 

26 intake and discharge structures, transmission lines, roads, parking areas, and other 

27 infrastructure. Appropriate permits would ensure that water quality impacts would be addressed 

28 through mitigation or best management practices, as stipulated in the permits. The U.S. Army 

29 Corps of Engineers and/or the Louisiana Department of Environmental Quality would oversee 

30 applicable permitting, including the Clean Water Act Section 404 permit, Section 401

31 certification, and Section 402(p) National Pollutant Discharge Elimination System (NPDES) 

32 general stormwater permit. Because of the short-term nature of the construction activities, use 

33 of existing infrastructure, and use of required best management practices, the NRC staff 

34 concludes that hydrological alterations to aquatic habitats and impacts to aquatic resources 

35 from construction of replacement power alternatives would be minimal.

36 Operation:

37 The NRC staff analyzed the operational impacts to aquatic biota in the GEIS (NRC 2013b) for a 

38 power plant using cooling towers. Based on the relatively slow withdrawal and discharge rates, 

39 the NRC staff determined that impacts to aquatic biota from replacement power alternatives at 

40 the RBS site, such as impingement, entrainment, and thermal effects, would be minimal. In 

41 addition, water use conflicts with aquatic resources would not be likely given that the new unit 

42 would withdraw less than 0.004 percent of the flow in the Mississippi River.

Impingement is the entrapment of all 

life stages of fish and shellfish on the 

outer part of an intake structure or 

against a screening device during 

periods of water withdrawal 

(40 CFR 125.83). Entrainment is the 

incorporation of all life stages of fish 

and shellfish with intake water flow 

entering and passing through a 

cooling-water intake structure and into 

a circulating water system

(40 CFR 125.83).
4-31

1 4.7.3.1 New Nuclear Alternative

2 The NRC staff did not identify any impacts on aquatic resources for the new nuclear alternative 

3 beyond those discussed in the impacts common to all replacement power alternatives. 

4 However, the common impact could be slightly more intense for the new nuclear alternative as 

5 compared to coal or gas alternatives, due to the larger land area requirement that could result in 

6 increased erosion and potential introduction of sediments to aquatic habitats. Nonetheless, 

7 because of the short-term nature of the construction activities, use of existing infrastructure, and 

8 required best management practices, the hydrological alterations to aquatic habitats and direct 

9 impacts to aquatic resources would be minimal. Therefore, NRC staff concludes that the 

10 impacts to aquatic resources from construction and operation of a new nuclear alternative would 

11 be SMALL.

12 4.7.3.2 Supercritical Pulverized Coal Alternative

13 In addition to the impacts to aquatic resources common to all alternatives, operation of the coal 

14 alternative could impact aquatic resources with additional activities. A coal plant would require 

15 coal deliveries, cleaning, and storage, which would require periodic dredging (if coal is delivered 

16 by barge). These activities would create dust, sedimentation, and turbidity and introduce trace 

17 elements and minerals into the water. Air emissions from the coal units would include sulfur 

18 dioxide, particulates, and mercury that would settle on water bodies or be introduced into the 

19 water from soil erosion. However, given the relatively fast flow of the Mississippi River, these 

20 contaminants would quickly dissipate from the area surrounding RBS. Therefore, the NRC staff 

21 concludes that the impacts to aquatic resources from construction and operation of the coal 

22 alternative would be SMALL.

23 4.7.3.3 Natural Gas Combined-Cycle Alternative

24 The impacts on aquatic resources common to all alternatives would be less intense for the 

25 natural gas alternative as compared to the new nuclear, coal, and combination alternatives 

26 because the natural gas alternative would disturb the least amount of land—likely resulting in 

27 less erosion and less potential for introducing sediments into aquatic habitats. The natural gas 

28 alternative would also withdraw and discharge the least amount of water from the Mississippi 

29 River, which would reduce the level of impingement and entrainment of aquatic biota as well as 

30 reduce the size and intensity of the thermal plume. 

31 In addition to the impacts on aquatic resources common to all replacement power alternatives, 

32 the natural gas alternative may create additional impacts because the natural gas plant would 

33 require construction of new pipelines, which could impact previously undisturbed habitats. This 

34 impact would vary depending on the route of the pipeline and would be more likely to impact 

35 terrestrial resources than aquatic resources. Because the natural gas alternative would be built 

36 at the RBS site, new pipelines could be collocated in existing corridors and existing 

37 infrastructure could be used to reduce impacts. During operations, air emissions from the 

38 natural gas units would include nitrogen oxide, carbon dioxide, and particulates that would settle 

39 on water bodies or be introduced into the water from soil erosion. However, given the relatively 

40 fast flow of the Mississippi River, these contaminants would quickly dissipate from the area 

41 surrounding RBS. The NRC staff concludes that the impacts to aquatic resources from 

42 construction and operation of a natural gas plant would be SMALL.
4-32

1 4.7.3.4 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and Demand Side 

2 Management)

3 The NRC staff did not identify any impacts for the natural gas and biomass portions of the 

4 combination alternative beyond those discussed in the impacts common to all replacement 

5 power alternatives and those described for the natural gas alternative. The demand-side 

6 management portion of the combination alternative, which would account for approximately 

7 11 percent of the alternative’s power generation, would neither require new construction nor 

8 require additional cooling or consumptive water use during operation. Thus, impacts to aquatic 

9 resources from the demand-side management portion of the combination alternative would be 

10 negligible. 

11 Based on the minimal impacts to aquatic resources, the NRC staff concludes that the impacts 

12 on aquatic resources from the combination alternative would be SMALL.

13 4.8 Special Status Species

14 This section describes the potential special status species impacts of the proposed action 

15 (license renewal) and alternatives to the proposed action.

16 4.8.1 Proposed Action 

17 Table 4-2 identifies the one RBS site-specific (Category 2) issue related to special status 

18 species and habitats applicable to the area during the license renewal term. This issue is 

19 analyzed below. 

20 4.8.1.1 Category 2 Issue Related to Special Status Species: Species and Habitats Protected 

21 Under the Endangered Species Act

22 Species and Habitats under U.S. Fish and Wildlife Service Jurisdiction

23 Section 3.8 considers whether one federally listed species, the pallid sturgeon 

24 (Scaphirhynchus albus), under the U.S. Fish and Wildlife Service’s (FWS’s) jurisdiction occurs 

25 in the action area based on the pallid sturgeon’s habitat requirements, life history, occurrence 

26 records, and other available information. In that section, the NRC staff concludes that this 

27 species may occur in the action area. The NRC staff also determines in Section 3.8 that no 

28 proposed species, candidate species, or critical habitats (proposed or designated) occur in the 

29 action area. Therefore, the proposed action (license renewal for an additional 20 years of 

30 operations at RBS) would have no effect on proposed species, candidate species, or critical 

31 habitats. The NRC staff analyzes the potential impacts of the proposed RBS license renewal on 

32 the pallid sturgeon below. The NRC staff’s Endangered Species Act (ESA) effect determination

33 for this species is summarized in Table 4-3.

34 Table 4-3. Effect Determinations for Federally Listed Species Under U.S. Fish and 

35 Wildlife Service Jurisdiction

Species Common Name

Federal 

Status(a) Effect Determination

Scaphirhynchus albus pallid sturgeon Federally

endangered

may affect, but is not likely 

to adversely affect
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1 Pallid Sturgeon (Scaphirhynchus albus)

2 In Section 3.8, the NRC staff concludes that pallid sturgeon juveniles and adults may occur in 

3 the action area based on occurrence data from the Lower Mississippi River, although such 

4 occurrences would be occasional to rare. Larval pallid sturgeon and eggs, however, are 

5 unlikely to occur in the RBS action area based on available capture and spawning records, all of 

6 which were recorded well upstream of RBS.

7 During the proposed license renewal term (2025–2045), pallid sturgeon in the action area could 

8 experience the following effects from continued operation of RBS: (1) impingement and 

9 entrainment, (2) thermal effects, (3) exposure to radionuclides and other contaminants, and 

10 (4) reduction in available prey due to impingement and entrainment or thermal impacts to prey

11 species. These impacts are described below in terms of direct, indirect, interrelated, and 

12 interdependent effects.

13 Direct Effects

14 Impingement and Entrainment

15 Impingement is the entrapment of all life stages of fish and shellfish on the outer part of an 

16 intake structure or against a screening device during periods of water withdrawal 

17 (Title 40, “Protection of Environment” of the Code of Federal Regulations (40 CFR) 125.83, 

18 “What Special Definitions Apply to This Subpart”). Entrainment is the incorporation of all life 

19 stages of fish and shellfish with intake water flow entering and passing through a cooling-water 

20 intake structure and into a circulating water intake structure (40 CFR 125.83). As indicated in 

21 Table 4-1 of this SEIS, the collective effects of impingement and entrainment for all Lower 

22 Mississippi River aquatic organisms would be SMALL over the course of the proposed license 

23 renewal term.

24 An important factor that influences a species’ ability to avoid impingement into a cooling-water 

25 intake structure is its swimming speed. Impingement of healthy juvenile pallid sturgeon can 

26 reasonably be assumed to occur in situations where a facility’s intake velocity is higher than 

27 juvenile burst swimming speeds. An individual would naturally exhibit burst swimming behavior 

28 when navigating short-term fast currents, capturing prey, and avoiding predators. Burst 

29 swimming behavior would also help an individual avoid the draw of water into a cooling-water 

30 intake system. 

31 In swimming stamina tests of hatchery-reared juvenile pallid sturgeon at Gavins Point National 

32 Fish Hatchery in South Dakota, Adams et al. (1999) observed maximum sustained swimming 

33 speed with no fatigue after 480 minutes of 25 cm/sec (9.8 in./sec) for juveniles of 17.0 to 

34 20.5 cm (6.7 to 8.1 in.) fork length and 10 cm/sec (3.9 in./sec) for juveniles of 13.0 to 16.8 cm 

35 (5.1 to 6.6 in.) fork length. Burst speeds were measured for the two groups at 55 to 70 cm/sec 

36 and 40 to 70 cm/sec (22 to 28 in./sec and 16 to 28 in./sec), respectively. Notably, juvenile pallid 

37 sturgeon in this study demonstrated a higher capacity for burst swimming than had been 

38 demonstrated in studies of other sturgeon species. Because of the various swimming behaviors 

39 observed during the study, Adams et al. (1999) concluded that observed swimming speeds do 

40 not solely represent steady-state swimming speeds. Similar to other lotic, benthic fish, pallid 

41 sturgeon juveniles were able to use their pectoral fins and overall body morphology to maintain 

42 station against velocity without swimming (Adams et al. 1999). Based on the results of these 

43 studies, the NRC staff assumes that juvenile pallid sturgeon are most likely to be susceptible to 

44 impingement at facilities with intake velocities greater than 2.3 fps (70 cm/sec; 28 in./sec). 
4-34

1 Smaller or weaker individuals would also be susceptible to impingement at facilities with intake 

2 velocities as low as 1.3 fps (40 cm/sec; 22 in./sec). 

3 The approach velocity of RBS’s cooling-water intake structure averages less than 0.5 fps 

4 (15 cm/sec; 6 in./sec) (Entergy 2017g). At low, medium, and high river flows, water flows past 

5 the intake structure at approximately 0.1, 0.2, and 0.7 fps (3, 6, and 21 cm/sec; 1.2, 2.4, and 

6 8.4 in./sec), respectively (Entergy 2017g). At these approach velocities, pallid sturgeon 

7 juveniles would be able to avoid impingement into the RBS cooling-water intake system even at 

8 high river flow based on observed burst speeds in Adams et al.’s (1999) study. The U.S. Fish 

9 and Wildlife Service (2017c) notes that juvenile pallid sturgeon exhibit a variety of complex 

10 swimming behaviors that increase their ability to resist strong flows, such as flows associated 

11 with cooling-water intake structures. Similarly, adult pallid sturgeon are expected to have 

12 sufficient swimming ability to avoid impingement. Further, these velocities are lower than 

13 average river flow near RBS, which was observed to be 3.88 fps (118 cm/sec; 46.6 in./sec) in 

14 the Lower Mississippi River main channel during studies associated with Entergy’s combined 

15 license (COL) application for a second reactor, River Bend Station, Unit 3 (RBS3) 

16 (Entergy 2008a). (Entergy ultimately withdrew the RBS3 application and the planned COL unit 

17 was never constructed.) Therefore, pallid sturgeon that may occur in the RBS action area 

18 would already be strong enough to navigate waters of significantly higher velocity than the RBS 

19 intake, and thus, impingement of these individuals during the proposed license renewal term is 

20 highly unlikely.

21 Another factor that makes impingement highly unlikely is the location of the RBS intake. The 

22 river screens of the intake are located in a man-made recession on the east bank of the 

23 Mississippi River. Pallid sturgeon is a deep water, channel-dwelling species. Individuals are 

24 typically found in areas where relative depths are 75 percent or higher than the maximum 

25 channel cross-section depth (FWS 2014c). Thus, individuals would be unlikely to occur in 

26 shallower waters near the RBS intake where they could be susceptible to impingement.

27 Pallid sturgeon are also unlikely to be subject to entrainment at RBS. Organisms susceptible to 

28 entrainment generally include ichthyoplankton (fish eggs and larvae), larval stages of shellfish 

29 and other macroinvertebrates, zooplankton, and phytoplankton. As described in 

30 Section 3.8.1.1, pallid sturgeon eggs and larvae do not occur in the action area because pallid 

31 sturgeon are not currently known to spawn in the Mississippi River main channel (FWS 2017c; 

32 FWS and NMFS 2009). Additionally, pallid sturgeon eggs are demersal and adhesive, and 

33 would therefore not be expected to drift downstream from spawning grounds in upstream 

34 tributaries. For these reasons, the NRC staff does not expect pallid sturgeon eggs and larvae to 

35 be entrained into the RBS cooling-water intake system. Therefore, no entrainment of pallid 

36 sturgeon would occur during the proposed license renewal term.

37 Based on the above review of pallid sturgeon swimming speeds and the RBS cooling-water 

38 intake system design and operation, the NRC staff concludes that the risk of pallid sturgeon 

39 impingement and entrainment at RBS during the license renewal term is a discountable impact 

40 because it is extremely unlikely to occur. Further, in 2017, the U.S. Fish and Wildlife Service

41 (2017b) determined that renewal of the RBS Louisiana Pollutant Discharge Elimination System

42 permit, which authorizes cooling-water intake, is not likely to adversely affect pallid sturgeon. 

43 The Fish and Wildlife Service’s review associated with the RBS Louisiana Pollutant Discharge 

44 Elimination System permit supports the NRC staff’s conclusion and is discussed in more detail 

45 below.
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1 Thermal Effects

2 North American sturgeon species generally prefer cooler waters and most prefer and perform 

3 optimally at water temperatures of 25 °C (77 °F) or less (Blevins 2011). Activity and growth of 

4 young sturgeon generally increases with temperature until an optimal temperature, usually 

5 below 25 °C (77 °F), is reached (Blevins 2011). Eggs and larval stages are likely more sensitive 

6 to high temperatures than juveniles and adults, which can find refuge in microhabitats with 

7 cooler water. In a study of 1,000 juvenile shovelnose sturgeon in the upper Missouri River, 

8 Kapperman et al. (2009) found that temperature tolerances range from 10.0 to 30.0 °C 

9 (50 to 86°F) with optimal growth occurring at 22.0 °C (71.6 °F). However, available literature 

10 suggests that pallid sturgeon likely tolerate higher water temperatures than shovelnose and 

11 other sturgeon species. For instance, data from a small bioenergetics model study of pallid 

12 sturgeon on the Lower Missouri River indicate that 25 to 28 °C (77 to 82.4 °F) is the optimal 

13 temperature range for feeding and growth (Chipps et al. 2010). Temperatures from 30 to 33 °C 

14 (86 to 91.4 °F) appear to be stressful, while temperatures above 33 °C (91.4 °F) begin to result 

15 in death (Chipps et al. 2010). At 33 °C (91.4 °F), 4-day survival of pallid sturgeon individuals 

16 was 83 percent, whereas at 35 °C (95 °F), all fish lost equilibrium within 30 seconds, and all 

17 individuals died within 2 hours (Chipps et al. 2010).

18 Within the action area, Mississippi River surface water temperatures fluctuate seasonally with 

19 lowest temperatures typically occurring in January and highest temperatures typically occurring 

20 in August. Temperatures in the Lower Mississippi River generally fluctuate between 64.6 °F 

21 (18.1 °C) to 88.7 °F (31.5 °C) in habitats near the RBS site (Entergy 2017g). Discharge of RBS 

22 cooling tower blowdown to the Mississippi River creates a small thermal plume at the discharge

23 point, which lies about 1 mi (1.6 km) downstream of the plant near the east bank of the river 

24 (Entergy 2017g). The thermal plume is described in detail in Section 3.8.1.1.

25 While the RBS thermal plume may reach temperatures that fall within the stressful range for 

26 pallid sturgeon during summer months, the plume is unlikely to result in measurable or 

27 detectable impacts on any sturgeon individuals that may occur in the action area. Because the 

28 thermal plume extends over a small area, pallid sturgeon could easily avoid the plume and swim 

29 through the large zone of passage. Additionally, swim time through the plume would be of short 

30 duration, the plume would not exceed pallid sturgeon thermal tolerances during cooler portions 

31 of the year, and the plume would only have the potential to exceed thermal tolerances during 

32 limited periods of time during the certain portions of the year (i.e., in summer months). While 

33 individuals may exhibit altered behavior to avoid the thermal plume, such behavioral changes 

34 would not affect fitness, would not result in other measurable effects, and would not reach the 

35 scale of a take. Further, because RBS discharges its thermal effluent along the riverbank, pallid 

36 sturgeon individuals are less likely to transit the river in or near the thermal plume due to the 

37 species’ previously discussed preference for deeper water. Pallid sturgeon eggs and larvae do 

38 not occur in the action area, and would, therefore, be unaffected by thermal effluent.

39 Based on the above review of pallid sturgeon thermal tolerances and the RBS thermal plume, 

40 the NRC staff concludes that potential for thermal effects on pallid sturgeon during the license 

41 renewal term is an insignificant impact because such impacts would not be able to be 

42 meaningfully measured or detected and would not reach the scale of a take. Further, in 2017, 

43 the U.S. Fish and Wildlife Service (2017b) determined that renewal of the RBS Louisiana 

44 Pollutant Discharge Elimination System permit, which authorizes heated discharge and sets 

45 corresponding temperature limitations, is not likely to adversely affect pallid sturgeon. The Fish 

46 and Wildlife Service review associated with the RBS Louisiana Pollutant Discharge Elimination 

47 System permit supports the NRC staff’s conclusion and is discussed in more detail below.
4-36

1 Exposure to Radionuclides and Other Contaminants

2 The NRC (2013b) determined in the GEIS that exposure to radionuclides would be of SMALL 

3 significance for aquatic resources because exposure would be well below EPA guidelines 

4 developed to protect aquatic biota. The GEIS also concludes that effects of nonradiological 

5 contaminants on aquatic organisms would be SMALL because best management practices and 

6 discharge limitations contained in applicable State-issued National Pollutant Discharge 

7 Elimination System permits would minimize the potential for impacts to aquatic resources. In 

8 Section 4.7 of this SEIS, the NRC staff did not identify any new and significant information that 

9 would call into question these conclusions’ applicability to the proposed RBS license renewal. 

10 Therefore, exposure of aquatic organisms to radionuclides and nonradiological contaminants 

11 during the license renewal term would not be detectable or would be so minor as to neither 

12 destabilize nor noticeably alter any important attribute of the aquatic environment.

13 In 2017, the U.S. Fish and Wildlife Service (2017c) determined that exposure to radionuclides 

14 and other contaminants at Waterford Steam Electric Station, Unit 3, a nuclear power plant that 

15 lies approximately 75 mi (120 km) southeast and downriver of RBS, is not likely to adversely 

16 affect the pallid sturgeon. Additionally, in biological opinions associated with the continued 

17 operation of three other nuclear power plants that draw cooling water from water bodies with 

18 Federally listed sturgeon populations, the National Marine Fisheries Service (2013, 2014) 

19 determined that measurable exposure of Atlantic sturgeon (Acipenser oxyrinchus oxyrinchus) 

20 and shortnose sturgeon (A. brevirostrum) to radionuclides and other contaminants resulting 

21 from continued operation of a nuclear power plant would be extremely unlikely and, therefore, 

22 represented an insignificant and discountable impact. 

23 The NRC staff did not identify any scientific studies or other information indicating that pallid 

24 sturgeon could experience measurable adverse effects from the minimal discharges of 

25 radionuclides and other contaminants that would occur during the proposed RBS license 

26 renewal period. Based on the above information, the NRC staff finds that exposure to 

27 radionuclides and other contaminants during the proposed license renewal period represents a 

28 discountable impact because it would not be able to be meaningfully detected, measured, or 

29 evaluated and insignificant because exposure would never reach the scale where a take would 

30 occur.

31 Reduction in Available Prey Due to Impingement and Entrainment or Thermal Impacts

32 The diet of pallid sturgeon changes with age and is described in Section 3.8. As shown in 

33 Table 4-1, impingement and entrainment of aquatic resources would be SMALL during the 

34 proposed license renewal period, and thus, would not be detectable or would be so minor as to 

35 neither destabilize nor noticeably alter the aquatic community during the proposed license 

36 renewal term. Thermal impacts on aquatic resources would also be SMALL during the 

37 proposed license renewal term. Accordingly, because RBS operations do not result in 

38 detectable impingement and entrainment or thermal impacts on the aquatic community, any 

39 small reductions in available prey that could result in effects on pallid sturgeon through the food 

40 web would not be able to be meaningfully measured, detected, or evaluated, and would, 

41 therefore, be a discountable impact.

42 Indirect Effects

43 Under the Endangered Species Act, indirect effects are those that are caused by the proposed 

44 action that do not occur until later in time, but are still reasonably certain to occur (Title 50, 
4-37

1 “Wildlife and Fisheries,” of the Code of Federal Regulations (50 CFR), Section 402.02, 

2 “Definitions”). The NRC did not identify any indirect effects associated with the proposed action 

3 that could affect the pallid sturgeon. Termination of RBS operations and associated 

4 decommissioning of the reactor would occur eventually regardless of license renewal. While the 

5 proposed license renewal would delay the date of reactor shutdown, it would not significantly 

6 alter decommissioning impacts.

7 Interrelated and Interdependent Effects

8 Interrelated actions are those actions that are part of a larger action and depend on the larger 

9 action for their justification (50 CFR 402.02). Interdependent actions are those actions having 

10 no independent utility apart from the proposed action (50 CFR 402.02). The NRC staff has not 

11 identified any information that would indicate that there would be any interrelated or 

12 interdependent actions associated with the proposed license renewal that might affect the pallid 

13 sturgeon.

14 Past U.S. Fish and Wildlife Service Reviews

15 In 2016 and 2017, the U.S. Fish and Wildlife Service reviewed the potential impacts of 

16 continued operation of the RBS cooling-water intake system upon two occasions: following 

17 Entergy’s request for comments on the RBS license renewal application and during the 

18 Louisiana Department of Environmental Quality’s (LDEQ) review of Entergy’s Louisiana 

19 Pollutant Discharge Elimination System permit renewal application.

20 • License Renewal Application Review: On July 25, 2016, Entergy (2016c)

21 requested U.S. Fish and Wildlife Service review of the RBS license renewal

22 application prior to finalizing and submitting the application to the NRC. The Fish

23 and Wildlife Service (2016) replied on August 26, 2016. The reply stated that the

24 Fish and Wildlife Service had reviewed the project for effects to federally listed

25 species under its jurisdiction and currently protected by the Endangered Species Act

26 and that the proposed license renewal was not likely to adversely affect the pallid

27 sturgeon.

28 • LPDES Permit Renewal Review: On June 15, 2017, the Louisiana Department of

29 Environmental Quality (2017b) submitted a copy of Entergy’s Louisiana Pollutant

30 Discharge Elimination System (LPDES) permit renewal application to the U.S. Fish

31 and Wildlife Service for its review in accordance with the terms of a memorandum of

32 agreement between the Louisiana Department of Environmental Quality and

33 Region 6 of the U.S. Environmental Protection Agency. The Fish and Wildlife

34 Service (2017b) replied on July 7, 2017. The reply stated that the Fish and Wildlife

35 Service had reviewed the project for effects to federally listed species under its

36 jurisdiction and currently protected by the Endangered Species Act and that the

37 proposed license renewal was not likely to adversely affect the pallid sturgeon.

38 The U.S. Fish and Wildlife Service’s conclusions during its license renewal application review 

39 and Louisiana Pollutant Discharge Elimination System permit renewal review further support the 

40 staff’s above conclusions that impingement and entrainment, thermal effects, exposure to 

41 radionuclides and other contaminants, and reduction in available prey due to impingement and 

42 entrainment or thermal impacts to prey species represent insignificant or discountable impacts.
4-38

1 Conclusion Regarding Pallid Sturgeon

2 Based on the foregoing assessment, the NRC staff concludes that the proposed RBS license 

3 renewal may affect, but is not likely to adversely affect the pallid sturgeon.

4 Species and Habitats under National Marine Fisheries Service Jurisdiction

5 As discussed in Section 3.8, no federally listed, proposed, or candidate species or critical 

6 habitats (proposed or designated) under National Marine Fisheries Service jurisdiction occur 

7 within the action area. Thus, the NRC staff concludes that the proposed action would have no 

8 effect on federally listed, proposed, and candidate species or critical habitats under National 

9 Marine Fisheries Service jurisdiction.

10 Cumulative Effects

11 The Endangered Species Act regulations at 50 CFR 402.12(f)(4) direct Federal agencies to 

12 consider cumulative effects as part of the proposed action effects analysis. Under the 

13 Endangered Species Act, cumulative effects are defined as “those effects of future State or 

14 private activities, not involving Federal activities, that are reasonably certain to occur within the 

15 action area of the Federal action subject to consultation” (50 CFR 402.02). Unlike the National 

16 Environmental Policy Act (NEPA) definition of cumulative impacts (see Section 4.16), 

17 cumulative effects under the Endangered Species Act do not include past actions or other 

18 Federal actions requiring separate Endangered Species Act Section 7 consultation. When 

19 formulating biological opinions under formal Endangered Species Act Section 7 consultation, 

20 the U.S. Fish and Wildlife Service and National Marine Fisheries Service (1998) consider 

21 cumulative effects when determining the likelihood of jeopardy or adverse modification. 

22 Therefore, cumulative effects need only be considered under the Endangered Species Act if 

23 listed species will be adversely affected by the proposed action and formal Section 7 

24 consultation is necessary (FWS 2014b). Because the NRC staff concluded earlier in this 

25 section that the proposed license renewal is not likely to adversely affect the pallid sturgeon, 

26 consideration of cumulative effects is not necessary. Further, the NRC staff did not identify any 

27 actions within the action area that meet the definition of cumulative effects under the 

28 Endangered Species Act.

29 Reporting Requirements

30 If in the future a federally listed species is observed on the RBS site, the NRC has measures in 

31 place to ensure that NRC staff would be appropriately notified so that the staff could determine 

32 the appropriate course of action. RBS’s operating license, Appendix B, “Environmental 

33 Protection Plan,” Section 4.1, “Unusual or Important Environmental Events” (NRC 1985) 

34 requires Entergy to report to the NRC within 24 hours any mortality or unusual occurrence of a 

35 species protected by the Endangered Species Act on the RBS site. This reporting requirement 

36 would remain in effect in a renewed license for RBS. Additionally, the NRC’s regulations 

37 containing notification requirements require that operating nuclear power reactors report to the 

38 NRC within 4 hours “any event or situation, related to...protection of the environment, for which 

39 a news release is planned or notification to other government agencies has been or will be 

40 made” (10 CFR 50.72(b)(2)(xi)). Such notifications include reports regarding federally listed 

41 species, as described in Section 3.2.12 of NUREG–1022, “Event Report Guidelines: 10 CFR 

42 50.72 and 50.73” (NRC 2013a).
4-39

1 4.8.1.2 Species and Habitats Protected Under the Magnuson–Stevens Act

2 As discussed in Section 3.8, the National Marine Fisheries Service has not designated essential 

3 fish habitat (EFH) in the Mississippi River pursuant to the Magnuson–Stevens Fishery 

4 Conservation and Management Act, as amended (16 U.S.C. §§ 1801–1884) (MSA). During its 

5 environmental review for the proposed license renewal of Waterford Steam Electric Station, 

6 Unit 3, the NRC staff contacted the National Marine Fisheries Service to discuss essential fish 

7 habitat, such as effects of the proposed license renewal on essential fish habitat prey species 

8 (NRC 2016a, 2016b). The National Marine Fisheries Service confirmed that the NRC is not 

9 required to consult under the Magnuson–Stevens Act because there is no essential fish habitat 

10 in the Mississippi River. Regarding prey species, the National Marine Fisheries Service stated 

11 that although some essential fish habitat prey species occur in the Mississippi River, the level of 

12 impingement and entrainment of these species is not expected to be of concern. The NRC staff 

13 finds these conclusions to be valid for RBS, which lies further upriver from the Gulf of Mexico 

14 than Waterford Steam Electric Station. Thus, the NRC staff concludes that the proposed action 

15 would have no effect on essential fish habitat.

16 4.8.2 No-Action Alternative

17 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

18 shut down before the expiration of the current facility operating license. The Endangered 

19 Species Act action area for the no-action alternative would most likely be the same or similar to 

20 the action area described in Section 3.8 for the proposed license renewal. The plant would 

21 require substantially less cooling water and would produce less thermal effluent, and thus, the 

22 potential for impacts to aquatic species and habitats related to cooling system operation would 

23 be significantly reduced. Overall, the effects on federally listed species and critical habitats 

24 would likely be smaller than the effects under continued operation but would depend on the 

25 action area associated with shutdown activities as well as the listed species and critical habitats 

26 present when the no-action alternative is implemented.

27 The National Marine Fisheries Service has not designated essential fish habitat in the 

28 Mississippi River, and thus the no-action alternative would not affect essential fish habitat. 

29 4.8.3 Replacement Power Alternatives: Common Impacts

30 All the replacement power alternatives would entail construction and operation of a new energy 

31 generating facility on the existing Entergy property. The Endangered Species Act action area 

32 associated with any new plant would be similar to the license renewal action area because all of 

33 the replacement power alternatives would be sited on the existing site. However, specifically 

34 defining the action area would depend on the planned construction activities, temporary and 

35 permanent structure locations, and timeline of the alternative. Similarly, the listed species and 

36 habitats potentially affected by a particular alternative would depend on the boundaries of that 

37 alternative’s action area and the species that are listed under the Endangered Species Act at 

38 the time that alternative is implemented. For instance, if RBS continues to operate until the end 

39 of its current license term (2025) and the replacement power alternative is then implemented at 

40 that time, the U.S. Fish and Wildlife and National Marine Fisheries Services may have listed 

41 new species or delisted currently listed species whose populations may have recovered. These 

42 listing activities would change the potential impacts to Endangered Species Act species and 

43 habitats. While the types of impacts on Endangered Species Act species and habitats would 

44 likely be similar to those described for terrestrial and aquatic resources in Sections 4.6 and 4.7, 

45 respectively, the magnitude of such impacts could be larger than for terrestrial and aquatic 
4-40

1 resources because Endangered Species Act-listed species are rare and more sensitive to 

2 environmental stressors.

3 The National Marine Fisheries Service has not designated essential fish habitat in the 

4 Mississippi River. Given that the replacement power alternatives would be built on the RBS 

5 site, the NRC staff expects no impacts on essential fish habitat. 

6 4.8.3.1 New Nuclear Alternative

7 The NRC staff did not identify any impacts for the new nuclear alternative beyond those 

8 discussed in the impacts common to all replacement power alternatives. Because the NRC 

9 would remain the licensing agency under this alternative, the Endangered Species Act would 

10 require the NRC to consult with the U.S. Fish and Wildlife Service, as applicable, prior to issuing 

11 a license for construction and operation of the new plant to consider whether the plant would 

12 affect any federally listed species or adversely modify or destroy designated critical habitat, if 

13 present. The magnitude of adverse impacts to Endangered Species Act-listed species would 

14 depend on the site layout, plant design, plant operations, and the listed species and habitats 

15 potentially present in the action area when the alternative is implemented. As described in the 

16 impacts common to all alternatives, the NRC expects no impacts to essential fish habitat from 

17 implementing the new nuclear alternative. 

18 4.8.3.2 Supercritical Pulverized Coal Alternative

19 The NRC staff did not identify any impacts for the coal alternative beyond those discussed in the 

20 impacts common to all replacement power alternatives. Unlike RBS license renewal or the 

21 licensing of a new nuclear alternative, the NRC does not license coal facilities; therefore, the 

22 NRC would not be responsible for initiating Endangered Species Act Section 7 consultation if 

23 listed species or habitats might be adversely affected under this alternative. The companies or 

24 entities implementing this alternative would be responsible for ensuring that their actions do not 

25 jeopardize the continued existence of listed species because the Endangered Species Act 

26 Section 7 take prohibitions apply to both Federal and non-Federal entities. The magnitude of 

27 adverse impacts to Endangered Species Act-listed species would depend on the site layout, 

28 plant design, operation, and the listed species and habitats potentially present in the action area 

29 when the alternative is implemented. As described in the impacts common to all alternatives, 

30 the NRC staff expects no impacts to essential fish habitat from implementing the coal 

31 alternative.

32 4.8.3.3 Natural Gas Combined-Cycle Alternative

33 The NRC staff did not identify any impacts for the natural gas alternative beyond those 

34 discussed in the impacts common to all alternatives. As previously described for the coal 

35 alternative, the companies or entities implementing this alternative would be responsible for 

36 ensuring that their actions to not jeopardize the continued existence of any listed species. The 

37 magnitude of adverse impacts to Endangered Species Act-listed species would depend on the 

38 site layout, plant design, plant operation, and the listed species and habitats potentially present 

39 in the action area when the alternative is implemented. As described in the impacts common to 

40 all alternatives, the NRC staff expects no impacts to essential fish habitat from implementation 

41 of the natural gas alternative.
4-41

1 4.8.3.4 Combination Alternative (Natural Gas Combined Cycle, Biomass, and Demand Side 

2 Management)

3 The NRC staff did not identify any impacts for the combination alternative beyond those 

4 discussed in the impacts common to all replacement power alternatives. As previously 

5 described for the coal alternative, the companies or entities implementing this alternative would 

6 be responsible for ensuring that their actions to not jeopardize the continued existence of any 

7 listed species. The magnitude of adverse impacts to Endangered Species Act-listed species 

8 would depend on the site layout, plant design, plant operations, and the listed species and 

9 habitats potentially present in the action area when the alternative is implemented. As 

10 described in the impacts common to all alternatives, the NRC staff expects no impacts to 

11 essential fish habitat from implementation of the combination alternative. 

12 4.9 Historic and Cultural Resources

13 This section describes the potential historic and cultural resources impacts of the proposed 

14 action (license renewal) and alternatives to the proposed action.

15 4.9.1 Proposed Action

16 Table 4-2 identifies one site-specific (Category 2) issue related to historic and cultural resources 

17 applicable to RBS during the license renewal term. This issue is analyzed below. 

18 4.9.1.1 Category 2 Issue Related to Historic and Cultural Resources: Historic and Cultural 

19 Resources

20 The National Historic Preservation Act of 1966, as amended (NHPA) 

21 (54 U.S.C. 300101 et seq.), requires Federal agencies to consider the effects of their 

22 undertakings on historic properties. Issuing a renewed operating license to a nuclear power 

23 plant is an undertaking that could potentially affect historic properties. Historic properties are 

24 defined as resources included on, or eligible for inclusion on, the National Register of Historic 

25 Places (NRHP). The criteria for eligibility are listed in Title 36, “Parks, Forests, and Public 

26 Property” of the Code of Federal Regulations (36 CFR) 60.4 “Criteria for Evaluation,” and 

27 include (1) association with significant events in history, (2) association with the lives of persons 

28 significant in the past, (3) embodiment of distinctive characteristics of type, period, or 

29 construction, and (4) sites or places that have yielded, or are likely to yield, important 

30 information.

31 The historic preservation review process (Section 106 of the National Historic Preservation Act) 

32 is outlined in regulations issued by the Advisory Council on Historic Preservation (ACHP) in 

33 36 CFR Part 800, “Protection of Historic Properties.”

34 In accordance with National Historic Preservation Act provisions, the NRC is required to make a 

35 reasonable effort to identify historic properties included in, or eligible for inclusion in, the 

36 National Register of Historic Places in the area of potential effect (APE). The area of potential 

37 effect for a license renewal action includes the power plant site, the transmission lines up to the 

38 first substation, and immediate environs that may be affected by the license renewal decision 

39 and land disturbing activities associated with continued reactor operations during the license 

40 renewal term.

41 If historic properties are present within the area of potential effect, the NRC is required to 

42 contact the State historic preservation officer (SHPO), assess the potential impact, and resolve 
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1 any possible adverse effects of the undertaking (license renewal) on historic properties. In 

2 addition, the NRC is required to notify the State historic preservation officer if historic properties 

3 would not be affected by license renewal or if no historic properties are present. In Louisiana, 

4 State historic preservation officer responsibilities are shared between the Division of Historic 

5 Preservation and the Division of Archaeology (LOCD 2011, 2017).

6 4.9.1.2 Consultation

7 In accordance with 36 CFR 800.8(c), “Coordination with the National Environmental Policy Act,” 

8 on September 15, 2017, the NRC initiated written consultations with the Advisory Council on 

9 Historic Preservation and the Louisiana State historic preservation officer (NRC 2017c, 2017d). 

10 Also on September 15, 2017, the NRC initiated consultation with the following 

11 Federally-recognized Tribes (NRC 2017e, see Appendix C.):

12 • Chitimacha Tribe of Louisiana

13 • Coushatta Tribe of Louisiana

14 • Jena Band of Choctaw Indians

15 • Tunica-Biloxi Tribe of Louisiana

16 • Alabama Coushatta Tribe of Texas

17 • The Choctaw Nation of Oklahoma

18 • Mississippi Band of Choctaw Indians

19 • The Seminole Nation of Oklahoma

20 • Seminole Tribe of Florida

21 In these letters, the NRC provided information about the proposed action, defined the area of 

22 potential effect, and indicated that the National Historic Preservation Act review would be 

23 integrated with the National Environmental Policy Act process, in accordance with 

24 36 CFR 800.8(c). The NRC invited participation in the identification and possible decisions 

25 concerning historic properties and also invited participation in the scoping process. To date, the 

26 NRC has received no comments from these Tribes specific to RBS license renewal. However, 

27 the Coushatta Tribe of Louisiana and the Choctaw Nation of Oklahoma previously indicated in 

28 correspondence to Entergy that the proposed action would result in “no historical properties 

29 affected” and “no effect on known historical or archaeological properties,” respectively 

30 (Entergy 2017h). Similarly, the Louisiana State Historic Preservation Officer previously 

31 reviewed the draft Phase 1A Literature Review and Archeological Sensitivity Assessment 

32 commissioned by Entergy in support of its license renewal application, and concurred that 

33 operation of RBS during the license renewal term would have no effect on known historic 

34 properties (Entergy 2017h). The NRC met with the Louisiana State historic preservation officer 

35 in October 2017. The Louisiana State historic preservation officer did not express any concerns 

36 about the proposed RBS license renewal during the meeting. 

37 4.9.1.3 Findings

38 As described in Section 3.9, there are more than 100 known historic and cultural resources 

39 located within the RBS area of potential effect, including 25 properties that are either listed on, 

40 or are considered eligible for listing on, the National Register of Historic Places. Entergy has 

41 both fleet-wide and site-specific administrative controls in place to manage and protect cultural 

42 resources. Entergy’s fleet-wide cultural resource protection plan requires that appropriate 

43 reviews, investigations, and consultations are completed before performing ground-disturbing 

44 activities in undisturbed or cultural resource-sensitive areas. Although training on this plan is 
4-43

1 not compulsory, all Entergy employees are required to adhere to the instructions contained in 

2 the procedure.

3 Entergy has also established a separate cultural resources protection plan in coordination with 

4 the Louisiana State Historic Preservation Officer to help ensure historic and cultural resources 

5 specific to RBS are considered before ground-disturbing activities. This plan is incorporated by 

6 reference in the RBS Environmental Protection Plan and includes provisions to protect areas on 

7 the property determined to be National Register of Historic Places-eligible. It also identifies the 

8 protocols to be followed should cultural resources be discovered during ground-disturbing 

9 activities. However, Entergy does not anticipate that any physical changes or ground-disturbing 

10 activities would be required to support license renewal of RBS (Entergy 2017h).

11 Based on (1) the location of National Register of Historic Places-eligible historic properties 

12 within the area of potential effect, (2) tribal input, (3) Entergy’s cultural resource protection 

13 plans, (4) the fact that no license renewal-related physical changes or ground-disturbing 

14 activities would occur, (5) State historic preservation officer input, and (6) a cultural resource 

15 assessment, the NRC staff concludes that license renewal would not adversely affect any 

16 known historic properties (36 CFR 800.4(d)(1)). Entergy could reduce the risk of potential 

17 impacts to historic and cultural resources located on or near the RBS site by ensuring workers 

18 engaged in planning and executing ground-disturbing activities are trained on the applicable 

19 cultural resource protection plans.

20 4.9.2 No-Action Alternative

21 If the NRC does not issue a renewed operating license, and Entergy terminates reactor

22 operations, this would have no immediate effect on historic properties and cultural resources at

23 RBS. As stated in the decommissioning GEIS, the NRC concluded that impacts to cultural 

24 resources would be SMALL at nuclear plants where decommissioning activities would only 

25 occur within existing industrial site boundaries. Impacts cannot be predicted generically if 

26 decommissioning activities would occur outside of the previously disturbed industrial site 

27 boundaries, because impacts depend on site-specific conditions. In these instances, impacts 

28 could only be determined through site-specific analysis (NRC 2002).

29 In addition, 10 CFR 50.82, “Termination of License,” requires power reactor licensees to submit 

30 a post-shutdown decommissioning activities report (PSDAR) to the NRC. The post-shutdown 

31 decommissioning activities report provides a description of planned decommissioning activities 

32 at the nuclear plant. Until the post-shutdown decommissioning activities report is submitted, the 

33 NRC cannot determine whether land disturbance would occur outside the existing industrial site 

34 boundary after the nuclear plant is shut down.

35 4.9.3 Replacement Power Alternatives: Common Impacts

36 Construction

37 The potential for impacts on historic and cultural resources from the construction of replacement 

38 power alternatives would vary depending on the degree of ground disturbance within the 

39 Entergy Louisiana, LLC property. For each replacement power alternative, this environmental 

40 review assumes that new facilities would be built on the RBS site on land adjacent to the 

41 existing RBS Unit 1. Use of previously disturbed areas of the Entergy property known to not 

42 contain historic and cultural resources would be maximized, and areas of greatest cultural 

43 sensitivity avoided. Undisturbed areas of the property that could potentially be affected by the 
4-44

1 construction of replacement power alternatives would need to be surveyed to identify and record 

2 historic and cultural resources. Any resources found in these surveys would need to be 

3 evaluated for eligibility on the National Register of Historic Places, and mitigation of adverse 

4 effects would need to be addressed if eligible resources were encountered.

5 Operation

6 The potential for impacts on historic and cultural resources from the operation of replacement 

7 power alternatives would vary with plant heights and associated exhaust stack or cooling tower 

8 plumes. These replacement power facilities would be located in an industrialized area where 

9 tall structures and visible plumes already exist. The nearest National Register of Historic Places 

10 site, the Star Hill Plantation, is about 1 mi (1.6 km) away to the northeast. NRC staff does not 

11 expect Impacts on significant cultural resources, such as to viewsheds of historic properties 

12 near the proposed plant site, due to the presence of tree buffers and changes in elevation.

13 4.9.3.1 New Nuclear Alternative 

14 Impacts on historic and cultural resources from the construction and operation of a new nuclear 

15 unit would include those common to all replacement power alternatives. The new nuclear 

16 alternative would require an estimated 250 ac (101 ha) of land for the power plant. Given the 

17 preference to site the power plant on previously disturbed land and given that no major 

18 infrastructure upgrades would be necessary, avoidance of significant historic and cultural 

19 resources would be possible and could be managed effectively. Therefore, the NRC staff 

20 concludes that construction and operation of a new nuclear power plant on the Entergy property 

21 would not adversely affect known historic and cultural resources.

22 4.9.3.2 Supercritical Pulverized Coal Alternative 

23 Impacts on historic and cultural resources from the construction and operation of a new coal 

24 power plant would include those common to all replacement power alternatives. The coal 

25 facility would require an estimated 100 ac (40 ha) of land for major permanent facilities, as well 

26 as additional land for coal mining and waste disposal. Impacts from the construction and 

27 operation of a new coal plant would be similar to the impacts described for the new nuclear 

28 alternative. Given the preference to site the power plant on previously disturbed land and given 

29 that no major infrastructure upgrades would be necessary, avoidance of significant historic and 

30 cultural resources would be possible and could be managed effectively. Therefore, the NRC 

31 staff concludes that construction and operation of a new coal power plant on the Entergy

32 property would not adversely affect known historic and cultural resources.

33 4.9.3.3 Natural Gas Combined-Cycle Alternative

34 Impacts on historic and cultural resources from the construction and operation of a new natural 

35 gas alternative would include those common to all replacement power alternatives. The natural 

36 gas facility would require an estimated 50 ac (20 ha) of land for the power plant, as well as up to 

37 25 ac (10 ha) for gas pipeline rights of way. Some infrastructure upgrades could be required, as 

38 well as construction of a new or upgraded pipeline. Impacts from the construction and operation 

39 of a new natural gas alternative would be similar to, but less than, the impacts described for the 

40 new nuclear and coal alternatives. Given the preference to site the power plant on previously 

41 disturbed land and given that no major infrastructure upgrades would be necessary, avoidance 

42 of significant historic and cultural resources would be possible and could be managed 

43 effectively. Therefore, the NRC staff concludes that construction and operation of a new natural 
4-45

1 gas power plant on the Entergy property would not adversely affect known historic and cultural 

2 resources.

3 4.9.3.4 Combination Alternative (Natural Gas Combined Cycle, Biomass, and Demand Side 

4 Management)

5 The combination alternative assumes that Entergy would build a new natural gas plant and four 

6 new biomass units on its existing property. Impacts on historic and cultural resources from the 

7 construction and operation of this facilities would include those common to all replacement 

8 power alternatives. The combination alternative would require a total of 120 ac (49 ha) of land 

9 for the natural gas and biomass components. Some infrastructure upgrades could be required, 

10 as well as construction of a new or upgraded natural gas pipeline. Additional offsite land for the 

11 biomass component is not anticipated for fuel feedstock but could be required for storing, 

12 loading, and transporting biomass fuel materials. The demand-side management component 

13 would be implemented through energy efficiency and demand-side management programs 

14 across the Entergy service area.

15 Impacts from the construction and operation of the natural gas and biomass components of the 

16 combination alternative would be similar to the new nuclear, coal and natural gas only 

17 alternatives. Given the preference to site the power plant on previously disturbed land and 

18 given that no major infrastructure upgrades would be necessary, avoidance of significant 

19 historic and cultural resources would be possible and could be managed effectively. Activities 

20 associated with the demand-side management component of this alternative would not have 

21 any direct impact on historic and cultural resources. Therefore, construction and operation of 

22 the combination alternative on the Entergy property would not adversely affect known historic 

23 and cultural resources.

24 4.10 Socioeconomics

25 This section describes the potential socioeconomic impacts of the proposed action (license 

26 renewal) and alternatives to the proposed action.

27 4.10.1 Proposed Action

28 Socioeconomic effects of ongoing reactor operations at RBS have become well established as 

29 regional socioeconomic conditions have adjusted to the presence of the nuclear power plant. 

30 Any changes in employment and tax revenue caused by license renewal and any associated 

31 refurbishment activities could have a direct and indirect impact on community services and 

32 housing demand, as well as traffic volumes in the communities around the nuclear power plant.

33 Entergy indicated in its environmental report that it has no plans to add non-outage workers 

34 during the license renewal term and that increased maintenance and inspection activities could 

35 be managed using the current workforce (Entergy 2017h). Consequently, people living in the 

36 vicinity of RBS would not experience any changes in socioeconomic conditions during the 

37 license renewal term beyond what is currently being experienced. Therefore, the impact of 

38 continued reactor operations during the license renewal term would not exceed the 

39 socioeconomic impacts predicted in the GEIS. For these issues, the GEIS predicted that 

40 socioeconomic impacts would be SMALL for all nuclear plants.
4-46

1 4.10.2 No-Action Alternative

2 4.10.2.1 Socioeconomics 

3 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

4 shut down on or before the expiration of the current facility operating license. This would have a 

5 noticeable impact on socioeconomic conditions in the parishes and communities near RBS. 

6 The loss of jobs, income, and tax revenue would have an immediate socioeconomic impact. As 

7 jobs are eliminated, some, but not all, of the 680 RBS workers would begin to leave the region. 

8 Employment and income from the buying and selling of goods and services needed to operate 

9 and maintain the nuclear power plant would also be reduced. The loss of tax revenue could 

10 result in the reduction or elimination of some public and educational services.

11 If RBS workers and their families move out of the region, increased housing vacancies and 

12 decreased demand would likely cause housing prices to fall. Socioeconomic impacts from the 

13 termination of reactor operations would be concentrated in East Baton Rouge and West 

14 Feliciana parishes. These are the communities most reliant on income from nuclear plant 

15 operations at RBS because the majority of RBS workers reside in these two parishes. 

16 However, the socioeconomic impact from the loss of jobs, income, and tax revenue, may be 

17 less noticeable in some communities because of the amount of time required for 

18 decommissioning. The socioeconomic impacts from not renewing the operating license and 

19 terminating reactor operations at RBS would, depending on the jurisdiction, range from SMALL 

20 to MODERATE.

21 4.10.2.2 Transportation 

22 Traffic congestion caused by commuting workers and truck deliveries on roads in the vicinity of 

23 RBS would be reduced after power plant shutdown. Most of the reduction in traffic volume 

24 would be associated with the loss of jobs. The number of truck deliveries to RBS would also be 

25 reduced until decommissioning. Traffic-related transportation impacts would be SMALL at RBS 

26 as a result of power plant shutdown.

27 4.10.3 Replacement Power Alternatives: Common Impacts

28 Workforce requirements for replacement power alternatives were evaluated to measure their 

29 possible effects on current socioeconomic and transportation conditions. Table 4-4 summarizes 

30 socioeconomic and transportation impacts of replacement power alternatives. The following 

31 provides a discussion of the common socioeconomic and transportation impacts during 

32 construction and operation of replacement power generating facilities.

33 4.10.3.1 Socioeconomics 

34 Socioeconomic impacts are defined in terms of changes in the social and economic conditions 

35 of a region. For example, the creation of jobs and the purchase of goods and services during 

36 the construction and operation of a replacement power plant could affect regional employment, 

37 income, and tax revenue. For each alternative, two types of jobs would be created: 

38 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term

39 socioeconomic impact, and (2) operations jobs, which have the greater potential for permanent, 

40 long-term socioeconomic impacts.
4-47

1 While the selection of a replacement power alternative would result in the creation of new jobs, 

2 income, spending, and tax revenues, it would also result in the loss of jobs at RBS and a 

3 corresponding reduction in income and tax revenue in local parishes and communities. These 

4 impacts are described in the no-action alternative (Section 4.10.2).

5 Construction

6 The relative economic effect of an influx of workers on the local economy and tax base would 

7 vary, with the greatest impacts occurring in the communities where the majority of construction 

8 workers would reside and spend their incomes. As a result, some local communities could 

9 experience an economic boom during construction from increased tax revenue and income 

10 generated by expenditures for goods and services and the increased demand for temporary 

11 (rental) housing. After construction, local communities would likely experience a return to 

12 preconstruction economic conditions.

13 Operation

14 Prior to the commencement of startup and operations, local communities would see an influx of 

15 operations workers and their families and the increased demand for permanent housing and 

16 public services. These communities would also experience the economic benefits from 

17 increased income and tax revenue generated by the purchase of goods and services needed to 

18 operate a new replacement power plant. Consequently, power plant operations would have a 

19 greater potential for effecting permanent, long-term socioeconomic impacts on the region.

20 4.10.3.2 Transportation

21 Transportation impacts are defined in terms of changes in level of service conditions on local 

22 roads in the region. Additional vehicles on local roadways during construction and operations 

23 could lead to traffic congestion, level of service impacts, and delays at intersections.

24 Construction

25 Transportation impacts during the construction of a replacement power plant would consist of 

26 commuting workers and truck deliveries of equipment and material to the construction site. 

27 Workers would arrive via site access roads and the volume of traffic would increase 

28 substantially during shift changes. In addition, trucks would transport equipment and material to 

29 the construction site, thus increasing the amount of traffic on local roads. The increase in traffic 

30 volumes could result in levels of service impacts and delays at intersections during certain hours 

31 of the day. In some instances, construction material could also be delivered by rail or barge.

32 Operation

33 Traffic-related transportation impacts would be greatly reduced after construction has been 

34 completed. Transportation impacts would include daily commuting by the operations workforce 

35 and deliveries of material, and the removal of commercial waste material by truck.
4-48

1 Table 4-4. Socioeconomic and Transportation Impacts of Replacement Power 

2 Alternatives

Alternative Resource Requirements Impacts Discussion

New Nuclear Construction: 3,500 

workers(a)

MODERATE 

to LARGE

Some nuclear workers could transfer 

from RBS to the new nuclear power 

Operations: 680 workers(a) SMALL to plant.

MODERATE

Supercritical 

Pulverized Coal

Construction: 2,200 

workers(b)

MODERATE 

to LARGE

Onsite coal storage would make it 

possible to receive several trains per 

day at a site with rail access. Coal 

and limestone delivery and ash 

removal via rail would cause levels of 

service impacts due to delays at 

railroad crossings. Coal and other 

materials could be delivered by barge. Operations: 300 workers(b) SMALL to 

MODERATE

Natural Gas 

Combined-Cycle

Construction: 1,450 

workers(b)

MODERATE 

to LARGE

Because natural gas fuel is 

transported by pipeline, local roads 

would experience little to no 

increased traffic during power plant 

operations.

Operations: 180 workers(b) SMALL to 

MODERATE

Combination, 

NGCC, Biomass 

and 

Demand-Side 

Management

Construction: 960 (NGCC) 

and 200 (Biomass) workers(c)

SMALL to 

MODERATE

The demand-side management 

component could generate additional 

employment, depending on the nature 

of the conservation and energy 

efficiency programs and the need for 

direct measure installations in homes 

and office buildings. Jobs would likely 

be few and scattered throughout the 

region, and would not have a 

noticeable effect on the local 

economy. The demand-side 

management component would not 

cause an increase traffic volumes on 

local roads and would therefore have 

no transportation impacts.

Operations: 120 (NGCC) and

88 (Biomass) workers(C)

SMALL

(a) Entergy 2017h, Times-Free Press 2015.

(b) Entergy 2017h, NRC 1996.

(c) Entergy 2017h, NRC 2013b.

Source: Entergy 2017h, NRC 1996, NRC 2013b, Times-Free Press 2015.

3 4.11 Human Health 

4 This section describes the potential human health impacts of the proposed action (license 

5 renewal) and alternatives to the proposed action.

6 4.11.1 Proposed Action

7 As identified in Table 4-1, the impacts of all generic human health issues would be SMALL. 

8 Table 4-2 identifies two site-specific (Category 2) issues (microbiological hazards and electric 

9 shock hazards) and one uncategorized issue (chronic exposure to electromagnetic fields) 
4-49

1 related to human health applicable to RBS during the license renewal term. These issues are 

2 analyzed below. 

3 4.11.1.1 Category 2 Issue Related to Human Health: Microbiological Hazards to the Public 

4 In the GEIS (NRC 2013b), the NRC determined that the effects of thermophilic microorganisms 

5 on the public for plants using cooling ponds, lakes, or canals or cooling towers or that discharge

6 to a river is a Category 2 issue (see Table 4-12) that requires site-specific evaluation during 

7 each license renewal review.

8 In order to determine whether the continued operations of RBS could promote increased growth 

9 of thermophilic microorganisms and thus have an adverse health effect on the public, the NRC 

10 staff considered several factors: the thermophilic microorganisms of concern, RBS’s thermal 

11 effluent characteristics, recreational use of the Mississippi River, and reports and input from the 

12 Louisiana Department of Health (LDH) and the Louisiana Office of Public Health (LOPH).

13 Section 3.11.3 describes the thermophilic microorganisms that the GEIS identified to be of 

14 potential concern at nuclear power plants and summarizes data from the Centers for Disease 

15 Control and Prevention (CDC), the Louisiana Office of Public Health, and the Louisiana 

16 Department of Health on the prevalence of waterborne diseases associated with these 

17 microorganisms. Data from the three organizations indicate that no outbreaks or cases of 

18 waterborne Salmonella, Pseudomonas aeruginosa, or Naegleria fowleri infection from the 

19 Mississippi River or recreational waters have occurred in Louisiana in the past 10 years of 

20 available data (CDC 2017d; LDH undated; LOPH 2013). Based on the information presented in 

21 Section 3.11.3, the thermophilic organisms most likely to be of potential concern at or near RBS 

22 are Shigella and Legionella. 

23 Shigellosis infections have been reported in the United States due to exposure in lakes, 

24 reservoirs, and other recreational waters (CDC 2004, 2006, 2008, 2011, 2014b, 2015a). RBS 

25 continuously discharges thermal effluent to the Mississippi River, creating a thermal plume with 

26 temperatures elevated above 90°F that is generally smaller than 54 ft by 5 ft (16.5 m by 1.5 m) 

27 (Entergy 2008a and 2017h). While the thermal discharge may occasionally be within the range 

28 of the optimal growth temperature for Shigella (95 °F (35 °C)), the thermal discharge is not likely 

29 to increase the rate of Shigellosis infections because the size of the thermal plume is relatively 

30 small compared to the width and depth of the Mississippi River, and the thermal effluent quickly 

31 dissipates given the fast flow of the Mississippi River near the discharge structure 

32 (Entergy 2017h). In addition, human contact with the thermal discharge is unlikely because 

33 recreational activities, such as swimming or boating, do not typically occur near the RBS 

34 discharge structure or near the thermal plume because of dangerous strong, swift currents 

35 (Entergy 2017h). The Louisiana Department of Health did not identify any concerns regarding 

36 any thermophilic organisms as result of RBS’s thermal effluent discharged into the Mississippi 

37 River (Entergy 2017d; NRC 2018b). Given the small area of thermally heated waters, the 

38 unlikelihood of the water to create conditions favorable to thermophilic microorganisms, and the 

39 lack of recreational activities that occur near the RBS thermal plume, infections are unlikely. 

40 Legionellosis outbreaks are often associated with complex water systems housed inside 

41 buildings or structures, such as cooling towers (CDC 2017a). RBS has cooling towers as part of 

42 the cooling-water system. Public exposure to aerosolized Legionella would not be likely 

43 because such exposure would be confined to a small area of the site that is restricted to public 

44 access. Plant workers would be the most likely to be exposed when cleaning or providing other 

45 maintenance services that involve the cooling-water system, including cooling towers and 
4-50

1 condensers. Entergy (2017g) stated that several procedural measures would minimize the 

2 likelihood of exposure, such as conducting a standard methodology for identifying industrial 

3 hazards prior to performance of such jobs, and implementing worker protection measures. For 

4 example, because respiratory or nasal infectivity routes are of primary concern with 

5 legionellosis, workers performing underwater activities should wear protective gear to prevent 

6 oral or nasal exposure to amoebae or other pathogenic bacteria (NRC 2013b).

7 Conclusion

8 CDC, Louisiana Office of Public Health, and Louisiana Department of Health data indicate that 

9 no outbreaks or cases of waterborne Salmonella, Pseudomonas aeruginosa, or Naegleria 

10 fowleri infection from the Mississippi River or other recreational waters have occurred in 

11 Louisiana (CDC 2017d; LDH undated; LOPH 2013). Although the thermophilic microorganism 

12 Shigella has been linked to waterborne outbreaks in Louisiana, Shigella infections are unlikely 

13 given the small area of thermally heated waters, the unlikelihood of the water to create 

14 conditions favorable to thermophilic microorganisms, and the lack of recreational water use near 

15 the RBS thermal plume. In addition, the Louisiana Department of Health did not identify any 

16 concerns regarding thermophilic organisms as result of RBS’s thermal effluent (Entergy 2017d; 

17 NRC 2018b). Although Legionella has the potential to occur within cooling towers and 

18 condensers at RBS, infection is not likely given that these areas are restricted to the public and 

19 Entergy has procedures to help ensure that plant workers take protective measures to minimize 

20 exposure to biological hazards. Based on the above information, the NRC staff concludes that 

21 the impacts of thermophilic microorganisms to the public are SMALL for RBS license renewal.

22 4.11.1.2 Uncategorized Issue Relating to Human Health: Chronic Effects of Electromagnetic 

23 Fields (EMFs)

24 The GEIS (NRC 2013b) does not designate the chronic effects of 60-Hz electromagnetic fields 

25 (EMFs) from power lines as either a Category 1 or Category 2 issue. Until a scientific 

26 consensus is reached on the health implications of electromagnetic fields, the NRC will not 

27 include them as Category 1 or 2 issues.

28 The potential for chronic effects from these fields continues to be studied and is not known at 

29 this time. The National Institute of Environmental Health Sciences (NIEHS) directs related 

30 research through the U.S. Department of Energy (DOE).

31 The report by the National Institute of Environmental Health Sciences (NIEHS 1999) contains 

32 the following conclusion:

33 The NIEHS concludes that ELF-EMF (extremely low frequency-electromagnetic 

34 field) exposure cannot be recognized as entirely safe because of weak scientific 

35 evidence that exposure may pose a leukemia hazard. In our opinion, this finding 

36 is insufficient to warrant aggressive regulatory concern. However, because 

37 virtually everyone in the United States uses electricity and therefore is routinely 

38 exposed to ELF-EMF, passive regulatory action is warranted such as continued 

39 emphasis on educating both the public and the regulated community on means 

40 aimed at reducing exposures. The NIEHS does not believe that other cancers or 

41 non-cancer health outcomes provide sufficient evidence of a risk to currently 

42 warrant concern.
4-51

1 This statement was not sufficient to cause the NRC to change its position with respect to the 

2 chronic effects of electromagnetic fields. The NRC staff considers the GEIS finding of 

3 “UNCERTAIN” still appropriate and will continue to follow developments on this issue.

4 4.11.1.3 Category 2 Issue Related to Human Health: Electric Shock Hazards

5 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

6 energized conductors or from induced charges in metallic structures has not been identified to 

7 be a problem at most operating plants and generally is not expected to be a problem during the 

8 license renewal term. However, a site-specific review is required to determine the significance 

9 of the electric shock potential along the portions of the transmission lines that are within the 

10 scope of RBS license renewal review. 

11 As discussed in Section 3.11.4, there are no offsite transmission lines that are in scope for this 

12 SEIS. Therefore, there are no potential impacts to members of the public. 

13 As discussed in Section 3.11.5, RBS maintains an occupational safety program in accordance 

14 with the Occupational Safety & Health Administration regulations for its workers, which includes 

15 protection from acute electric shock. Therefore, the NRC staff concludes that the potential 

16 impacts from acute electric shock during the license renewal term would be SMALL.

17 4.11.1.4 Severe Accidents

18 As shown in Table 4-1, design-basis accidents are addressed in the GEIS (NRC 2013b) as a 

19 Category 1 issue. Severe nuclear accidents are those that are more severe than design-basis 

20 accidents because they could result in substantial damage to the reactor core, whether or not 

21 there are serious offsite consequences. In the GEIS, the NRC staff assessed the effects of 

22 severe accidents during the period of extended operation, using the results of existing analyses 

23 and site-specific information to conservatively predict the environmental impacts of severe 

24 accidents for each plant during the period of extended operation.

25 Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, 

26 fires, and sabotage have not traditionally been discussed in quantitative terms in final 

27 environmental statements and were not specifically considered for the RBS site in the GEIS

28 (NRC 1996). However, the GEIS did evaluate existing impact assessments performed by the 

29 NRC and by the industry at 44 nuclear plants in the United States and concluded that the risk 

30 from beyond-design-basis earthquakes at existing nuclear power plants is SMALL. The GEIS 

31 for license renewal performed a discretionary analysis of terrorist acts in connection with license 

32 renewal, and concluded that the core damage and radiological release from such acts would be 

33 no worse than the damage and release expected from internally initiated events. In the GEIS, 

34 the Commission concludes that the risk from sabotage and beyond-design-basis earthquakes at 

35 existing nuclear power plants is small and additionally, that the risks from other external events 

36 are adequately addressed by a generic consideration of internally initiated severe accidents 

37 (NRC 2013b).

38 Based on information in the 1996 GEIS, the staff found the following to be true:

39 The probability weighted consequences of atmospheric releases, fallout onto 

40 open bodies of water, releases to ground water, and societal and economic 

41 impacts from severe accidents are small for all plants. However, alternatives to 
4-52

1 mitigate severe accidents must be considered for all plants that have not 

2 considered such alternatives.

3 The NRC staff identified no new and significant information related to severe accidents during 

4 its review of Entergy’s environmental report for RBS (Entergy 2017h), the site audit, the scoping

5 process, or the evaluation of other available information. Therefore, there are no impacts 

6 related to these issues for RBS beyond those discussed in the GEIS. However, in accordance 

7 with 10 CFR 51.53(c)(3)(ii)(L), the staff has reviewed severe accident mitigation alternatives 

8 (SAMAs) for RBS.

9 Severe Accident Mitigation Alternatives

10 Section 51.53(c)(3)(ii)(L) of 10 CFR Part 51 requires that license renewal applicants consider 

11 alternatives to mitigate severe accidents if the staff has not previously evaluated SAMAs for the 

12 applicant's plant in an EIS or related supplement or in an environmental assessment. The 

13 purpose of this consideration is to assure that plant changes (i.e., hardware, procedures, and 

14 training) with the potential for improving severe accident safety performance are identified and 

15 evaluated. SAMAs have not been previously considered for RBS; therefore, SAMAs are 

16 addressed in the following discussion and in Appendix F to this SEIS. 

17 Overview of SAMA Process

18 This section presents a summary of Entergy’s SAMA evaluation for RBS and the NRC staff’s 

19 review of that evaluation. The NRC staff performed its review with contract assistance from 

20 Pacific Northwest National Laboratory. The NRC staff's review is available in greater detail in 

21 Appendix F to this SEIS; the applicant’s SAMA analysis is described in Section 4.15.1 and 

22 Attachment D (Severe Accident Mitigation Alternatives Analysis) in Entergy’s environmental 

23 report for the RBS license renewal application.

24 Entergy conducted its River Bend SAMA evaluation using a four-step approach. In the first 

25 step, Entergy quantified the level of risk associated with potential reactor accidents using the 

26 plant-specific probabilistic risk assessment (PRA) and other risk models.

27 In the second step, Entergy examined the major risk contributors and identified possible ways 

28 (SAMAs) of reducing that risk. Common ways of reducing risk are changes to components, 

29 systems, procedures, and training. Entergy initially identified 206 potential SAMAs for RBS. 

30 Entergy performed an initial screening to eliminate any SAMAs that were not applicable to RBS 

31 due to design differences, had already been implemented at RBS, or were combined into a 

32 more comprehensive or plant-specific SAMA. As a result of this initial screening, 50 unique 

33 SAMAs remained for further evaluation.

34 In the third step, Entergy estimated the benefits and the costs associated with each of the 

35 SAMAs. Estimates were made of how much each SAMA could reduce risk. Those estimates 

36 were developed in terms of dollars in accordance with NRC guidance for performing regulatory 

37 analyses (NRC 1997). A more conservative monetary equivalent of unit dose of $5,500 per 

38 person-rem was used in the benefit calculations using the methodology in NUREG-1530, Rev. 1 

39 (NRC 2015b). The cost of implementing the proposed SAMAs was also estimated.

40 Finally, in the fourth step, Entergy compared the costs and benefits of each of the remaining 

41 SAMAs to determine whether each SAMA was cost beneficial, meaning the benefits of the 

42 SAMA were greater than the cost (a positive cost benefit). Entergy concluded in its 
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1 environmental report that several of the SAMAs it evaluated are potentially cost beneficial 

2 (Entergy 2017h, Entergy 2017g).

3 The potentially cost-beneficial SAMAs do not relate to adequately managing the effects of aging 

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

5 license renewal pursuant to 10 CFR Part 54, “Requirements for Renewal of Operating Licenses 

6 for Nuclear Power Plants.” Entergy did, however, enter the 10 potentially cost beneficial SAMAs 

7 into the action tracking process to further evaluate their implementation (Entergy 2017h, Entergy 

8 2017g), and the NRC staff has referred those SAMAs to appropriate members of the NRC’s 

9 operating reactor staff in the Office of Nuclear Reactor Regulation (NRR) for followup 

10 consideration. Entergy’s SAMA analyses and the NRC staff's review are discussed in more 

11 detail below.

12 Estimate of Risk

13 Entergy submitted an assessment of SAMAs for RBS as part of its environmental report 

14 (Entergy 2017h). Entergy based this assessment on the most recent revision of the River Bend 

15 PRA; an internal events model and plant-specific offsite consequence analysis performed using 

16 the MELCOR Accident Consequence Code System 2 (MACCS) computer program; and insights 

17 from the RBS individual plant examination (IPE) (Entergy 1993), individual plant examination of 

18 external events (IPEEE) (Entergy 1995), and the RBS internal flooding PRA.

19 Entergy combined two distinct analyses to form the basis for the risk estimates it used in the 

20 SAMA analysis: (i) the RBS Level 1 and 2 PRA model, which is an updated version of the IPE 

21 (Entergy 1993), and (ii) a supplemental analysis of offsite consequences and economic impacts 

22 (essentially a Level 3 PRA model) developed specifically for the SAMA analysis. The scope of 

23 the models does not include external events or internal flooding events.

The RBS core damage frequency (CDF) for internal events is approximately 2.8 × 10−5 24 per year. 

25 Table 4-5 provides the breakdown of CDF by initiating event for RBS for internal events. 

26 Entergy used the PRA model for RBS in determining the potential risk reduction benefits of each 

27 SAMA. Entergy accounted for the potential risk reduction benefits associated with external 

28 events (e.g., fire, seismic, high wind and other events) and internal flooding events by 

29 multiplying the estimated benefits obtained from the River Bend PRA by a factor of seven.

30 Table 4-5. River Bend Station Core Damage Frequency for Internal Events

Initiating Event

CDF

(per reactor-year)

% CDF

Contribution

Loss of Offsite Power 1.9 × 10−6 69

Reactor Trip/Turbine Trip 2.8 × 10−7 10

Inadvertent Opening of Safety Relief Valve (SRV) 1.5 × 10−7 6

Failure of the Normal Service Water (NSW)/

Service Water Cooling (SWC) System

1.2 × 10−7 4

Loss of Condenser Heat Sink 7.3 × 10−8 3

Loss of the Feedwater/Condensate System 6.8 × 10−8 2

Loss of Offsite Power Lead RSS1 5.0 × 10−8 2
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Initiating Event

CDF

(per reactor-year)

% CDF

Contribution

Loss of Offsite Power Lead RSS2 5.0 × 10−8 2

Other Initiating Eventsa 8.0 × 10−8 3

Total CDF (Internal Events) 2.8 × 10−5 100b

(a) Multiple initiating events with each contributing less than 1 percent

(b) Sum of contributors does not add up to 100 percent due to round off error.

Source: Derived from Entergy 2017h

1 Entergy estimated the dose to the population within 50 mi (80 km) of the RBS site to be 

2 approximately 0.0121 person-Sievert (Sv) (1.21 person-rem) per year (Entergy 2017h). The 

3 breakdown of the total population dose and offsite economic cost risk by containment release 

4 mode is summarized in Table 4-6. Containment penetration failures in which the containment 

5 fails prior to core damage and debris cooling is unsuccessful (Source Term Category (STC) 9 

6 and STC10) are the dominant contributors to population dose risk.

7 Table 4-6. Breakdown of Population Dose and Offsite Economic Cost by Containment 

8 Release Mode

Containment Release 

Modeb

Population Dose Riska Offsite Economic Cost Risk

personrem/yr% 

Contribution

$/yr % 

Contribution

STC1 (Intact) 1.0 × 10−2 1 3.6 <1

STC4 2.1 × 10−2 2 1.3 × 102 2

STC7 7.8 × 10−3 1 5.8 <1

STC8 1.2 × 10−2 1 1.8 × 101 <1

STC9 4.7 × 10−1 39 2.5 × 103 34

STC10 5.5 × 10−1 46 3.9 × 103 53

STC13 6.1 × 10−2 5 2.9 × 102 4

STC14 6.9 × 10−2 6 4.7 × 102 6

Otherc 4.7 × 10−3 <1 3.0 × 101 <1

Total 1.21 100d 7.3 × 103 100

(a) Unit Conversion Factor: 1 Sv = 100 rem

(b) Release Mode descriptions provided in Section D.1.2.3.1 of the ER (Entergy 2017h)

(c) Multiple release categories with each contributing less than 1 percent to frequency, population

dose, and offsite economic cost risk

(d) Sum of contributors does not add up to 100 percent due to round off error

Source: Derived from Entergy 2017h. 

9 The NRC staff has reviewed Entergy's data and evaluation methods and concludes that the 

10 quality of the risk analyses is adequate to support an assessment of the risk reduction potential 
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1 for candidate SAMAs. Accordingly, the staff based its assessment of offsite risk on the CDFs, 

2 offsite doses, and offsite economic costs reported by Entergy.

3 Potential Plant Improvements

4 Once Entergy identified the dominant contributors to plant risk, it searched for ways to reduce 

5 that risk. In identifying potential SAMAs, Entergy considered SAMAs identified in industry 

6 documents including the SAMA analyses performed for other operating plants, insights from the 

7 plant-specific PRA models, plant improvements identified in the River Bend IPE, and plant 

8 improvements identified in the IPEEE. Entergy identified 206 potential risk-reducing 

9 improvements (SAMAs) to plant components, systems, procedures, and training.

10 In evaluating potential SAMAs, Entergy performed a qualitative screening and eliminated 

11 158 SAMAs from further consideration because they were not applicable to RBS due to design 

12 differences, they had already been implemented at RBS, they were similar in nature or could be 

13 combined with another SAMA, they had excessive implementation costs, or they were expected 

14 to have very low benefits. Entergy then performed a detailed cost-benefit analysis for each of 

15 the 50 remaining SAMAs.

16 The staff concludes that Entergy used a systematic and comprehensive process for identifying 

17 potential plant improvements for RBS, and that the set of SAMAs Entergy evaluated in its 

18 environmental report, together with those it evaluated in response to NRC staff inquiries, is 

19 reasonably comprehensive and, therefore, acceptable.

20 Evaluation of Risk Reduction and Costs of Improvements

21 Entergy evaluated the risk reduction potential of the 50 candidate SAMAs in addition to other 

22 SAMAs identified in response to NRC staff inquiries. Entergy performed SAMA evaluations 

23 using generally conservative assumptions. Entergy used PRA model requantification to 

24 determine the potential benefits for each SAMA, except for those SAMAs that specifically 

25 address internal floods and internal fires. The CDF, population dose, and offsite economic cost 

26 reductions for internal events were estimated using the River Bend PRA models 

27 (Entergy 2017h). For the internal flooding-related SAMA, Entergy used the RBS flooding 

28 analysis to estimate the reduction in CDF. The ratio of this CDF reduction to the total CDF for 

29 internal events was multiplied by the total present dollar value equivalent associated with 

30 completely eliminating severe accidents from internal events at RBS. For the two internal fire 

31 related SAMAs, Entergy used the fire analysis results to estimate the reduction in CDF. For 

32 each of these SAMA candidates, the ratio of the internal fire CDF reduction from implementing 

33 the SAMA to the total internal events CDF was multiplied by the total present dollar value 

34 equivalent associated with completely eliminating severe accidents from internal events at RBS 

35 to obtain the benefit for the reduction in the internal fire CDF.

36 The NRC staff reviewed the assumptions Entergy used to evaluate the benefit or risk reduction 

37 estimate for each of the plant improvements. The NRC staff concludes that the rationale and 

38 assumptions for estimating risk reduction are sufficient and appropriate for use in the SAMA

39 evaluation because they are technically sufficient and meet the guidance provided in 

40 NEI 05-01A.

41 Entergy estimated the costs of implementing each of the candidate SAMAs through the 

42 development of RBS-specific cost estimates or with cost estimates developed by other NRC 
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1 licensees for similar improvements at other nuclear power plants. The cost estimates 

2 conservatively did not account for inflation.

3 The NRC staff reviewed the bases for the applicant's cost estimates. For certain improvements, 

4 the staff also compared the cost estimates to estimates developed elsewhere for similar 

5 improvements, including estimates developed as part of other licensees' analyses of SAMAs for 

6 operating reactors. The NRC staff also reviewed the basis for the cost estimates during the 

7 NRC audit of the SAMA analysis. The NRC staff concludes that the cost estimates Entergy

8 provided are sufficient and appropriate for use in the SAMA evaluation.

9 Cost-Benefit Comparison

10 Entergy based its cost-benefit analysis primarily on NUREG/BR-0184 (NRC 1997) and executed 

11 its analysis consistent with this guidance. A more conservative monetary equivalent of unit 

12 dose of $5,500 per person-rem was used in the benefit calculations using the methodology in 

13 NUREG-1530, Rev. 1 (NRC 2015b). Entergy also followed NEI 05-01A, “Severe Accident 

14 Mitigation Alternatives (SAMA) Guidance Document” (NEI 2005), which was endorsed in NRC 

15 Regulatory Guide 4.2, Supplement 1 (NRC 2013). NEI 05-01A states that two sets of estimates 

16 should be developed—one using a 3 percent discount rate and one using a 7 percent discount 

17 rate (NEI 2005). Entergy provided a base set of results using a discount rate of 7 percent and a 

18 29-year license renewal period and based its decisions regarding potentially cost-beneficial

19 SAMAs on these values. Entergy also performed sensitivity analyses involving two of the 

20 MACCS offsite contamination inputs, in accordance with the Commission’s decision in the 

21 Indian Point license renewal proceeding (CLI-16-07) (NRC 2016d).

22 In Entergy’s analysis, if the implementation costs for a candidate SAMA exceeded the 

23 calculated benefit, Entergy determined that the SAMA was not cost beneficial. If the SAMA 

24 benefit exceeded the estimated cost, then Entergy considered the SAMA candidate potentially 

25 cost beneficial. Considering the results from the baseline and sensitivity analyses, the full set of 

26 potentially cost-beneficial SAMAs that Entergy identified in its environmental report and in 

27 response to NRC staff inquiries are:

28 • SAMA No. 94a—Enhance procedures for actions on loss of heating, ventilation and

29 air conditioning (HVAC) to the high pressure core spray (HPCS) pump room

30 • SAMA No. 94b—Enhance procedures for actions on loss of HVAC to the residual

31 heat removal (RHR) B and C (B/C) pump rooms

32 • SAMA No. 94c—Enhance procedures for actions on loss of HVAC to the low

33 pressure core spray (LPCS) and RHR A pump rooms

34 • SAMA No. 97—Perform study and analysis to add steps to trip unneeded emergency

35 core cooling system (ECCS) pumps on loss of HVAC

36 • SAMA No. 102—Operator procedure revisions to provide additional space cooling to

37 the emergency diesel generator (EDG) room via the use of portable equipment

38 • SAMA No. 169—Improve internal flooding procedures

39 • SAMA No. 185—Upgrade the alternate shutdown system (ASDS) panel to include

40 additional system controls for opposite division

41 • SAMA No. 198—Develop a procedure for alternating operation of low pressure

42 ECCS pumps for loss of standby service water (SSW)

43 • SAMA No. 205—Revise flexible coping strategies (FLEX) procedures to allow use of

44 FLEX equipment in non-extended loss of alternative current power (ELAP) conditions
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1 • SAMA No. 5.b.ii—Improve procedures and training on injection with the fire water 

2 system

3 Entergy entered the 10 potentially cost-beneficial SAMAs into the action tracking process to 

4 further evaluate their implementation (Entergy 2017h, Entergy 2017g). The NRC staff reviewed 

5 Entergy’s cost-benefit evaluations of each SAMA and concludes that, with the exception of the 

6 10 potentially cost-beneficial SAMAs discussed above; the costs of the SAMAs evaluated would 

7 be higher than the associated benefits.

8 Conclusions

9 The NRC staff reviewed Entergy's analysis and concludes that Entergy’s methods and the 

10 implementation of those methods were sound. The treatment of SAMA benefits and costs 

11 support the general conclusion that Entergy’s SAMA evaluations are reasonable and sufficient 

12 for the license renewal application submittal.

13 The staff agrees with Entergy’s conclusion that the 10 candidate SAMAs discussed in this 

14 section are potentially cost beneficial, which was based on generally conservative treatment of 

15 costs, benefits, and uncertainties. This conclusion of a small number of potentially 

16 cost beneficial SAMAs is consistent with the low residual level of risk indicated in the River Bend 

17 PRA and the fact that Entergy has already implemented the plant improvements identified from 

18 the IPE and IPEEE. Because the potentially cost beneficial SAMAs do not relate to aging 

19 management during the period of extended operation, Entergy does not need to implement

20 them as part of license renewal in accordance with Title 10 of the Code of Federal Regulations, 

21 Part 54. Nevertheless, Entergy stated that it has entered each of these potentially 

22 cost beneficial SAMAs into the RBS action tracking system to further evaluate their 

23 implementation, and the NRC staff has referred those SAMAs to appropriate staff members for 

24 follow-up consideration. 

25 4.11.2 No-Action Alternative

26 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

27 shut down on or before the expiration of the current facility operating license. Human health 

28 risks would be smaller following plant shutdown. The reactor unit, which currently operates 

29 within regulatory limits, would emit less radioactive gaseous, liquid, and solid material to the 

30 environment. In addition, following shutdown, the variety of potential accidents at the plant 

31 (radiological or industrial) would be reduced to a limited set associated with shutdown events 

32 and fuel handling and storage. In Section 4.11.1, the NRC staff concluded that the impacts of 

33 continued plant operation on human health would be SMALL, except for “Chronic effects of 

34 electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. In Section 4.12, the 

35 NRC staff concluded that the impacts of accidents during operation are SMALL. Therefore, as 

36 radioactive emissions to the environment decrease, and as the likelihood and types of accidents 

37 decrease following shutdown, the NRC staff concludes that the risk to human health following 

38 plant shutdown would be SMALL.

39 4.11.3 Replacement Power Alternatives: Common Impacts

40 Impacts on human health from construction of a power station would be similar to impacts 

41 associated with the construction of any major industrial facility. Compliance with worker 

42 protection rules, the use of personal protective equipment, training, and placement of 

43 engineered barriers would control those impacts on workers at acceptable levels. 
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1 The human health impacts from the operation of a power station include public risk from 

2 inhalation of gaseous emissions. Regulatory agencies, including the U.S. Environmental 

3 Protection Agency and State agencies, base air emission standards and requirements on 

4 human health impacts. These agencies also impose site-specific emission limits to protect 

5 human health. 

6 4.11.3.1 New Nuclear Alternative

7 The construction impacts of one new nuclear unit would include those identified in 

8 Section 4.11.3. Since the NRC staff expects the licensee would limit access to active 

9 construction areas to only authorized individuals, the impacts on human health from the 

10 construction of one new nuclear unit would be SMALL.

11 The human health effects from the operation of one new nuclear unit would be similar to those 

12 of operating the existing RBS unit. As presented in Section 4.11.1, impacts on human health 

13 from the operation of RBS would be SMALL, except for “chronic effects of electromagnetic fields 

14 (EMFs),” for which the impacts are UNCERTAIN. Therefore, the NRC staff concludes that the 

15 impacts on human health from the operation of one new nuclear unit would be SMALL.

16 4.11.3.2 Supercritical Pulverized Coal Alternative

17 The construction impacts of a coal power plant would include those identified in Section 4.11.3 

18 as common to all replacement power alternatives. Since limiting the active construction area 

19 access to only authorized individuals is expected, the impacts on human health from the 

20 construction of a coal power plant would be SMALL.

21 The human health effects from the operation of a coal power plant would include those identified 

22 in Section 4.11.3 as common to all power replacement alternatives. Coal-fired power 

23 generation introduces worker risks from coal and limestone mining; worker and public risk from 

24 coal, lime, and limestone transportation; and public risk from inhalation of stack emissions. In 

25 addition, human health risks are associated with the management and disposal of coal 

26 combustion waste. Coal combustion generates waste in the form of ash; equipment for 

27 controlling air pollution generates additional ash and scrubber sludge. Human health risks may 

28 extend beyond the facility workforce to the public depending on the public’s proximity to the coal 

29 combustion waste disposal facility. The character and the constituents of coal combustion 

30 waste depend on both the chemical composition of the source coal and the technology used to 

31 combust it. Generally, the primary sources of adverse consequences from coal combustion 

32 waste are from exposure to sulfur oxide and nitrogen oxide in air emissions, radioactive 

33 elements such as uranium and thorium, and heavy metals and hydrocarbon compounds 

34 contained in fly ash, bottom ash, and scrubber sludge (NRC 2013b). Regulatory agencies, 

35 including the U.S. Environmental Protection Agency (EPA) and state agencies, base air 

36 emission standards and requirements on human health impacts. These agencies also impose 

37 site-specific emission limits as needed to protect human health. Given the regulatory oversight 

38 exercised by the EPA and State agencies, the NRC staff concludes that the human health 

39 impacts from radiological doses, inhaled toxins, and particulates generated from the operation 

40 of a coal alternative would be SMALL. 

41 4.11.3.3 Natural Gas Combined Cycle Alternative

42 The construction impacts of a natural gas alternative would include those identified in 

43 Section 4.11.3 as common to the construction of all replacement power alternatives. Since the
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1 NRC staff expects the builder will limit access to the active construction area to only authorized 

2 individuals, the impacts on human health from the construction of a natural gas alternative 

3 would be SMALL.

4 The human health effects from the operation of a natural gas alternative would include those 

5 identified in Section 4.11.3 as common to the operation of all replacement power alternatives. 

6 The risk may be attributable to nitrogen oxide emissions that contribute to ozone formation, 

7 which in turn contribute to health risk (NRC 2013b). Given the regulatory oversight exercised by 

8 EPA and State agencies, the NRC staff concludes that the human health impacts from the 

9 natural gas alternative would be SMALL.

10 4.11.3.4 Combination Alternative (Natural Gas Combined Cycle, Biomass, and Demand Side 

11 Management)

12 Impacts on human health from construction of a combination of natural gas, biomass, and 

13 demand-side management alternative would include those identified in Section 4.11.3 as 

14 common to the construction of all replacement power alternatives. Since the NRC staff expects 

15 the builder will limit access to the active construction area to only authorized individuals, the 

16 impacts on human health from the construction of a natural gas, biomass, and demand-side 

17 management combination alternative would be SMALL.

18 Operational hazards at a natural gas facility are discussed in Section 4.11.3.3. 

19 Operational hazards for biomass energy consists of the direct burning of forest residue/wood 

20 waste, which would likely include forest residue, primary mill residues, secondary mill residues, 

21 or urban wood residues. Given this method of fuel for power generation, the health impacts 

22 would be similar to those found in a comparably sized fossil-fuel power generation facility, and 

23 less for the biomass plants evaluated in this SEIS given the smaller total output (160 MWe) of 

24 the biomass plants included in this combination alternative,

25 Operational hazards impacts for the demand-side management portion of this alternative would 

26 be minimal and localized to activities such as weatherization efficiency of an end-user’s home or 

27 facility. The GEIS notes that the environmental impacts are likely to center on indoor air quality 

28 (NRC 2013b). This is because of increased weatherization of the home in the form of extra 

29 insulation and reduced air turnover rates from the reduction in air leaks. However, the actual 

30 impact is highly site specific and not yet well established.

31 Therefore, given the expected compliance with worker and environmental protection rules and 

32 the use of personal protective equipment, training, and engineered barriers, the NRC staff 

33 concludes that the potential human health impacts for the natural gas, biomass, and 

34 demand-side management alternative would be SMALL.

35 4.12 Environmental Justice

36 In section 3.12 of this SEIS, the NRC staff explains the basis for its consideration of 

37 environmental justice impacts in an EIS and identifies environmental justice populations (i.e., 

38 minority and low-income populations) within a 50-mi (80-km) radius of RBS. In this section, the 

39 staff describes the potential human health and environmental effects of the proposed action 

40 (license renewal) and alternatives to the proposed action on minority and low-income 

41 populations.
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1 4.12.1 Proposed Action

2 The NRC addresses environmental justice matters for license renewal by (1) identifying the 

3 location of minority and low-income populations that may be affected by the continued operation 

4 of the nuclear power plant during the license renewal term, (2) determining whether there would 

5 be any potential human health or environmental effects to these populations and special 

6 pathway receptors (groups or individuals with unique consumption practices and interactions 

7 with the environment), and (3) determining whether any of the effects may be disproportionately 

8 high and adverse. Adverse health effects are measured in terms of the risk and rate of fatal or 

9 nonfatal adverse impacts on human health. Disproportionately high and adverse human health 

10 effects occur when the risk or rate of exposure to an environmental hazard for a minority or low11 income population is significant and exceeds the risk or exposure rate for the general population 

12 or for another appropriate comparison group. Disproportionately high environmental effects 

13 refer to impacts or risks of impacts on the natural or physical environment in a minority or low14 income community that are significant and appreciably exceed the environmental impact on the 

15 larger community. Such effects may include biological, cultural, economic, or social impacts.

16 Figures 3-22 and 3-23 show the location of predominantly minority and low-income population 

17 block groups residing within a 50-mi (80-km) radius of RBS. This area of impact is consistent 

18 with the 50-mi (80-km) impact analysis for public and occupational health and safety. This 

19 chapter (Chapter 4) of the SEIS presents the assessment of environmental and human health 

20 impacts for each resource area. With the exception of groundwater resources, which would 

21 have SMALL to MODERATE impacts, the NRC staff’s analyses of impacts for all other 

22 environmental resource areas indicated that the impact from license renewal would be SMALL.

23 Potential impacts on minority and low-income populations (including migrant workers or Native 

24 Americans) would mostly consist of socioeconomic and radiological effects; however, radiation 

25 doses from continued operations during the license renewal term are expected to continue at 

26 current levels, and they would remain within regulatory limits. Section 4.11.1.4 discusses the 

27 environmental impacts from severe accidents that might occur during the license renewal term. 

28 The Commission has determined that the probability-weighted consequences of severe 

29 accidents are small. 

30 Therefore, based on this information and the analysis of human health and environmental 

31 impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 

32 adverse human health and environmental effects on minority and low-income populations from 

33 the continued operation of RBS during the license renewal term.

34 Subsistence Consumption of Fish and Wildlife

35 As part of addressing environmental justice concerns associated with license renewal, the NRC 

36 also assessed the potential radiological risk to special population groups (such as migrant 

37 workers or Native Americans) from exposure to radioactive material received through their 

38 unique consumption practices and interactions with the environment, including the subsistence 

39 consumption of fish, wildlife, and native vegetation; contact with surface waters, sediments, and 

40 local produce; absorption of contaminants in sediments through the skin; and inhalation of 

41 airborne radioactive material released from the plant during routine operation. The special 

42 pathway receptors analysis is an important part of the environmental justice analysis because 

43 consumption patterns may reflect the traditional or cultural practices of minority and low-income 

44 populations in the area, such as migrant workers or Native Americans. The results of this 

45 analysis is presented here.
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1 Section 4-4 of Executive Order 12898, “Federal Actions to Address Environmental Justice in 

2 Minority Populations and Low-Income Populations,” (1994) (59 FR 7629) directs Federal 

3 agencies, whenever practical and appropriate, to collect and analyze information about the 

4 consumption patterns of populations that rely principally on fish and wildlife for subsistence and 

5 to communicate the risks of these consumption patterns to the public. In this SEIS, the NRC 

6 considered whether there were any means for minority or low-income populations to be 

7 disproportionately affected by examining impacts on American Indian, Hispanics, migrant 

8 workers, and other traditional lifestyle special pathway receptors. The assessment of special 

9 pathways considered the levels of radiological and nonradiological contaminants in fish, 

10 sediments, water, milk, and food products on or near RBS.

11 Radionuclides released to the atmosphere may deposit on soil and vegetation, and may 

12 therefore eventually be incorporated into the human food chain. To assess the impact of RBS 

13 operations to humans from the ingestion pathway, Entergy collects and analyzes samples of air, 

14 water, sediment, fish, food products, and milk, if available, for radioactivity as part of its ongoing, 

15 comprehensive Radiological Environmental Monitoring Program.

16 To assess the impact of nuclear power plant operations on the environment, samples are 

17 collected annually from the environment and analyzes them for radioactivity. A plant effect 

18 would be indicated if the radioactive material detected in a sample was larger or higher than 

19 background levels. Two types of samples are collected. The first type, a control sample, is 

20 collected from areas that are beyond the influence of the nuclear power plant or any other 

21 nuclear facility. These control samples are used as reference data to determine normal 

22 background levels of radiation in the environment. The second type of samples, indicator 

23 samples, are collected near the nuclear power plant from areas where any radioactivity 

24 contribution from the nuclear power plant will be at its highest concentration. These indicator 

25 samples are then compared to the control samples, to evaluate the contribution of nuclear 

26 power plant operations to radiation or radioactivity levels in the environment. An effect would be 

27 indicated if the radioactivity levels detected in an indicator sample was larger or higher than the 

28 control sample or background levels.

29 Entergy collected samples from the aquatic and terrestrial environment in the vicinity of RBS 

30 in 2016. The aquatic environment includes surface water, groundwater, fish, and shoreline 

31 sediment. Aquatic monitoring results for 2016 of water, sediment, and fish showed only 

32 naturally occurring radioactivity and radioactivity associated with fallout from past atmospheric 

33 nuclear weapons testing and were consistent with levels measured before the operation of RBS. 

34 Entergy detected no radioactivity greater than the minimum detectable activity in any aquatic 

35 sample during 2016, and identified no adverse long-term trends in aquatic monitoring data 

36 (Entergy 2017f).

37 The terrestrial environment includes airborne particulates, milk, and broad leaf vegetation. 

38 Terrestrial monitoring results for 2016 of broad leaf garden vegetable samples showed only 

39 naturally occurring radioactivity. Since milk samples were unavailable, Entergy collected 

40 vegetation samples to monitor the ingestion pathway. The radioactivity levels detected were 

41 consistent with levels measured prior to the operation of RBS. Entergy detected no radioactivity 

42 greater than the minimum detectable activity in any terrestrial samples during 2016. The 

43 terrestrial monitoring data also showed no adverse trends in the terrestrial environment 

44 (Entergy 2017f).

45 Analyses performed on all samples collected from the environment at RBS in 2016 showed no 

46 significant measurable radiological constituent above background levels. Overall, radioactivity 
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1 levels detected in 2016 were consistent with previous levels as well as radioactivity levels 

2 measured prior to the operation of RBS. Radiological environmental monitoring program 

3 (REMP) sampling in 2016 did not identify any radioactivity above the minimum detectable 

4 activity (Entergy 2017f).

5 Based on the radiological environmental monitoring data from RBS, the NRC finds that no 

6 disproportionately high and adverse human health impacts would be expected in special 

7 pathway receptor populations in the region as a result of subsistence consumption of water, 

8 local food, fish, and wildlife. In addition, the continued operation of RBS would not have 

9 disproportionately high and adverse human health and environmental effects on these 

10 populations.

11 4.12.2 No-Action Alternative

12 Under the no-action alternative, the NRC would not issue a renewed license, and RBS would 

13 shut down on or before the expiration of the current facility operating license. Impacts on 

14 minority and low-income populations would depend on the number of jobs and the amount of 

15 tax revenues lost by communities in the immediate vicinity of the power plant after RBS ceases 

16 operations. Not renewing the operating licenses and terminating reactor operations could have 

17 a noticeable impact on socioeconomic conditions in the communities located near RBS. The 

18 loss of jobs and income could have an immediate socioeconomic impact. Some, but not all, of 

19 the 680 employees would begin to leave after reactor operations are terminated. In addition, 

20 the plant would generate less tax revenue, which could reduce the availability of public services 

21 in West Feliciana Parish. This could disproportionately affect minority and low-income 

22 populations that may have become dependent on these services. See also Appendix J, 

23 “Socioeconomics and Environmental Justice Impacts Related to the Decision to Permanently 

24 Cease Operations,” of NUREG-0586, Supplement 1, Volume 1, “Final Generic Environmental 

25 Impact Statement on Decommissioning of Nuclear Facilities: Regarding the Decommissioning of 

26 Nuclear Power Reactors” (the Decommissioning GEIS, NRC 2002), for additional discussion of 

27 these impacts.

28 4.12.3 Replacement Power Alternatives: Common Impacts

29 Construction

30 Potential impacts to minority and low-income populations from the construction of a new 

31 replacement power plant would mostly consist of environmental and socioeconomic effects 

32 (e.g., noise, dust, traffic, employment, and housing impacts). The extent of effect experienced 

33 by these populations is difficult to determine since it would depend on the location of the power 

34 plant and transportation routes. Noise and dust impacts from construction would be short term 

35 and primarily limited to onsite activities. Minority and low-income populations residing along site 

36 access roads would be affected by increased truck traffic and increased commuter vehicle 

37 traffic, especially during shift changes. However, these effects would be temporary, would be 

38 limited to certain hours of the day, and would not likely be high and adverse. Increased demand 

39 for rental housing during construction could disproportionately affect low-income populations. 

40 However, given the proximity of RBS to the New Orleans metropolitan areas, construction 

41 workers could commute to the site, thereby reducing the potential demand for rental housing.
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1 Operation

2 Low-income populations living near the power plant that rely on subsistence consumption of fish 

3 and wildlife could be disproportionately affected. Emissions during power plant operations could 

4 disproportionately affect nearby minority and low income populations, depending on the type of 

5 replacement power. However, permitted air emissions would remain within regulatory 

6 standards during operations.

7 Conclusion

8 Based on this information and the analysis of human health and environmental impacts 

9 presented in this SEIS, it is not likely that the construction and operation of a new replacement 

10 power plant and demand-side management would have disproportionately high and adverse 

11 human health and environmental effects on minority and low-income populations. However, this 

12 determination would depend on the location, plant design, and operational characteristics of the 

13 new power plant. Therefore, the NRC cannot determine whether any of the replacement power 

14 alternatives would result in disproportionately high and adverse human health and 

15 environmental effects on minority and low-income populations.

16 4.12.3.1 New Nuclear Alternative

17 Potential impacts to minority and low-income populations from the construction and operation of 

18 a new nuclear power plant would be the similar to the construction impacts described above. 

19 Potential impacts would mostly consist of radiological effects during operations; however, the 

20 NRC staff expects radiation doses to be well within regulatory limits.

21 4.12.3.2 Supercritical Pulverized Coal and Natural Gas Combined-Cycle Alternatives

22 Potential impacts to minority and low-income populations from the construction and operation of 

23 a new power plant would be the similar to the construction and operation impacts described 

24 above.

25 4.12.3.3 Combination Alternative (Natural Gas Combined-Cycle, Biomass, and Demand-Side 

26 Management)

27 Potential impacts to minority and low-income populations from the construction and operation of 

28 new natural gas and biomass power plants would be the similar to the construction and 

29 operation impacts described above. Low-income populations could benefit from weatherization 

30 and insulation programs in a demand-side management energy conservation program. This 

31 could have a greater effect on low-income populations than the general population, as low32 income households generally experience greater home energy burdens than the average 

33 household. Increased utility bills due to increasing power costs could also disproportionately 

34 affect low-income populations. However, programs, such as the Louisiana Low Income Home 

35 Energy Assistance Program, are available to assist low-income families in paying for electricity.

36 4.13 Waste Management

37 This section describes the potential waste management impacts of the proposed action (license 

38 renewal) and alternatives to the proposed action.
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1 4.13.1 Proposed Action

2 As identified in Table 4-1, the impacts of all generic waste management resource issues would 

3 be SMALL. Table 4-2 does not identify any RBS site-specific (Category 2) waste management 

4 issues resulting from issuing a renewed license for an additional 20 years of operations. 

5 4.13.2 No-Action Alternative

6 If the NRC chooses the no-action alternative, it would not issue a renewed license, and RBS 

7 would cease operation at the end of the term of the initial operating license or sooner and enter 

8 decommissioning. The plant, which is currently operating within regulatory limits, would 

9 generate less spent nuclear fuel, emit less gaseous and liquid radioactive effluents into the 

10 environment, and generate less low-level radioactive and nonradioactive wastes. In addition, 

11 following shutdown, the variety of potential accidents at the plant (radiological and industrial) 

12 would be reduced to a limited set associated with shutdown events and fuel handling and 

13 storage. Therefore, as radioactive emissions to the environment decrease, and the likelihood 

14 and variety of accidents decrease following shutdown and decommissioning, the NRC staff 

15 concludes that impacts resulting from waste management from implementation of the no-action 

16 alternative would be SMALL.

17 4.13.3 Replacement Power Alternatives: Common Impacts

18 Impacts from waste management common to all analyzed replacement power alternatives

19 would be from construction-related debris generated during construction activities, and this 

20 waste would be recycled or disposed of in approved landfills.

21 4.13.3.1 New Nuclear Alternative

22 Impacts from the waste generated during the construction of a new nuclear unit would include 

23 those identified in Section 4.13.3 as common to all replacement power alternatives. 

24 During normal plant operations, routine plant maintenance and cleaning activities would 

25 generate radioactive low-level waste, spent nuclear fuel, and high-level waste, as well as 

26 nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 

27 management at RBS. Quantities of radioactive and nonradioactive waste generated by RBS 

28 would be comparable to that generated by the new nuclear plant.

29 According to the GEIS (NRC 2013b), the NRC does not expect the generation and management 

30 of solid radioactive and nonradioactive waste during the license renewal term to result in 

31 significant environmental impacts.

32 Based on this information, the waste impacts would be SMALL for the new nuclear alternative.

33 4.13.3.2 Supercritical Pulverized Coal Alternative

34 Impacts from the waste generated during the construction of a coal power plant would include 

35 those identified in Section 4.13.3 as common to all replacement power alternatives. 

36 Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 

37 for controlling air pollution generates additional ash, spent selective catalytic reduction catalyst, 

38 and scrubber sludge. The management and disposal of the large amounts of coal combustion 

39 waste is a significant part of the operation of a coal-fired power generating facility.
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1 Although a coal-fired power generating facility is likely to use offsite disposal of coal combustion 

2 waste, some short-term storage of coal combustion waste (either in open piles or in surface 

3 impoundments) is likely to take place on site, thus establishing the potential for leaching of toxic 

4 chemicals into the local environment (NRC 2013b).

5 Based on the large volume and high toxicity of waste generated by coal combustion, the NRC 

6 staff concludes that the impacts from waste generated at a coal-fired plant would be 

7 MODERATE.

8 4.13.3.3 Natural Gas Combined-Cycle Alternative

9 Impacts from the waste generated during the construction of a natural gas power plant would 

10 include those identified in Section 4.13.3 as common to all replacement power alternatives.

11 Waste generation from natural gas technology would be minimal. The only significant waste 

12 generated at a natural gas combined-cycle power plant would be spent selective catalytic 

13 reduction catalyst (plants use selective catalytic reduction catalyst to control nitrogen oxide 

14 emissions).

15 The spent catalyst would be regenerated or disposed of offsite. Other than the spent selective 

16 catalytic reduction catalyst, waste generation at an operating natural gas fired plant would be 

17 limited largely to typical operations and maintenance of nonhazardous waste (NRC 2013b). 

18 Overall, the NRC staff concludes that waste impacts from the natural gas alternative would be 

19 SMALL.

20 4.13.3.4 Combination Alternative (Natural Gas Combined Cycle, Biomass, and Demand Side 

21 Management)

22 Impacts from the waste generated during the construction of a natural gas, biomass, and 

23 demand-side management alternative would include those identified in Section 4.13.3 as 

24 common to all replacement power alternatives.

25 During construction of the biomass-fired plants, land clearing and other construction activities 

26 would generate waste that could be recycled, disposed of onsite, or shipped to an offsite waste 

27 disposal facility. For operations, a wood biomass-fired plant may use as fuel the residues from 

28 forest clear cut and thinning operations, noncommercial species, or harvests of forests for 

29 energy purposes. In addition to the gaseous emissions, wood ash is the primary waste product 

30 of wood combustion (NRC 2013b). Given the regulatory oversight exercised by EPA and state 

31 agencies, the NRC staff concludes that the waste impacts from the biomass-fired plants 

32 considered as part of the combination alternative would be SMALL.

33 For demand-side management, there may be an increase in wastes generated during 

34 installation or implementation of energy conservation measures, such as appropriate disposal of 

35 old appliances, installation of control devices, and building modifications. New and existing 

36 recycling programs would help minimize the amount of generated waste (NRC 2013b).

37 Overall, NRC staff concludes that waste impacts for the natural gas, biomass, and

demand-side management combination alternative would be SMALL.

Please note: Chapter 2, Table 2-2, summarizes the environmental impacts

of the proposed action and alternatives to the proposed action. 
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1 

2 

3 

4 

4.14 Evaluation of New and Significant Information 

5 

As stated in Section 4.1 of this SEIS, for Category 1 (generic) issues, the NRC staff can rely on 

6 

the analysis in the GEIS (NRC 2013b) unless otherwise noted. Table 4-1 lists the Category 1 

7 

issues that apply to RBS during the proposed license renewal period. For these issues, the 

8 

NRC staff did not identify any new and significant information during its review of the applicant’s 

9 

environmental report, the site audits, or the scoping period that would change the conclusions 

10

presented in the GEIS. 

11

New and significant information must be new based on a review of the GEIS (NRC 2013b) as 

12

codified in Table B-1 of Appendix B to Subpart A of 10 CFR Part 51. Such information must 

13

also bear on the proposed action or its impacts, presenting a seriously different picture of the 

14

impacts from those envisioned in the GEIS (i.e., impacts of greater severity than impacts 

15

considered in the GEIS, considering their intensity and context).

16

In accordance with 10 CFR 51.53(c), “Operating License Renewal Stage,” the applicant’s 

17

environmental report must analyze the Category 2 (site specific) issues in Table B-1 of 

18

10 CFR Part 51, Subpart A, Appendix B. Additionally, the applicant’s environmental report must 

19

discuss actions to mitigate any adverse impacts associated with the proposed action and 

20

environmental impacts of alternatives to the proposed action. In accordance with 10 CFR 

21

51.53(c)(3), the applicant’s environmental report does not need to analyze any Category 1 issue 

22

unless there is new and significant information on a specific issue.

23

NUREG-1555, Supplement 1, Revision 1, “Standard Review Plans for Environmental Reviews 

24

for Nuclear Power Plants for Operating License Renewal” describes the NRC process for 

25

identifying new and significant information (NRC 2013c). The search for new information 

26

includes:

27

• review of an applicant’s environmental report (Entergy 2017h) and the process for

28

discovering and evaluating the significance of new information

29

• review of public comments

30

• review of environmental quality standards and regulations

31

• coordination with Federal, State, and local environmental protection and resource

32

agencies

33

• review of technical literature as documented through this SEIS

34

New information that the staff discovers is evaluated for significance using the criteria set forth 

35

in the GEIS. For Category 1 issues in which new and significant information is identified, 

36

reconsideration of the conclusions for those issues is limited in scope to assessment of the 

37

relevant new and significant information; the scope of the assessment does not include other 

facets of an issue that the new information does not affect. 

The NRC staff reviewed the discussion of environmental impacts associated with operation 

during the renewal term in the GElS and has conducted its own independent review, including a 
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1 public involvement process (e.g., public meetings and comments) to identify new and significant 

2 issues for the RBS license renewal application environmental review. The NRC staff has not 

3 identified new and significant information on environmental issues related to operation of RBS 

4 during the renewal term. The NRC staff also determined that information provided during the 

5 public comment period did not identify any new issue that requires site-specific assessment.

6 4.15 Impacts Common to All Alternatives

7 This section describes the impacts that the NRC staff considers common to all alternatives

8 discussed in this SEIS, including the proposed action and replacement power alternatives. The 

9 continued operation of a nuclear power plant and replacement fossil fuel power plants both 

10 involve mining, processing, and the consumption of fuel that result in comparative impacts 

11 (NRC 2013b). In addition, the following sections discuss termination of operations and the 

12 decommissioning of both a nuclear power plant and replacement fossil fuel power plants and 

13 greenhouse gas emissions.

14 4.15.1 Fuel Cycle

15 This section describes the environmental impacts associated with the fuel cycles of both the 

16 proposed action and all replacement power alternatives. Most replacement power alternatives 

17 employ a set of steps in the use of their fuel sources, which can include extraction, 

18 transformation, transportation, and combustion. Emissions generally occur at each stage of the 

19 fuel cycle (NRC 2013b).

20 4.15.1.1 Uranium Fuel Cycle

21 The uranium fuel cycle includes uranium mining and milling, the production of uranium 

22 hexafluoride, isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation 

23 of radioactive materials, and management of low-level wastes and high-level wastes related to 

24 uranium fuel cycle activities. The GEIS describes in detail the generic potential impacts of the 

25 radiological and nonradiological environmental impacts of the uranium fuel cycle and 

26 transportation of nuclear fuel and wastes (NRC 1996, 1999, 2013b). The GEIS does not identify 

27 any site-specific (Category 2) uranium fuel cycle issues. Table 4-1 lists applicable Category 1 

28 issues. 

29 4.15.1.2 Replacement Power Plant Fuel Cycles

30 Fossil Fuel Energy Alternatives

31 Fuel cycle impacts for a fossil fuel-fired plant result from the initial extraction of fuel, cleaning 

32 and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 

33 solid wastes from fuel combustion. These impacts are discussed in more detail in 

34 Section 4.12.1.2 of the GEIS (NRC 2013b) and can generally include:

35 • significant changes to land use and visual resources

36 • impacts to air quality, including release of criteria pollutants, fugitive dust, volatile

37 organic compounds, and coalbed methane into the atmosphere

38 • noise impacts

39 • geology and soil impacts due to land disturbances and mining

40 • water resource impacts, including degradation of surface water and groundwater

41 quality
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1 • ecological impacts, including loss of habitat and wildlife disturbances

2 • historic and cultural resources impacts within the mine or pipeline footprint

3 • socioeconomic impacts from employment of both the mining workforce and service

4 and support industries

5 • environmental justice impacts

6 • health impacts to workers from exposure to airborne dust and methane gases

7 • generation of coal and industrial wastes

8 New Nuclear Energy Alternatives

9 Uranium fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport 

10 of fuel to the facility, and management and ultimate disposal of spent fuel. The environmental 

11 impacts of the uranium fuel cycle are discussed above in Section 4.15.1.1.

12 Renewable Energy Alternatives

13 The fuel cycle for renewable energy facilities is difficult to define for different technologies 

14 because these natural resources exist regardless of any effort to harvest them for electricity 

15 production. Impacts from the presence or absence of these renewable energy technologies are 

16 often difficult to determine (NRC 2013b).

17 4.15.2 Terminating Power Plant Operations and Decommissioning

18 This section describes the environmental impacts associated with the termination of operations 

19 and the decommissioning of a nuclear power plant and replacement power alternatives. All 

20 operating power plants will terminate operations and be decommissioned at some point after the 

21 end of their operating life or after a decision is made to cease operations. For the proposed 

22 action at RBS, license renewal would delay this eventuality for an additional 20 years beyond 

23 the current license period, which ends in 2025.

24 4.15.2.1 Existing Nuclear Power Plant

25 Decommissioning would occur whether RBS is shut down at the end of its current operating 

26 license or at the end of the license renewal term. NUREG-0586, Supplement 1, “Final Generic 

27 Environmental Impact Statement on Decommissioning of Nuclear Facilities: Regarding the 

28 Decommissioning of Nuclear Power Reactors” (the Decommissioning GEIS), evaluates the 

29 environmental impacts from the activities associated with the decommissioning of any reactor

30 before or at the end of an initial or renewed license (NRC 2002). Additionally, the License 

31 Renewal GEIS (NRC 2013b) discusses the incremental environmental impacts associated with 

32 decommissioning activities resulting from continued plant operation during the renewal term. As 

33 noted in Table 4-1, there is one Category 1 issue applicable to RBS decommissioning following 

34 the license renewal term. The License Renewal GEIS did not identify any site-specific 

35 (Category 2) decommissioning issues. 

36 4.15.2.2 Replacement Power Plants

37 Fossil Fuel Energy Alternatives

38 The environmental impacts from the termination of power plant operations and 

39 decommissioning of a fossil fuel-fired plant are dependent on the facility’s decommissioning 

40 plan. General elements and requirements for a fossil fuel plant decommissioning plan are 
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1 discussed in Section 4.12.2.2 of the License Renewal GEIS and can include the removal of 

2 structures to at least 3 ft (1 m) below grade; removal of all coal, combustion waste, and 

3 accumulated sludge; removal of intake and discharge structures; and the cleanup and 

4 remediation of incidental spills and leaks at the facility. The decommissioning plan outlines the 

5 actions necessary to restore the site to a condition equivalent in character and value to the site 

6 on which the facility was first constructed (NRC 2013b).

7 The environmental consequences of decommissioning are discussed in Section 4.12.2.2 of the 

8 License Renewal GEIS and can generally include the following:

9 • short-term impacts on air quality and noise from the deconstruction of facility

10 structures

11 • short-term impacts on land use and visual resources

12 • long-term reestablishment of vegetation and wildlife communities

13 • socioeconomic impacts due to decommissioning the workforce and the long-term

14 loss of jobs

15 • elimination of health and safety impacts on operating personnel and general public

16 New Nuclear Alternatives

17 Termination of operations and decommissioning impacts for a nuclear plant include all activities 

18 related to the safe removal of the facility from service and the reduction of residual radioactivity 

19 to a level that permits release of the property under restricted conditions or unrestricted use and 

20 termination of a license (NRC 2013b). The environmental impacts of the uranium fuel cycle are 

21 discussed in Section 4.15.1.1.

22 Renewable Alternatives

23 Termination of power plant operation and decommissioning for renewable energy facilities 

24 would be similar to the impacts discussed for fossil fuel-fired plants above. Decommissioning 

25 would involve the removal of facility components and operational wastes and residues to restore 

26 the site to a condition equivalent in character and value to the site on which the facility was first 

27 constructed (NRC 2013b).

28 4.15.3 Greenhouse Gas Emissions and Climate Change

29 The following sections discuss greenhouse gas emissions and climate change impacts. 

30 Section 4.15.3.1 evaluates greenhouse gas emissions associated with operation of RBS and 

31 replacement power alternatives. Section 4.15.3.2 discusses the observed changes in climate 

32 and the potential future climate change during the license renewal term based on climate model 

33 simulations under future global greenhouse gas emission scenarios. The potential impacts of 

34 future changes of climate on resources are considered and the cumulative impacts of global 

35 greenhouse gas emissions on climate are discussed in Section 4.16.11, “Global Climate

36 Change.”

37 4.15.3.1 Greenhouse Gas Emissions from the Proposed Project and Alternatives

38 Gases found in the Earth’s atmosphere that trap heat and play a role in the Earth’s climate are 

39 collectively termed greenhouse gases. Greenhouse gases include carbon dioxide (CO2); 

40 methane (CH4); nitrous oxide (N2O); water vapor (H2O); and fluorinated gases, such as 

41 hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The 

42 Earth’s climate responds to changes in concentrations of greenhouse gases in the atmosphere 

43 because these gases affect the amount of energy absorbed and heat trapped by the 
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1 atmosphere. Increasing greenhouse gas concentrations in the atmosphere generally increase 

2 the Earth’s surface temperature. Atmospheric concentrations of carbon dioxide, methane, and 

3 nitrous oxide have significantly increased since 1750 (IPCC 2007, 2013). Carbon dioxide, 

4 methane, nitrous oxide, water vapor, and fluorinated gases (termed long-lived greenhouse 

5 gases) are well mixed throughout the Earth’s atmosphere, and their impact on climate is long 

6 lasting as a result of their long atmospheric lifetime (EPA 2009b). Carbon dioxide is of primary 

7 concern for global climate change, due to its long atmospheric lifetime, and it is the primary gas 

8 emitted as a result of human activities. Climate change research indicates that the cause of the 

9 Earth’s warming over the last 50 years is due to the buildup of greenhouse gases in the 

10 atmosphere resulting from human activities (USGCRP 2014; 2017; IPCC 2013). The EPA has 

11 determined that greenhouse gases “may reasonably be anticipated both to endanger public 

12 health and to endanger public welfare” (74 FR 66496).

13 Proposed Action 

14 Operation of RBS emits greenhouse gases directly and indirectly. RBS’s direct greenhouse gas 

15 emissions result from stationary portable combustion sources (see Table 3-4) and stationary 

16 refrigeration appliances. Indirect greenhouse gas emissions originate from mobile combustion 

17 sources (e.g., employee vehicles, visitor and delivery vehicles). Table 4-7 presents quantified 

18 annual greenhouse gas emissions from sources at RBS. 

19 Entergy does not maintain an inventory of greenhouse gas emissions resulting from visitor and 

20 delivery vehicles. Chlorofluorocarbon and hydrochlorofluorocarbon emissions from refrigerant 

21 sources can result from leakage, servicing, repair, or disposal of refrigerant sources. 

22 Chlorofluorocarbons and hydrochlorofluorocarbons are ozone-depleting substances that are 

23 regulated by the Clean Air Act under Title VI. Entergy maintains a program to manage 

24 stationary refrigeration appliances at RBS to recycle, recapture, and reduce emissions of 

25 ozone-depleting substances (Entergy 2017h). Estimating greenhouse gas emissions from 

26 refrigerant sources is complicated due to their ability to deplete ozone, which is also a 

27 greenhouse gas, making their global warming potentials difficult to quantify. Consequently, 

28 greenhouse gas emissions from refrigerant sources are commonly excluded from greenhouse 

29 gas inventories (EPA 2014b). Therefore, Table 4-7 does not account for potential greenhouse 

30 gas emissions from stationary refrigeration appliances or visitor and delivery vehicles. 

Table 4-7. Estimated Greenhouse Gas Emissions(a) 31 from Operation at River Bend Station

Year

RBS Combustion Sources(b)

(tons/year)

Workforce 

Commuting(c)

(tons/year) Total (tons/year)

2011 650 2,900 3,550

2012 400 2,900 3,300

2013 620 2,900 3,520

2014 360 2,900 3,260

2015 820 2,900 3,720

(a) Emissions are rounded up.

(b) Includes stationary and portable diesel and gasoline engines described in Table 3-4.

(c) Emissions consider RBS full-time employees and does not include 700-900 contractor workers during refueling

outages that occur on a 2-year cycle and last approximately 25-30 days.

Sources: Entergy 2017h, 2016e
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1 No-Action Alternative

2 As discussed in previous no-action alternative sections, the no-action alternative represents a 

3 decision by the NRC not to renew the operating license of a nuclear power plant beyond the 

4 current operating license term. At some point, all nuclear plants will terminate operations and 

5 undergo decommissioning. The impacts from decommissioning are considered in the 

6 Decommissioning GEIS (NUREG–0586, NRC 2002). Therefore, the scope of impacts 

7 considered under the no-action alternative includes the immediate impacts resulting from 

8 activities at RBS that would occur between plant shutdown and the beginning of 

9 decommissioning (i.e., activities and actions necessary to cease operation of RBS). RBS 

10 operations would terminate at or before the end of the current license term. When the plant 

11 stops operating, a reduction in greenhouse gas emissions from activities related to plant 

12 operation, such as use of diesel generators and employee vehicles, would occur. The NRC 

13 staff anticipates that greenhouse gas emissions for the no-action alternative would be less than 

14 those presented in Table 4-7, “Estimated Greenhouse Gas Emissions from Operation at River 

15 Bend Station.”

16 Since the no-action alternative will result in a loss of power generating capacity due to 

17 shutdown, greenhouse gas emissions associated with replacement baseload power generation 

18 are discussed below for each replacement power alternative analyzed. 

19 New Nuclear Alternative

20 The GEIS presents life-cycle greenhouse gas emissions associated with nuclear power 

21 generation. As presented in Tables 4.12-4 through 4.12-6 of the GEIS (NRC 2013b), life-cycle 

22 greenhouse gas emissions from nuclear power generation can range from 1 to 288 grams 

23 carbon equivalent per kilowatt-hour (g Ceq/kWh). Nuclear power plants do not burn fossil fuels 

24 to generate electricity and do not directly emit greenhouse gases. Sources of greenhouse gas 

25 emissions from the new nuclear alternative would include stationary combustion sources such 

26 as diesel generators, boilers, and pumps similar to existing sources at RBS (see Section 3.2.1). 

27 The NRC staff estimates that greenhouse gas emissions from a new nuclear alternative would 

28 be similar to greenhouse gas emissions from RBS.

29 Supercritical Pulverized Coal Alternative

30 The GEIS (NRC 2013b) presents lifecycle greenhouse gas emissions associated with coal 

31 power generation. As presented in Table 4.12-4 of the GEIS, lifecycle greenhouse gas 

32 emissions from coal power generation can range from 264 to 1,689 g Ceq/kWh. The NRC staff 

33 estimates that direct emissions from operation of two 600-MWe units equipped with carbon 

34 capture and storage would total 1.30 million tons (1.18 million MT) of carbon dioxide equivalents 

35 per year.

36 Natural Gas Combined-Cycle Alternative

37 The GEIS (NRC 2013b) presents life-cycle greenhouse gas emissions associated with natural 

38 gas power generation. As presented in Table 4.12-5 of the GEIS, life-cycle greenhouse gas 

39 emissions from natural gas can range from 120 to 930 g Ceq/kWh. The NRC staff estimates that 
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1 direct emissions from operation of three 400 MWe natural gas combined-cycle units would total 

2 3.9 million tons (3.6 million MT) of carbon dioxide equivalents per year.

3 Combination Alternative

4 For the combination alternative, greenhouse gases would primarily be emitted from the natural 

5 gas and biomass-fired portions of this combination alternative. The NRC staff estimates that 

6 operation of the natural gas and biomass-fired units would emit a total of 4.7 million tons 

7 (4.2 million MT) of carbon dioxide equivalents per year.

8 Summary of Greenhouse Gas emissions from the Proposed Action and Alternatives

9 Table 4-8 presents the direct greenhouse gas emissions from facility operations under the 

10 proposed action and alternatives. Greenhouse gas emissions from the proposed action (license 

11 renewal), no-action alternative, and new nuclear alternative would be the lowest. Greenhouse 

12 gas emissions from the natural gas, coal, and combination alternatives are several orders of 

13 magnitude greater than those from the continued operation of RBS. Therefore, if RBS 

14 generating capacity were to be replaced by any of these three alternatives, there would be an 

15 increase in greenhouse gas emissions. Consequently, continued operation of RBS (the 

16 proposed action) results in greenhouse gas emissions avoidance.

17 Table 4-8. Direct Greenhouse Gas Emissions from Facility Operations Under the 

18 Proposed Action and Alternatives

Technology/Alternative CO2eq (tons/year)

Proposed Action (RBS license renewal)(a) 820

No-Action Alternative(b) 820

New Nuclear(c) 820

Supercritical Pulverized Coal(d) 1.3 x 106

Natural Gas Combined-Cycle(e) 3.9 x 106

Combination Alternative(f) 4.7 x 106

(a) Greenhouse gas emissions include only direct emissions from combustion sources for the year 2013

presented in Table 4-7 (Source: Entergy 2017h).

(b) Emissions resulting from activities at RBS that would occur between plant shutdown and the beginning of

decommissioning and assumed not to be greater than greenhouse gas emissions from operation of RBS.

(c) Emissions assumed to be similar to RBS operation.

(d) Emissions from direct combustion of coal and assumes 90 percent removal of the carbon dioxide produced

by facility power generation. Greenhouse gas emissions estimated using emission factors developed by

the U.S. Department of Energy’s (DOE’s) National Energy Technology Laboratory (NETL 2010b).

(e) Emissions from direct combustion of natural gas. Greenhouse gas emissions estimated using emission

factors developed by DOE’s National Energy Technology Laboratory (NETL 2010a).

(f) Emissions from the natural gas combined-cycle and Biomass components of the alternative. Biomass

greenhouse gas emissions estimated using emission factors developed by DOE’s National Renewable

Energy Laboratory (NREL 1997).

19 4.15.3.2 Climate Change

20 Climate change is the decades or longer change in climate measurements (e.g., temperature 

21 and precipitation) that has been observed on a global, national, and regional level (IPCC 2007; 

22 EPA 2016a; USGCRP 2014). Climate change can vary regionally, spatially, and seasonally, 
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1 depending on local, regional, and global factors. Just as regional climate differs throughout the 

2 world, the impacts of climate change can vary between locations.

3 On a global level, from 1901 to 2015, average surface temperatures rose at a rate of 0.15  ̊F 

4 (0.08  ̊C) per decade, and total annual precipitation increased at an average rate of 

5 0.8 in. (2 cm) per decade (EPA 2016a). The year 2016 was the warmest on record globally 

6 (NASA 2017). The observed global change in average surface temperature and precipitation 

7 has been accompanied by an increase in sea surface temperatures, a decrease in global glacier 

8 ice, an increase in sea level, and changes in extreme weather events. Such extreme events 

9 include an increase in the frequency of heat waves, heavy precipitation, and recorded maximum 

10 daily high temperatures (IPCC 2007; USGCRP 2009, 2014; EPA 2016a).

11 In the United States, the U.S. Global Change Research Program (USGCRP) reports that, from 

12 1895 to 2016, average surface temperature increased by 1.8 °F (1.0 °C) and, since 1901, 

13 average annual precipitation has increased by 4 percent (USGCRP 2017). On a seasonal 

14 basis, warming has been the greatest in winter. Since the 1980s, an increase in the length of 

15 the frost-free season, the period between the last occurrence of 32  ̊F (0 °C) in the spring and 

16 first occurrence of 32  ̊F (0 °C) in the fall, has been observed for the contiguous United States; 

17 between 1991 and 2011, the average frost-free season was 10 days longer than between 1901 

18 and 1960 (USGCRP 2014). Observed climate-related changes in the United States include 

19 increases in the frequency and intensity of heavy precipitation, earlier onset of spring snowmelt 

20 and runoff, rise of sea level in coastal areas, increase in occurrence of heat waves, and a 

21 decrease in occurrence of cold waves (USGCRP 2014). Since the 1980s, the intensity, 

22 frequency, and duration of North Atlantic hurricanes has increased; however, there is no trend in 

23 landfall frequency along the U.S. eastern and Gulf coasts (USGCRP 2014).

24 Temperature data indicate that the Southeast region of the United States, where RBS is 

25 located, did not experience significant warming overall for the time period from 1900 to 2012 

26 (USGCRP 2014). The lack of warming in the Southeast has been termed “the warming hole” 

27 (NOAA 2013b). Annual and seasonal temperatures across the Southeast have exhibited 

variability during the 20th 28 century. However, since 1970, average annual temperatures have 

29 steadily increased and have been accompanied by an increase in the number of days with 

30 daytime maximum temperatures above 90 °F (32.2 °C) and nights above 75 °F (23.9 °C) 

31 (USGCRP 2009, NOAA 2013a, IPCC 2007, USGCRP 2014). Average annual precipitation data 

32 for the Southeast does not exhibit an increasing or decreasing trend for the long-term period 

33 (1895–2011) (NOAA 2013b). However, precipitation in the Southeast region varies 

34 considerably throughout the seasons and average precipitation has increased in the fall and 

35 decreased in the summer (NOAA 2013b and USGCRP 2009). The average number of 

36 frost-free days increased by 4 days in the Southeast region during the 1986–2015 time frame 

37 relative to 1901–1960 (USGCRP 2017). 

38 The NRC staff analyzed temperature and precipitation trends for the period of 1865 to 2016 in 

39 the east central region of Louisiana (NOAA 2017). Average annual temperatures show large 

40 year-to-year variations and no clear trend is observed (NOAA 2017). Average annual 

41 precipitation also displays year-to-year variations; however, precipitation has increased at a rate 

42 of 0.39 in. (1.0 cm) per decade. No trends in the number of extreme precipitation events 

43 (defined as precipitation greater than 4 inches, averaged over 5-year periods) since 1900 have 

44 been observed for Louisiana (Frankson et al., 2017). Relative sea level along the southeastern 

45 Louisiana coast has increased by more than 8 in. (20 cm) between 1960 and 2015 

46 (EPA 2016a). Sea level rise in coastal Louisiana is partially driven by land subsidence, which 

47 occurs as a result of both natural and anthropogenic processes (Jones et al. 2016).
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1 Future global greenhouse gas emission concentrations (emission scenarios) and climate 

2 models are commonly used to project possible climate change. Climate models indicate that 

3 over the next few decades, temperature increases will continue due to current greenhouse gas 

4 emission concentrations in the atmosphere (USGCRP 2014). Over the longer term, the 

5 magnitude of temperature increases and climate change effects will depend on both past and 

6 future global greenhouse gas emissions (IPCC 2007, 2013; USGCRP 2009, 2014). Climate 

7 model simulations often use greenhouse gas emission scenarios to represent possible future 

8 social, economic, technological, and demographic development that, in turn, drive future 

9 emissions. The Intergovernmental Panel on Climate Change (IPCC) has generated various 

10 climate scenarios commonly used by climate-modeling groups (IPCC 2000). For instance, the 

11 A2 scenario is representative of a high-emission scenario in which greenhouse gas emissions 

12 continue to rise during the 21st century from 40 gigatons (GT) of CO2eq per year in 2000 to 

13 140 GT of CO2eq per year by 2100. The B1 scenario, on the other hand, is representative of a 

14 low-emission scenario in which emissions rise from 40 GT of CO2eq per year in 2000 to 50 GT of 

15 CO2eq per year midcentury before falling to 30 GT of CO2eq per year by 2100. Therefore, climate 

16 model simulations identify how climate may change in response to the Earth’s atmospheric 

17 greenhouse gas composition.

18 For the license renewal period of RBS (2025–2045), climate model simulations 

19 (between 2021 and 2050 relative to the reference period (1971–1999)) indicate an increase in 

20 annual mean temperature in the Southeast region from 1.5–3.5 °F (0.83–1.9 °C), with larger 

21 temperature increases for the northwest part of the region, for both a 

22 low- and high-emission-modeled scenario (NOAA 2013b). Increases in temperature during this 

23 time period are projected to occur for all seasons with the largest increase occurring in the 

24 summertime (June, July, and August). Climate model simulations (for the time period 

25 2021–2050) suggest spatial differences in annual mean precipitation changes for the Southeast 

26 with some areas experiencing an increase and others a decrease in precipitation. On a 

27 seasonal basis, climate models are not in agreement on the sign (increases or decreases) of 

28 precipitation changes. For Louisiana, a 0 to 3 percent decrease in annual mean precipitation is 

29 predicted under both a low- and high-emission-modeled scenario; however, these changes in 

30 precipitation were not significant and the models indicate changes that are less than normal 

31 year-to-year variations (NOAA 2013b). Climate models are not in agreement when projecting 

32 changes in Atlantic hurricane activity; however, models agree that under a warmer climate, 

33 hurricane-associated rainfall rates and wind speed will increase (USGCRP 2014; EPA 2016a).

34 Changes in climate have broader implications for public health, water resources, land use and 

35 development, and ecosystems. For instance, changes in precipitation patterns and increase in 

36 air temperature can affect water availability and quality, distribution of plant and animal species, 

37 land use patterns, and land cover, which can in turn affect terrestrial and aquatic habitats. In 

38 the next section of this SEIS, the NRC staff considers the potential cumulative, or overlapping, 

39 impacts from climate change on environmental resources that could be impacted by the 

40 proposed action. In accordance with 10 CFR Part 51, Appendix A to Subpart A, “Format for 

41 Presentation of Material in Environmental Impact Statements,” the level of detail on climate 

42 change impacts that the NRC staff provides within the cumulative discussions in this SEIS are 

43 commensurate with the potential for adverse or significant impacts to a specific resource area.

44 4.16 Cumulative Impacts

45 Cumulative impacts may result when the environmental effects associated with the proposed 

46 action (license renewal) are added to the effects from other past, present, and reasonably 

47 foreseeable future actions. Cumulative impacts can result from individually minor, but 
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1 collectively significant, actions taking place over a period of time. An impact that may be 

2 SMALL by itself could result in a greater impact when combined with the impacts of other 

3 actions. As further described in the GEIS (NRC 2013b), both the license renewal and other 

4 actions (related and nonrelated, including trends such as urbanization and global climate 

5 change) will generate effects that could contribute to cumulative impacts on a number of 

6 resources. Cumulative impacts represent the total impacts on a given resource. 

7 This section also describes the impact contributors from other actions for each resource area for 

8 which a cumulative impacts analysis has been performed. However, the NRC staff no longer 

9 assigns a significance level (i.e., SMALL, MODERATE, or LARGE) for the total cumulative 

10 impact on a resource. This is because it is usually not meaningful or possible to attribute the 

11 relative contribution to the total impact on a resource that results from individual actions. In 

12 addition, the NRC’s regulations for implementing the National Environmental Policy Act in 10 

13 CFR Part 51, “Environmental Protection Regulations for Domestic Licensing and Related 

14 Regulatory Functions,” do not require that the staff make a determination of significance for 

15 each cumulative impact resource area.

16 For the purposes of this analysis, past actions are those that occurred prior to the receipt of the 

17 license renewal application, present actions are those that are occurring during current power 

18 plant operations, and future actions are those that are reasonably foreseeable to occur through 

19 the end of power plant operation, including the period of extended operation. Therefore, the 

20 analysis considers potential cumulative impacts through the end of the current license term, as 

21 well as through the 20-year renewal license term.

22 To evaluate cumulative impacts, the NRC staff combines the incremental impacts of the 

23 proposed action, as described in Sections 4.2 to 4.13, with the impacts of other past, present, 

24 and reasonably foreseeable future actions regardless of which agency (Federal or non-Federal) 

25 or person undertakes such actions. A cumulative impacts analysis accounts for both 

26 geographic (spatial) and time (temporal) considerations of past, present, and reasonably 

27 foreseeable future actions to determine whether other potential actions are likely to contribute to 

28 the total impact. In addition, because cumulative impacts accrue to resources and focus on 

29 overlapping impacts with the proposed action, the NRC staff performs no cumulative impacts 

30 analysis for resource areas where the proposed action is unlikely to have any incremental 

31 impacts on that resource. Consequently, the NRC staff did not perform a cumulative impacts 

32 analysis for the following resource areas: land use, noise, terrestrial resources, and geology and 

33 soils. 

34 In performing this cumulative impacts analysis, the NRC staff used the information provided in 

35 Entergy’s environmental report; Entergy’s responses to requests for additional information; 

36 information from other Federal, State, and local agencies; scoping comments; and information 

37 the staff gathered during a visit to RBS to identify past, present, and reasonably foreseeable 

38 future actions. In general, the effects of past actions are described in Chapter 3, the affected 

39 environment, which serves as the environmental baseline for the cumulative impacts analysis. 

40 Appendix E of this SEIS describes other actions and projects that the NRC staff identified during 

41 this review and considered in its analysis of the potential cumulative effects.

42 4.16.1 Air Quality

43 The region of influence (ROI) considered in the cumulative air quality analysis is the 

44 West Feliciana Parish because air quality designations in Louisiana are made at the parish 
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1 level. No refurbishment-related activities are proposed during the license renewal period. As a 

2 result, the NRC staff expects similar emissions during the license renewal period, as presented 

3 in Section 3.3.2, from operation of RBS. Appendix E provides a list of present and reasonably 

4 foreseeable projects that could contribute to cumulative impacts to air quality. Current air 

5 emission sources operating in West Feliciana Parish have not resulted in long-term National 

6 Ambient Air Quality Standards (NAAQS) violations given the designated 

7 unclassifiable/attainment status for all National Ambient Air Quality Standards in 

8 West Feliciana Parish. Consequently, cumulative changes to air quality in West Feliciana 

9 Parish would be the result of future projects and actions that change present-day emissions 

10 within the parish.

11 Development and construction activities identified in Appendix E (e.g., River Bend Station 

12 Demolition Activities and ISFI installation) can increase air emissions during their respective 

13 construction period, but those air emissions would be temporary and localized. However, future 

14 operation of new commercial and industrial facilities and increases in vehicular traffic can result 

15 in overall long-term air emissions that contribute to cumulative air quality impacts. Any new 

16 stationary sources of emissions that would be established in the region would be required to 

17 apply for an air permit from the Louisiana Department of Environmental Quality and be operated 

18 in accordance with regulatory requirements. However, as noted in Appendix E, there are few 

19 reasonably foreseeable actions. 

20 Climate change can impact air quality as a result of changes in meteorological conditions. The 

21 formation, transport, dispersion, and deposition of air pollutants depend, in part, on weather 

22 conditions (IPCC 2007). Ozone has been found to be particularly sensitive to climate change 

23 (IPCC 2007; EPA 2009a). Ozone is formed, in part, as a result of the chemical reaction of 

24 nitrogen oxides and volatile organic compounds in the presence of heat and sunlight. Sunshine, 

25 high temperatures, and air stagnation are favorable meteorological conditions to higher levels of 

26 ozone (IPCC 2007; EPA 2009b). The emission of ozone precursors also depends on 

27 temperature, wind, and solar radiation (IPCC 2007). Both nitrogen oxide and biogenic volatile 

28 organic compound emissions are expected to be higher in a warmer climate (EPA 2009a). 

29 Although surface temperatures are expected to increase in the Southeast region, this may not 

30 necessarily result in an increase in ozone concentrations (Diem et al., 2017). For instance, 

31 during the fall in the Southeast, ozone concentrations correlate with humidity 

32 (Zhang et al., 2016). Wu et al. (2008) modeled changes in ozone levels in response to climate 

33 change and found negligible climate change-driven ozone concentrations for the Southeast 

34 region. Tao et al. (2007) found differences in future changes in ozone for the Southeast with 

35 decreases in ozone concentrations under a low-emission modelled scenario and increase under 

36 a high-emission modelled scenario. Among modelled studies of climate-related ozone changes, 

37 model simulations for the Southeast region have the least consensus. 

38 In summary, given the few number of reasonably foreseeable projects that may increase air 

39 emissions in the region and combined with present-day emissions from various facilities, the 

40 NRC staff concludes that the cumulative impacts on air quality would not be significant. 

41 4.16.2 Water Resources

42 4.16.2.1 Surface Water Resources

43 The description of the affected environment in Section 3.5.1 serves as the baseline for the 

44 cumulative impacts assessment for surface water resources. The geographic area considered 

45 for the surface water resources component of this analysis comprises the 
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1 Lower Mississippi-Baton Rouge watershed, with a detailed focus on the St. Francisville reach of 

2 the Lower Mississippi River centered on a 5-mi (8-km) radius of the RBS river intake and 

3 discharge structures. The St. Francisville reach traverses three Louisiana parishes (i.e., West 

4 Feliciana, East Feliciana, and Point Coupee) that are applicable to this analysis. As such, this 

5 review centered on those projects and activities that would withdraw water from, or discharge 

6 effluents to, the cited segment of the Lower Mississippi River or to contributing water bodies. 

7 Water Use Considerations 

8 In support of this cumulative impacts analysis, the NRC staff obtained and evaluated the best 

9 available data on projected trends in water use, as compiled by water resources management 

10 agencies. The U.S. Geological Survey, in cooperation with the Louisiana Department of 

11 Transportation and Development, maintains water withdrawal and use information for the State 

12 of Louisiana. Every 5 years, the U.S. Geological Survey publishes a water use report that 

13 presents data by category of use (public supply, industrial, power generation, livestock, 

14 irrigation, and aquaculture) for each parish and surface water basin (Sargent 2012). Since 

15 2012, the U.S. Geological Survey has been estimating withdrawals in Louisiana on an annual 

16 basis (USGS 2017h). Data that the U.S. Geological Survey collects include water withdrawals,

17 but the data do not quantify consumptive water use (i.e., water that is withdrawn but not 

18 returned to its source).

19 Table 4-9 presents cumulative surface water withdrawals from the Lower Mississippi River and 

20 tributaries relative to the three parishes that bound the St. Francisville reach of the Lower 

21 Mississippi River. As shown in the table, major surface water usage is for thermoelectric power 

22 generation and industrial use (e.g., paper products), with relatively minor volumes for other uses 

23 (Sargent 2012). 

Entities withdrew a total of about 372 mgd (575 cfs; 16.2 m3 24 /s) of surface water within the three 

25 parishes in 2014, with the majority withdrawn from the mainstem of the Lower Mississippi River. 

26 As shown in Table 4-9, withdrawals for thermoelectric power generation account for more than 

27 90 percent of the total volume withdrawn. In addition to RBS, this volume reflects total 

28 withdrawals for such power generation and industrial facilities as the Big Cajun II Power Plant 

29 and Hood Container of Louisiana, as described in Table E-1 in Appendix E. RBS withdraws an 

average of 17.7 mgd (27.4 cfs; 0.77 m3 30 /s) of water from the Lower Mississippi River. Thus, RBS 

31 accounts for about 5 percent of the total withdrawals from the St. Francisville reach of the river.

32 Table 4-9. Cumulative Surface Water Withdrawals from the Lower Mississippi River, 

33 St. Francisville Reach, 2014

Water Use Sector Volume (mgd)(a)

Thermoelectric Power Generation 340.11

Aquaculture 16.1

Industrial 14.51

General Irrigation 1.03

Livestock 0.27

Total 372.02

Note: To convert million gallons per day (mgd) to cubic feet per second (cfs), multiply by 1.547.

(a) Reported values include withdrawals by users in Pointe Coupee, West Feliciana, and East Feliciana parishes.

Source: USGS 2017k
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1 The mean annual discharge (flow) of the Lower Mississippi River through the St. Francisville 

reach is 547,373 cfs (15,463 m3 2 /s). This is equivalent to approximately 354,000 mgd. Total 

3 surface water withdrawals from the St. Francisville reach are currently equivalent to 

4 approximately 0.11 percent of the mean annual flow of the river. Conservatively assuming that 

5 all the water withdrawn is for consumptive use and not returned to the river, this volume has a 

6 negligible impact on downstream and instream water availability. 

7 In predicting future surface water demands and cumulative impacts on surface waters, the NRC 

8 staff considered past, present, and reasonably foreseeable future actions as well as available 

9 data on water use trends. Between 2012 and 2014, total surface water withdrawals within the 

10 three-parish region increased by about 10 percent, primarily due to withdrawals for power 

11 generation in Point Coupee Parish. For the entire Mississippi Basin, however, surface water 

12 withdrawals only increased by about 1 percent (0.5 percent per year) over the same timeframe 

13 (USGS 2017f). 

14 Using a growth rate of 0.5 percent per year for the whole of the river basin, the NRC staff 

15 projected potential surface water demand in the St. Francisville reach of the Lower Mississippi 

16 River. Accordingly, total annual surface water withdrawals along the reach could increase from 

372 mgd (575 cfs; 16.2 m3

/s) to as much as 434 mgd (671 cfs; 18.9 m3 17 /s) by the end of the 

18 period of extended operation in 2045, should RBS receive a renewed operating license. This 

19 total projected increase is equivalent to approximately 0.12 percent of the mean annual flow of 

20 the Lower Mississippi River through the St. Francisville reach. The NRC staff finds that this very 

21 small cumulative increase would be negligible compared to the range of flow conditions through 

22 the St. Francisville reach and would have no appreciable impact on instream uses or 

23 downstream water availability.

24 Water Quality Considerations

25 Water quality along the Mississippi River varies due to environmental changes along the river 

26 and within its basin, hydrologic modifications (e.g., locks, dams, levees), and point and nonpoint 

27 pollutant sources (Alexander 2012; National Research Council 2008). Because of the 

28 regulatory and infrastructure improvement mechanisms afforded under the Federal Water 

29 Pollution Control Act (i.e., Clean Water Act of 1972, as amended (CWA)) (33 U.S.C. 1251 et 

30 seq.) that focused on industrial wastewater and public sewage discharges, the water quality of 

31 the Mississippi River has improved dramatically over the last several decades. Nonpoint source 

32 pollution remains a problem, however, and the potential for continued increases in agricultural 

33 production in the Midwest region of the United States is likely to increase sediment- and 

34 nutrient-laden runoff to the Mississippi River (National Research Council 2008). 

35 As discussed in Section 3.5.1.3 of this SEIS, the St. Francisville reach of the Lower Mississippi 

36 River supports its designated water uses for secondary contact recreation, fish and wildlife 

37 propagation, and drinking water supply. However, the river segment encompassing the 

38 St. Francisville reach is impaired for primary contact recreation due to fecal coliform bacteria. 

39 Wastewater discharges from existing and new and modified industrial manufacturing, power 

40 generation, wastewater treatment, and large commercial facilities would be subject to regulation 

41 under the Federal Clean Water Act. Across a particular watershed, Section 303(d) of the 
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1 Federal Clean Water Act requires states to identify all “impaired” waters for which effluent 

2 limitations and pollution control activities are not sufficient to attain water quality standards and 

3 to establish total maximum daily loads (TMDLs) to ensure future compliance with water quality 

4 standards. On an individual facility basis, State-administered National Pollutant Discharge 

5 Elimination System (LPDES in Louisiana) permits issued under Section 402 of the Clean Water 

6 Act set limits on wastewater, stormwater, and other point source discharges to surface waters, 

7 including runoff from construction sites. Closed-cycle cooling water, industrial effluents, and 

8 stormwater discharged from the RBS site are subject to effluent limitations and monitoring 

9 imposed under Entergy’s State-issued Louisiana Pollutant Discharge Elimination System permit 

10 for the site. RBS is only one of several large industrial facilities that contribute effluents to the 

11 St. Francisville reach of the Lower Mississippi River.

12 Future development projects can result in water quality degradation if those projects increase 

13 sediment loading and the discharge of other pollutants to nearby surface water bodies. The 

14 magnitude of cumulative impacts would depend on the nature and location of the actions 

15 relative to surface water bodies; the number of actions (e.g., facilities or projects); and whether 

16 facilities comply with regulating agency requirements (e.g., land use restrictions, habitat 

17 avoidance and restoration requirements, stormwater management, and wastewater discharge 

18 limits). 

19 Furthermore, Section 404 of the Clean Water Act governs the discharge of dredge and fill 

20 materials to navigable waters, including wetlands, primarily through permits issued by the 

21 U.S. Army Corps of Engineers. The U.S. Army Corps of Engineers also regulates construction

22 affecting navigable waterways, such as for flood control, under Section 10 of the Rivers and 

23 Harbors Act of 1899 (33 U.S.C. 403 et seq.). 

24 Consequently, a substantial regulatory framework exists to address current and potential future 

25 sources of water quality degradation within the mainstem of the Lower Mississippi River with 

26 respect to potential cumulative impacts on surface water quality. 

27 Climate Change and Related Considerations

28 The NRC staff also considered the best available information regarding the potential impacts of 

29 climate change at a regional and local scale, including the U.S. Global Change Research 

30 Program’s (USGCRP’s) most recent compilations of the state of knowledge relative to global 

31 climate change effects (USGCRP 2014, 2017). 

32 Climate change can impact surface water resources as a result of changes in temperature and 

33 precipitation. Given the size of the Mississippi River Basin, contributions to river flow and 

34 downstream discharge are affected by precipitation changes beyond the Southeast region. 

35 Runoff and streamflow have increased in the Mississippi River Basin over time 

36 (USGCRP 2014). However, increased evapotranspiration, as a result of higher temperatures in 

37 the future, could reduce the volume of water available for surface runoff and streamflow. 

38 Changes in runoff in a watershed along with reduced stream flows and higher air temperatures 

39 all contribute to an increase in the ambient temperature of receiving waters. For instance, when 

40 considering the effects of climate change (increasing temperatures and evapotranspiration), 

41 total water demand for Louisiana is projected to increase by an additional 10 to 15 percent 

42 by 2060 (USGCRP 2014). Meanwhile, an increase in heavy precipitation events has been 

43 observed, and is expected to persist, for the Southeast. Such a trend toward heavy 
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1 precipitation increases the rate of runoff from the land surface and the transport of pollutants to 

2 surface waters such as the Lower Mississippi River. 

3 Elevated surface water temperature, along with degraded surface water quality, also can 

4 decrease the cooling efficiency of thermoelectric power generating facilities and plant capacity. 

5 As intake water temperatures warm, cooling water makeup requirements increase 

6 (USCRP 2014). Degraded surface water quality also increases the costs of water treatment for 

7 both industrial cooling water and potable water. Power plants, other industrial interests, and 

8 public water supply facilities would have to account for any changes in water temperature and 

9 quality in operational practices and procedures, and perhaps would be required to invest in 

10 additional infrastructure and capacity. 

11 In summary, no substantial adverse changes in surface water availability or ambient water 

12 quality are expected during the license renewal term. The NRC staff expects that the existing 

13 regulatory framework will be sufficient to effectively manage effluent discharges and stormwater

14 runoff from existing and proposed facilities. Surface water withdrawals from the St. Francisville 

15 reach of the Lower Mississippi River would be unlikely to result in any water use conflicts during 

16 the RBS license renewal term. Climate change could result in minor incremental changes in the 

17 hydrology and ambient water quality of the Lower Mississippi River. 

18 4.16.2.2 Groundwater Resources

19 The regional groundwater and surface water systems, including West Feliciana Parish, the 

20 Mississippi River and the groundwater discharge area at Baton Rouge, LA are described in 

21 Section 3.5.

22 In 2014, groundwater withdrawals in West Feliciana Parish were reported as 5.71 million gpd 

23 (21.6 million L/d). Of that volume, 74 percent or 4.22 million gpd (16 million L/d) was for public 

24 water supply (drinking water) use (USGS 2017h). Although the Mississippi River Alluvial 

25 Aquifer constitutes a large fresh groundwater resource in Louisiana, State well-registration 

26 records listed only 10 wells screened in the aquifer in West Feliciana Parish in 2009. For the 

27 same year, State well-registration records listed 64 active water wells screened in the Upland 

28 Terrace Aquifer, 128 active water wells screened in the Evangeline equivalent aquifer system, 

29 and 46 active water wells screened in the Jasper equivalent aquifer system (USGS 2014b). This 

30 is a very small portion of the total volume of groundwater consumed annually in West Feliciana 

31 Parish (USGS 2017h).

32 Beneath RBS, groundwater in the Evangeline and Jasper equivalent aquifers flows south or 

33 southwest towards water wells in the Baton Rouge area. Withdrawal of groundwater from wells 

34 in the Baton Rouge area is large enough that it is lowering water levels in the Evangeline and 

35 Jasper equivalent aquifers over a large area of West and East Feliciana Parish. 

36 (Entergy 2008b, 2017h, USGS 2004, 2014b, 2015, 2017k, 2017h).

37 Regionally, the largest groundwater declines are in the area of Baton Rouge. For example, in 

38 Baton Rouge, water level declines as much as 365 ft (111 m) have been experienced in the 

39 “2,000-foot” sand of the Jasper equivalent aquifer system. Another side effect of this decline is 

40 that groundwater withdrawal in the Baton Rouge area has caused saltwater to move northward 

41 across the Baton Rouge Fault and threaten some of the groundwater resources in the Baton 

42 Rouge area (USGS 2013) (Figure 4-1).
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1 From 1960–2012, water level declines in the sand aquifers of the Evangeline and Jasper 

2 equivalent aquifer systems have been greater in the southern areas of West Feliciana Parish 

3 than in the northern areas of the parish. In the northern part of the parish, from 1960 to 2017 

4 groundwater level declines of approximately 28 ft (8.5 m) in the 2,400-foot” sand have been 

5 recorded (USGS 2017e). In contrast, in an area in the southern part of the parish, between 

6 1960 and 2017, water levels in“2,400-foot” sand declined by 75 ft (23 m) (USGS 2014b).

7 RBS is located between these two areas. As previously discussed in Section 3.5.2.3, 

8 83 percent of the groundwater consumed at RBS is produced from two wells completed in the 

9 “2,800-foot” sand of the Jasper equivalent aquifer system. From 1985 to 2005, these two wells 

10 experienced a water level decline of approximately 25 to 30 ft (7.6 to 9.1 m) (Figure 4-2).

11 The “2,800-foot” sand of the Jasper equivalent aquifer system is also a major source of 

12 industrial and public water in the Baton Rouge area (Nashreen 2003, USGS 2013, 2015). While 

13 withdrawal of groundwater from the Evangeline and Jasper equivalent aquifer systems at RBS 

14 must have contributed to the decline in water levels in these two wells, like the other sands in 

15 the Evangeline and Jasper equivalent aquifer systems in West Feliciana Parish, much of this 

16 decline is likely in response to regional pumping (Entergy 2008b).

17 Climate change over the period of license renewal may result in increased precipitation. This 

18 could increase the volume of water recharging aquifers in the region (EPA 2016b). However, 

19 the rate of regional groundwater consumption is likely to remain the dominant force influencing 

20 regional groundwater availability.

21 As described in Section 4.5.1.2, over the period of license operations, RBS’s consumption of 

22 Mississippi River water should have no discernible impact on the availability of groundwater

23 supplies. Further, the NRC staff does not expect RBS activities to impact the quality of 

24 groundwater in any regional aquifers or indirectly impact regional surface water bodies via 

25 existing onsite groundwater contamination.

26 In summary, there is no significant cumulative effect from the proposed action on regional 

27 groundwater resources, and there is no significant cumulative impact on regional surface water

28 resources from onsite groundwater contamination.
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1 Source: Modified from Entergy 2008b

2 Figure 4-1. Salt Water Intrusion into Aquifers Beneath Baton Rouge, LA
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1 Source: Modified from Entergy 2008b

2 Figure 4-2. Groundwater Level Drop in "2,800-Foot" Sand Aquifer Beneath River Bend 

3 Station
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1 4.16.3 Aquatic Resources

2 Section 4.7 finds that the direct and indirect impacts on aquatic resources from the proposed 

3 license renewal would be SMALL for all aquatic ecology issues. The geographic area that the 

4 NRC staff considered in the cumulative aquatic resources analysis includes the vicinity of the 

5 intake and discharge structures on the Mississippi River affected by RBS water withdrawal and 

6 discharge. The baseline, or benchmark, for assessing cumulative impacts on aquatic resources 

7 takes into account the preoperational environment as recommended by EPA (1999a) for its 

8 review of National Environmental Policy Act documents.

9 Section 3.7 presents an overview of the current condition of the Mississippi River and the history 

10 and factors that led to current conditions. In summary, the direct and indirect impacts from 

11 human modifications in the Mississippi River has drastically changed available habitats and the 

12 biological communities that can inhabit and spawn within the river. Since the 1700s, efforts to 

13 control flooding and increase navigation along the Mississippi River have deepened the main 

14 channel and decreased the availability of high-quality shallow water habitats associated with 

15 floodplains, backwaters, and oxbow lakes. In addition to physical changes to aquatic habitat, 

16 land use changes within the Mississippi River basin have introduced new industrial and 

17 chemical inputs into the river and resulted in degraded water quality conditions 

18 (Brown et al. 2005). 

19 Many natural and human activities can influence the current and future aquatic life in the area 

20 surrounding RBS. Potential biological stressors include operational impacts from RBS 

21 (as described in Section 4.7); modifications to the Mississippi River; runoff from industrial, 

22 agricultural, and urban areas; other water users and dischargers; and climate change.

23 4.16.3.1 Modifications to the Mississippi River 

24 The relative abundance of hard substrate, deep channel, and river bank habitat has been 

25 largely influenced by human activities intended to decrease flooding events and increase 

26 navigability. The U.S. Army Corps of Engineers and the Mississippi River Commission continue 

27 to oversee a comprehensive river management program that includes: 

28 • levees for containing flood flows

29 • floodways for the passage of excess flows past critical reaches of the Mississippi

30 River

31 • channel improvement and stabilization to provide an efficient and reliable navigation

32 channel, increase the flood-carrying capacity of the river, and protect the levee

33 system

34 • tributary basin improvements for major drainage basins to include dams and

35 reservoirs, pumping plants, auxiliary channels, and pumping stations (MRC 2016)

36 Implementing this management program will continue to affect the relative availability of aquatic 

37 habitats, resulting in, for example, a decrease in the amount of soft sediment river bank habitat 

38 and an increase in the amount of hard substrates (e.g., riprap or other materials used to line the 

39 river bank). Consequently, invertebrates that depend on a hard surface for attachment and can 

40 colonize human-made materials, such as tires, concrete, or riprap used to line river banks, likely 

41 will continue to increase in relative abundance as compared to species that require soft 

42 sediments along the river bank. 
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1 The Mississippi River Commission also implements various programs to support the 

2 sustainability of aquatic life within the Mississippi River. For example, the Davis Pond and 

Caernarvon freshwater diversion structures divert more than 18,000 ft3

/s (510 m3 3 /s) of fresh 

4 water to coastal marshlands. The input of freshwater helps to preserve the marsh habitat and 

5 reduce coastal land loss (MRC 2016). In addition, the Mississippi River Commission conducted 

6 research and determined that using grooved articulated concrete mattresses to line river banks 

7 can help support benthic invertebrate and fish populations. For example, such concrete 

8 mattresses increases larval insect production, which is an important source of prey for many fish 

9 (MRC 2016). 

10 4.16.3.2 Runoff from Industrial, Agricultural, and Urban Areas 

11 Nearly 40 percent of the land within the contiguous United States drains into the Mississippi 

12 River. Land use changes and industrial activities within this area have had a substantial impact 

13 on aquatic habitat and water quality within the Mississippi River. For example, the Mississippi 

14 River historically experienced decreased water quality as a result of industrial discharges, 

15 agricultural runoff, municipal sewage discharges, surface runoff from mining activity, and 

16 surface runoff from municipalities. However, over the past few decades, water quality within the 

17 Mississippi River has improved because of the implementation of the Clean Water Act and other 

18 environmental regulations (Caffey et al. 2002). For example, most of the older, first-generation 

19 chlorinated insecticides have been banned since the late 1970s. Similarly, the addition and 

20 upgrading of numerous municipal sewage treatment facilities, rural septic systems, and animal 

21 waste management systems have helped to significantly decrease the concentration of median 

22 fecal coliform bacteria in the Mississippi River (Caffey et al. 2002). Despite the trend of 

23 improving water quality within the Mississippi River, trace levels of some contaminants and 

24 increased nutrients from agricultural lands remain a source of concern for aquatic life 

25 (Caffey et al. 2002; Rabalais et al. 2009).

26 4.16.3.3 Water Users and Discharges 

27 Several other facilities withdraw and discharge water from and to the Lower Mississippi River 

28 (e.g., see Table E-1). These facilities also may entrain and impinge aquatic organisms and add 

29 to the cumulative thermal stress to aquatic populations that inhabit waters near RBS. 

30 One method for estimating the cumulative entrainment rate is to calculate the percent of flow 

31 that is withdrawn by all the facilities in the region (EPA 2002a, NRC 2013b). This method 

32 assumes that planktonic organisms are equally distributed throughout the waterbody, and 

33 therefore, the percent of water withdrawn is the same as the percent of planktonic organisms 

34 entrained. Table 4-9 estimates the cumulative surface water withdrawals from the Lower 

35 Mississippi River in the St. Francisville Reach in 2014. As described in Section 4.16.3, the NRC 

36 staff determined that the total surface water withdrawals from the St. Francisville reach were 

37 equivalent to approximately 0.11 percent of the mean annual flow of the river. Based on the 

38 assumption that eggs and larvae are evenly distributed, facilities in the St. Francisville Reach 

39 would entrain less than 0.5 percent of the free flowing eggs and larvae. Furthermore, most 

40 species in the portion of the Lower Mississippi River spawn in the spring, when flows are high 

41 and a smaller fraction of the river water would be withdrawn. Therefore, the impacts would 

42 likely be negligible. 

43 Several engineered design factors and operational controls also suggest that the cumulative 

44 impacts from other water users and discharges would be minimal. For example, the location of 

45 the intake system is a design factor that can affect impingement and entrainment because 
4-86

1 locating intake systems in areas with high biological productivity or sensitive biota can 

2 negatively affect aquatic life (EPA 2004). The location of the intake structure at RBS and 

3 several other facilities within the Lower Mississippi River is within deep, fast-flowing water, 

4 which suggests that the area immediately surrounding the intakes does not provide suitable 

5 habitat for fish eggs and larvae (Baker et al. 1991; ENSR 2007; LDEQ 2010; Entergy 2017h). 

6 In association with Entergy’s application to build an additional unit at RBS, Entergy (2008a) 

7 evaluated the potential cumulative thermal impacts for RBS Unit 1, the proposed RBS Unit 3, 

8 and the Big Cajun plant (a coal-fired plant in New Roads, LA). Entergy (2008a) estimated the 

9 thermal plume at both RBS and Big Cajun and determined that the plumes would not come into 

10 contact with one another, thereby leaving a sufficient zone of passage for biota to avoid the 

11 thermal plume. 

12 Climate patterns (e.g., increased droughts and saltwater intrusion) and increased water 

13 demands upstream of RBS also may increase the number of water users and rate of withdrawal 

14 from the Mississippi River (Caffey et al. 2002). Aquatic life, especially threatened and 

15 endangered species, rely on sufficient flow within streams and rivers to survive. As described in 

16 Section 4.12.3.1, continued regulation of the flow by the U.S. Army Corps of Engineers is 

17 expected to preserve the course and flow of the Mississippi River. Additionally, Entergy and 

18 other water dischargers would be required to comply with Louisiana Pollutant Discharge 

19 Elimination System permits that must be renewed every 5 years, allowing the Louisiana 

20 Department of Environmental Quality to ensure that the permit limits provide the appropriate 

21 level of environmental protection. 

22 4.16.3.4 Climate Change 

23 The potential effects of climate change, including increased temperatures and heavy 

24 downpours, could result in degradation to aquatic resources in the Lower Mississippi 

25 River. Increased temperature and thermal stress to aquatic biota could increase the frequency 

26 of shellfish-borne illness, alter the distribution of native fish, increase the local loss of rare 

27 species, and increase the displacement of native species by non-native species 

28 (USGCRP 2009, 2014, 2017).

29 More rainfall and heavy downpours can increase the rate of runoff and pollutants reaching the 

30 Mississippi River because the pollutants washed away in the high volume of runoff have less 

31 time to absorb into the soil before reaching the river. Over the past 50 years, as a result of 

32 climate change and land use changes, the Mississippi River Basin is yielding an additional 

33 32 million acre-feet (4 million hectare meters) of nitrogen load, which is being discharged into 

34 the Gulf of Mexico. Future increases in runoff would further increase the sediment load within 

35 the Mississippi River and concurrently limit photosynthesis and growth of primary producers that 

36 provide an important food source for fish and other aquatic organisms.

37 The cumulative effects of increased temperatures, altered river flows, and increased sediment 

38 loading could exacerbate existing environmental stressors, such as high nutrient levels and low 

39 dissolved oxygen, both of which are associated with eutrophication (when excess nutrient levels 

40 in water lead to overgrowth of plants and algae, which may lead to oxygen depletion of the 

41 water). A decline in oxygen is especially likely within shallow aquatic habitats that provide 

42 high-quality habitat for spawning, foraging, and resting. Low oxygen also may lead to fish, 

43 shellfish, eggs, and larvae mortality. 
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1 4.16.3.5 Protected Habitats 

2 Several wildlife management areas, parks, and recreation sites lie within the vicinity of RBS 

3 (see Table E-1). The continued preservation of these areas will protect aquatic habitats, and 

4 these areas will become ecologically more important in the future because they will provide 

5 large areas of protected aquatic habitats as other stressors increase in magnitude and intensity.

6 4.16.3.6 Conclusion

7 The direct and indirect impacts to aquatic resources from historical Mississippi River 

8 modifications, and pollutants and sediments introduced into the river, have had a substantial 

9 effect on aquatic life and their habitat. The incremental impacts from RBS would have minimal 

10 impacts on aquatic resources. The cumulative stress from the activities described above, 

11 spread across the geographic area of interest, depends on many factors that the NRC staff 

12 cannot quantify. This stress may alter some aquatic resources. For example, climate change 

13 may increase the temperature of the Mississippi River and the rate of runoff into the river. This 

14 may alter the habitat for species most sensitive to nutrient loading, high levels of contaminants, 

15 and higher temperatures.

16 4.16.4 Historic and Cultural Resources

17 As described in Section 4.9 of this SEIS, historic properties (36 CFR 800.5(b), “Finding No 

18 Adverse Effect”) at RBS are not likely to be adversely affected by license renewal-related 

19 activities because no ground-disturbing activities or physical changes would occur beyond 

20 ongoing maintenance activities during the license renewal term. As discussed in Section 4.9, 

21 Entergy has site procedures and work instructions to ensure that plant personnel consider 

22 cultural resources on RBS lands during planned maintenance activities.

23 The geographic area considered in this analysis is the area of potential effect associated with 

24 the proposed undertaking, as described in Section 3.9. The archaeological record for the region 

25 indicates prehistoric and historic occupation of the RBS and its immediate vicinity. The 

26 construction of RBS resulted in the destruction and loss of cultural resources within portions of 

27 the industrial site area. However, historic or cultural resources can still be found within certain 

28 portions of the RBS site. Present and reasonably foreseeable projects that could affect these 

29 resources, in addition to the effects of ongoing maintenance and operational activities during the 

30 license renewal term, are summarized in Appendix E. Direct impacts would occur if historic and 

31 cultural resources in the area of potential effect were physically removed or disturbed during 

32 maintenance activities. It is unlikely that the projects discussed in Appendix E would impact 

33 historic and cultural resources on the RBS site because those resources are not in areas which 

34 would be subject to foreseeable future development during the license renewal term. 

35 Therefore, the NRC staff concludes that the contributory effects of continued reactor operations 

36 and maintenance at RBS, when combined with other past, present, and reasonably foreseeable 

37 future activities, would have no new or increased impact on cultural resources within the area of 

38 potential effect beyond what already has been experienced.

39 4.16.5 Socioeconomics

40 This section addresses socioeconomic factors that have the potential to be directly or indirectly 

41 affected by changes in operations at RBS in addition to the aggregate effects of other past, 

42 present, and reasonably foreseeable future actions. As discussed in Section 4.10, continued 
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1 operation of RBS during the license renewal term would have no impact on socioeconomic 

2 conditions in the region beyond what is already being experienced.

3 The primary geographic area of interest considered in this cumulative analysis is East Baton 

4 Rouge and West Feliciana parishes, where approximately 70 percent of RBS employees reside 

5 (see Table 3-13). This is where the economy, tax base, and infrastructure would most likely be 

6 affected because the majority of RBS workers and their families reside, spend their incomes, 

7 and use their benefits within these two parishes.

8 Because Entergy has no plans to hire additional workers during the license renewal term, 

9 overall expenditures and employment levels at RBS would remain relatively unchanged with no 

10 new or increased demand for housing and public services. Based on this and other information 

11 presented in Chapter 4, the NRC staff concludes there would be no contributory effect on 

12 socioeconomic conditions in the region during the license renewal term from the continued 

13 operation of RBS beyond what is currently being experienced. Therefore, the only contributory 

14 effects would come from reasonably foreseeable future planned activities at RBS, unrelated to 

15 the proposed action (license renewal), and other reasonably foreseeable planned offsite 

16 activities, such as residential development in East Baton Rouge and West Feliciana parishes. 

17 The availability of new housing could attract individuals and families from outside the region, 

18 thus increasing the local population and causing increased traffic on local roads and increased 

19 demand for public services.

20 Entergy has no reasonably foreseeable future planned activities at RBS beyond continued 

21 reactor operations and maintenance. When combined with other past, present, and reasonably 

22 foreseeable future activities, the NRC staff concludes that the contributory effects of continuing 

23 reactor operations and maintenance at RBS would have no new or increased socioeconomic 

24 impact in the region beyond what is currently being experienced.

25 4.16.6 Human Health

26 The NRC and EPA established radiological dose limits to protect the public and workers from 

27 both acute and long term exposure to radiation and radioactive materials. These dose limits are 

28 codified in 10 CFR Part 20, “Standards for Protection Against Radiation,” and 

29 40 CFR Part 190, “Environmental Radiation Protection Standards for Nuclear Power 

30 Operations.” As discussed in Section 4.11, the NRC staff concluded that impacts to human 

31 health from continued plant operations are SMALL. For the purposes of this analysis, the 

32 geographical area considered is the area included within an 80 km (50 mi) radius of the RBS 

33 plant site. There are no other nuclear power plants within the 80 km (50 mi) radius of RBS, but 

34 that radius does overlap with the 80 km (50 mi) radius of Waterford Steam Electric Station, 

35 Unit 3, which is approximately 121 km (75 mi) southeast. As discussed in Section 3.1.4.4, in 

36 addition to storing its spent nuclear fuel in a storage pool, RBS stores some of its spent nuclear 

37 fuel in an onsite independent spent fuel storage installation (ISFSI).

38 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 

39 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 

40 facilities, and transportation of fuel and waste. As discussed in Section 3.1.4.5, RBS has a 

41 radiological environmental monitoring program (REMP) that measures radiation and radioactive 

42 materials in the environment from RBS, its ISFSI, and all other sources. The NRC staff 

43 reviewed the radiological environmental monitoring results for the 5 year period from 2012 to 

44 2017 as part of the cumulative impacts assessment. The NRC staff’s review of Entergy’s data 

45 showed no indication of an adverse trend in radioactivity levels in the environment from RBS or 
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1 its ISFSI. The data showed that there was no measurable significant impact to the environment 

2 from operations at RBS.

3 In summary, the NRC staff concludes that there is no significant cumulative effect from the 

4 proposed action of license renewal on human health. The staff based this conclusion on NRC 

5 staff’s review of radiological environmental monitoring program data, radioactive effluent release 

6 data, and worker dose data; the staff’s expectation that RBS will continue to comply with 

7 Federal radiation protection standards during the period of extended operation; and the 

8 continued regulation of any future development or actions in the vicinity of the RBS site by the 

9 NRC and the State of Louisiana.

10 4.16.7 Environmental Justice

11 The environmental justice cumulative impact analysis evaluates the potential for 

12 disproportionately high and adverse human health and environmental effects on minority and 

13 low-income populations that could result from past, present, and reasonably foreseeable future 

14 actions, including the continued operational effects of RBS during the renewal term. As 

15 discussed in Section 4.12 of this SEIS, there would be no disproportionately high and adverse 

16 impacts on minority and low-income populations from the continued operation of RBS during the 

17 license renewal term.

18 Everyone living near RBS, including minority and low-income populations, currently experiences 

19 its operational effects. The NRC addresses environmental justice matters for license renewal 

20 by identifying the location of minority and low-income populations, determining whether there 

21 would be any potential human health or environmental effects to these populations, and 

22 determining whether any of the effects may be disproportionately high and adverse.

23 Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal adverse 

24 impacts on human health. Disproportionately high and adverse human health effects occur 

25 when the risk or rate of exposure to an environmental hazard for a minority or 

26 low-income population is significant and exceeds the risk or exposure rate for the general 

27 population or for another appropriate comparison group. Disproportionately high environmental 

28 effects refer to impacts or risks of impacts in the natural or physical environment in a minority or 

29 low-income community that are significant and appreciably exceed the environmental impact on 

30 the larger community. Such effects may include biological, cultural, economic, or social 

31 impacts. Some of these potential effects have been identified in resource areas presented in 

32 preceding sections of this chapter of the SEIS. As previously discussed in this chapter, with the 

33 exception of radionuclides to groundwater, the impact from license renewal for all other 

34 resource areas (e.g., land, air, water, and human health) would be SMALL.

35 As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 

36 adverse impacts on minority and low-income populations from the continued operation of RBS 

37 during the license renewal term. Because Entergy has no plans to hire additional workers 

38 during the license renewal term, employment levels at RBS would remain relatively constant, 

39 and there would be no additional demand for housing or increase in traffic. Based on this 

40 information and the analysis of human health and environmental impacts presented in the 

41 preceding sections, it is not likely there would be any disproportionately high and adverse 

42 contributory effect on minority and low-income populations from the continued operation of RBS 

43 during the license renewal term. Therefore, the NRC staff concludes that the only contributory 

44 effects would come from the other reasonably foreseeable future planned activities at RBS, 
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1 unrelated to the proposed action (license renewal), and other reasonably foreseeable planned 

2 offsite activities.

3 Entergy has no reasonably foreseeable future planned activities at RBS beyond continued 

4 reactor operations and maintenance. When combined with other past, present, and reasonably 

5 foreseeable future activities, the NRC staff concludes that the contributory effects of continuing 

6 reactor operations and maintenance at RBS would not likely cause disproportionately high and 

7 adverse human health and environmental effects on minority and low-income populations 

8 residing in the vicinity of RBS beyond what those populations have already experienced.

9 4.16.8 Waste Management and Pollution Prevention

10 This section describes waste management impacts during the license renewal term when added 

11 to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 

12 the purpose of this cumulative impacts analysis, the NRC staff considered the area within a 

13 50 mi (80 km) radius of RBS. In Section 4.11, the NRC staff concluded that the potential human 

14 health impacts from RBS’s waste during the license renewal term would be SMALL.

15 As discussed in Sections 3.1.4 and 3.1.5, Entergy maintains waste management programs for 

16 radioactive and nonradioactive waste generated at RBS and is required to comply with Federal 

17 and State permits and other regulatory waste management requirements. The nuclear power 

18 plants and other facilities within a 50 mi (80 km) radius of RBS are also required to comply with 

19 appropriate NRC, EPA, and State requirements for the management of radioactive and 

20 nonradioactive waste. Current waste management activities at RBS would likely remain 

21 unchanged during the license renewal term, and continued compliance with Federal and State 

22 requirements for radioactive and nonradioactive waste is expected.

23 In summary, the NRC staff concludes that there is no significant cumulative effect from the 

24 proposed action of license renewal from radioactive and nonradioactive waste. This is based on 

25 RBS’s expected continued compliance with Federal and State of Louisiana requirements for 

26 radioactive and nonradioactive waste management and the expected regulatory compliance of 

27 other waste producers in the area.

28 Global Greenhouse Gas Emissions 

29 The cumulative impact of a greenhouse gas emission source on climate is global. Greenhouse 

30 gas emissions are transported by wind and become well mixed in the atmosphere as a result of 

31 their long atmospheric residence time. Therefore, the extent and nature of climate change is 

32 not specific to where greenhouse gases are emitted. Due to the global significance of 

33 greenhouse gas emissions, a global climate change cumulative impacts analysis inherently 

34 considers the entire Earth’s atmosphere and therefore global emissions (as opposed to county, 

35 State, or national emissions). As discussed in Section 4.15.3.2, climate change and 

36 climate-related environmental changes have been observed on a global level, and climate 

37 models indicate that future climate change will depend on present and future global greenhouse 

38 gas emissions. Climate models indicate that short-term climate change (through the year 2030) 

39 is dependent on past greenhouse gas emissions. Therefore, climate change is projected to 

40 occur with or without present and future greenhouse gas emissions from RBS. With continued 

41 increases in global greenhouse gas emission rates, climate models project that Earth’s average 

42 surface temperature will continue to increase and climate-related changes will persist. 
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1 In April 2017, EPA published, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 

2 1990–2015” (Greenhouse Gas Inventory). As the official U.S. inventory of greenhouse gas 

3 emissions this EPA report identifies and quantifies the primary anthropogenic sources and sinks 

4 of greenhouse gases. The EPA Greenhouse Gas Inventory is an essential tool for addressing 

5 climate change and participating with the United Nations Framework Convention on Climate 

6 Change to compare the relative global contribution of different emission sources and 

7 greenhouse gases to climate change. In 2015, the United States emitted 6,586.7 million metric 

8 tons (MMT) of carbon dioxide equivalents (CO2eq) and from 1990 to 2015, emissions increased 

9 by 3.5 percent (EPA 2017c). In 2015 and 2016, the total amount of CO2eq emissions related to 

10 electricity generation was 2,058 MMT and 1,920 MMT, respectively. The Energy Information 

11 Administration (EIA) reported that, in 2014, the electric power sector alone in Louisiana was 

12 responsible for 39.3 MMT of carbon dioxide (CO2eq) (EIA 2017a). Facilities that emit 25,000 MT 

13 CO2eq or more per year are required to annually report their greenhouse gas emissions to EPA. 

14 These facilities are known as direct emitters, and the data are publicly available in EPA’s 

15 facility-level information on greenhouse gases tool (FLIGHT). In 2015, FLIGHT-identified 

16 facilities in Louisiana emitted a total of 138 MMT of CO2eq and facilities in West Feliciana emitted 

17 a total of 0.12 MMT of CO2eq (EPA 2017c). 

18 Appendix E provides a list of current and reasonably foreseeable future projects and actions 

19 that could contribute to greenhouse gas emissions. Permitting and licensing requirements and 

20 other mitigative measures can minimize the impacts of greenhouse gas emissions. For 

21 instance, in 2012, EPA issued a final Greenhouse Gas Tailoring Rule (77 FR 41051) to address 

22 greenhouse gas emissions from stationary sources under the Clean Air Act permitting 

23 requirements. The Greenhouse Gas Tailoring Rule establishes when an emission source will 

24 be subject to permitting requirements and control technology to reduce greenhouse gas 

25 emissions.

26 EPA’s Greenhouse Gas Inventory illustrates the diversity of greenhouse gas sources, such as 

27 electricity generation (including fossil fuel combustion and incineration of waste), industrial 

28 processes, and agriculture. As presented in Section 4.15.3, annual direct greenhouse gas 

29 emissions from combustion sources resulting from ancillary operations at RBS range from 3,260 

30 to 3,720 MT of CO2eq. In comparing RBS’s greenhouse gas emission to total U.S. greenhouse 

31 gas emissions, emissions from electricity production in Louisiana, or emissions on a parish 

32 level, greenhouse gas emissions from RBS are relatively minor. When compared to global 

33 emissions, RBS greenhouse gas emission are negligible (see Table 4-10). Furthermore, as 

34 presented in Table 4-8, the coal, natural gas, and combination alternatives’ annual greenhouse 

35 gas emissions are higher by several orders of magnitude than those from the continued 

36 operation of RBS. Therefore, if RBS’s generating capacity were to be replaced by other non37 nuclear power generating alternatives assessed in this SEIS, there would be an increase in 

38 greenhouse gas emissions. Consequently, the NRC staff concludes that the continued 

39 operation of RBS (the proposed action) would result in greenhouse gas emissions avoidance 

40 and would have a net, beneficial contribution to greenhouse gas emissions and climate change 

41 impacts during the license renewal term compared to alternative baseload replacement power

42 generation sources assessed in this SEIS.

43 Table 4-10. Comparison of Greenhouse Gas Emission Inventories

Source CO2eq MMT/year

Global Emissions (2015) (a) 33,000
4-92

Source CO2eq MMT/year

U.S. Emissions (2015)(b) 6,587

Louisiana (2015)(c) 138

West Feliciana Parish, LA (2015)(c) 0.12

RBS(d) 3.4 x 10-3

(a) Carbon dioxide emissions obtained from GCP 2017 and converted to carbon dioxide equivalents.

(b) Source: EPA 2017c

(c) Greenhouse gas emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year

(EPA 2017b).

(d) Emissions rounded from Entergy 2017h and largest annual emission presented.

Source: GCP 2017, EPA 2017c, EPA 2017b, Entergy 2017h

1 4.17 Resource Commitments Associated with the Proposed Action

2 This section describes the NRC’s consideration of potentially unavoidable adverse 

3 environmental impacts that could result from implementation of the proposed action and 

4 alternatives; the relationship between short-term uses of the environment and the maintenance 

5 and enhancement of long-term productivity; and the irreversible and irretrievable commitments 

6 of resources. 

7 4.17.1 Unavoidable Adverse Environmental Impacts

8 Unavoidable adverse environmental impacts are impacts that would occur after implementation 

9 of all workable mitigation measures. Carrying out any of the replacement energy alternatives

10 considered in this SEIS, including the proposed action, would result in some unavoidable 

11 adverse environmental impacts.

12 Minor unavoidable adverse impacts on air quality would occur due to emission and release of 

13 various chemical and radiological constituents from power plant operations. Nonradiological 

14 emissions resulting from power plant operations are expected to comply with EPA emissions 

15 standards, although the alternative of operating a fossil-fueled power plant in some areas may 

16 worsen existing attainment issues. Chemical and radiological emissions would not exceed the 

17 national emission standards for hazardous air pollutants.

18 During nuclear power plant operations, workers and members of the public would face 

19 unavoidable exposure to minor levels of radiation as well as hazardous and toxic chemicals. 

20 Workers would be exposed to radiation and chemicals associated with routine plant operations 

21 and the handling of nuclear fuel and waste material. Workers would have higher levels of 

22 exposure than members of the public, but doses would be administratively controlled and would 

23 not exceed regulatory standards or administrative control limits. In comparison, the alternatives

24 involving the construction and operation of a non-nuclear power generating facility would also 

25 result in unavoidable exposure to hazardous and toxic chemicals to workers and the public.

26 The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 

27 hazardous waste, and nonhazardous waste, would be unavoidable. Hazardous and 

28 nonhazardous wastes would be generated at non-nuclear power generating facilities. Wastes 

29 generated during plant operations would be collected, stored, and shipped for suitable 

30 treatment, recycling, or disposal in accordance with applicable Federal and State regulations. 

31 Due to the costs of handling these materials, NRC staff expects that power plant operators 
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1 would optimize all waste management activities and operations in a way that generates the 

2 smallest possible amount of waste.

3 4.17.2 Relationship between Short-Term Use of the Environment and 

4 Long-Term Productivity

5 The operation of power generating facilities would result in short-term uses of the environment, 

6 as described in Chapter 4. Short term is the period of time that continued power generating 

7 activities take place.

8 Power plant operations require short-term use of the environment and commitment of resources 

9 (e.g., land and energy), indefinitely or permanently. Certain short-term resource commitments 

10 are substantially greater under most energy alternatives, including license renewal, than under 

11 the no-action alternative because of the continued generation of electrical power and the 

12 continued use of generating sites and associated infrastructure. During operations, all energy 

13 alternatives entail similar relationships between local short-term uses of the environment and 

14 the maintenance and enhancement of long-term productivity.

15 Air emissions from nuclear power plant operations introduce small amounts of radiological and 

16 nonradiological emissions to the region around the plant site. Over time, these emissions would 

17 result in increased concentrations and exposure, but the NRC staff does not expect that these 

18 emissions would impact air quality or radiation exposure to the extent that they would impair 

19 public health and long-term productivity of the environment.

20 Continued employment, expenditures, and tax revenues generated during power plant 

21 operations directly benefit local, regional, and State economies over the short term. Local 

22 governments investing project-generated tax revenues into infrastructure and other required 

23 services could enhance economic productivity over the long term.

24 The management and disposal of spent nuclear fuel, low-level radioactive waste, hazardous 

25 waste, and nonhazardous waste requires an increase in energy and consumes space at 

26 treatment, storage, or disposal facilities. Regardless of the location, the use of land to meet 

27 waste disposal needs would reduce the long-term productivity of the land.

28 Power plant facilities are committed to electricity production over the short term. After 

29 decommissioning these facilities and restoring the area, the land could be available for other 

30 future productive uses.

31 4.17.3 Irreversible and Irretrievable Commitment of Resources

32 Resource commitments are irreversible when primary or secondary impacts limit the future 

33 options for a resource. For example, the consumption or loss of nonrenewable resources are 

34 irreversible. An irretrievable commitment refers to the use or consumption of resources for a 

35 period of time (e.g., for the duration of the action under consideration) that are neither 

36 renewable nor recoverable for future use. Irreversible and irretrievable commitments of 

37 resources for electrical power generation include the commitment of land, water, energy, raw 

38 materials, and other natural and man-made resources required for power plant operations. In 

39 general, the commitments of capital, energy, labor, and material resources are also irreversible.

40 The implementation of any of the replacement energy alternatives considered in this SEIS 

41 would entail the irreversible and irretrievable commitments of energy, water, chemicals, and—in 
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1 some cases—fossil fuels. These resources would be committed during the license renewal 

2 term and over the entire life cycle of the power plant, and they would be unrecoverable.

3 Energy expended would be in the form of fuel for equipment, vehicles, and power plant 

4 operations and electricity for equipment and facility operations. Electricity and fuel would be 

5 purchased from offsite commercial sources. Water would be obtained from existing water 

6 supply systems. These resources are readily available, and the NRC staff does not expect the 

7 amounts required to deplete available supplies or exceed available system capacities.
5-1

1 5 CONCLUSION

2 This draft supplemental environmental impact statement (SEIS) contains the NRC staff’s 

3 environmental review of Entergy Louisiana, LLC and Entergy Operations, Inc.’s (collectively 

4 referred to as Entergy) application for a renewed operating license for River Bend Station, Unit 1 

5 (RBS), as required by Title 10 of the Code of Federal Regulations (10 CFR) Part 51, 

6 “Environmental Protection Regulations for Domestic Licensing and Related Regulatory 

7 Functions.” The regulations at 10 CFR Part 51 implement the National Environmental Policy 

8 Act of 1969, as amended (42 U.S.C. 4321 et seq.). This chapter briefly summarizes the 

9 environmental impacts of license renewal, lists and compares the environmental impacts of 

10 alternatives to license renewal, and presents the NRC staffs conclusions and recommendation.

11 5.1 Environmental Impacts of License Renewal

12 After reviewing the site-specific (Category 2) environmental issues in this SEIS, the NRC staff

13 concluded that issuing a renewed license for RBS would have SMALL impacts for the 

14 Category 2 issues applicable to license renewal at RBS with one exception: for groundwater

15 issues, the impact would be SMALL to MODERATE. The NRC staff considered mitigation

16 measures for each Category 2 issue, as applicable. The NRC staff concluded that no additional 

17 mitigation measure is warranted.

18 5.2 Comparison of Alternatives

19 In Chapter 4 of this SEIS, the staff considered the following alternatives to issuing a renewed 

20 operating license to RBS:

21 • no-action alternative

22 • new nuclear alternative

23 • supercritical pulverized coal alternative

24 • natural gas combined-cycle alternative

25 • combination alternative of natural gas combined-cycle, biomass, and

26 demand-side management

27 Based on the review presented in this draft SEIS, the NRC staff concludes that the 

28 environmentally preferred alternative is the proposed action, recommending that a renewed

29 RBS operating license be issued. As shown in Table 2-2, all other power-generation 

30 alternatives have impacts in at least two resource areas that are greater than license renewal, in 

31 addition to the environmental impacts inherent with new construction projects. To make up the 

32 lost power generation if the NRC does not issue a renewed license for RBS (i.e., the no-action 

33 alternative), energy decisionmakers would likely implement one of the four power replacement 

34 alternatives discussed in this chapter, or a comparable alternative capable of replacing the 

35 power generated by RBS. 

36 5.3 Preliminary Recommendation

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

38 license renewal for RBS are not so great that preserving the option of license renewal for 

39 energy-planning decisionmakers would be unreasonable. This recommendation is based on the 

40 following:
5-2

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

2 Statement for License Renewal of Nuclear Plants” 

3 • the environmental report submitted by Entergy

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

5 • the NRC staff’s independent environmental review

6 • the NRC staff’s consideration of public comments
6-1

1 6 REFERENCES

2 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

3 Protection against Radiation.”

4 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic Licensing of 

5 Production and Utilization Facilities.”

6 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

7 Protection Regulations for Domestic Licensing and Related Regulatory Functions.”

8 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

9 Renewal of Operating Licenses for Nuclear Power Plants.”

10 10 CFR Part 61. Code of Federal Regulations, Title 10, Energy, Part 61, “Licensing 

11 Requirements for Land Disposal of Radioactive Waste.”

12 10 CFR Part 71. Code of Federal Regulations, Title 10, Energy, Part 71, “Packaging and 

13 Transportation of Radioactive Material.”

14 10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, “Licensing 

15 Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level Radioactive 

16 Waste, and Reactor-Related Greater than Class C Waste.”

17 10 CFR Part 100. Code of Federal Regulations, Title 10, Energy, Part 100, “Reactor Site 

18 Criteria.”

19 15 CFR Part 930. Code of Federal Regulations, Title 15, Commerce and Foreign Trade, 

20 Part 930, “Federal Consistency with Approved Coastal Management Programs.”

21 40 CFR Part 50. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 

22 “National Primary and Secondary Ambient Air Quality Standards.”

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7-1

1 7 LIST OF PREPARERS

2 Members of the U.S. Nuclear Regulatory Commission’s (NRC’s) Office of Nuclear Reactor 

3 Regulation (NRR) prepared this supplemental environmental impact statement with assistance 

4 from other NRC organizations and support from Pacific Northwest National Laboratory. 

5 Table 7-1 identifies each contributor’s name, affiliation, and function or expertise.

6 Table 7-1. List of Preparers

Name Education/Experience Function or Expertise

NRC Staff (in alphabetical order)

Benjamin Beasley M.S. Nuclear Engineering; B.S. Chemical 

Engineering; 27 years of combined industry 

and Government experience including 

nuclear plant system analysis, risk analysis, 

and project management, with 13 years of 

management experience

Management Oversight

Jerry Dozier M.S. Reliability Engineering; M.B.A.

Business Administration; B.S. Mechanical

Engineering; 30 years of experience

including operations, reliability engineering,

technical reviews, and NRC branch

management

Severe Accident Mitigation 

Alternative (SAMA)

David Drucker B.S. General Engineering

M.S. Engineering Management

35 years of project and program

management experience

Project Management

Kevin Folk M.S. Environmental Biology; B.A.,

Geoenvironmental Studies; 29 years of

experience in NEPA compliance; geologic,

hydrologic, and water quality impacts

analysis; utility infrastructure analysis,

environmental regulatory compliance; and

water supply and wastewater discharge

permitting

Cooling and Auxiliary Water 

Systems, Surface Water 

Resources

William Ford M.S. Geology; 46 years of combined

industry and Government experience

working on groundwater, surface water, and

geology projects

Geology; Groundwater

Briana Grange B.S. Conservation Biology; 12 years of 

experience in environmental impact 

analysis, Section 7 consultations, and 

essential fish habitat consultations

Land Use and Visual Resources; 

Special Status Species and 

Habitats; Terrestrial Resources

Robert Hoffman B.S. Environmental Resource Management;

32 years of experience in NEPA

compliance, environmental impact 

assessment, alternatives identification and 

development, and energy facility siting.

Alternatives; Historic and Cultural 

Resources; Cumulative impacts

Nancy Martinez B.S. Earth and Environmental Science; A.M.

Earth and Planetary Science; 7 years of 

experience in environmental impact analysis

Greenhouse Gas Emissions and 

Climate Change; Air Quality, 

Meteorology, and Noise 
7-2

Name Education/Experience Function or Expertise

Michelle Moser M.S. Biological Sciences; B.S.

Environmental Sciences; 17 years of

experience in ecological studies,

environmental impact assessment, and

protected resource management

Aquatic Resources and

Microbiological Hazards

William Rautzen B.S. Health Physics; B.S. Industrial

Hygiene; M.S. Health Physics; 8 years

of experience in environmental impact

analysis

Human health, radiological, and 

waste management

Jeffrey Rikhoff M.R.P. Regional Planning, M.S., Economic

Development and Appropriate Technology;

38 years of combined industry and

Government experience including 31 years

of NEPA compliance, socioeconomics and

environmental justice impact analyses,

cultural resource impact assessments,

consultations with American Indian tribes,

and comprehensive land-use and

development planning studies

Environmental Justice; 

Socioeconomics

PNNL Staff (in alphabetical order)

Edward Schmidt M.S. Nuclear Engineering; B.S. Mechanical

Engineering; over 50 years of nuclear

industry experience including 35 years of

experience in performing, managing and

reviewing Probabilistic Risk Assessments.

SAMA

Steve Short M.S. and B.S. Nuclear Engineering; MBA;

over 30 years of nuclear industry

experience including probabilistic risk

assessment, life-cycle cost analysis,

nuclear safety and accident consequence

analysis, and decision analysis.

SAMA

1 
8-1

1 8 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS 

2 TO WHOM COPIES OF THIS SEIS ARE SENT

3 Table 8-1. List of Agencies, Organizations, and Persons to Whom Copies 

4 of this SEIS Are Sent

Name and Title Affiliation and Address

Mr. William Maguire, Site Vice President Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA 70775

Robert Houston, NEPA Section Chief USEPA – Region 6

Attn: Robert Houston

6EN - WS

1445 Ross Ave. Suite 1200

Dallas, TX 75202

Brad Schexnayder LA Department of Environmental Quality

Office of Environmental Compliance

Radiological Emergency Planning and Response

P.O. Box 4312

Baton Rouge, LA 70821-4312

Ms. Melissa Darden, Chairman Chitimacha Tribe of Louisiana

P.O. Box 661

Charenton, LA 70523

Kimberly Walden, THPO Chitimacha Tribe of Louisiana

P.O. Box 661

Charenton, LA 70523

Mr. David Sickey, Chairman Coushatta Tribe of Louisiana

P.O. Box 818

Elton, LA 70532

Linda Langley, THPO Coushatta Tribe of Louisiana

P.O. Box 818

Elton, LA 70532

Ms. B. Cheryl Smith, Chief Jena Band of Choctaw Indians

P.O. Box 14

Jena, LA 71342

Alina Shively, THPO Jena Band of Choctaw Indians

P.O. Box 14

Jena, LA 71342

Mr. Joey P. Barbry, Chairman Tunica-Biloxi Tribe of Louisiana

P.O. Box 1589

Marksville, LA 71351

Earl Barbry, Jr. THPO Tunica-Biloxi Tribe of Louisiana

P.O. Box 1589

Marksville, LA 71351

Ms. Jo Ann Battise, Chairperson Alabama Coushatta Tribe of Texas

571 State Park Road 56

Livingston, TX 77351
8-2

Name and Title Affiliation and Address

Bryant Celestine Alabama Coushatta Tribe of Texas

571 State Park Road 56

Livingston, TX 77351

Mr. Gary Batton, Chief The Choctaw Nation of Oklahoma

P.O. Drawer 1210

Durant, OK 74702

Ian Thompson, THPO The Choctaw Nation of Oklahoma

P.O. Drawer 1210

Durant, OK 74702

Ms. Phyliss J. Anderson, Chief Mississippi Band of Choctaw Indians

P.O. Box 6010

Choctaw Branch

Choctaw, MS 39350

Kenneth Carleton, THPO Mississippi Band of Choctaw Indians

P.P. Box 6010

Choctaw Branch

Choctaw, MS 39350

Mr. Gregory Chilcoat, Principal Chief The Seminole Nation of Oklahoma

P.O. Box 1498

Wewoka, OK 74884

Theodore Isham The Seminole Nation of Oklahoma

P.O. Box 1498

Wewoka, OK 74884

Mr. Marcellus W. Osceola, Chairman Seminole Tribe of Florida

6300 Stirling Road

Hollywood, FL 33024

Paul N. Backhouse, THPO Seminole Tribe of Florida

6300 Stirling Road

Hollywood, FL 33024

Mr. Kevin Couhig, Parish President West Feliciana Parish

P.O. Box 1843

St. Francisville, LA 70775

ecobb@wfparish.org

Mr. Phil Boggan, State Historic 

Preservation Officer

Louisiana Office of Cultural Development

P.O. Box 44247

Baton Rouge, LA 70804-4247

Mr. Reid Nelson, Director Office of Federal Agency Programs

Advisory Council on Historic Preservation

401 F Street NW, Suite 308

Washington, DC 20001-2637

Joseph Ranson, Field Supervisor U.S. Fish and Wildlife Service

Louisiana Ecological Services Field Office

646 Cajundome Boulevard, Suite 400

Lafayette, LA 70506-4290

joseph_ranson@fws.gov

Amy Trahan, Fish and Wildlife Biologist U.S. Fish and Wildlife Service

Louisiana Ecological Services Field Office

646 Cajundome Boulevard, Suite 400

Lafayette, LA 70506-4290

amy_trahan@fws.gov
8-3

Name and Title Affiliation and Address

Bruce Fielding Louisiana Department of Environmental Quality

Water Permits Division 

PO Box 4313 

Baton Rouge, LA 70821-4313 

Bruce.Fielding@la.gov

Raoult Ratard MD, MPH & TM, FACPM

State Epidemiologist

Louisiana Department of Health

1450 Poydras Street 

Suite 1652

New Orleans, LA 70112 

raoult.ratard@la.gov

JiYoung Wiley, Environmental Scientist LA Department of Environmental Quality

Office of Environmental Compliance

Radiological Emergency Planning and Response

P.O. Box 4312

Baton Rouge, LA 70821-4312

Ji.Wiley@la.gov

1 

9-1

9 INDEX

accidents, xxiv, xxv, 4-52, 7-2, F-3, F-5, F-7, 

F-11, F-14, F-15, F-17, F-18, F-19, F-29,

F-31, F-39, F-42, F-45, F-46

Advisory Council on Historic Preservation 

(ACHP), xxiii, 1-7, 4-41, 4-42, 8-2, B-6, 

C-3, C-4

aesthetic, 3-115

alternatives, xix, xx, 1-5, 2-1, 2-3, 2-4, 2-5, 

2-6, 2-9, 2-13, 2-17, 2-18, 2-20, 4-1, 4-5,

4-6, 4-7, 4-8, 4-9, 4-10, 4-11, 4-12, 4-15,

4-16, 4-20, 4-21, 4-22, 4-23, 4-24, 4-27,

4-28, 4-29, 4-30, 4-31, 4-32, 4-39, 4-40,

4-41, 4-43, 4-44, 4-45, 4-46, 4-49, 4-52,

4-59, 4-60, 4-64, 4-65, 4-66, 4-67, 4-68,

4-69, 4-70, 4-73, 4-92, 4-93, 4-94, 4-95,

5-1, 7-2, B-2, C-2, F-1, F-2, F-28, F-31,

F-32, F-50

archaeological resources, 1-6, 3-95, 3-97, 

4-42, 4-88

biocide, 3-45, 4-21

biological assessment, C-1, C-2 

biota, 3-42, 3-80, 3-81, 3-89, 4-27, 4-29, 

4-30, 4-31, 4-36, 4-87

boiling water reactor, xxiii, 2-1, 3-3, F-1, F-5, 

F-8, F-14, F-25, F-26, F-50

chronic effects, 2-22, 4-51, 4-59

Clean Air Act (CAA), xxiii, 3-26, 3-27, 4-12, 

4-13, 4-71, 4-92, B-3, B-8

closed-cycle cooling, xix, 2-7, 2-9, 2-10, 

2-11, 2-12, 2-13, 3-3, 4-4, 4-20, 4-22

Coastal Zone Management Act (CZMA), 

3-21, B-4, B-8

cold shock, 4-30

consumptive use, 3-41, 4-17, 4-18, 4-22, 

4-26, 4-29, 4-79

cooling system, xviii, xix, xxiii, 1-4, 1-6, 2-7, 

2-10, 2-11, 2-12, 2-13, 3-3, 3-4, 3-7, 3-8,

3-40, 3-41, 3-79, 3-112, 4-2, 4-3, 4-4,

4-21, 4-39, 4-57

core damage frequency (CDF), xxiii, 4-54, 

4-56, F-1, F-2, F-3, F-5, F-8, F-9, F-10,

F-11, F-12, F-13, F-14, F-15, F-16, F-17,

F-18, F-19, F-22, F-27, F-31, F-33, F-34,

F-36, F-37, F-38, F-39, F-40, F-41, F-42,

F-43, F-46, F-47, F-48, F-49, F-50

Council on Environmental Quality (CEQ), 

xxiii, 1-4, 3-114, 3-115

critical habitat, xix, 2-22, 3-91, 3-92, 3-94, 

4-32, 4-38, 4-39, 4-40, B-5, C-1, C-2, C-3

cultural resources, xix, 2-5, 2-22, 3-94, 3-97, 

4-5, 4-7, 4-41, 4-42, 4-43, 4-44, 4-45,

4-68, 4-88, 7-2, B-1, B-6

design-basis accident, 4-1, 4-52

discharges, 2-9, 2-10, 2-11, 3-6, 3-7, 3-9, 

3-10, 3-18, 3-39, 3-40, 3-41, 3-43, 3-44,

3-45, 3-48, 3-49, 3-50, 3-82, 3-83, 3-91,

3-111, 3-112, 3-119, 4-2, 4-3, 4-5, 4-6,

4-17, 4-20, 4-21, 4-25, 4-26, 4-27, 4-29,

4-30, 4-31, 4-35, 4-36, 4-49, 4-50, 4-69,

4-77, 4-78, 4-80, 4-81, 4-85, 4-86, 7-1,

B-1, B-3, B-4

dose, xxvi, 3-9, 3-10, 3-11, 3-110, 3-111, 

3-119, 4-53, 4-54, 4-55, 4-56, 4-89, 4-90,

B-2, F-1, F-3, F-4, F-22, F-23, F-24, F-41,

F-45, F-46

dredging, 3-39, 3-50, 3-81, 4-2, 4-3, 4-20, 

4-30, 4-31, 4-80

education, 3-106, 4-3 

electromagnetic fields, xxiv, 2-22, 4-5, 4-49, 

4-51, 4-58, 4-59

endangered and threatened species, 1-6, 

3-50, 3-74, 3-89, 4-87, B-1, B-5, C-1, C-2

Endangered Species Act (ESA), xxiv, 1-6, 

1-7, 2-5, 2-22, 3-78, 3-91, 3-93, 4-32,

4-36, 4-37, 4-38, 4-39, 4-40, 4-41, 6-7,

B-5, B-8, C-1, C-2, C-3, C-4, C-5

Entergy Louisiana, LLC and Entergy 

Operations, Inc., xvii, xviii, xix, xxi, 1-1, 

1-2, 1-5, 1-7, 2-1, 2-2, 2-4, 2-5, 2-7, 2-8,

2-9, 2-10, 2-11, 2-12, 2-13, 2-15, 2-18,

2-19, 2-22, 3-1, 3-2, 3-3, 3-4, 3-5, 3-6,

3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 3-13, 3-14,

3-15, 3-16, 3-17, 3-18, 3-19, 3-20, 3-21,

3-22, 3-23, 3-24, 3-25, 3-26, 3-27, 3-28,

3-30, 3-31, 3-32, 3-33, 3-34, 3-35, 3-36,

3-37, 3-38, 3-39, 3-40, 3-41, 3-42, 3-43,

3-45, 3-46, 3-47, 3-48, 3-49, 3-50, 3-51,

3-52, 3-53, 3-54, 3-55, 3-56, 3-57, 3-58,

3-59, 3-60, 3-61, 3-62, 3-63, 3-64, 3-65,

3-66, 3-67, 3-69, 3-70, 3-71, 3-74, 3-75,

3-78, 3-79, 3-81, 3-82, 3-83, 3-84, 3-87,

3-88, 3-90, 3-91, 3-95, 3-96, 3-97, 3-98,

3-100, 3-107, 3-108, 3-109, 3-110, 3-111,

3-113, 3-114, 3-119, 3-120, 4-6, 4-7,
9-2

4-17, 4-18, 4-19, 4-20, 4-25, 4-26, 4-27,

4-34, 4-35, 4-37, 4-38, 4-39, 4-42, 4-43,

4-44, 4-45, 4-49, 4-50, 4-52, 4-53, 4-54,

4-55, 4-56, 4-57, 4-58, 4-62, 4-67, 4-71,

4-73, 4-76, 4-80, 4-81, 4-82, 4-83, 4-84,

4-87, 4-88, 4-89, 4-90, 4-91, 4-93, 5-1,

5-2, 8-1, A-1, B-7, B-8, C-2, D-1, D-2,

E-1, E-3, E-4, E-5, E-6, E-8, F-1, F-2, F-3,

F-4, F-5, F-8, F-9, F-10, F-11, F-12, F-13,

F-14, F-15, F-16, F-17, F-18, F-19, F-20,

F-21, F-22, F-23, F-24, F-25, F-26, F-27,

F-28, F-29, F-30, F-31, F-32, F-33, F-34,

F-43, F-44, F-45, F-46, F-47, F-48, F-49,

F-50, F-51, F-52, F-53, F-54

entrainment, 3-94, 4-3, 4-30, 4-31, 4-33, 

4-34, 4-36, 4-37, 4-39, 4-86, F-20

environmental justice (EJ), 2-5, 3-115, 4-60, 

4-61, 4-68, 4-90, 7-2

essential fish habitat (EFH), xix, xxiv, 2-22, 

3-94, 4-5, 4-39, 4-40, 4-41, 7-1, B-5, C-3

eutrophication, 4-3, 4-87, 6-25

evaporative loss, 4-21

Fish and Wildlife Coordination Act (FWCA), 

xxiv, B-8 

Generic Environmental Impact Statement 

(GEIS), xvii, xviii, xix, xxi, xxiv, 1-3, 1-4, 

1-7, 2-1, 2-2, 2-3, 2-4, 2-5, 2-15, 2-22,

3-100, 3-113, 4-2, 4-4, 4-6, 4-25, 4-27,

4-30, 4-36, 4-43, 4-45, 4-49, 4-51, 4-52,

4-60, 4-63, 4-65, 4-66, 4-67, 4-68, 4-69,

4-72, 4-75, 5-2

greenhouse gases, xxiv, 2-6, 2-11, 4-10,

4-11, 4-12, 4-13, 4-14, 4-27, 4-67, 4-70,

4-71, 4-72, 4-73, 4-74, 4-91, 4-92, 6-10

groundwater, xix, 2-20, 3-3, 3-8, 3-13, 3-35, 

3-36, 3-44, 3-45, 3-48, 3-49, 3-50, 3-52,

3-56, 3-59, 3-62, 3-63, 3-64, 3-65, 3-67,

3-68, 3-106, 3-107, 4-4, 4-16, 4-18, 4-19,

4-20, 4-21, 4-22, 4-23, 4-24, 4-61, 4-62,

4-68, 4-81, 4-82, 4-90, 5-1, 7-1, B-1, E-3,

E-4

hazardous waste, 3-14, 3-111, 4-93, 4-94, 

B-5

high-level waste, xviii, 1-4, 4-4, 4-65, 4-68

impingement, 3-94, 4-30, 4-31, 4-33, 4-34, 

4-36, 4-37, 4-39, 4-86

independent spent fuel storage installation 

(ISFSI), 3-12, 3-15, 3-18, 4-89

Indian tribes, 1-7, 3-95, 3-115, 4-61, 7-2 

invasive species, 3-78

low-level waste, 3-44, 3-48, 4-65, 4-68

Magnuson–Stevens Fishery Conservation 

and Management Act (MSA), xxv, 1-6, 

1-7, 2-5, 3-91, 3-94, 4-39, B-5, B-8, C-3,

C-5, F-15, F-52

Marine Mammal Protection Act (MMPA), 

xxv, B-8 

mitigation, xviii, xxvi, 1-4, 1-5, 4-10, 4-30, 

4-44, 4-93, 5-1, D-1, F-14, F-16, F-31,

F-32

mixed waste, 3-9 

National Environmental Policy Act (NEPA), 

xviii, xxv, 1-1, 1-8, 2-1, 2-3, 2-4, 3-95, 

3-114, 3-115, 4-4, 4-38, 4-42, 4-76, 4-85,

5-1, 7-1, 7-2, A-1, B-2, B-8, C-1, C-3, C-5

National Marine Fisheries Service (NMFS), 

xxv, 3-91, 3-92, 3-93, 3-94, 4-34, 4-36, 

4-38, 4-39, 4-40, B-5, C-1, C-2, C-3, C-4,

C-5

National Pollutant Discharge Elimination 

System (NPDES), xxv, 3-42, 3-43, 3-45, 

3-49, 4-30, 4-36, 4-79, B-1, B-4, B-8, E-4

Native American tribes, 1-7, 4-61

no-action alternative, xx, 2-1, 2-3, 2-4, 2-20, 

4-1, 4-6, 4-9, 4-15, 4-19, 4-20, 4-27, 4-30,

4-39, 4-46, 4-47, 4-58, 4-63, 4-64, 4-71,

4-72, 4-73, 4-94, 5-1

nonattainment, 3-27

once-through cooling, 4-21

postulated accidents, 4-1 

pressurized water reactor, xxvi

radon, 3-13

reactor, xvii, xxiii, xxvi, 2-1, 2-2, 2-3, 2-4, 

2-9, 2-22, 3-1, 3-3, 3-7, 3-8, 3-9, 3-15,

3-18, 3-30, 3-44, 3-65, 3-111, 4-1, 4-4,

4-22, 4-27, 4-30, 4-34, 4-37, 4-41, 4-43,

4-45, 4-46, 4-52, 4-53, 4-54, 4-58, 4-63,

4-69, 4-88, 4-89, 4-91, 6-6, E-1, F-2, F-3,

F-5, F-6, F-8, F-11, F-12, F-13, F-15,

F-16, F-17, F-19, F-20, F-38, F-42, F-46,

F-47

refurbishment, 2-2, 4-20, 4-22, 4-26, 4-45, 

4-76, F-47

replacement power, xx, xxvi, 2-3, 2-4, 2-5, 

2-6, 2-9, 2-11, 2-19, 4-1, 4-6, 4-7, 4-8,

4-9, 4-10, 4-12, 4-15, 4-16, 4-20, 4-21,

4-22, 4-23, 4-24, 4-27, 4-28, 4-30, 4-31,

4-32, 4-39, 4-40, 4-41, 4-43, 4-44, 4-45,

4-46, 4-47, 4-59, 4-60, 4-63, 4-65, 4-66,

4-67, 4-68, 4-69, 4-70, 4-72, 4-92, F-28,

F-47

salinity gradients, 4-2 
9-3

scoping, xvii, xviii, xxi, 1-2, 1-6, 4-2, 4-42, 

4-52, 4-66, 4-76, A-1, C-3, C-4, D-1, F-22

seismic, xxvi, 3-31, 3-35, 4-54, F-10, F-11, 

F-12, F-16, F-27, F-31, F-32

severe accident mitigation alternative 

(SAMA), xvii, xix, xxvi, 1-2, 4-52, 4-53, 

4-54, 4-55, 4-56, 4-57, 7-1, 7-2, D-1, D-2,

F-1, F-2, F-3, F-5, F-8, F-9, F-10, F-11,

F-12, F-13, F-14, F-15, F-16, F-17, F-18,

F-19, F-20, F-21, F-22, F-23, F-24, F-25,

F-26, F-27, F-28, F-29, F-30, F-31, F-32,

F-33, F-34, F-36, F-37, F-38, F-39, F-40,

F-41, F-42, F-43, F-44, F-45, F-48, F-49,

F-50, F-52

severe accidents, xvii, xix, xxvi, 1-2, 1-6, 

4-1, 4-52, 4-56, 4-61, D-1, F-1, F-3, F-5,

F-10, F-17, F-25, F-30, F-33, F-47, F-48

solid waste, xx, 2-13, 2-17, 3-9, 3-10, 3-12, 

3-110, 3-119, 4-14, 4-68, B-1, B-6, B-7

spent fuel, xviii, 1-4, 2-22, 3-8, 3-12, 3-15, 

4-4, 4-30, 4-69

State Historic Preservation Office (SHPO), 

1-7, 2-22, 4-42, 4-43, 8-2

stormwater, 3-43, 3-48, 3-62, 3-119, 4-20, 

4-21, 4-25, 4-26, 4-30, 4-79, 4-80, 4-81,

B-4

surface runoff, 3-36, 3-43, 3-44, 3-45, 3-48, 

3-67, 3-81, 3-82, 4-19, 4-20, 4-22, 4-23,

4-25, 4-28, 4-74, 4-79, 4-80, 4-81, 4-85,

4-86, 4-87, 4-88, B-4

surface water, 3-36, 3-40, 3-41, 3-42, 3-48, 

3-50, 3-62, 3-80, 3-113, 4-2, 4-16, 4-17,

4-18, 4-19, 4-20, 4-21, 4-22, 4-23, 4-24,

4-26, 4-35, 4-61, 4-62, 4-68, 4-77, 4-78,

4-79, 4-80, 4-81, 4-82, 4-86, 7-1, B-1, B-4

taxes, 3-107

transmission line corridors, 3-70

transmission lines, 2-7, 2-8, 2-11, 2-12, 

3-15, 3-16, 3-23, 3-113, 4-2, 4-3, 4-6, 4-8,

4-27, 4-28, 4-29, 4-30, 4-41, 4-51

tritium, 3-13, 3-49, 3-59, 3-62, 3-63, 3-65, 

3-67, 3-68, 4-18, 4-19, 6-10, 6-21

U.S. Army Corps of Engineers, 3-39, 3-50, 

3-80, 3-81, 4-20, B-4, E-10

U.S. Department of Energy (DOE), xxiii, 2-5, 

2-9, 2-13, 2-14, 2-16, 2-17, 2-18, 3-13,

4-12, 4-13, 4-14, 4-51, 4-73

U.S. Environmental Protection Agency 

(EPA), xxiv, 2-5, 2-17, 2-19, 3-9, 3-10, 

3-11, 3-26, 3-27, 3-28, 3-29, 3-30, 3-36,

3-42, 3-43, 3-49, 3-59, 3-61, 3-65, 3-67,

3-107, 3-111, 3-119, 4-4, 4-12, 4-13,

4-14, 4-36, 4-37, 4-38, 4-58, 4-59, 4-66,

4-70, 4-71, 4-73, 4-74, 4-75, 4-77, 4-82,

4-85, 4-86, 4-87, 4-89, 4-91, 4-92, 4-93,

B-1, B-2, B-3, B-4, B-5, B-8, E-2, E-3,

E-4, E-8, E-9

U.S. Fish and Wildlife Service (FWS), xxiv, 

1-6, 1-8, 3-23, 3-78, 3-91, 3-92, 3-93,

3-94, 4-32, 4-34, 4-35, 4-36, 4-37, 4-38,

4-40, 8-2, B-5, B-7, C-1, C-2, C-4, C-5,

E-5, E-10

uranium, 3-3, 3-15, 3-110, 4-1, 4-4, 4-8, 

4-59, 4-68, 4-69, 4-70

wastewater, 3-6, 3-14, 3-37, 3-43, 3-44, 

3-45, 3-48, 3-49, 3-63, 4-21, 4-79, 4-80,

7-1, B-7, E-4, E-6, E-7

A-1

1 APPENDIX A 

2 COMMENTS RECEIVED ON THE RIVER BEND STATION, UNIT 1 

3 ENVIRONMENTAL REVIEW

4 A.1 Comments Received During the Scoping Period

5 The scoping process for the environmental review of the River Bend Station, Unit 1 (RBS) 

6 license renewal began in September 2017, in accordance with the National Environmental 

7 Policy Act of 1969, 42 U.S.C. 4321 et seq. (NEPA). On September 14, 2017, the U.S. Nuclear 

8 Regulatory Commission (NRC) issued a notice of intent to conduct an environmental scoping 

9 process for license renewal of RBS; that notice was published in the Federal Register on 

10 September 20, 2017 (82 FR 44004). The scoping process included a public meeting held in 

11 St. Francisville, LA, on September 19, 2017. The NRC issued a press releases and purchased 

12 newspaper advertisements to advertise that meeting. In addition to participation from Entergy

13 and local officials, several members of the public attended the meeting. After the NRC staff 

14 presented prepared statements on the license renewal process, the staff opened the meeting 

15 for public comments. Attendees were provided the opportunity to make oral statements that 

16 would be recorded and transcribed by a certified court reporter. A summary and transcript of 

17 the scoping meeting are available in NRC’s Agencywide Documents Access and Management 

18 System (ADAMS). The ADAMS Public Electronic Reading Room is accessible at 

19 http://www.nrc.gov/reading-rm/adams.html. The scoping meeting summary is available at 

20 ADAMS Accession No. ML17293A615. The transcript of the meeting is available at ADAMS 

21 Accession No. ML17293A547.

22 The only commenter at the public meeting was Mr. Kevin Couhig, Parish President of West 

23 Feliciana Parish. Mr. Couhig’s comments are found in the meeting transcript. In addition to 

24 Mr. Couhig’s comments, the NRC received one written comment from an unknown individual 

25 with an unknown affiliation (available at ADAMS Accession No. ML17304A065). The RBS 

26 Scoping Summary Report, dated April 24, 2018, contains the comments from Mr. Couhig and 

27 the unknown individual as well as NRC staff responses to these comments (ADAMS Accession 

28 No. ML17362A554). While none of these comments affected the scope of the license renewal 

29 environmental review, they were considered and addressed, as appropriate, in the development 

30 of this draft supplemental environmental impact statement (DSEIS). 

B-1

1 APPENDIX B 

2 APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

3 There are a number of Federal laws and regulations that affect environmental protection, health, 

4 safety, compliance, and consultation at every NRC-licensed nuclear power plant. Some of 

5 these laws and regulations require permits by or consultation with other Federal agencies or 

6 State, Tribal, or local governments. Certain Federal environmental requirements have been 

7 delegated to State authorities for enforcement and implementation. Furthermore, States have 

8 also enacted laws to protect public health and safety and the environment. It is the NRC’s 

9 policy to make sure nuclear power plants are operated in a manner that provides adequate 

10 protection of public health and safety and protection of the environment through compliance with 

11 applicable Federal and State laws, regulations, and other requirements, as appropriate. 

12 The Atomic Energy Act of 1954, as amended (AEA) (42 U.S.C. 2011 et seq.), authorizes the 

13 NRC to enter into an agreement with any State that allows the State to assume regulatory 

14 authority for certain activities (see 42 U.S.C. 2021). Louisiana has been an NRC Agreement

15 State since 1967, and the Louisiana Department of Environmental Quality (LDEQ) has 

16 regulatory responsibility over certain byproduct, source, and quantities of special nuclear 

17 materials not sufficient to form a critical mass. In addition, LDEQ maintains a Radiological 

18 Emergency Planning and Response Program to provide response capabilities to radiological 

19 accidents or emergencies at the commercial nuclear power plants in and near the State of 

20 Louisiana. (LDEQ undated).

21 In addition to carrying out some Federal programs, state legislatures develop their own laws. 

22 State statutes can supplement, as well as implement, Federal laws for protection of air, surface 

23 water, and groundwater. State legislation may address solid waste management programs, 

24 locally rare or endangered species, and historic and cultural resources.

25 The U.S. Environmental Protection Agency (EPA) has the primary responsibility to administer 

26 the Clean Water Act (33 U.S.C. 1251 et seq., herein referred to as CWA). The National 

27 Pollutant Discharge Elimination System (NPDES) program addresses water pollution by 

28 regulating the discharge of potential pollutants to waters of the United States. EPA allows for 

29 primary enforcement and administration through state agencies, as long as the state program is 

30 at least as stringent as the Federal program.

31 EPA has delegated the authority to issue NPDES permits to the State of Louisiana. The 

32 Louisiana Department of Environmental Quality provides oversight for public water supplies, 

33 issues permits to regulate the discharge of industrial and municipal wastewaters—including 

34 discharges to groundwater, and monitors State water resources for water quality. The 

35 Department issues Louisiana Pollutant Discharge Elimination System (LPDES) permits to 

36 regulate and control water pollutants. 

37 B.1 Federal and State Requirements

38 River Bend Station, Unit 1 (RBS) is subject to various Federal and State requirements. 

39 Table B-1 lists the principal Federal and State regulations and laws that are used or mentioned 

40 in this supplemental environmental impact statement for RBS.
B-2

1 Table B-1. Federal and State Requirements

Law/regulation Requirements

Current operating license and license renewal

Atomic Energy Act, 

42 U.S.C. 2011 et seq.

The Atomic Energy Act (AEA) of 1954, as amended, and the Energy 

Reorganization Act of 1974 (42 U.S.C. 5801 et seq.) give the NRC the 

licensing and regulatory authority for commercial nuclear energy use. 

They allow the NRC to establish dose and concentration limits for 

protection of workers and the public for activities under NRC jurisdiction. 

The NRC implements its responsibilities under the AEA through 

regulations set forth in Title 10, “Energy,” of the Code of Federal 

Regulations (CFR).

National Environmental 

Policy Act of 1969, 

42 U.S.C. 4321 et seq.

The National Environmental Policy Act (NEPA), as amended, requires 

Federal agencies to integrate environmental values into their 

decisionmaking process by considering the environmental impacts of 

proposed Federal actions and reasonable alternatives to those actions. 

NEPA establishes policy, sets goals (in Section 101), and provides means 

(in Section 102) for carrying out the policy. NEPA Section 102(2) contains 

action-forcing provisions to ensure that Federal agencies follow the letter 

and spirit of the Act. For major Federal actions significantly affecting the 

quality of the human environment, Section 102(2)(C) of NEPA requires 

Federal agencies to prepare a detailed statement that includes the 

environmental impacts of the proposed action and other specified 

information.

10 CFR Part 20 Regulations in 10 CFR Part 20, “Standards for Protection Against 

Radiation,” establish standards for protection against ionizing radiation 

resulting from activities conducted under licenses issued by the NRC. 

These regulations are issued under the AEA of 1954, as amended, and 

the Energy Reorganization Act of 1974, as amended. The purpose of 

these regulations is to control the receipt, possession, use, transfer, and 

disposal of licensed material by any licensee in such a manner that the 

total dose to an individual (including doses resulting from licensed and 

unlicensed radioactive material and from radiation sources other than 

background radiation) does not exceed the standards for protection 

against radiation prescribed in the regulations in this part.

10 CFR Part 51 Regulations in 10 CFR Part 51, “Environmental Protection Regulations for 

Domestic Licensing and Related Regulatory Functions,” contain the NRC’s 

regulations that implement NEPA.

10 CFR Part 50 Regulations in 10 CFR Part 50, “Domestic Licensing of Production and 

Utilization Facilities,” are NRC regulations issued under the AEA, as 

amended (68 Stat. 919), and Title II of the Energy Reorganization Act of 

1974 (88 Stat. 1242), to provide for the licensing of production and 

utilization facilities, including power reactors. 

10 CFR Part 54 NRC regulations in 10 CFR Part 54, “Requirements for Renewal of 

Operating Licenses for Nuclear Power Plants,” govern the issuance of 

renewed operating licenses and renewed combined licenses for nuclear 

power plants licensed under Sections 103 or 104b of the AEA, as 

amended, and Title II of the Energy Reorganization Act of 1974 

(88 Stat. 1242). The regulations focus on managing adverse effects of 

aging. The rule is intended to ensure that important systems, structures, 

and components will continue to perform their intended functions during 

the period of extended operation.
B-3

Law/regulation Requirements

Air quality protection

Clean Air Act,

42 U.S.C. 7401 et seq.

The Clean Air Act (CAA) is intended to “protect and enhance the quality of 

the nation’s air resources so as to promote the public health and welfare 

and the productive capacity of its population.” The CAA establishes 

regulations to ensure maintenance of air quality standards and authorizes 

individual States to manage permits. Section 118 of the CAA requires 

each Federal agency, with jurisdiction over properties or facilities engaged 

in any activity that might result in the discharge of air pollutants, to comply 

with all Federal, State, inter-State, and local requirements with regard to 

the control and abatement of air pollution. Section 109 of the CAA directs 

the U.S. Environmental Protection Agency (EPA) to set National Ambient 

Air Quality Standards (NAAQS) for criteria pollutants. The EPA has 

identified and set NAAQS for the following criteria pollutants: particulate 

matter, sulfur dioxide, carbon monoxide, ozone, nitrogen dioxide, and 

lead. Section 111 of the CAA requires the establishment of national 

performance standards for new or modified stationary sources of 

atmospheric pollutants. Section 160 of the CAA requires that specific 

emission increases must be evaluated before permit approval to prevent 

significant deterioration of air quality. Section 112 requires specific 

standards for release of hazardous air pollutants (including radionuclides). 

These standards are implemented through plans developed by each State 

and approved by the EPA. The CAA requires sources to meet standards 

and obtain permits to satisfy those standards. Nuclear power plants may 

be required to comply with the CAA Title V, Sections 501–507, for sources 

subject to new source performance standards or sources subject to 

National Emission Standards for Hazardous Air Pollutants. EPA regulates 

the emissions of air pollutants using 40 CFR Parts 50 to 99.

Water resources protection

Clean Water Act, 

33 U.S.C. 1251 et seq., and 

the NPDES (40 CFR 122)

The Clean Water Act (CWA) was enacted to “restore and maintain the 

chemical, physical, and biological integrity of the Nation’s water.” The Act 

requires all branches of the Federal Government with jurisdiction over 

properties or facilities engaged in any activity that might result in a 

discharge or runoff of pollutants to surface waters, to comply with Federal, 

State, inter-State, and local requirements. As authorized by the CWA, the 

National Pollutant Discharge Elimination System (NPDES) permit program 

controls water pollution by regulating point sources that discharge 

pollutants into waters of the United States. The NPDES program requires 

all facilities that discharge pollutants from any point source into waters of 

the United States to obtain an NPDES permit. A nuclear power plant may 

also participate in the NPDES General Permit for Industrial Stormwater 

due to stormwater runoff from industrial or commercial facilities to waters 

of the United States. EPA is authorized under the CWA to directly 

implement the NPDES program; however, EPA has authorized many 

States to implement all or parts of the national program. Section 401 of 

the CWA requires States to certify that the permitted discharge would 

comply with all limitations necessary to meet established State water 

quality standards, treatment standards, or schedule of compliance. 

The U.S. Army Corps of Engineers (USACE) is the lead agency for 

enforcement of CWA wetland requirements (33 CFR Part 320, “General 

Regulatory Policies”). Under Section 401 of the CWA, the EPA or a 

delegated State agency has the authority to review and approve, 

condition, or deny all permits or licenses that might result in a discharge to 

waters of the State, including wetlands. 
B-4

Law/regulation Requirements

Coastal Zone Management 

Act of 1972, as amended 

(16 U.S.C. 1451 et seq.)

Congress enacted the Coastal Zone Management Act (CZMA) in 1972 to 

address the increasing pressures of over-development upon the Nation’s 

coastal resources. The National Oceanic and Atmospheric Administration 

administers the Act. The CZMA encourages States to preserve, protect, 

develop, and, where possible, restore or enhance valuable natural coastal 

resources such as wetlands, floodplains, estuaries, beaches, dunes, 

barrier islands, and coral reefs, as well as the fish and wildlife using those 

habitats. Participation by States is voluntary. To encourage States to 

participate, the CZMA makes Federal financial assistance available to any 

coastal State or territory, including those on the Great Lakes, as long as 

the State or territory is willing to develop and implement a comprehensive 

coastal management program.

Wild and Scenic Rivers Act, 

16 U.S.C. 1271 et seq.

The Wild and Scenic River Act created the National Wild and Scenic 

Rivers System, which was established to protect the environmental values 

of free-flowing streams from degradation by impacting activities, including 

water resources projects.

Louisiana Administrative 

Code (LAC), Title 33, 

“Environmental Quality”: 

Part IX, “Water Quality”

Establishes the State of Louisiana’s rules and regulations related to water 

quality.

Waste management and pollution prevention

Resource Conservation and 

Recovery Act, 

42 U.S.C. 6901 et seq.

The Resource Conservation and Recovery Act (RCRA) requires the EPA

to define and identify hazardous waste; establish standards for its 

transportation, treatment, storage, and disposal; and require permits for 

persons engaged in hazardous waste activities. Section 3006, 

“Authorized State Hazardous Waste Programs” (42 U.S.C. 6926), allows 

States to establish and administer these permit programs with EPA 

approval. EPA regulations implementing the RCRA are found in 40 CFR 

Parts 260 through 283. Regulations imposed on a generator or on a 

treatment, storage, and/or disposal facility vary according to the type and 

quantity of material or waste generated, treated, stored, and/or disposed. 

The method of treatment, storage, and/or disposal also impacts the extent 

and complexity of the requirements.

Pollution Prevention Act, 

42 U.S.C. 13101 et seq.

The Pollution Prevention Act establishes a national policy for waste 

management and pollution control that focuses first on source reduction, 

then on environmental issues, safe recycling, treatment, and disposal.

LAC 33: Part I, Chapter 39 Title 33, “Environmental Quality” of the Louisiana Administrative Code, 

Part I, Chapter 39, “Notification Regulations and Procedures for 

Unauthorized Discharges,” establishes regulations for reporting 

unauthorized discharges or spills.

LAC 33:Part V and LAC 33 

Part:VII

LAC 33: Part V,“Hazardous Waste and Hazardous Materials”

LAC 33: Part VII,“Solid Waste”

LAC 33: Part XI LAC 33 Part XI, “Environmental Quality: Underground Storage Tanks,” 

establishes regulations for underground storage tank systems.

LAC 33:XI.715 LAC 33 Part XI, Section 715, “Release Response and Corrective Action 

for UST Systems Containing Petroleum or Hazardous Substances,” 

regulates reportable Spills from an underground storage tank containing a 

petroleum product.
B-5

Law/regulation Requirements

Tennessee Department of 

Environment and 

Conservation Rule 

1200-2-10-32

“Licensing of Shippers of Radioactive Materials into or Within Tennesee,” 

establishes the requirements for the licensing of shippers of radioactive 

material in that State.

Protected species

Endangered Species Act,

16 U.S.C. 1531 et seq.

The Endangered Species Act (ESA) was enacted to prevent the further 

decline of endangered and threatened species and to restore those 

species and their critical habitats. Section 7, “Interagency Cooperation,” of 

the Act requires Federal agencies to consult with the U.S. Fish and 

Wildlife Service (FWS) or the National Marine Fisheries Service (NMFS) 

on Federal actions that may affect listed species or designated critical 

habitats.

Magnuson–Stevens Fishery 

Conservation and 

Management Act, 

16 U.S.C. 1801-1884 

The Magnuson–Stevens Fishery Conservation and Management Act, as 

amended, governs marine fisheries management in U.S. Federal waters. 

The Act created eight regional fishery management councils and includes 

measures to rebuild overfished fisheries, protect essential fish habitat, and 

reduce bycatch. Under Section 305 of the Act, Federal agencies are 

required to consult with the National Marine Fisheries Service for any 

Federal actions that may adversely affect essential fish habitat.

Historic preservation and cultural resources

National Historic 

Preservation Act, 

16 U.S.C. 470 et seq.

The National Historic Preservation Act was enacted to create a national 

historic preservation program, including the National Register of Historic 

Places and the Advisory Council on Historic Preservation (ACHP). 

Section 106 of the Act requires Federal agencies to take into account the 

effects of their undertakings on historic properties. The Advisory Council 

on Historic Preservation regulations implementing Section 106 of the Act 

are found in 36 CFR Part 800, “Protection of Historic Properties.” The 

regulations call for public involvement in the Section 106 consultation 

process, including involvement from Indian Tribes and other interested 

members of the public, as applicable.

1 B.2 Operating Permits and Other Requirements

2 Table B-2 lists the permits and licenses issued by Federal, State, and local authorities for 

3 activities at RBS, as identified in Chapter 9 of the Environmental Report (ER). 

4 Table B-2. Operating Permits and Other Requirements

Permit

Responsible 

Agency Number Expiration Date Authorized Activity

Authorization to 

export waste

Central Interstate 

Low-Level 

Radioactive 

Waste 

Commission 

None Updated annually Export of low-level 

radioactive waste 

outside the region

Louisiana Pollutant 

Discharge Elimination 

System permit

Louisiana 

Department of 

Environmental 

Quality (LDEQ)

LA0042731 October 1, 

2016(a)

Discharge of 

wastewaters to waters 

of the State
B-6

Permit

Responsible 

Agency Number Expiration Date Authorized Activity

Air permit LDEQ 3160-00009-04 Current air permit 

does not include 

expiration date (b)

Operation of air 

emission sources 

(diesel generators, 

diesel pumps, portable 

auxiliary boiler, and 

portable gas/diesel 

generators)

Hazardous waste 

generator 

identification

LDEQ LAD070664818 None Hazardous waste 

generation.

Industrial solid waste

site identification

LDEQ G-2104-125 None Industrial solid waste

generation

Onsite wastewater

treatment system

Louisiana 

Department of 

Health and 

Hospitals

1030185 None Mo-Dad sanitary 

wastewater treatment 

for leach field at small 

structure near 

unmanned 

checkpoint facility 

leading to the plant

Radioactive waste

transport permit

Mississippi 

Emergency 

Management 

Agency

1511 Updated annually Transportation of 

radioactive waste into, 

within, or through the 

State of Mississippi

Operating license NRC NPF-47 August 29, 2025 Operation of RBS

Radioactive waste

license for delivery

Tennessee 

Department of 

Environment and 

Conservation

TLA002-Ll6 Updated annually Shipment of 

radioactive material 

into Tennessee to a 

disposal or processing 

facility

Authorization to 

import waste

Texas Low-Level 

Radioactive 

Waste Disposal 

Compact 

Commission 

TLLRWDCC #2-

0103-00

Updated annually Import low-level 

radioactive waste to a 

Texas LLRW disposal 

compact facility.

Generator site access 

permit

Utah Department 

of Environmental 

Quality 

1110007082 Updated annually Site access permit for 

disposal of Class A 

wastes

General permit U.S. Army Corp 

of Engineers 

NOD-23 April 30, 2022 Dredging activities at 

the intake structure

Hazardous materials 

certificate of 

registration

U.S. Department 

of Transportation 

061616550010Y Updated annually Radioactive and 

hazardous materials 

shipments

Depredation permit U.S. Fish and

Wildlife Service

MBS8598A-0 Updated annually Taking of migratory 

birds.

Onsite wastewater

treatment system

Louisiana 

Department of 

Health and 

Hospitals 

1089509 None Mo-Dad sanitary 

wastewater treatment 

for leach field at the 

auxiliary control room 

located in the Unit 2 

excavation
B-7

Permit

Responsible 

Agency Number Expiration Date Authorized Activity

Industrial solid waste

site identification

LDEQ G-089-3276 None Industrial solid waste

generation

(a) Entergy submitted a timely application for renewal of its LPDES permit on May 3, 2016, and the Louisiana

Department of Environmental Quality (LDEQ) has determined it to be administratively complete (Entergy 2017a).

(b) The current air permit does not contain an expiration date. However, in 2015, the LDEQ promulgated

amendments to LAC 33:III.503 to establish a regulatory framework setting forth renewal procedures and

maximum terms for minor source air permits of not more than 10 years. Therefore, unless extended, RBS’s air

permit will expire on July 8, 2019.

Source: Entergy 2017a

1 B.3 References

2 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

3 Protection Against Radiation.”

4 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic Licensing of 

5 Production and Utilization Facilities.”

6 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

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

8 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

9 renewal of operating licenses for nuclear power plants.”

10 40 CFR Part 122. Code of Federal Regulations, Title 40, Protection of Environment, Part 122, 

11 “EPA administered permit programs: the National Pollutant Discharge Elimination System.”

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

13 Clean Air Act of 1963, as amended. 42 U.S.C. §7401 et seq.

14 Clean Water Act of 1977, as amended. 33 U.S.C. §1251 et seq.

15 Coastal Zone Management Act of 1972, as amended. 16 U.S.C. §1451 et seq.

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

17 Energy Reorganization Act of 1974. 42 U.S.C. §5801 et seq.

18 [Entergy] Entergy Louisiana, LLC and Entergy Operations, Inc. 2017a. Appendix E, Redacted 

19 Applicant’s Environmental Report, Operating License Renewal Stage, River Bend Station. West 

20 Feliciana Parish, LA. May 2017. 859 p. ADAMS Accession No. ML17174A531.

21 Fish and Wildlife Coordination Act of 1934, as amended. 16 U.S.C. §661 et seq.

22 Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. §1361 et seq.

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

24 16 U.S.C. §1801 et seq.
B-8

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

2 National Historic Preservation Act of 1966, as amended. 54 U.S.C. §300101 et seq.

3 Pollution Prevention Act of 1990. 42 U.S.C. §13101 et seq.

4 Resource Conservation and Recovery Act of 1976, as amended. 42 U.S.C. §6901 et seq.

5 Wild and Scenic Rivers Act, as amended. 16 U.S.C. §1271 et seq.
C-1

1 APPENDIX C 

2 CONSULTATION CORRESPONDENCE REVIEW 

3 C.1 Endangered Species Act Section 7 Consultation

4 As a Federal agency, the U.S. Nuclear Regulatory Commission (NRC) must comply with the 

5 Endangered Species Act of 1973, as amended (16 United States Code (U.S.C.) § 1531 et seq.), 

6 as part of any action authorized, funded, or carried out by the agency. In this case, the 

7 proposed agency action is whether to issue a renewed license for the continued operation of 

8 River Bend Station, Unit 1 (RBS), which would authorize operation for an additional 20 years 

9 beyond the current license term. Under section 7 of the ESA, the NRC must consult with the 

10 U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS)

11 (referred to jointly as “the Services” and individually as “Service”), as appropriate, to ensure that 

12 the proposed agency action is not likely to jeopardize the continued existence of any 

13 endangered or threatened species or result in the destruction or adverse modification of 

14 designated critical habitat. 

15 C.1.1 Federal Agency Obligations under Section 7, “Interagency Cooperation,” of the

16 Endangered Species Act

17 The Endangered Species Act and the regulations that implement Section 7 of the Act (Title 50 

18 of the Code of Federal Regulations (50 CFR) Part 402, “Interagency Cooperation—Endangered 

19 Species Act of 1973, as Amended”) describe the consultation process that Federal agencies 

20 must follow in support of agency actions. As part of this process, the Federal agency shall 

21 either request that the Services (1) provide a list of any listed or proposed species or designated 

22 or proposed critical habitats that may be present in the action area or (2) request that the 

23 Services concur with a list of species and critical habitats that the Federal agency has created 

24 (50 CFR 402.12(c)). If any such species or critical habitats may be present, the Federal agency 

25 prepares a biological assessment to evaluate the potential effects of the action and determine 

26 whether the species or critical habitat are likely to be adversely affected by the action 

27 (50 CFR 402.12(a); 16 U.S.C. §1536(c)). Biological assessments are required for any agency 

28 action that is a “major construction activity” (50 CFR 402.12(b)), which is defined as a 

29 construction project or other undertaking having construction-type impacts that is a major 

30 Federal action significantly affecting the quality of the human environment under the National 

31 Environmental Policy Act of 1969, as amended (42 U.S.C. §4321 et seq.; herein referred to as 

32 NEPA) (51 FR 19926). Federal agencies may fulfill their obligations to consult with the Services 

33 under ESA Section 7 and to prepare a biological assessment, if required, in conjunction with the 

34 interagency cooperation procedures required by other statutes, including NEPA 

35 (50 CFR 402.06(a)). In such cases, the Federal agency should include the results of the ESA 

36 Section 7 consultation in the NEPA document (50 CFR 402.06(b)).

37 C.1.2 Biological Assessment

38 License renewal does not require the preparation of a biological assessment because it is not a 

39 major construction activity. However, this supplemental environmental impact statement (SEIS) 

40 includes an evaluation of the potential impacts to federally listed species and critical habitats to 

41 support the NRC’s Endangered Species Act effect determinations for listed species and critical 

42 habitats that may occur in the action area.

43 The NRC staff structured its evaluation in accordance with the Services’ suggested biological 

44 assessment contents described at 50 CFR 402.12(f). Section 3.8 of this report describes the 

45 action area as well as the federally listed and proposed species and designated and proposed 
C-2

1 critical habitats potentially present in the action area. This section includes information pursuant 

2 to 50 CFR 402.12(f)(1), (2), and (3). Section 4.8 of this SEIS provides an assessment of the 

3 potential effects of the proposed RBS license renewal on the species and critical habitats 

4 present. This section also contains the NRC’s effect determinations, which are consistent with 

5 those in Section 3.5 of the Endangered Species Consultation Handbook (FWS and 

6 NMFS 1998). Finally, Section 4.8 addresses cumulative effects and alternatives to the 

7 proposed action pursuant to 50 CFR 402.12(f)(4) and (5).

8 C.1.3 Chronology of Endangered Species Act Section 7 Consultation

9 Endangered Species Act Section 7 Consultation with the U.S. Fish and Wildlife Service

10 During its review of the Entergy Louisiana, LLC and Entergy Operations, Inc. (collectively 

11 referred to as Entergy) license renewal application, the NRC staff considered whether any 

12 federally listed, proposed, or candidate species or proposed or designated critical habitats may 

13 be present in the action area (as defined at 50 CFR 402.02) for the proposed RBS license 

14 renewal. With respect to species under the FWS’s jurisdiction, the NRC staff submitted project 

15 information to the Service’s Environmental Conservation Online System (ECOS) Information for 

16 Planning and Conservation (IPaC) system to obtain a list of species in accordance with 

17 50 CFR 402.12(c). On August 30, 2017, the Service provided the NRC with a list of threatened 

18 and endangered species that may occur in the proposed action area. The list included one 

19 species, the pallid sturgeon (Scaphirhynchus albus), and stated that no critical habitats are 

20 within the project area under review.

21 The NRC staff evaluated the potential impacts to the pallid sturgeon in Section 3.8 and 

22 Section 4.8 of this SEIS. The staff concludes that the proposed license renewal may affect, but 

23 is not likely to adversely affect, the pallid sturgeon. No other listed species, proposed or 

24 candidate species, or proposed or designated critical habitats occur in the action area. The 

25 NRC staff will submit a copy of this draft SEIS, upon its issuance, to the FWS for review 

26 accompanied by a request for the Service to concur with the staff’s “not likely to adversely 

27 affect” determination in accordance with 50 CFR 402.12(j).

28 Table C-1 lists the letters and other correspondence pursuant to the NRC’s compliance with the 

29 Endangered Species Act Section 7 for RBS license renewal. The NRC staff will update this 

30 table in the final SEIS to include any correspondence transpiring between the issuance of this 

31 draft SEIS and the final SEIS.

32 Table C-1. Endangered Species Act Section 7 Consultation Correspondence with the 

33 U.S. Fish and Wildlife Service

Date Sender and Recipient Description

ADAMS Accession 

No.(a)

August 30, 2017 Louisiana Ecological 

Services Field Office

(FWS) to B. Grange 

(NRC)

List of threatened and endangered 

species for the proposed RBS 

license renewal

ML17242A116

(a) Access these documents through the NRC’s Agencywide Documents Access and Management System

(ADAMS) at http://adams.nrc.gov/wba/.
C-3

1 Endangered Species Act Section 7 Consultation with the National Marine Fisheries Service

2 As discussed in Section 3.8 and Section 4.8 of this report, no federally listed species or critical 

3 habitats under the NMFS’s jurisdiction occur within the action area. Therefore, the NRC did not 

4 engage the NMFS pursuant to ESA Section 7 for the proposed RBS license renewal.

5 C.2 Essential Fish Habitat Consultation

6 The NRC must comply with the Magnuson–Stevens Fishery Conservation and Management 

7 Act, as amended (16 U.S.C. §1801 et seq.), for any actions authorized, funded, or undertaken, 

8 or proposed to be authorized, funded, or undertaken that may adversely affect any essential fish 

9 habitat (EFH) identified under the Magnuson–Stevens Act.

10 In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that, under the Magnuson–

11 Stevens Act, the NMFS has not designated any essential fish habitat in the Mississippi River 

12 and that the proposed RBS license renewal would have no effect on essential fish habitat. 

13 Thus, the Magnuson–Stevens Act does not require the NRC to consult with the NMFS for the 

14 proposed action.

15 C.3 National Historic Preservation Act Section 106 Consultation

16 The National Historic Preservation Act of 1966, as amended (NHPA), requires Federal agencies 

17 to consider the effects of their undertakings on historic properties and consult with applicable 

18 State and Federal agencies, Tribal groups, individuals, and organizations with a demonstrated 

19 interest in the undertaking before taking action. Historic properties are defined as resources 

20 that are eligible for listing on the National Register of Historic Places. The historic preservation 

21 review process (Section 106 of the NHPA) is outlined in regulations issued by the Advisory 

22 Council on Historic Preservation (ACHP) in 36 CFR Part 800, “Protection of Historic Properties.” 

23 In accordance with 36 CFR 800.8(c), “Use of the NEPA Process for Section 106 Purposes,” the 

24 NRC has elected to use the NEPA process to comply with its obligations under Section 106 of 

25 the National Historic Preservation Act.

26 Table C-3 lists the chronology of consultation and consultation documents related to the NRC’s 

27 National Historic Preservation Act Section 106 review of the RPS license renewal. The NRC 

28 staff is required to consult with the noted agencies and organizations in accordance with the 

29 statutes listed above.

30 Table C-2. National Historic Preservation Act Correspondence

Date Sender and Recipient Description

ADAMS 

Accession No. (a)

September 15, 2017 B. Beasley (NRC) to M. Darden,

Chitimacha Tribe of Louisiana

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to L. Poncho,

Coushatta Tribe of Louisiana

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to B.C. Smith,

Jena Band of Choctaw Indians

Request for scoping

comments/notification of 

Section 106 review

ML17255A024
C-4

Date Sender and Recipient Description

ADAMS 

Accession No. (a)

September 15, 2017 B. Beasley (NRC) to J.P. Barbry,

Tunica-Biloxi Tribe of Louisiana

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to J.A. Battise,

Alabama Coushatta Tribe of 

Texas

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to G. Batton,

The Choctaw Nation of 

Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to P.J.

Anderson, Mississippi Band of 

Choctaw Indians

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to L.M. Harjo,

The Seminole Nation of 

Oklahoma

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B Beasley (NRC) to M. W. 

Osceola, Seminole Tribe of 

Florida

Request for scoping

comments/notification of 

Section 106 review

ML17255A024

September 15, 2017 B. Beasley (NRC) to P. Boggan,

Louisiana Office of Cultural 

Development

Request for scoping

comments/notification of 

Section 106 review

ML17255A051

September 15, 2017 B. Beasley (NRC) to R. Nelson,

Advisory Council on Historic 

Preservation

Request for scoping

comments/notification of 

Section 106 review

ML17255A036

(a) Access these documents through the NRC’s Agencywide Documents Access and Management System

(ADAMS) at http://adams.nrc.gov/wba/.

1 C.4 References

2 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

3 Part 800, “Protection of historic properties.”

4 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

5 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

6 51 FR 19926. U.S. Fish and Wildlife Service and National Marine Fisheries Service. 

7 Interagency cooperation—Endangered Species Act of 1973, as amended; final rule. Federal 

8 Register 51:19926-19963. June 3, 1986.

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

10 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 

11 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 

12 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 

13 Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf> 

14 (accessed 16 January 2018).
C-5

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

2 16 U.S.C. § 1801 et seq.

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

4 [NHPA] National Historic Preservation Act of 1966, as amended. 54 U.S.C. §300101 et seq.

D-1

APPENDIX D 

CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE

This appendix contains a chronological listing of correspondence between the U.S. Nuclear 

Regulatory Commission (NRC) and external parties as part of the agency’s environmental 

review of the River Bend Station, Unit 1 (RBS) license renewal application (LRA). This 

appendix does not include consultation correspondence or comments received during the 

scoping process. For a list and discussion of consultation correspondence, see Appendix C of 

this supplemental environmental impact statement (SEIS). For scoping comments, see 

Appendix A of this SEIS and the NRC’s, “Scoping Summary Report” (Agencywide Documents 

Access and Management System (ADAMS) Accession No. ML17362A554). All documents are 

available electronically from the NRC’s Public Electronic Reading Room found at: 

http://www.nrc.gov/reading-rm.html. From this site, the public can gain access to ADAMS, 

which provides text and image files of the NRC’s public documents. The ADAMS accession 

number for each document is included in the following table.

D.1 Environmental Review Correspondence

Table D-1 lists the environmental review correspondence, by date, beginning with the request 

by Entergy Louisiana, LLC and Entergy Operations, Inc. (collectively referred to as Entergy) to 

renew the operating license for RBS.

Table D-1. Environmental Review Correspondence

Date Correspondence Description

ADAMS 

Accession No.

May 25, 2017 Transmittal of RBS license renewal application from Entergy

to NRC

ML17153A285

June 20, 2017 Letter from NRC to Entergy regarding receipt and availability 

of RBS license renewal application 

ML17156A093

July 10, 2017 Letter from NRC to Entergy—supplemental information 

needed for acceptance of requested licensing action

ML17186A159

August 1, 2017 Letter from Entergy to NRC with supplemental information ML17213A064

August 7, 2017 Determination of acceptability and sufficiency for docketing, 

proposed review schedule, and opportunity for a hearing 

regarding the application for renewed operating licenses for 

RBS

ML17187A035

September 14, 2017 Notice of intent to prepare an environmental impact 

statement and conduct scoping for RBS license renewal

ML17223A193

September 19, 2017 Transcript from public scoping meeting ML17293A547

October 13, 2017 Letter from NRC to Entergy transmitting severe accident

mitigation alterative (SAMA) audit plan

ML17284A100

October 13, 2017 Letter from NRC to Entergy transmitting environmental audit 

plan

ML17278A775

November 7, 2017 Letter from NRC to Entergy transmitting environmental 

requests for additional information (RAIs)

ML17311A422

November 8, 2017 Letter from NRC to Entergy transmitting SAMA requests for 

additional information (RAIs)

ML17317A002
D-2

Date Correspondence Description

ADAMS 

Accession No.

November 27, 2017 Letter from NRC to Entergy transmitting environmental audit 

summary

ML17319A503

December 5, 2017 Letter from Entergy to NRC transmitting SAMA RAI 

responses

ML17339A795

December 5, 2017 Letter from Entergy to NRC transmitting responses to 

environmental RAIs 

ML17353A049

December 7, 2017 Letter from NRC to Entergy transmitting SAMA audit 

summary

ML17324A506

January 24, 2018 Letter from Entergy transmitting clarification of SAMA RAI 

responses

ML18025B711

April 24, 2018 Scoping Summary Report ML17362A554
E-1

1 APPENDIX E 

2 PROJECTS AND ACTIONS CONSIDERED IN THE CUMULATIVE 

3 IMPACTS ANALYSIS REVIEW 

4 Table E-1 identifies projects and actions the U.S. Nuclear Regulatory Commission (NRC) staff 

5 considered when analyzing cumulative environmental impacts related to the continued operation

6 of River Bend Station, Unit 1 (RBS) for an additional 20-years after the current licensing 

7 period. For an analysis of the potential cumulative impacts associated with each of these 

8 projects and actions, see Chapter 4 (Section 4.16) of this report. However, please note that 

9 Chapter 4 does not consider every project and action listed in Table E-1 in each resource area 

10 because of the uniqueness of the resource and its geographic area of consideration.

11 Table E-1. Projects and Actions NRC Staff Considered in the Cumulative Impacts 

12 Analysis

Project Name Summary of Project

Location

(Relative

to RBS) Status

Onsite Facilities/Projects

River Bend Station 

demolition activities

Demolition of retired

support facilities 

Onsite Demolition of the old 

Maintenance Shop and 

ANCO building were 

completed in October 2017.

Demolition of the Field 

Administration Building will 

occur in 2018. The Pipe 

Shop requires further 

evaluation prior to 

demolition and presently 

has no set schedule. 

(Entergy 2017a) 

River Bend Station 

Independent Spent 

Fuel Storage 

Installation Expansion

Planned expansion of 

existing storage facility to 

add additional pad

Onsite Construction scheduled for 

2020. (Entergy 2017a)

Nuclear Energy Facilities

Waterford Steam 

Electric Station, Unit 3

Nuclear power plant; 

one 1,188-MWe 

Combustion Engineering 

design pressurized-water 

reactor

St Charles Parish, 

LA, approximately 

75 mi (121 km) 

southeast. The 

50-mi (80-km)

radius of this

facility overlaps

with that of River

Bend Station.

Operational 

(Entergy 2017b; NRC 2017)
E-2

Project Name Summary of Project

Location

(Relative

to RBS) Status

Fossil Fuel Energy Facilities

Big Cajun I 

Power Plant

Natural gas-fueled plant with 

430-MW generating capacity

Jarreau, LA, 

approximately 

6 mi (10 km) 

south-southwest

Operational 

(EIA 2017a; NRG 2015a)

Big Cajun II 

Power Plant

Coal- and natural gas-fueled 

plant with 1,743-MW 

generating capacity (from 

two coal units (totaling 1,168 

MW) and one natural gas 

unit (575 MW))

Jarreau, LA, 

approximately 

3 mi (5 km) 

southwest

Operational

(EIA 2017b; NRG 2015b)

New Roads 

Power Plant

Natural gas-fueled peaking 

plant with approximately 

7 MW generating capacity

collocated with Big Cajun II

Jarreau, LA, 

approximately 3 

mi (5 km) 

southwest

Operational

(EIA 2017c)

Louisiana 1 Power 

Plant

Industrial gas-fueled plant 

with approximately 382 MW 

generating capacity

Baton Rouge, LA, 

approximately 

20 mi (32 km) 

east-southeast

Operational

(EIA 2017d)

Louisiana 2 Power 

Plant

Natural gas-fueled plant with 

138 MW generating capacity

Baton Rouge, LA, 

approximately 

20 mi (32 km) 

east-southeast

Operational 

(EIA 2017e)

Renewable Energy Facilities

FSidney A. Murray Jr., 

HHydroelectric Station

Hydroelectric facility with 

approximately 192 MW 

generating capacity

Concordia 

Parrish, LA, 

approximately 

28 mi (46 km) 

northwest

Operational 

Manufacturing Facilities

Hood Container of 

Louisiana, 

St. Francisville Mill 

Proposed expansion of 

corrugated paper plant with 

approximately 17 MW 

capacity, biomass-fueled, 

combined heat and power 

plant

West Feliciana 

Parish, LA, 

approximately 

3 mi (5 km) south

Operational

(CPE 2016; EIA 2017j; 

EPA 2017b

Georgia Pacific Paper manufacturing plant 

with approximately 128 MW 

capacity, biomass-fueled, 

combined heat and power 

plant

East Baton Rouge 

Parish, LA, 

approximately 

8 mi (13 km) 

south-southeast

Operational

(EIA 2017g; EPA 2017b)

ExxonMobil Petroleum refinery with 

approximately 77 MW 

capacity, natural gas-fueled, 

combined heat and power 

plant

East Baton Rouge 

Parish, LA, 

approximately 21 

mi (34 km) southsoutheast

Operational

(EIA 2017h; 

ExxonMobil 2017a)
E-3

Project Name Summary of Project

Location

(Relative

to RBS) Status

ExxonMobil 

Chemical Co.

Petrochemical 

manufacturing plant

East Baton Rouge

Parish, 

approximately 

15 mi (24 km) 

south-southeast

Operational

(EIA 2017i; 

ExxonMobil 2017b) 

Oxbow Carbon LLC Petroleum coke calcining 

facility

East Baton Rouge

Parish, LA, 

approximately 

13mi (21 km) 

southeast

Operational

(EPA 2017b; Oxbow 2015)

Formosa Plastics Plastics manufacturing plant 

with approximately 100 MW 

capacity, natural gas-fueled, 

combined heat and power 

plant

East Baton Rouge

Parish, LA, 

approximately 

20 mi (31 km) 

southeast

Operational

(EIA 2017k; Formosa 2017, 

EPA 2017b)

Placid Refining LLC Oil refinery with 

approximately 7 MW 

capacity, natural gas-fueled, 

combined heat and power 

plant

West Baton 

Rouge Parish, LA, 

approximately 

21 mi (33 km) 

south-southeast

Operational

(EIA 2017l; Placid 2017) 

Landfills

East Baton Rouge 

Parish North Landfill

Municipal solid-waste landfill East Baton Rouge 

Parish, LA, 

approximately 

12 mi (19 km) 

south-southeast

Operational

(LDEQ 2017)

Ronaldson Field 

Landfill

Construction and demolition 

debris landfill and recycling

East Baton Rouge 

Parish, LA, 

approximately 

16 mi (25 km) 

southeast

Operational

(City of Baton Rouge 2017; 

Ronaldson Field 2015) 

Woodside Landfill Municipal solid-waste landfill Livingston Parish, 

LA, approximately 

35 mi (56 km) 

southeast

Operational

(LDEQ 2017; WM 2014)

Water Supply and Treatment Facilities

West Feliciana Parish 

Water District 13 

Municipal water supply 

with groundwater source 

St. Francisville, 

LA, 

approximately 

3 mi (5 km) 

northwest

Operational 

(EPA 2017a; 

Entergy 2017b)

Town of 

St. Francisville

Water System

Municipal water supply 

with groundwater source

St. Francisville, 

LA, approximately 

3 mi (5 km) 

northwest

Operational 

(EPA 2017a; Entergy

2017b)
E-4

Project Name Summary of Project

Location

(Relative

to RBS) Status

Baton Rouge Water 

Company

Municipal water supply 

with groundwater source

Baton Rouge, LA, 

approximately 

26 mi (42 km) 

southeast

Operational 

(EPA 2017b; Entergy

2017b)

City of Baker Water 

System 

Municipal water supply with 

groundwater source

Baker, LA, 

approximately 

15 mi (24 km) 

southeast

Operational 

(EPA 2017b; Entergy

2017b)

Zachary Water 

System

Municipal water supply with 

groundwater source

Zachary, LA, 

approximately 

13 mi (21 km) 

southeast

Operational 

(EPA 2017b; Entergy

2017b)

Louisiana State 

Penitentiary

Penitentiary water supply 

with groundwater source

Angola, LA, 

approximately 

20 mi (33 km) 

northwest

Operational 

(EPA 2017a)

Town of St. 

Francisville 

Wastewater 

Treatment Plant

Wastewater treatment plant St. Francisville, 

LA, approximately 

4 mi (6 km) west 

northwest

Operational

(Entergy 2017b; 

EPA 2017c)

North Wastewater 

Treatment Plant

Wastewater treatment plant Baton Rouge, LA, 

approximately 

17 mi (28 km) 

southeast

Operational 

(Entergy 2017b; 

EPA 2017d)

Central Wastewater 

Treatment Plant

Wastewater treatment plant Baton Rouge, LA, 

approximately 

24 mi (39 km) 

southeast

Operational 

(Entergy 2017b; 

EPA 2017d)

South Wastewater 

Treatment Plant

Wastewater treatment plant Baton Rouge, LA, 

approximately 

30 mi (49 km) 

southeast

Operational 

(Entergy 2017b; 

EPA 2017d)

Various minor 

National Pollutant 

Discharge Elimination 

System permitted 

wastewater

discharges

Various businesses with 

smaller wastewater

discharges

Within 50 mi 

(31 km)

Operational

(EPA 2017d)

Parks and Recreation Sites

Audubon State 

Historic Site

100-ac (40-ha) historic site

offering hiking, picnicking,

and birdwatching

Approximately 

3 mi (5 km) 

northeast

Operational;

Managed by Louisiana 

Department of Culture, 

Recreation, and Tourism 

(Entergy 2017b; 

DCRT 2017a)
E-5

Project Name Summary of Project

Location

(Relative

to RBS) Status

Rosedown Plantation 

State Historic Site 

370-ac (150-ha) historic site

offering tours, hiking, and

picnicking

Approximately 

3 mi (5 km) 

northwest

Operational;

Managed by Louisiana 

Department of Culture, 

Recreation, and Tourism 

(Entergy 2017b; DCRT 

2017b

Port Hudson 

Battlefield/Port 

Hudson State Historic 

Site 

900-ac (360-ha) state

historic site offering hiking,

picnicking, and birdwatching

Approximately 

6 mi (10 km) 

southeast

Operational;

Managed by Louisiana 

Department of Culture, 

Recreation, and Tourism 

(Entergy 2017b; DCRT 

2017c; NPS 2017)

Cat Island National 

Wildlife Refuge

10,500-ac (4,300-ha) refuge 

offering hunting, fishing, 

hiking, and canoeing

Approximately 

6 mi (10 km) westnorthwest

Operational;

Managed by U.S. Fish and 

Wildlife Service (Entergy

2017b, USFWS 2017d) 

Homochitto National 

Forest 

192,000-ac (78,000-ha) 

recreation area offering 

hunting, picnicking, camping, 

and hiking

Extends across 

multiple 

Mississippi 

counties, 

approximately 

36 mi (58 km) 

north-northeast

Operational;

Managed by U.S. Forest 

Service (Entergy 2017b; 

USDA 2012

Tunica Hills Wildlife 

Management Area 

6,500-ac (2,600-ha) wildlife 

management area offering 

hunting, trapping, hiking, 

camping, birding, biking, and 

horseback riding

Approximately 

15 mi (24 km) 

northwest 

Operational;

Managed by Louisiana 

Department of Wildlife and 

Fisheries (Entergy 2017b; 

LDWF 2017c)

Port Hudson National 

Cemetery

20-ac (8-ha) Civil War-era

military cemetery

Approximately 

7 mi (12 km) eastnortheast 

Operational;

Managed by the U.S. 

Department of Veterans 

Affairs (Entergy 2017b; 

NPS undated)

Atchafalaya National 

Wildlife Refuge/ 

Sherburne Wildlife 

Management Area/ 

Bayou Des Ourses 

Area

44,000-ac (18,000-ha) 

combined tract of Federal 

and state wildlands 

Approximately 

25 mi (40 km) 

southwest

Operational;

Managed by as a single unit 

by the Louisiana 

Department of Wildlife and 

Fisheries (USFWS 2017a; 

Entergy 2017b) 

Lake Ophelia National 

Wildlife Refuge

17,500-ac (7,100-ha) refuge 

offering hunting, fishing, 

boating, and hiking

Approximately 

40 mi (64 km) 

northwest

Operational;

Managed by U.S. Fish and 

Wildlife Service (USFWS 

2017b; Entergy 2017b)

St. Catherine Creek 

National Wildlife 

Refuge

24,600-ac (10,000-ha) 

refuge offering hunting, 

fishing, hiking, and canoeing

Approximately 

40 mi (64 km) 

north

Operational;

Managed by U.S. Fish and 

Wildlife Service (USFWS 

2017c; Entergy 2017b)
E-6

Project Name Summary of Project

Location

(Relative

to RBS) Status

Mary Ann Brown 

Nature Preserve

100-ac (40-ha) preserve

offering hiking, camping

picnicking, and birdwatching

Approximately 

6 mi (10 km) 

northeast

Operational;

Managed by the Nature 

Conservancy (ABA 2013, 

Entergy 2017b)

Richard K. Yancey 

Wildlife Management 

Area

70,000-ac (28,000-km) 

wildlife management area 

offering hunting, trapping, 

fishing, boating, and 

camping

Concordia Parish, 

LA, approximately 

25 mi (40 km) 

northwest

Operational;

Managed by Louisiana 

Department of Wildlife and 

Fisheries (Entergy 2017b; 

LDWF 2017a) 

Thistlewaite Wildlife 

Management Area

11,000-ac (4,500-km) wildlife 

management area offering 

hunting, trapping, birding, 

and hiking

St. Landry Parish, 

LA, approximately 

38 mi (61 km) 

west-southwest

Operational;

Managed by Louisiana 

Department of Wildlife and 

Fisheries (Entergy 2017b; 

LDWF 2017b)

Recreational Areas Various parks, boat 

launches, and campgrounds 

Within 10 mi 

(16 km)

Operational

Transportation Projects

Baton Rouge 

Metropolitan Airport

Full-service commercial 

airport 

In East Baton 

Rouge Parish, LA, 

approximately 

19 mi (30 km) 

southeast

Operational;

Environmental Assessment 

being prepared to address 

potential impacts from 

proposed runway 

expansion and 

improvements (BTR 2017)

Other Aviation 

Facilities

Six private heliports, three 

private airfields, and one 

public general aviation 

airport

Located within 

10 mi (16 km) of 

River Bend 

Station

Operational

(Entergy 2017b)

Other Facilities/Projects

West Feliciana Parish 

Hospital 

New hospital construction Approximately 

3 mi (1.2 km) 

west-northwest

Construction completed 

August 2017 

(Entergy 2017a) 

Bayou Sara 

Streambank 

Stabilization Project 

Proposed project to address 

severe streambank erosion 

threatening St. Francisville 

wastewater treatment facility, 

levees, and road access 

Approximately 

4 mi (6 km) westnorthwest 

southeast

U.S. Federal Emergency 

Management Agency 

evaluating funding request 

(Entergy 2017a)

Joint Emergency 

Services Training 

Center (JESTC)

Louisiana State Police Joint 

Emergency Services 

Training Center featuring 

emergency vehicle tracks, 

explosives ranges, and 

tactical firearm ranges

Zachery, LA, 

approximately 

11 mi (18 km) 

south-southeast

Operational

(JESTC 2017)
E-7

Project Name Summary of Project

Location

(Relative

to RBS) Status

St. Francisville Army 

Corps of Engineers 

Mat Yard

210 ac (85 ha) plant and 

storage yard for casting 

concrete erosion control 

mats 

St. Francisville, 

LA. approximately 

3 mi (5 km) westnorthwest

Operational 

(USACOE 2017)

Future Development Construction of housing units 

and associated commercial 

buildings; roads, bridges, 

and rail; water and/or 

wastewater treatment and 

distribution facilities; and 

associated pipelines as 

described in local land-use 

planning documents

Throughout region Construction would occur in 

the future, as described in 

State and local land-use 

planning documents

1 E.1 References

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3 November 2017).

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6 [CPE] Commercial Property Executive. 2016. “Hood Container Expands Manufacturing Facility 

7 in Louisiana” November 22. Available at <https://www.cpexecutive.com/post/hood-container8 expands-manufacturing-facility-in-louisiana/> (accessed 20 November 2017).

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12 [DCRT] Louisiana Department of Culture, Recreation, and Tourism. 2017b. Rosedown 

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15 18 December 2017).

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E-8

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13 [Entergy] Entergy Operations, Inc. 2017a. Letter from Maguire WF, Site Vice President, River 

14 Bend Station, to NRC Document Control Desk. Subject: Response to License Renewal 

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19 Application. West Feliciana Parish, LA. May 2017. 1,301 p. ADAMS Accession Nos. 

20 ML17153A286 and ML17153A287.

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25 &fac_city=&pop_serv=500&pop_serv=3300&pop_serv=10000&pop_serv=100000&pop_serv=1

26 00001&sys_status=active&pop_serv=&wsys_id=&fac_state=LA&last_fac_name=&page=1&quer

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41 Equal+to&naics_to=&chem_name=&chem_search=Beginning+With&cas_num=&page_no=1&o

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E-9

1 [EPA] U.S. Environmental Protection Agency. 2017d. “Envirofacts Multisystem Search – East 

2 Baton Rouge Parish, Louisiana”. Available at <https://iaspub.epa.gov/enviro/efsystemquery.

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5 st+Baton+Rouge&state_code=LA&TribalLand=0&TribeType=selectTribeALL&selectTribe=nosel

6 ect&selectTribe=noselect&tribedistance1=onLand&sic_type=Equal+to&sic_code_to=&naics_typ

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26 December 2017).

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29 December 2017).

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32 December 2017).

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37 21 September 2017). 

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E-10

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3 November 2017).

4 [Oxbow] Oxbow Carbon LLC. 2015. Calcining Fact Sheet. Available at 

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6 December 2017).

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13 December 2017).

14 [USACE] U. S. Army Corps of Engineers. 2017. New Orleans District – Concrete Mats. 

15 Available at <http://www.mvn.usace.army.mil/Missions/Engineering/Channel-Improvement-and16 Stabilization-Program/Revetment-Types/Concrete/> (accessed 16 November 2017) 

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18 Available at <https://www.fws.gov/refuge/atchafalaya/> (accessed 7 December 2017).

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20 Available at <https://www.fws.gov/refuge/Lake_Ophelia/> (accessed 7 December 2017).

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22 Available at <https://www.fws.gov/refuge/st_catherine_creek/> (accessed 7 December 2017).

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25 Waste Management. 2014. Woodside Landfill Fact Sheet. Available at 

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27 December 2017).
F-1

1 APPENDIX F 

2 U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF

3 SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR RIVER BEND 

4 STATION, UNIT 1, IN SUPPORT OF LICENSE RENEWAL 

5 APPLICATION REVIEW

6 F.1 Introduction

7 Entergy Louisiana, LLC and Entergy Operations, Inc. (Entergy or the applicant) submitted an 

8 assessment of severe accident mitigation alternatives (SAMAs) for River Bend Station (RBS), in 

9 Section 4.15 and Attachment D of the Environmental Report (ER) (Entergy 2017a). This 

10 assessment was based on the most recent revision to the RBS probabilistic risk assessment 

11 (PRA), including an internal events model and a plant-specific offsite consequence analysis 

12 performed using the MELCOR Accident Consequence Code System 2 (MACCS) computer 

13 code, as well as insights from the RBS individual plant examination (IPE) (Entergy 1993), the 

14 RBS individual plant examination of external events (IPEEE) (Entergy 1995), and the RBS 

15 internal flooding PRA. In identifying and evaluating potential SAMAs, Entergy considered 

16 SAMAs that addressed the major contributors to core damage frequency (CDF), population 

17 dose at RBS and offsite economic cost, as well as insights and SAMA candidates found to be 

18 potentially cost-beneficial from the analysis of other boiling water reactor (BWR) nuclear power 

19 generating stations. Entergy initially identified a list of 206 potential SAMAs. This list was 

20 reduced to 50 unique SAMA candidates by eliminating SAMAs that (a) were not applicable to 

21 RBS, (b) had already been implemented at RBS, (c) were combined with another SAMA 

22 candidate, (d) had an excessive implementation cost, or (e) were expected to have a very low 

23 benefit. Of the 50 unique SAMA candidates remaining, Entergy concluded in the ER that eight 

24 candidate SAMAs are potentially cost beneficial.

25 As a result of the review of the SAMA assessment, the U.S. Nuclear Regulatory Commission 

26 (NRC) staff issued a request for additional information (RAI) to Entergy by email dated 

27 November 9, 2017 (NRC 2017a). Key questions involved: 

28 • the status of the Level 1 PRA model relative to current and planned future design

29 and operating features,

30 • the modeling of containment failure in the Level 2 analysis,

31 • the impact of Level 2 cutset truncation on the determination of Source Term

32 Category (STC) frequency,

33 • selection of representative sequences for each STC in the Level 2 analysis,

34 • clarifications of the adequacy of the treatment of external events in the SAMA

35 analysis,

36 • selection of input parameters to the Level 3 analysis,

37 • the review of the internal flood and fire PRA for identification of candidate SAMAs,

38 • the use of the results of PRA importance analysis to identify RBS specific SAMA

39 candidates, and

40 • further information on the cost-benefit analysis of several specific candidate SAMAs

41 and low-cost alternatives.

42 Entergy submitted additional information by letters dated December 5, 2017 (Entergy 2017b) 

43 and January 24, 2018 (Entergy 2018). In response to the staff RAIs, Entergy provided further 

44 information on: 
F-2

1 • the history and key changes to PRA models,

2 • the results of an updated PRA,

3 • the development of the Level 2 containment release model,

4 • the modeling of containment failures,

5 • the basis for inputs to the Level 3 analysis,

6 • the identification and screening of SAMA candidates,

7 • the results of an updated cost-benefit analysis for several SAMAs, and

8 • the cost of various SAMAs and potential low-cost alternatives.

9 Entergy’s responses addressed the staff’s concerns and resulted in the identification of two 

10 additional potentially cost-beneficial SAMAs (RAI response to questions 5.b.ii and 6.c.i in 

11 Reference Entergy 2017b). 

12 An assessment of the SAMAs for RBS is presented below. Guidance for the SAMA analysis 

13 submittal is provided in NEI 05-01A, “Severe Accident Mitigation Alternatives (SAMA) Guidance 

14 Document” (NEI 2005) which was endorsed in Regulatory Guide 4.2, Supplement 1

15 (NRC 2013).

16 F.2 Estimate of Risk for RBS

17 Section F.2.1 summarizes Entergy’s estimates of offsite risk at RBS. The summary is followed 

18 by the staff’s review of Entergy’s risk estimates in Section F.2.2. 

19 F.2.1 Entergy’s Risk Estimates

20 Two distinct analyses are combined to form the basis for the risk estimates used in the RBS 

21 SAMA analysis: (1) the RBS Level 1 and 2 PRA model, which is an updated version of the RBS 

22 IPE (Entergy 1993), and (2) a supplemental analysis of offsite consequences and economic 

23 impacts (essentially a Level 3 PRA model) developed specifically for the RBS SAMA analysis. 

24 The scope of the RBS PRA used for the SAMA analysis, PRA Revision 5A (RBS R5A) does not 

25 include external events or internal flooding events.

The RBS internal events CDF is 2.79 × 10−6 26 per reactor-year as determined from quantification 

27 of the Level 1 PRA model. This value was used as the baseline CDF in the SAMA evaluations 

28 (Entergy 2017a). The CDF is based on the risk assessment for internally initiated events, which 

29 did not include internal flooding. Entergy did not explicitly include the contribution from external 

30 events within the RBS risk estimates; however, it did account for the potential risk reduction 

31 benefits associated with external events and internal flooding events by multiplying the 

32 estimated benefits for internal events by a factor of 7. This is discussed further in 

33 Sections F.2.2 and F.6.2.

34 The breakdown of CDF by initiating events is provided in Table F-1. As shown in this table, loss 

35 of offsite power (LOSP) and reactor/turbine trip are the dominant contributors to the CDF. While 

36 not listed explicitly in Table F-1 because they can occur as a result of multiple initiators, Entergy

stated that station blackouts (SBO) contribute about 39 percent (1.1 × 10−6 37 per reactor-year) of 

38 the total internal events CDF and anticipated transients without scram (ATWS) contribute about 

0.2 percent (6.6 × 10−9 39 per reactor-year) to the total internal events CDF (Entergy 2017a).
F-3

1 Table F-1. RBS CDF For Internal Events 

Initiating Event CDF

(per reactor-year)

% CDF

Contribution

Loss of Offsite Power 1.9 × 10−6 69

Reactor Trip/Turbine Trip 2.8 × 10−7 10

Inadvertent Opening of Safety Relief Valve (SRV) 1.5 × 10−7 6

Failure of the Normal Service Water

(NSW)/Service Water Cooling (SWC) System 1.2 × 10−7 4 

Loss of Condenser Heat Sink 7.3 × 10−8 3

Loss of the Feedwater/Condensate System 6.8 × 10−8 2 

Loss of Offsite Power Lead RSS1 5.0 × 10−8 2 

Loss of Offsite Power Lead RSS2 5.0 × 10−8 2 

Other Initiating Eventsa 8.0 × 10−8 3 

Total CDF (Internal Events) 2.8 × 10−6 100b

a Multiple initiating events with each contributing less than 1 percent. 

b Sum of contributors does not add up to 100 percent due to round off error.

2 The full Level 2 RBS PRA model that forms the basis for the SAMA evaluation was developed 

3 specifically for the SAMA analysis. The RBS Level 2 model includes two types of 

4 considerations: 1) a deterministic analysis of the physical processes for a spectrum of severe 

5 accident progressions, and 2) a probabilistic analysis component in which the likelihoods of the 

6 various outcomes are assessed. The Level 2 model uses containment event trees (CETs) 

7 containing both phenomenological and systemic events. Each of the Level 1 core damage 

8 sequences is then evaluated by a CET to assess the frequency of various containment release 

9 modes based on the operational configurations of the RBS containment safeguard systems.

10 The CET considers the influence of physical and chemical processes on the integrity of the 

11 containment and on the release of fission products once core damage has occurred. The 

12 quantified CET sequences are binned into a set of end states that are subsequently grouped 

13 into 14 release categories (or source term categories - STCs) that provide the input to the 

14 Level 3 consequence analysis. The frequency of each STC was obtained by summing the 

15 frequency of the individual accident progression CET endpoints binned into the release 

16 category. Source terms were developed for the release categories using the results of Modular 

17 Accident Analysis Program (MAAP) Version 4.0.7 computer code calculations. From these 

18 results, source terms were chosen to be representative of the release categories. The results of 

19 this analysis for RBS are provided in Table D.1–7 of ER Attachment D (Entergy 2017a). 

20 Entergy computed offsite consequences for potential releases of radiological material using the 

21 MACCS, Version 3.10.0 code and analyzed exposure and economic impacts from its 

22 determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 

23 site-specific input values for core radionuclide inventory, source term and release 

24 characteristics, site meteorological data, projected population distribution and growth within a 

25 50-mile (80-kilometer (km)) radius, emergency response evacuation modeling, and local

26 economic data. Radionuclide inventory in the reactor core is based on a plant-specific 

27 evaluation and corresponds to 3,100 megawatts thermal (MWt), which is slightly higher than the 

28 RBS rated power Level of 3,091 MWt (Entergy 2017a, Attachment D). The estimation of onsite 

29 impacts (in terms of clean-up and decontamination costs and occupational dose) is based on 

30 guidance in NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook

31 (NRC 1997a). Additional details on the input parameter assumptions are discussed below.
F-4

1 In Table D.1-22 of the ER, the applicant estimated the dose risk to the population within 80 km 

2 (50 mi) of the RBS site to be 0.0121 person-Sieverts (Sv) per year (1.21 person-rem per year) 

3 (Entergy 2017a). The population dose risk (PDR) and offsite economic cost risk (OECR)

4 contributions by containment release mode are summarized in Table F-2. Containment 

5 penetration failures in which the containment fails prior to core damage and debris cooling is 

6 unsuccessful (STC9 and STC10) provide the greatest contribution, totaling approximately 

7 85 percent of the PDR and 87 percent of the OECR. 

8 Table F-2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk for 

9 Internal Events

Release Mode Population Dose Riska Offsite Economic Cost Risk

IDb Frequency

(per year) 

personrem/yr% 

Contribution $/yr % Contribution

STC1 

(Intact) 5.6 × 10−7 1.0 × 10−2 1 3.6 <1

STC4 2.0 × 10−8 2.1 × 10−2 2 1.3 × 102 2 

STC7 6.4 × 10−8 7.8 × 10−3 1 5.8 <1

STC8 6.4 × 10−8 1.2 × 10−2 1 1.8 × 101 <1

STC9 9.0 × 10−7 4.7 × 10−1 39 2.5 × 103 34

STC10 9.0 × 10−7 5.5 × 10−1 46 3.9 × 103 53

STC13 1.4 × 10−7 6.1 × 10−2 5 2.9 × 102 4 

STC14 1.4 × 10−7 6.9 × 10−2 6 4.7 × 102 6 

Otherc 5.6 × 10−9 4.7 × 10−3 <1 3.0 × 101 <1

Total 2.8 × 10−6 1.21 100d 7.3 × 103 100

a Unit Conversion Factor: 1 Sv = 100 rem.

b Release Mode descriptions provided in Section D.1.2.3.1 of the ER (Entergy 2017a). 

c Multiple release categories with each contributing less than 1 percent to frequency, population dose, 

and offsite economic cost risk.

d Sum of contributors does not add up to 100 percent due to round off error.

10 F.2.2 Review of Entergy’s Risk Estimates

11 Entergy’s determination of offsite risk at RBS is based on three major elements of analysis:

12 • the Level 1 risk models that form the bases for the 1993 IPE submittal

13 (Entergy 1993), and the external event analyses of the 1995 IPEEE submittal

14 (Entergy 1995),

15 • the major modifications to the IPE model that have been incorporated in the 2015

16 RBS R5A PRA; a new full Level 2 risk model; a standalone updated 2012 internal

17 floods model and the 1995 IPEEE fire assessment, and

18 • the combination of offsite consequence measures from MACCS analyses with

19 release frequencies and radionuclide source terms from the Level 2 PRA model.

20 Each analysis element was reviewed to determine the acceptability of Entergy’s risk estimates 

21 for the SAMA analysis, as summarized further in this section. 
F-5

1 F.2.2.1 Internal Events CDF Model

2 Section 11.2.3.1 of NUREG–1560, Volume 2, Individual Plant Examination Program: 

3 Perspectives on Reactor Safety and Plant Performance Parts 2–5, Final Report (NRC 1997b) 

shows that the IPE-based total internal events CDF for BWR 5/6 plants ranges from 1 × 10−5 4 per 

year to 4 × 10−5 per year, with an average CDF for the group of 2 × 10−5 5 per year. The internal 

events CDF value from the 1993 RBS IPE (1.55 × 10−5 6 per reactor-year) is consistent with the 

7 values reported at that time for other BWR 5 and BWR 6 units. Other plants have updated the 

8 values for CDF subsequent to the IPE submittals to reflect modeling and hardware changes, 

9 which in many cases, has resulted in substantially reduced CDFs compared to those reported in 

10 the IPE. The internal events CDF result for RBS that was used for the SAMA analysis 

(2.79 × 10−6 11 per year) is in the range reported in previous SAMA analyses for other similar 

12 plants.

13 From its review of the RBS IPE submittal, the NRC staff concluded that the licensee's IPE 

14 process was capable of identifying the most likely severe accidents and severe accident

15 vulnerabilities, and therefore, the RBS IPE process met the intent of Generic Letter (GL) 88-20 

16 (NRC 1996). Although no vulnerabilities were identified in the IPE, a number of improvements 

17 were identified by Entergy. The NRC staff’s IPE safety evaluation report (SER) indicated that 

18 seven improvements had been implemented. 

19 There have been nine revisions to the RBS IPE Level 1 model since the 1993 IPE submittal 

20 leading up to Revision 5A that was utilized for the SAMA analysis. A listing of the changes 

21 made to the RBS PRA since the original IPE submittal, with corresponding CDF and Large Early 

22 Release Frequency (LERF) results (Entergy 2017a, Entergy 2017b), is summarized in 

23 Table F-3. A comparison of internal events CDF between the 1993 IPE and the Revision 5A 

PRA model indicates a significant decrease in the total CDF (from 1.6 × 10−5 24 per reactor-year to 

2.8 × 10−6 25 per reactor-year). 

26 Table F-3. Summary of Major PRA Models and Corresponding CDF and LERF Results

PRA 

Model Summary of Significant Changes from Prior Model CDF(per year)

LERF (per 

year)

IPE

(1993) 

• Original model developed in response to NRC

Generic Letter 88-20.

1.6 × 10−5

(Note 1)

1.8 × 10−6

(Note 2)

RBS 

PRA R2

• Added new SBO diesel that provides backup power

to Division 1 or 2 emergency direct current (DC)

power during SBO events

• Removed check valve disk between fire protection

water (FPW) system and the service water system

• The FPW injection path was modified from injecting

through low pressure core injection (LPCI) line to

injecting through the shutdown cooling line

• Various enhancements to the model, including

addition of high pressure core spray (HPCS) room

cooler as a failure of HPCS, addition of safetyrelated 480 volt alternating current (VAC) power

models and additional detail to system models

3.6 × 10−6 Not 

Available 

(NA)
F-6

PRA 

Model Summary of Significant Changes from Prior Model CDF(per year)

LERF (per 

year)

RBS 

PRA 

R2A,B,C

(1997)

• Modified instrument air system modeling to separate

service air from instrument air and removed cooling

from the instrument air compressors and

aftercoolers

• Removed standby switchgear room dependence on

control building heating, ventilation, and air

conditioning (HVAC)

• Incorporated the new suppression pool cooling and

cleanup system into the model

• Added partial loss of offsite power logic to the nonsafety related systems

• The HPCS and reactor core isolation cooling (RCIC)

models were updated to allow for the likelihood that

the system is initially aligned to the suppression pool

• The electric power model was extended to include

the 230 kilovolt (KV) system

• The reactor heat removal pump seal failure due to

loss of reactor plant component cooling water

(RPCCW) was removed from the suppression pool

cooling fault tree

2.0 × 10−6 NA

RBS 

PRA 

R2D

• Revised RCIC modeling to reflect the re-routing of

the RCIC injection from the reactor pressure vessel

(RPV) spray nozzle to the feedwater A injection line

and RCIC modifications that locked open the RCIC

turbine lube oil cooler valve and removed the check

valve internals from the turbine exhaust check valve

• Incorporated procedure changes that allow bypass

of RCIC high temperature trip and swapping RCIC

suction flow back to the condensate storage tank

(CST) during a SBO

• Updated selected plant specific data

• Added additional detail to the modeling of offsite

power supplies

• Incorporated modeling of alternate power sources

for the safety-related 4160 VAC buses

2.7 × 10−6 NA

RBS 

PRA R3

• Model event trees were modified as a result of an

analysis that shows containment failure occurs

sooner on loss of all decay heat removal than

previously assumed

• The probability of non-recovery of decay heat

removal was revised because of the shorter

containment failure time

• The probability of non-recovery of offsite power was

changed to include additional industry data

accumulated since Revision 2D

• A recovery action was added to the model to

represent non-recovery of a diesel generator when a

diesel generator failed to start, failed to run, or the

auto start signal failed to start and load the diesel

• The instrument air fault tree was expanded to

include the service air system as backup

9.4 × 10−6 NA
F-7

PRA 

Model Summary of Significant Changes from Prior Model CDF(per year)

LERF (per 

year)

RBS 

R3A

(2002)

• The probability of non-recovery of offsite power was

updated using the convolution method and the

Revision 3 curve for non-recovery of offsite power

• Added recovery action to align the Division III

emergency diesel generator (EDG) to the Division I

or II bus in accordance with a revision to the SBO

procedure

• Two new diesel recoveries were added. The two

additional recovery actions are failure to recover a

diesel in 6 hours and 12 hours.

• A human error event was added to the model to

represent the operator action for verifying the SBO

bypass valve opened during a SBO

3.4 × 10−6 NA

RBS R4 • Included interfacing system loss of coolant accident

(ISLOCA)

• Updated ATWS modeling

• Updated human reliability analysis

• Updated generic and plant failure rates

• Updated loss of offsite power (LOOP) analysis

• Improved common cause failure analysis

• Developed initiating event fault trees

1.9 × 10−6 NA

RBS 

R4A

• Added interim modeling of the control building

electrical switchgear room cooling, modeled as a

single basic event

3.6 × 10−6 2.5 × 10−8

RBS R5

(Note 3)

• Updated plant specific failure and initiating event

data through spring 2009

• Updated and expanded common cause analysis

• Incorporated more recent industry data on

frequency and recovery from LOOP events

• Updated time to core damage and suppression pool

heat up time based on extensive new MAAP

analysis

• Updated human reliability analysis to incorporate

refined time to core damage and procedure changes

• Increased level of detail in system models

• Removed credit for containment venting through

3-inch vent path based on refined thermal hydraulic

calculations

• Accounted for RCIC depressurization for small

break loss of coolant accident (LOCA) scenarios

2.6 × 10−6 2.5 × 10−8
F-8

PRA 

Model Summary of Significant Changes from Prior Model CDF(per year)

LERF (per 

year)

RBS 

R5A

(Note 4)

• Enhanced and increased rigor in the modeling of

long-term loss of decay heat removal recovery. This

resulted in an increase in the long-term decay heat

removal (DHRLT) non-recovery probability but

allowed for application of procedural recoveries for

certain circumstances.

• Enhanced and increased rigor in the modeling of the

loss of normal service water initiating event, by

crediting the fact that successful initiation of standby

service water would prevent a plant scram

• Incorporated selected findings from the RBS PRA

Peer Review into the model

• Captured changes to the service water cooling

(SWC) fan and heat exchanger success criteria,

which had previously been incorporated into the

fault tree used in the online risk model

• Constructed a single fault tree for quantification of

both CDF and LERF

2.8 × 10−6 2.3 × 10−8

RBS R6

(Note 5)

• Incorporated extended loss of AC power (ELAP)

procedure and diverse and flexible coping strategies

(FLEX) support guidelines and FLEX equipment into

the PRA model

• Incorporated a model for containment venting based

on deflating containment airlock seals based on

procedure enhancements made in response to PRA

Revision 5 risk insights

• Updated control building cooling logic reflecting new

information developed on building heatup and

equipment survivability which greatly decreased the

risk contribution to CDF from the control building

HVAC and control building chilled water systems

• Improved RCIC heatup calculations performed in

conjunction with the FLEX project which showed

significantly less room heatup than previous

calculations

• Credited the condensate transfer systems as an

injection source for the reactor pressure vessel, per

emergency operating procedures

1.1 × 10−6 NA

Note 1. Truncation values varied from 1 x 10-9 per year for IPE to 1 x 10-12 per year for RBS R5A CDF. 

Note 2. Frequency of gross containment failure.

Note 3. R5 was reviewed in the 2011 BWR Owners Group PRA peer review.

Note 4. R5A is an interim revision used for the SAMA analysis.

Note 5. R6 is a full revision completed after the SAMA analysis, and was used to respond to NRC staff RAIs. 

1 The ER indicates that the PRA model used for the SAMA analysis reflects the RBS as-built, as2 operated configuration as of April 30, 2009, and that no other planned major plant modifications 

3 which could adversely impact the SAMA analysis results have been identified. In NRC staff 

4 RAIs (NRC 2017a), Entergy was asked to clarify the intent of this statement relative to any 

5 changes made to plant operations, procedures and/or physical modifications in the eight years 

6 since the stated configuration date, and any planned future changes and their potential impact 

7 on the SAMA analysis as well as the impact of updated plant data since 2009. In its response 

8 to the RAIs (Entergy 2017b), Entergy explained that PRA Revision 5A used for the SAMA 
F-9

1 analysis was an "interim" revision, not a full periodic revision, and so data and initiating event 

2 frequencies are from PRA Revision 5. Furthermore, PRA Revision 6, a full periodic revision that

3 was approved by Entergy subsequent to the SAMA analysis, incorporated updated plant data 

4 through May 2014 as well as significant plant changes since PRA Revision 5. Entergy reported 

that the Revision 6 full power internal events CDF (without internal flooding) is 1.07 × 10-6 5 per 

year compared to 2.60 × 10-6 per year for the R5 last periodic update and 2.79 × 10-6 6 per year 

7 for R5A used in the SAMA analysis. Entergy concluded that since the changes made to plant 

8 operations, procedures and physical modifications in the five years between the Revision 5A 

9 configuration date and the Revision 6 configuration date resulted in a CDF reduction, and did 

10 not increase the CDF of important sequences, they would not adversely affect the SAMA 

11 analysis. Entergy also indicated that incorporation of updated plant data from 2009 to 2014 

12 resulted in a reduction in the CDF contribution from most of the important sequences from the 

13 Revision 5A model to the Revision 6 model. However, the frequency of the Loss of the

14 Feedwater / Condensate System initiator did increase from Revision 5A to Revision 6, which 

15 contributed to an increase in the CDF contribution from this initiator. Entergy concluded that this 

16 increase would not result in additional cost-beneficial SAMAs (Entergy 2017b). 

17 In response to these same RAIs, Entergy also described the plant procedures that establish the

18 RBS engineering change process, with respect to assessing the impact on the PRA of 

19 engineering changes, and the PRA maintenance and update process. PRA Model Change 

20 Requests (MCRs) document items to be assessed against the plant PRA to determine impacts 

21 to the PRA model. MCRs are graded to determine the timing of making necessary changes to 

22 the PRA model. Entergy indicated that the MCRs initiated in the three years since the 

23 Revision 6 PRA configuration date do not include any existing or planned changes that would 

24 adversely affect the SAMA analysis (Entergy 2017b). 

25 The NRC staff considered the peer reviews and other assessments performed for the RBS PRA 

26 and the potential impact of the review findings on the SAMA evaluation. The most relevant of 

27 these is the July 2011 peer review of the 2011 RBS R5 model against the requirements of the 

28 American Society of Mechanical Engineers (ASME)/ American Nuclear Society (ANS)

29 Probabilistic Risk Assessment (PRA) standard and the requirements of Regulatory Guide 1.200, 

30 Revision 2 (NRC 2009). This peer review was a full-scope review including internal flooding 

31 and LERF. Of the applicable supporting requirements, more than 85 percent were satisfied at 

32 Capability Category II or greater, with the majority of the supporting requirements not met 

33 relating to internal floods. The peer review report included 59 findings. Seven of these findings 

34 were against LERF-related supporting requirements. The resolutions of a number of these 

35 findings were incorporated in the RBS R5A PRA model used for the SAMA analysis 

36 (Entergy 2017a). As discussed below, the internal flood model has been updated and revised 

37 to address many of the internal flood findings. Also, as discussed below, the LERF model has 

38 been superseded by the full Level 2 model developed for the SAMA analysis.

39 ER Table D.1-13 lists the 18 peer review findings that remain open, with their disposition and 

40 impact on the SAMA analysis. Thirteen of the 18 open findings are stated to be related to 

41 documentation. Entergy concluded that the resolution of all 18 would have negligible or no 

42 impact on the SAMA analysis.

43 In response to an NRC staff RAI (Entergy 2017b), Entergy confirmed that no changes have 

44 been made to the RBS model used in the SAMA analysis since the peer review that would 

45 constitute an upgrade as defined by the PRA standard, ASME/ANS RA-Sa-2009 

46 (ASME/ANS 2009), as endorsed by RG 1.200, Revision 2 (NRC 2009). Entergy does indicate 
F-10

1 that the SAMA analysis utilizes a full-scope Level 2 analysis instead of the simplified LERF 

2 analysis incorporated in the Revision 5A model. This is discussed further in Section F.2.2.3.

3 The ER provides a brief discussion of the Entergy risk management process that ensures that 

4 the applicable PRA model is an accurate reflection of the as-built and as-operated plant as 

5 defined in the Entergy fleet procedure EN-DC-151, "PSA Maintenance and Update.” This 

6 process includes routinely performing the following activities:

7 • Design changes and procedure changes are reviewed for their impact on the PRA

8 model. Potential PRA model changes resulting from these reviews are entered into

9 the MCR database, and a determination is made regarding the significance of the

10 change with respect to the current PRA model.

11 • New procedures and revisions to existing procedures that are relevant to the PRA

12 are reviewed for their impact on the PRA model.

13 • New engineering calculations and revisions to existing calculations are reviewed for

14 their impact on the PRA model.

15 • Plant specific initiating event frequencies, failure rates, and maintenance

16 unavailability are updated regularly. Procedure EN-DC-151 suggests an update

17 frequency of approximately every four years.

18 • Industry standards, experience, and technologies are periodically reviewed to ensure

19 that any changes are appropriately incorporated into the models.

20 Given that the RBS internal events (excluding internal floods) Level 1 PRA model has been peer 

21 reviewed and the peer review findings were all addressed, that Entergy has in place procedures 

22 to assure the technical quality of the PRA, and that Entergy has satisfactorily addressed the 

23 NRC staff’s questions regarding the PRA, the NRC staff finds the RBS Level 1 PRA model to be 

24 reasonable and acceptable for the SAMA analysis and concludes that the internal events 

25 Level 1 PRA model is of sufficient quality to support the SAMA evaluation.

26 F.2.2.2 External Events

27 NEI 05-01A allows the use of an external events multiplier on the maximum benefit and on the 

28 upper bound estimated benefits for individual SAMA candidates during the Phase II screening if 

29 external events are not included in the PRA utilized for SAMA analysis (NEI 2005). As stated 

30 above, the RBS PRA that was utilized for the SAMA analysis does not include external events. 

31 The SAMA submittal cites the fire PRA developed for the RBS IPEEE to address the CDF due 

32 to fire events, a standalone analysis of internal floods to address the CDF due to internal floods, 

33 a separate estimate of seismic events CDF based on the approach used by NRC staff in its 

34 safety/risk assessment for Generic Issue (GI) 199 (NRC 2010) but with a more realistic plant 

35 specific fragility, and the RBS IPEEE to assess the impact of other (high winds, floods, and 

36 other) external events.

37 The final RBS IPEEE was submitted in 1995 (Entergy 1995), in response to Supplement 4 of 

38 GL 88–20 (NRC 1991a). No fundamental weaknesses or vulnerabilities to severe accident risk 

39 in regard to the external events were identified in the RBS IPEEE. However, five enhancements 

40 related to fire events were identified. All have been implemented (Entergy 2017b). In the NRC 

41 staff's safety evaluation of the RBS IPEEE (NRC 2001), the staff stated that “[o]n the basis of 

42 the IPEEE review, the NRC staff concludes that the River Bend Station IPEEE process is 

43 capable of identifying the most likely severe accidents and severe accident vulnerabilities, and 

44 therefore, that River Bend Station has met the intent of Supplement 4 to GL 88-20." 
F-11

1 Seismic Events

2 As discussed in the ER, the RBS IPEEE seismic analysis was a reduced-scope seismic margins 

3 assessment (SMA) following the NRC IPEEE guidance (i.e., NRC 1991a, NRC 1991b). The 

4 SMA approach is deterministic in nature and does not result in probabilistic risk information.

5 Based on the results of the licensee's seismic walkdown conducted for the IPEEE, the licensee 

6 found that all components, structures, and systems reviewed were seismically rugged for the 

7 design basis seismic loading.

8 Following the accident at the Fukushima Dai-ichi Nuclear Power Plant, Entergy conducted 

9 additional seismic walkdowns at RBS. The NRC staff concluded that the licensee had, through 

10 the implementation of the walkdown guidance activities and in accordance with plant processes 

11 and procedures, verified the plant configuration with the current seismic licensing basis; 

12 addressed degraded, nonconforming, or unanalyzed seismic conditions; and verified the 

13 adequacy of monitoring and maintenance programs for protective features. Furthermore, the 

14 NRC staff confirmed that no immediate safety concerns were identified (NRC 2014a).

15 In its review of Entergy's response to the Fukushima Near Term Task Force Recommendation 

16 2.1 for a Seismic Hazard and Screening Report, the NRC staff confirmed that no further 

17 response or regulatory actions associated with the 50.54(f) letter review of Phase 1 or Phase 2 

18 of the Near-term Task Force Recommendation 2.1 is required for RBS (NRC 2016a). 

19 The NRC staff also notes that Entergy submitted its Seismic Mitigating Strategies Assessment 

20 Report in August 2016, which concluded that the flexible coping strategies (FLEX) developed, 

21 implemented, and maintained in accordance with NRC Order EA-12-049 can be implemented 

22 considering the impacts of the re-evaluated seismic hazard and that no further seismic 

23 evaluations were necessary (Entergy 2016a). In its review, the NRC staff concluded that 

24 sufficient information has been provided to demonstrate that the licensee's plans for the 

25 development and implementation of guidance and strategies under Order EA-12-049 

26 appropriately address the reevaluated seismic hazard information stemming from the 50.54(f) 

27 letter (NRC 2016b). 

28 Since RBS was a reduced-scope seismic plant, the method to address seismic risk for the 

29 IPEEE focused on walkdowns of success path equipment and systems. Thus, no seismic core 

30 damage estimate was developed. For the purposes of incorporating the impact of a SAMA on 

31 seismic risk, Entergy developed a seismic CDF based on the approach in NRC’s Safety/Risk 

32 Assessment for GI-199, “Implications of Updated Probabilistic Seismic Hazard Estimated in 

33 Central and Eastern United States on Existing Plants” (NRC 2010). The NRC assessment 

34 conservatively determined that the weakest link model seismic core damage frequency (SCDF) 

for RBS is 2.5 × 10-5 35 per reactor-yr. Entergy estimated the seismic risk using the same methods 

36 and hazard curves as the NRC used, with the exception of using more realistic plant-specific 

37 fragility values instead of the more conservative values used by the NRC. Entergy’s more 

realistic SCDF was determined to be 2.5 × 10-6 38 per reactor-yr. Entergy further indicated that this 

estimate is also considered conservative since the SCDF would be 8.3 × 10-7 39 per reactor-yr if 

40 the 2010 Electric Power Research Institute (EPRI) seismic hazard curves were used. The more 

realistic SCDF of 2.5 × 10-6 41 per reactor-yr was used in the SAMA analysis (Entergy 2017a).

42 Entergy was asked in an NRC staff RAI to provide more information on, and support for, these 

43 more realistic fragility values (NRC 2017a). Entergy indicated that plant-specific fragilities were 

44 calculated using two different methods, the hybrid method and the separation of variables 

45 method. The results from the separation of variables method was used for the RBS SAMA
F-12

1 analysis because it resulted in more conservative fragilities. The factors considered in the 

2 separation of variables method included strength, inelastic energy absorption, spectral shape, 

3 damping, wave incoherence, modeling, directional components, and modal combination.

4 Realistic (but still conservative) values were applied for each of these factors. This resulted in a 

5 more realistic plant fragility than was used by the NRC in GI-199, which utilized the Safe 

6 Shutdown Earthquake (SSE) Peak Ground Acceleration (PGA) as a measure of the high 

7 confidence of low probability of failure for determining the plant seismic fragility (Entergy 2017b). 

8 Both the hybrid method and the separation of variables methods are acceptable methods for 

9 calculating seismic fragilities per the EPRI Seismic Evaluation Guidance (EPRI 2012), which is 

10 endorsed by the NRC (NRC 2012a).

11 Considering that the revised seismic CDF is based on realistic seismic plant fragility estimates

12 calculated using NRC-endorsed guidance and on conservative seismic hazard curves, the NRC 

13 staff concludes that the seismic CDF, as discussed above, is acceptable for use in the 

14 development of the external events multiplier.

15 Fire Events

16 As discussed in the ER, Entergy performed a Fire PRA to meet the objectives of the IPEEE. 

17 The methodology was based on a combination of EPRI Fire-Induced Vulnerability Evaluation

18 (FIVE) (EPRI 1992) methods and the PRA methods in the EPRI draft “Fire Risk Implementation 

19 Guide” (EPRI 1994). Overall, the method was a progressive screening analysis. If at any time 

in the screening a fire area dropped below 1 × 10-6 20 per reactor-yr, the fire area was screened 

21 out. Areas were screened from further analysis when they could be shown to be of low risk 

22 significance. The models and methods used in the internal events IPE served as the basis for 

23 quantification of the conditional core damage probabilities (CCDPs). The CDF of the areas that 

did not screen totaled 2.25 × 10-5 24 per reactor-yr in the original IPEEE submittal (Entergy 1995).

25 Table D.1-10 of the ER, as shown in Table F-4, provides a listing of the fire areas and their 

26 contribution to the fire CDF for the seven areas not screened out. The dominant areas 

27 contributing to the fire CDF are the control room, Division 1 standby switchgear room and the 

28 control room ventilation room on elevation 116 feet.

29 Table F-4. Fire Areas Included in Final Phase of IPEEE Screening

Fire Area Description Total Compartment 

CDF (per reactor-yr)

C-25 Control Room 4.87 × 10-6

C-15 Division 1 Standby Switchgear Room 4.75 × 10-6

C-17 Control Room Ventilation Room EL. 116’ 4.56 × 10-6

C-4 Air Conditioning Unit (ACU) West Room 3.31 × 10-6

AB-2/Z-2 HPCS & HPCS Hatch Area 2.23 × 10-6

ET-1 B-Tunnel East 1.48 × 10-6

AB-1/Z-4 Auxiliary Building: West Side Crescent Area 1.26 × 10-6

Total Fire CDF 2.25 × 10-5

30 The RBS IPEEE fire analysis was reviewed by the NRC staff as part of the IPEEE review 

31 (NRC 2001). The RBS IPEEE fire analysis review concluded that two additional fire areas 

would not be screened out and the fire CDF would be increased to 2.5 × 10-5 32 per reactor-yr. 

33 The impact of this on the external event multiplier is discussed below.
F-13

1 While no vulnerabilities or improvements with respect to fire were identified, the IPEEE submittal 

2 identified five insights or enhancements. The insights were primarily related to improvements in 

3 fire related procedures and the selection of equipment credited in the RBS Safe Shutdown 

4 Analysis. All have been implemented (Entergy 2017b).

5 In the ER, Entergy indicates that since a fire risk assessment utilizes the internal events model 

6 in the determination of the fire CDF, the results are impacted by changes to the internal events 

7 model. As discussed above, the IPE model has been updated many times. The Revision 5A 

internal events CDF used for the SAMA analysis is 2.79 × 10-6 8 per reactor-yr compared to the 

IPE CDF, on which the IPEEE fire CDF is based, of 1.55 × 10-5 9 per reactor-yr. This is more 

10 than a factor of five less than the original IPE CDF and it might be reasonably assumed that an 

11 update of the fire PRA analysis with the Revision 5A internal events model would result in a fire 

CDF one-fifth of the original fire CDF (4.5 × 10-6 12 per reactor-yr). This would account for updated 

13 modeling of the internal events portion of the model that was used in the fire analysis, but would 

14 not necessarily address all of the conservatisms inherent in the FIVE methodology. Entergy 

15 concluded that even though a reduction by a factor of 5 in the fire CDF may be justifiable, the 

RBS fire CDF was reduced by a more conservative factor of 2.5, to 9.0 × 10-6 16 per reactor-yr for 

17 the SAMA analysis (Entergy 2017a).

18 As discussed above, in response to an NRC staff RAI, Entergy indicated that the current 

Revision 6 PRA has an internal events CDF of 1.07 × 10-6 19 per reactor-yr. This would indicate 

20 that there might be even further conservatism in the fire CDF used in the SAMA analysis 

21 (Entergy 2017b).

22 Considering that the RBS fire PRA model has been reviewed by the NRC staff as part of the 

23 IPEEE program, and that accounting for reductions in the internal events CDF due to plant 

24 improvements was done in a conservative manner, the staff concludes that the fire PRA model, 

25 as discussed above, is appropriate for determining the external events multiplier in the SAMA

26 and provides an acceptable basis for identifying and evaluating the benefits of SAMAs.

27 Internal Floods

28 Since the RBS Level 1 model does not include contributions from internal flooding hazards, 

29 Entergy cited an earlier internal flooding analysis that was revised and updated in 2012 for use 

30 in the SAMA analysis. Table D.1-11 of the ER, as shown in Table F-5, provides the results of 

the internal flood analysis. The total internal flood CDF is 4.97 × 10-6 31 per reactor-yr with floods 

32 in the auxiliary building dominating the result (Entergy 2017a). 

33 Table F-5. Internal Flooding CDF by Building

Building Building CDF

(per reactor-yr)

Auxiliary Building 2.91 × 10-6

Control Building 6.34 × 10-7

Diesel Building 7.95 × 10-7

Fuel Building 4.08 × 10-8

Radwaste Building 3.65 × 10-10

Turbine Building 4.25 × 10-8

Tunnels 5.46 × 10-7

TOTAL 4.97 × 10-6
F-14

1 Entergy was asked in an RAI to identify the internal events model used in this updated flood 

2 analysis, characterize it with respect to the internal events model used in the SAMA analysis 

3 (RBS 5A), and assess the impact of any difference between the two models (NRC 2017a). 

4 Entergy responded that the 2012 internal flooding fault tree model is based on the RBS 

5 Revision 5 PRA model, that the Revision 5A model CDF is 7 percent higher than the Revision 5 

6 CDF, and that the differences between the Revision 5 and 5A models are not expected to have 

7 significant impact on the internal flooding overall CDF (Entergy 2017b). Entergy also stated that 

8 the internal flooding initiators are mapped to transient initiators and associated logic in the 

9 Revision 5 fault tree in order to create flooding sequences, and that the transient accident logic 

10 in the Revision 5A model is essentially the same as the transient logic in Revision 5. 

11 In addition, Entergy indicated that Revision 6 of the RBS PRA was approved on 

October 5, 2017, with an overall CDF of 3.03 × 10-6 12 per year and that the internal flooding 

contribution to this overall CDF is 1.96 × 10-6 13 per year, which is approximately 40 percent of the 

14 Revision 5 internal flooding CDF (Entergy 2017b). Based on this result, Entergy concluded that 

15 the internal flooding CDF used in the SAMA analysis is conservative.

16 As discussed above, the July 2011 peer review of the RBS R5 PRA model was a full-scope 

17 review that included internal flooding. Entergy indicates that the majority of the supporting 

18 requirements assessed as "not met" in the peer review were related to internal flooding. 

19 Entergy was asked in an NRC staff RAI to discuss the results of the self-assessment of the 

20 2012 internal flood model as well as the status of meeting those requirements determined to be 

21 "not met" in the 2011 peer review and, for any internal flood requirements "not met," to discuss 

22 the impact on the SAMA analysis (NRC 2017a). Entergy responded that during the 2011 peer 

23 review, 18 of the 59 Findings were related to the internal flooding PRA element and that 14 of 

24 these 18 Findings were considered closed by the update to the internal flooding analysis 

25 approved in 2012, leaving four Findings open to be resolved as part of PRA Revision 6

26 (Entergy 2017b). 

27 Entergy further indicated in the RAI response that due to changes in the approach for the 

28 internal flooding analysis performed for Revision 6, and due to the number of original findings 

29 from the 2011 peer review, Entergy determined the Revision 6 internal flooding PRA should be 

30 considered an upgrade. As a result, it was the subject of a focused-scope BWR Owner’s Group 

31 (BWROG) PRA peer review conducted in September 2017. While the focused-scope peer 

32 review report has not been issued, preliminary results included one "Not Met" requirement 

33 related to documentation of sources of model uncertainty, and eight Findings related to internal 

34 flooding. Entergy concluded that none of these findings are expected to appreciably impact the 

35 results of the internal flooding PRA. Further, since the Revision 6 internal flooding model is a 

36 complete upgrade, findings from the focused-scope peer review are unrelated to the internal 

37 flooding model used in the SAMA analysis (Entergy 2017b).

38 Entergy states that the dominant contributors to internal flood risk in the Revision 6 model were 

39 examined for possible mitigation, but no additional SAMAs were postulated. None of the 348 

individual internal flooding scenarios exceeded 1.0 x 10-6 per year for CDF or 1.0 x 10-8 40 per year 

41 for LERF (Entergy 2017b). 

42 Considering that the 2012 internal flooding analysis PRA model used for the SAMA assessment 

43 has been peer reviewed, that resolution of open findings would not be expected to impact the 

44 internal flooding CDF or the SAMA analysis, that the more current Revision 6 internal flooding 

45 model yields a CDF that is 40 percent of that used in the SAMA analysis, and that an 

46 examination of the dominant contributors to internal flood risk in the Revision 6 model did not 
F-15

1 result in the identification of additional SAMAs, the NRC staff concludes that the internal 

2 flooding analysis provides an acceptable basis for identifying and evaluating internal flooding 

3 SAMAs and that the internal flooding CDF is acceptable for use in the development of the 

4 external events multiplier.

5 High Winds, Floods, and Other External Events

6 Entergy explained in the ER that the conclusion of the RBS IPEEE was that RBS meets the 

7 applicable NRC Standard Review Plan (SRP) requirements for high winds, floods, and other 

8 external events. Based on these IPEEE results, and that no adverse findings were identified 

9 from walkdowns, Entergy concluded that the contribution to CDF from external hazards is less 

than 1 x 10-6 10 per reactor-yr and that, therefore, these events are not significant contributors to 

11 external event risk.

12 Following the accident at the Fukushima Dai-ichi Nuclear Power Plant, Entergy conducted 

13 additional external flood walkdowns as requested by NRC's 10 CFR 50.54(f) letter 

14 (NRC 2012b). Based on its review of Entergy's submittal, the NRC staff concluded that the 

15 licensee's implementation of the flooding walkdown methodology meets the intent of the 

16 walkdown guidance and that the licensee, through the implementation of the walkdown 

17 guidance activities and, in accordance with plant processes and procedures, verified the plant 

18 configuration with the current flooding licensing basis; addressed degraded, nonconforming, or 

19 unanalyzed flooding conditions; and verified the adequacy of monitoring and maintenance. 

20 Furthermore, the NRC staff noted that the licensee's walkdown results, which were verified by 

21 the staff's inspection, identified no immediate safety concerns (NRC 2014b).

22 Enclosure 2 to the NRC staff’s 10 CFR 50.54(f) request for information (NRC 2012b) requested 

23 licensees to re-evaluate flood-causing mechanisms using present-day methodologies and 

24 guidance. Concurrently with the re-evaluation of flooding hazards, licensees were required to 

25 develop and implement mitigating strategies in accordance with NRC Order EA-12-049, 

26 "Requirements for Mitigation Strategies for Beyond-Design-Basis External Events" 

27 (NRC 2012c).

28 Entergy submitted the RBS reevaluated flood hazard assessment on March 12, 2014 

29 (Entergy 2014a), and the NRC staff provided its assessment of the reevaluation on 

30 August 31, 2016 (NRC 2016c). In its assessment, the NRC staff confirmed the licensee's 

31 determination that (a) the reevaluated flood hazard results for local intense precipitation (LIP) 

32 and for streams and rivers (West Creek probable maximum flood (PMF) and Mississippi River 

33 PMF) are not bounded by the current design basis flood hazard and (b) that additional 

34 assessments of plant response need to be performed for LIP and for rivers and streams flood35 causing mechanisms.

36 Entergy submitted the flooding mitigating strategies assessment (MSA) for RBS on 

37 October 24, 2016 (Entergy 2016b), and the NRC staff provided its assessment of the Entergy 

38 submittal on May 2, 2017 (NRC 2017b). The NRC staff assessment confirmed that the 

39 licensee's flood hazard MSA was performed consistent with applicable guidance. Further, 

40 based on the licensee's appropriate hazard characterization, the methodology used in the MSA 

41 evaluation, and the description of its combination of strategies (i.e., current FLEX strategy and 

42 modified FLEX strategy), the staff concluded that the licensee has demonstrated that the 

43 mitigation strategies, if appropriately implemented, are reasonably protected from reevaluated 

44 flood hazard conditions for beyond-design-basis external events. 
F-16

1 On June 28, 2017, Entergy submitted its focused evaluation of the external flooding 

2 mechanisms for which the reevaluated flooding hazards are not bounded by the current design 

3 basis (Entergy 2017c). Entergy's evaluation concluded that permanent passive protection is in 

4 place for the PMF on West Creek, for the PMF on the Mississippi River, and for the LIP 

5 flood-causing mechanisms. The NRC staff’s evaluation of this submittal concluded that the 

6 licensee has demonstrated that effective flood protection exists for LIP and for streams and 

7 rivers flood mechanisms during a beyond-design-basis external flooding event at RBS

8 (NRC 2017c).

9 The NRC staff noted in an RAI that this focused evaluation was a deterministic (that is, not a 

10 probabilistic) evaluation and asked Entergy to provide a discussion of these external flood 

11 hazards and the associated impact on RBS to support the assertion that they would not 

12 contribute to the external events multiplier nor lead to any cost-beneficial SAMAs (NRC 2017). 

13 Entergy responded that the RBS external flooding focused evaluation demonstrated that there 

14 was adequate physical margin for the LIP hazard and for the PMF hazards on West Creek and 

15 the Mississippi River. Entergy further noted that the analyses used several conservative inputs, 

16 assumptions, and/or methods in the reevaluation of the hazards, and that conservative 

17 assumptions concerning both the magnitude of rainfall events and the response of local RBS 

18 mitigating or aggravating site features were identified (Entergy 2017b).

19 Considering that permanent passive protection is in place at RBS for these conservatively 

20 analyzed floods and that the NRC staff has concluded that these protective measures provide 

21 effective measures for protection against beyond-design-basis external flooding events, that the 

22 NRC staff has concluded that flooding mitigation strategies implemented at RBS are reasonably 

23 protected from reevaluated flood hazard conditions for beyond-design-basis external events, 

24 and that the contribution to CDF from high winds and other external events is negligible, the 

25 NRC staff concludes that not including a CDF contribution for these hazards in the development 

26 of the external events multiplier is acceptable. Furthermore, the NRC staff concludes that the 

27 need for any mitigating action for external floods is being addressed by the NRC Order 

28 EA-12-049 program as a current operating issue and therefore no additional external flooding 

29 SAMAs need to be considered under license renewal.

30 External Events Multiplier

31 As stated in the ER (Entergy 2017a), a multiplier of 7 was used to adjust the internal event risk 

32 benefit associated with a SAMA to account for external events and internal flooding events. 

This multiplier was based on a total internal and external events CDF of 1.93 x 10-5 33 per 

reactor-yr, which is the sum of the CDF for internal events of 2.79 × 10-6 34 per reactor-yr, the CDF 

for seismic events of 2.5 × 10-6 per reactor-yr, the CDF for fire events of 9.0 × 10-6 35 per 

reactor-yr, and the CDF for internal flood events of 4.97 × 10-6 36 per reactor-yr. The external 

events multiplier was therefore calculated by Entergy to be 6.9 (1.93 × 10-5 37 per reactor-yr / 

2.79 × 10-6 38 per reactor-yr). Entergy conservatively used a value of 7 in the SAMA analysis.

39 The sources of these external event CDF values are discussed in the previous sections. For 

the fire CDF, the results of the RBS fire IPEEE PRA (2.25 × 10-5 40 per reactor-yr) was modified by 

41 Entergy to account for the impact of the lower internal events CDF used for the SAMA analysis 

42 compared to that on which the IPEEE fire CDF was based. Entergy concluded that even though 

43 a reduction by more than a factor of 5 (actual ratio of IPE CDF to Revision 5A CDF is 

1.55 × 10-5 per reactor-yr / 2.79 × 10-6 44 per reactor-yr = 5.55) in the fire CDF may be justifiable, 

the RBS fire CDF was reduced by a factor of 2.5, to 9.0 × 10-6 45 per reactor-yr for the SAMA 

46 analysis (Entergy 2017a).
F-17

1 As discussed above, the NRC staff review of the RBS IPEEE fire analysis concluded that the 

total fire CDF should be 2.5 × 10-5 per reactor-yr versus the IPEEE submittal value of 2.25 × 10-5 2 

3 per reactor-yr. The NRC staff has evaluated the impact of this difference on the SAMA

4 assessment. If the same methodology used by Entergy to determine the fire CDF contribution 

5 to the external events multiplier (the IPEEE fire CDF divided by 2.5) is used, the fire CDF would 

increase from 9.0 × 10-6 per reactor-yr to 1.0 × 10-5 6 per reactor-yr, or an 11 percent increase in 

7 fire CDF. If this value were used to determine the external events multiplier, the calculated 

8 value would be 7.26 versus the value used in SAMA analysis of 7.0, or only a 3.7 percent 

9 increase. Considering the assumptions and uncertainties associated with this analysis, and that 

10 the current Revision 6 internal events CDF is about 40 percent of that used for the SAMA 

11 analysis, the NRC staff considers the external events multiplier of 7.0 to be reasonable for the 

12 SAMA analysis.

13 F.2.2.3 Level 2 Fission Product Release Analysis

14 The NRC staff reviewed the general process used by Entergy to translate the results of the 

15 Level 1 PRA into containment releases, as well as the results of the Level 2 analysis, as 

16 described in the ER and in responses to staff RAIs (Entergy 2017b). Entergy indicated that the 

17 full Level 2 model used for the SAMA analysis was created specifically for the SAMA analysis 

18 since the RBS R5A included only a LERF model. As indicated in ER Table D.1-12, the full level 

2 LERF result of 2.3 x 10-8 19 per reactor-year was very close to the simplified LERF-only model 

LERF result of 2.5 × 10-8 20 per reactor-year. 

21 Per the ER (Entergy 2017a), the Level 2 analysis is linked to the Level 1 model by extending the 

22 model to include the CET which characterizes the post core melt accident response. The CET 

23 considers the influence of physical and chemical processes on the integrity of the containment 

24 and on the release of fission products. Each Level 1 CDF accident sequence was grouped into 

25 one of six groups for use in the Level 2 analysis. These groups provide the entry conditions for 

26 the Level 2 analysis. A Level 1 sequence group, or a combination of groups, is directly linked to 

27 the fault tree logic representing the appropriate CET Level 2 sequence for evaluation.

28 The top events of the CET represent events that may have a significant impact on the ability of 

29 the containment to remain intact and contain the fission products released from the core by the 

30 core damage accident. The top events describe either phenomenological events or processes 

31 of severe accident response, potential recovery or mitigating actions, or containment system 

32 responses that impact the severe accident progression. The CET events and their respective 

33 nodal equations are related to additional fault tree logic to ensure complete linking of all 

34 system-related interactions. A list of the nine CET functional events and their descriptions used 

35 for the Level 2 analysis is provided in ER Table D.1-6 (Entergy 2017a). The NRC staff notes 

36 that the CET nodes or functional events are relatively complex and may involve more than 

37 simple success or failure. A single CET is used with nodes evaluated by fault tree logic which, 

38 in some cases, are representations of decomposition event trees. SBO and non-SBO Level 1 

39 sequences are processed by the single CET.

40 The CET end points represent the outcomes of possible containment accident progression 

41 sequences with each end point representing a complete sequence from initiator to release to 

42 the environment. Associated with each CET end point or end state is an atmospheric 

43 radionuclide source term including the timing, magnitude, and other conditions associated with 

44 the release. Because of the large number of CET end points, they are grouped into release 

45 categories. Entergy defined 14 release categories, labeled source term categories (STCs). 

46 One release category is for no containment failure, four represent large early releases, one 
F-18

1 represents a large late rupture of containment due to hydrogen effects with the remaining eight 

2 representing containment penetration failures with various combinations of containment status 

3 at the time of core damage, core debris cooling successful/unsuccessful, and auxiliary building 

4 scrubbing successful/unsuccessful.

5 In response to NRC staff RAIs regarding containment failure modes and the definition of the 

6 STCs (NRC 2017a), Entergy indicated that a detailed, plant-specific evaluation of the RBS 

containment internal pressure fragility was performed in 1992 (Entergy 2018). Median and 95th 7 

8 percentile non-exceedance pressures were calculated for all relevant containment penetrations 

9 and for the regions of the containment structure itself. The analysis determined that as 

10 containment pressurizes, leakage failures of containment penetrations (e.g., the containment 

11 hatch, containment dome ventilation opening and drywell equipment hatch/personnel door) 

12 occur at much lower pressures than the large containment rupture failure mechanisms. STCs 7 

13 through 14 involve sequences with gradual pressurization of containment, and the MAAP 

14 analyses predict releases from the leakage failures of containment. The pressures do not reach 

15 the level of containment rupture. STCs 5 and 6 represent large ruptures of containment due to 

16 rapid pressure loading caused by hydrogen explosions. 

17 Entergy indicated that for gradual pressurization of the containment, the MAAP analyses 

18 showed a peak containment pressure of 63.7 psig. The fragility analysis calculated a median 

large containment rupture pressure of 107 psig and a 95th 19 percentile non-exceedance large 

20 containment rupture pressure of 86 psig. Since the peak containment pressure reached in the 

MAAP analyses using the median pressure distribution is well below both the median and 95th 21

22 percentile non-exceedance large containment rupture pressures, Entergy concluded that the 

23 MAAP analyses have appropriately considered the potential containment failure modes and that 

24 further MAAP analyses to consider additional uncertainty in the pressure distribution from the 

25 containment fragility analysis would not result in identification of additional cost-beneficial 

26 SAMAs (Entergy 2018). Based on the margin between the calculated peak containment 

pressure and the calculated median and 95th 27 percentile non-exceedance large containment 

28 rupture pressures, the NRC staff concluded that the applicant’s containment failure analysis is 

29 acceptable for use in the SAMA analysis.

30 The 14 STCs and their frequencies are provided in ER Table D.1–8. The frequency of each 

31 STC is the sum of the frequencies of the various CET end points assigned to that CET. As 

32 discussed in the ER, the Level 2 CET analysis splits up most of the Level 1 CDF sequences into 

33 several additional sequences or endpoints. The effect of truncation performed during the 

34 quantification results in loss of some of the Level 1 sequences and therefore, at the same 

35 truncation, a lower total STC frequency compared to the CDF. Entergy assigned this 

36 unaccounted for release frequency to the intact category, STC 1. 

37 In response to an NRC staff RAI concerning the appropriateness of this assignment 

38 (NRC 2017a), Entergy indicated that the difference between the internal events CDF

(2.79 × 10-6 per year) and the total frequency of the internal events Level 2 STCs (2.58 × 10-6 39

per year) is 2.09 × 10-7 40 per year, or 8.1 percent of the CDF (Entergy 2017b). Entergy estimated 

41 that if this extra frequency were assigned to other STCs, the best estimate increase in maximum 

42 averted cost risk (MACR) would be 4.7 percent. Entergy concluded that conservatisms in 

43 assessing the benefit of each SAMA would compensate for a change of this small magnitude 

44 and that, therefore, redistribution of the truncation difference proportionally to other STCs would 

45 not change the conclusions of the SAMA analysis (Entergy 2017b). The NRC staff reviewed the 

46 cost and benefit inputs to the assessment of any SAMAs where an increase in benefit of this 
F-19

1 magnitude would make the SAMA beneficial and concluded that no new cost-beneficial SAMAs 

2 would be identified.

3 Per the ER (Entergy 2017a), MAAP 4.0.7 was used to determine the progression of the various 

4 Level 2 sequences and the resulting timing and magnitude of fission product releases. Entergy 

5 stated that many different accident sequences were analyzed using MAAP, primarily focused on 

6 the significant core damage sequences. Significant sequences were defined to be those that 

7 contribute to the top 95 percent of CDF and any sequence that individually contributes at least 

8 one percent to the total CDF. A representative MAAP case was then chosen for each STC. 

9 The ER provided a discussion of the basis for the selection of the representative MAAP case for 

10 each STC. This discussion indicates that the selection was conservative. For the STCs that 

11 dominate the risk, the case with the highest Cesium Iodide (CsI) release fraction was selected 

12 from the available applicable MAAP cases.

13 In response to an NRC staff RAI requesting an expanded description of the MAAP cases and 

14 associated sequences (NRC 2017a), Entergy provided a description of the 11 sequences (5 for 

15 STCs 7–10 and 6 for STCs 11–14) along with their frequencies as well as the time molten core 

16 concrete interaction (MCCI) starts (Entergy 2017b). The total frequency of these sequences is 

17 approximately 95 percent of the total internal events CDF. An examination of this information 

18 indicated that for the STC 7–10 sequences, one sequence, S2-A6, had a start of MCCI of 

19 approximately 36 hours, compared to that for the representative sequence, T-14, of 64 hours. 

20 Responding to a concern that the earlier time for the start of MCCI could lead to a higher risk 

21 than that used in the analysis, Entergy indicated that T-14 had both a shorter time between the 

22 declaration of a general emergency and reactor vessel failure and a higher CsI release fraction 

23 than for S2A-6, leading to a more conservatively calculated risk (Entergy 2017b).

24 The NRC staff noted in an RAI that Entergy's discussion of the representative MAAP cases for 

25 STCs 7 through 10 indicates that the same MAAP case (T-14) was used both for categories 

26 without MCCI as well as for those with MCCI (NRC 2017a). Similarly, for STCs 11 through 14, 

27 the same MAAP case (T-TB-3) was used both for categories without MCCI as well as for those 

28 with MCCI. The release fractions for otherwise similar categories (STCs 7 and 9, STCs 8 

29 and 10, STCs 11 and 13; as well as STCs 12 and 14) are however different, even though they 

30 result from the same MAAP case. From the discussion, it appears that the results prior to MCCI 

31 were used for the categories without MCCI while the results at the end of the run were used for 

32 the categories with MCCI. Entergy was asked to clarify this approach and justify the use of 

33 MAAP results prior to MCCI occurring for the categories without MCCI rather than the 

34 end-of-run result for a MAAP case without MCCI (NRC 2017a).

35 In response to the RAI, Entergy confirmed the above description of the approach used to 

36 evaluate the release fractions for sequences where there is no MCCI and discussed the MAAP 

37 modeling of MCCI to support this methodology (Entergy 2017b). The RBS Level 2 PRA utilizes 

38 probabilities of successful or unsuccessful debris cooling from NUREG/CR-4551 (NRC 1990). 

39 Different conditional probabilities are based on the spread of the debris, which depends on the 

40 reactor pressure at the time of vessel failure and the degree of debris entrainment. These 

41 conditional probabilities are not MAAP inputs, but are taken from NUREG/CR-4551. The MAAP 

42 code contains input parameters and assumptions that make MCCI more or less likely to occur. 

43 Due to MAAP settings in the RBS Level 2 MAAP model, MCCI occurred in nearly all cases. 

44 Therefore, to estimate the releases for cases that should not have MCCI (based on the 

45 NUREG/CR-4551 probabilities) the release fractions were taken up to the MAAP predicted time 

46 of the start of MCCI (Entergy 2017b).
F-20

1 Entergy further explained that for some of the STCs (STCs 7 -10, involving containment failure 

2 prior to core damage), the analysis did not predict MCCI until more than 30 hours after core 

3 damage and containment failure had both occurred. Entergy concluded that for these 

4 scenarios, the releases had stabilized, and continuing the run beyond that at which MCCI is 

5 predicted to have started would have had a negligible impact on the releases. As discussed 

6 below, this was subsequently confirmed by a MAAP run with MCCI suppressed and extending 

7 the run time to 48 hours after generation of a general emergency. This analysis resulted in a 

8 0.1 percent increase in the base case MACR (Entergy 2017b).

9 Entergy also noted that, in other cases, MCCI occurred before containment failure 

10 (STCs 11–14). For the STCs with no MCCI, the fission product releases would more 

11 appropriately be represented by MAAP analyses with MCCI suppressed, but with the case 

12 continued beyond containment failure. The MAAP case (T-TB-3) result for these STCs up to 

13 the time of the onset of MCCI noticeably under-predicted the noble gas release fraction. The 

14 release categorization should have been continued past containment failure in order to observe 

15 the release fraction plateaus. In order to evaluate the impact, a new MAAP analysis was 

16 performed for Case T-TB-3, in which the MAAP inputs are identical except for modification of 

17 some internal parameters to suppress MCCI. The new analysis was run to 20 hours post18 containment failure and most of the release fractions are approximately a factor of 5 higher than 

19 those previously calculated. However, other than the noble gas release fraction, they have a 

20 very low magnitude. In addition, STCs 11 and 12 each have a low frequency. Entergy 

21 concluded that due to the combination of low frequency and low consequence, the updated 

22 source term analysis for these STCs (STCs 11 and 12) continues to have a negligible impact on 

23 the SAMA analysis (Entergy 2017b).

24 The ER, with regard to the MAAP analysis of fission product release, states, "In general, cases 

25 were run to a minimum of 140 hours to ensure that any late MCCI effects are understood.” In 

26 an RAI, Entergy was asked to provide the MAAP run times for each STC, as well as the time of 

27 declaration of a general emergency, the time of core damage, the time of containment failure 

28 and time of the start of release, and to clarify the meaning/definitions for the plume durations 

29 and plume delays given in Table D.1-21 (NRC 2017a). Entergy provided the requested 

30 information in Table 2.f-1 of the RAI responses (Entergy 2017b). The run times for the no-MCCI 

31 STCs 7 and 8 and STCs 11 and 12, are less than 48 hours after the time of declaration of 

32 general emergency. As discussed above, the run times for these STCs was taken to be the 

33 time of the start of MCCI. For STCs 7 and 8, the run time was 63.4 hours or approximately 34 

34 hours after the general emergency time of declaration of 29.2 hours. A MAAP run was made for 

35 these STCs with MCCI suppressed and the run time extended to 48 hours after declaration of a 

36 general emergency. This resulted in a 0.1 percent increase in the base case MACR 

37 (Entergy 2017b).

38 In the same RAI response, Entergy explained that for STCs 11 and 12 the run time was 

39 17.6 hours, or less than one hour after the general emergency time of declaration of 17.2 hours. 

40 As discussed above, a new MAAP analysis was performed in which MAAP inputs were set to 

41 suppress MCCI. The new analysis was run to 20 hours post-containment failure for a total run 

42 time of 42.9 hours, which is approximately 26 hours after the declaration of general emergency. 

43 While most of the release fractions are approximately a factor of 5 higher than those previously 

44 calculated, other than the noble gas release fraction, they are all of very low magnitude. In 

45 addition, STCs 11 and 12 each have a low frequency that is more than two orders of magnitude 

46 less than the STCs that contribute significantly to the total risk. Entergy concluded that, due to 

47 the combination of low frequency and low consequence, the updated source term analysis for 

48 these STCs (STCs 11 and 12) continue to have a negligible impact on the SAMA analysis, and 
F-21

1 extending the run times for these cases is therefore not warranted (Entergy 2017b). Based on 

2 the low frequency and low consequence contributions to risk by STCs 11 and 12, the NRC staff 

3 agrees that extending the MAAP run times for the representative cases to 48 hours is not 

4 warranted.

5 The ER states, with regard to the Level 2 PRA, that "It was prepared and reviewed by qualified 

6 personnel in accordance with existing industry standards" and that "...a team of RBS experts 

7 representing various site organizations (e.g. Operations, System Engineering, 

8 Mechanical/Safety Analysis, PRA, and License Renewal) performed a review of the results to 

9 confirm that the model is representative of the plant and the results are reasonable" 

10 (Entergy 2017a). Entergy was asked in an NRC staff RAI to provide more information on the 

11 compliance of the RBS Level 2 analysis with the LERF requirements of the ASME/ANS PRA 

12 standard and the conclusions of the RBS expert team review (NRC 2017a). Entergy explained 

13 in the RAI response that, as discussed above, the 2011 LERF model was updated in 2016 to 

14 develop a full Level 2 PRA to support the license renewal SAMA analysis (Entergy 2017b). The 

15 self-assessment of the 2016 Level 2 PRA found that all of the ASME/ ANS PRA Standard LERF 

16 supporting requirements were met to at least Category II except for the following:

17 SR LE-C13 – Met at Category I because of conservative treatment of 

18 containment bypass. Entergy concluded that this is also conservative to the 

19 SAMA analysis, as it has the potential to overestimate the benefit of some 

20 SAMAs. 

21 Entergy noted that this supporting requirement was considered "met" by the subsequent peer 

22 review of the Revision 6 PRA, with no facts and observations (F&Os) assigned to this 

23 supporting requirement. As discussed above, changes to the LERF element of the Revision 6 

24 PRA were based upon the Level 2 model developed for the SAMA analysis. In its RAI 

25 response, Entergy explained that these changes to the LERF model were considered an 

26 upgrade. A BWROG focused-scope peer review of the LERF elements of the Revision 6 PRA 

27 was conducted in September 2017. In this peer review, all LERF supporting requirements were 

28 considered "met.” Entergy provided the three findings from this focused-scope peer review and 

29 determined that their resolution would have no impact on the SAMA results.

30 Based on its review of the Level 2 methodology that is in accordance with the NEI 05-01A 

31 guidance, Entergy's responses to NRC staff RAIs, the results of a MAAP run that extended the 

32 run time to 48 hours after declaration of general emergency for STCs 7 and 8, and Entergy’s 

33 bases for determining that the resolution to internal Entergy and independent peer reviews of 

34 the Level 2 model would not impact the SAMA results, the NRC staff concludes that the Level 2 

35 PRA, as used in the SAMA analysis, provides an acceptable basis for evaluating the benefits 

36 associated with various SAMAs. 

37 F.2.2.4 Level 3 Consequence Analysis

38 Entergy used the MACCS, Version 3.10.0, code and a core inventory from a plant-specific 

39 calculation to determine the offsite consequences from potential releases of radioactive material 

40 (Entergy 2017a). Entergy calculated the core inventory for 3,100 MWt, which is slightly higher 

41 than the rated power level of 3,091 MWt for RBS (Entergy 2016).

42 The NRC staff reviewed the process used by Entergy to extend the containment performance 

43 (Level 2) portion of the PRA to an assessment of offsite consequences (Level 3 PRA model). 

44 Source terms used to characterize fission product releases for the applicable containment 
F-22

1 release categories and the major input assumptions used in the offsite consequence analyses 

2 were considered. In response to an NRC staff RAI regarding inventory used in the SAMA

3 radiological dose calculations and the maximum inventory expected during the 20-year period of 

4 extended operation if license renewal is approved (NRC 2017a), Entergy explained that initial 

5 scoping efforts have been initiated to evaluate changing the fuel from the GNF-2 currently used, 

6 and assumed in the SAMA analysis, to GNF-3 fuel (Entergy 2017b). Entergy’s preliminary 

7 assessment is that the source terms for individual isotopes are expected to increase by about 

8 two percent by changing to GNF-3 fuel. Entergy also concluded that this small impact is 

bounded by the 95th 9 percentile CDF uncertainty analysis discussed in Section F.6.2 of this 

10 appendix. The NRC staff finds the use of the source terms based on GNF-2 fuel to be 

11 acceptable for the SAMA analysis because the potential impact of using source terms for GNF-3 

fuel is small and bounded by the 95th 12 percentile CDF uncertainty analysis.

13 Additional plant-specific input to the Level 3 assessment includes the core release fractions and 

14 source terms for each release category, site-specific meteorological data, projected population 

15 distribution and expected growth out to the year 2045 within an 80-km (50-mi) radius, 

16 emergency evacuation modeling, and economic data. This information is provided in 

17 Section D.1.5 of Attachment D to the ER (Entergy 2017a). 

18 According to the ER, Entergy considered site-specific meteorological data for calendar years 

19 2008 through 2014. Entergy used meteorological data (wind speed, wind direction, atmospheric 

20 stability, accumulated precipitation) from 2013 with minimum mixing height data for 2008 and 

21 2009 for the analysis as inputs to the MACCS code because they were the most conservative 

22 data sets (Entergy 2017a). Meteorological data were acquired from the RBS meteorological 

23 monitoring system and from the National Climatic Data Center (NCDC).

24 In an NRC staff RAI, Entergy was asked to explain why meteorological data for the year 2013 

25 were the most conservative and how missing data were accounted for in the SAMA analysis 

26 (NRC 2017a). In response to the RAI, Entergy explained that all 14 release categories were 

27 evaluated using all available meteorological data sets from 2008 through 2014 to determine 

28 which data set resulted in the highest PDR and OECR, and that the 2013 data using the 

29 minimum mixing height averages from previous years resulted in the highest PDR and OECR, 

30 which were the data used in the SAMA analysis (Entergy 2017b). Temperature data from 2008 

31 through 2014 used to develop the atmospheric stability factor were obtained from the RBS 

32 meteorological monitoring system. Over the seven-year period, 0.7 percent of temperature data 

33 were missing, with 22 hours (0.3 percent) of data missing in the year 2013 data. The hours of 

34 missing data were filled by interpolation.

35 Entergy further explained in response to the RAI that wind speed, wind direction, precipitation, 

36 and mixing height data were obtained from the NCDC (Entergy 2017b). Over the seven-year 

37 period, 4.2 percent of wind direction data, 0.4 percent of wind speed data, and 1.8 percent of 

38 precipitation data were missing, with 36 hours (0.4 percent) of wind data and 58 hours 

39 (0.7 percent) of precipitation data missing in the year 2013 data. Missing wind data were filled 

40 using interpolation, except that eight sequential missing hours were filled with data from 2014 

41 for the same hours. Missing precipitation data were filled with zero. Furthermore, interpolation 

42 was used to develop wind direction data when the NCDC data contained a direction value of 

43 “variable,” which cannot be used as input to the MACCS model. There were 402 hours (4.6 

44 percent) of wind direction data in 2013 that had a variable wind direction. In its RAI response, 

45 Entergy provided an example of how interpolation was used to develop missing data and to 

46 replace “variable” wind direction data (Entergy 2017b).
F-23

1 For mixing height data, Entergy explained in its RAI response that morning and afternoon 

2 values for the vicinity of RBS were obtained from NCDC for the years 2000 through 2009 

3 because data for the years after 2009 are not available (Entergy 2017b). Seasonal mixing 

4 height averages were calculated for the years 2000 through 2009, and these average values 

5 were used for the years 2010 through 2014. For the years 2008 and 2009, the actual calculated 

6 average values for those years were used.

7 The sources of data and models for atmospheric dispersion used by the applicant are consistent 

8 with standard industry practice and are acceptable for calculating consequences from potential 

9 airborne releases of radioactive material. Because multiple years of meteorological data were 

10 considered by the applicant, and the annual data set that resulted in the largest total population 

11 dose and offsite economic cost was selected for the SAMA analysis, the NRC staff finds that the 

12 data selection was performed in accordance with NEI 05-01A, and thus, the meteorological data 

13 are appropriate for use in the SAMA analysis.

14 Entergy projected population distribution and expected growth within a radius of 80 km (50 mi) 

15 out to the year 2045 to account for an anticipated 29-year period of remaining plant life (at the 

16 time the calculation was performed), including nine years remaining on the original operating 

17 license plus a 20-year period of extended operation (Entergy 2017a). The Entergy assessment 

18 used U.S. Census 2000 and 2010 data and scaled the population data to 2045 using parish19 level (Louisiana) and county-level (Mississippi) projection estimates. Transient populations 

20 were included in the projections. Additionally, for parishes and counties with declining 

21 population projections, Entergy clarified that the highest estimated population for the time 

22 between 2010 and 2045 was used for the 2045 projection (Entergy 2017a). The total projected 

23 population of the 80 km (50 mi) zone of analysis is 1,475,914, and the distribution of the 2045 

24 total population is summarized in Table D.1-14 of the ER. The NRC staff considers the 

25 methods and assumptions for estimating population to be reasonable and acceptable for 

26 purposes of the SAMA evaluation because its review of Entergy’s assessment determined that 

27 Entergy considered appropriate data sources, used a reasonable approach for applying data, 

28 followed NRC guidance (NEI 2005), and added conservatism by not crediting negative 

29 population growth.

30 Entergy performed a sensitivity analysis on the time to declaration of an emergency by imposing 

31 a 15-minute delay in the emergency declaration from the alarm times determined by the MAAP 

32 analyses, and reported the PDR and OECR to be unchanged (Entergy 2017a). In response to 

33 an NRC staff RAI to explain why the PDR and OECR were unchanged in this sensitivity analysis 

34 (NRC 2017a), Entergy explained that the MAAP results shown in Table D.1-21 of the ER is the 

35 earliest time an alarm would be declared resulting in the evacuation of the 10-mile emergency 

36 planning zone (EPZ), but that procedurally the assessment, classification, and declaration of an 

37 emergency condition may take up to 15 minutes after the availability of indications that an 

38 emergency action level (EAL) threshold has been exceeded (Entergy 2017b). For this reason, a

39 sensitivity analysis was performed adding a 15-minute delay in the declaration of an emergency. 

40 The reason there was no change in the PDR from this delay is two-fold: 1) the fraction of the 

41 population that is evacuated is a small fraction, about two percent, of the total population 

42 impacted by a release and 2) the change in the alarm time did not change the relation of the 

43 alarm times for each STC to the corresponding release times. Regarding the first reason, the 

44 population within the 10-mile emergency planning zone (EPZ) that is evacuated in response to a 

45 general alarm is approximately two percent of the total impacted population that resides within 

46 the 50-mile radius of the plant. Regarding the second reason, in the baseline SAMA analysis 1) 

47 for STCs 2 through 6, 13, and 14, the alarm occurs after the initial plume but prior to subsequent 

48 plumes, 2) for STCs 7 through 10 the alarm occurs prior to the initial alarm, and 3) for STCs 11 
F-24

1 and 12 the evacuation occurs after all plume releases (the NRC notes that STC 1 is intact 

2 containment so releases to the population are minimal). This relationship did not change with a 

3 15-minute delay in the emergency declaration. Entergy further explained that the MACCS

4 results do show small variations in the population dose, but that they are minor and do not result 

5 in a noticeable change in the PDR (Entergy 2017b). The NRC staff concludes that the impact of 

6 a 15-minute delay in the emergency declaration is expected to be small given that the 

7 evacuating population is small relative to the total exposed population, that this delay is a 

8 relatively small incremental time compared to the general emergency declaration time, and that 

9 this delay is small compared to the duration of the plume releases.

10 Entergy assumed that 95 percent of the population would evacuate (Entergy 2017a). This 

11 assumption is conservative relative to the NUREG-1150 study (NRC 1990), which assumed 

12 evacuation of 99.5 percent of the population within the 10-mile EPZ. Entergy performed a 

13 sensitivity analysis on the percent of the population assumed to evacuate, reducing it to 90 

14 percent of the 10-mile EPZ population and increasing it to 100 percent of the population. The 

15 PDR and OECR were determined to be unchanged (Entergy 2017a). The evacuated population 

16 was assumed to move at an average speed of 10 meters per second (22.4 miles per hour). 

17 This evacuation speed is lower than the average evacuation speed in 11 of 12 evacuation 

18 scenarios evaluated, with the average evacuation speed for the slowest scenario being 8.3 m/s 

19 (18.5 miles per hour) (Entergy 2017a). Entergy performed a sensitivity analysis on the 

20 evacuation speed, reducing it by half to 5 meters per second (11.2 miles per hour) and 

21 increasing it by 50 percent to 15 meters per second (33.6 miles per hour). The PDR and OECR 

22 were determined to be unchanged (Entergy 2017a). In response to an NRC staff RAI to explain 

23 why the PDR and OECR were unchanged in both of these sensitivity analyses (NRC 2017a), 

24 Entergy explained that the population within the 10-mile EPZ that is evacuated is a small 

25 fraction, approximately two percent, of the total impacted population that resides within the 50-

26 mile radius of the plant. Since a relatively small number of people are affected by evacuation, 

27 the results of the sensitivity analysis show that the changes in the fraction of people evacuating 

28 and in the evacuation speed do not noticeably change the PDR results (Entergy 2017b). Given 

29 that Entergy performed a site-specific analysis to determine evacuation assumptions and 

30 parameters and showed radiological consequence results were insensitive to changes to certain 

31 evacuation parameters, the NRC staff concludes that the evacuation assumptions and analysis 

32 are reasonable and acceptable for the purposes of the SAMA evaluation.

33 The site-specific economic data were provided from the 2012 U.S. Census of Agriculture, 

34 SECPOP 2013, U.S. Bureau of Labor Statistics, and gross metropolitan product (GMP) from the 

35 U.S. Office of Management and Budget. Parish and county representation within a spatial

36 element was based on the parish or county with the greatest area contribution. Data for certain 

37 counties and parishes were not incorporated into the analysis because of their small area 

38 contributions within a spatial element. Agricultural data were obtained from 2012 U.S. Census 

39 of Agriculture data for the 80-km (50-mi) area and applied to the MACCS crop categories. 

40 Economic costs for evacuation, relocation, and decontamination were scaled to year 2016 costs 

41 from 2006 values obtained from MACCS using the ratio of the 2016 and 2006 consumer price 

42 index (CPI) values. Using the site-specific information, Entergy determined that the non43 farmland decontamination costs (CDNFRM) was $30,586/person. Entergy performed a 

44 sensitivity analysis on two of the MACCS offsite contamination inputs, increasing the 

45 decontamination time (TIMDEC) to approximately 365 days and increasing the non-farmland 

46 decontamination costs (CDNFRM) to $100,000 per person. These values bound the sensitivity 

47 analysis values recommended in the U.S. Nuclear Regulatory Commission’s decision in the 

48 Indian Point license renewal proceeding (NRC 2016d). In Entergy’s sensitivity analysis, the 

49 OECR was reported to increase by 78 percent, the PDR was reported to be unchanged, and the 
F-25

1 maximum averted cost risk (see Section F.6.1) was reported to increase by 28 percent. This 

2 change in the maximum averted cost risk is bounded by the uncertainty analysis results 

3 discussed in Section F.6.2. Thus, the staff considers the MACCS values, adjusted to 2016 

4 costs using the CPI, that were used by the applicant to be reasonable for the SAMA analysis.

5 In summary, the NRC staff reviewed Entergy’s assessments of the source term, radionuclide 

6 releases, meteorological data, projected population distribution, emergency response, and 

7 regional economic data and evaluated Entergy’s responses to the NRC staff’s RAIs, as 

8 previously described in this subsection. Based on its review, the NRC staff concludes that 

9 Entergy’s consequence analysis is acceptable and that Entergy’s methodology to estimate 

10 offsite consequences for RBS and consideration of parameter sensitivities provide an 

11 acceptable basis to assess the risk reduction potential for candidate SAMAs. Accordingly, the 

12 NRC staff based its assessment of offsite risk of severe accidents at RBS on the CDFs, 

13 population doses, and offsite economic costs reported by Entergy.

14 F.3 Potential Plant Improvements

15 Entergy’s process for identifying potential plant improvements (in the form of SAMAs), an 

16 evaluation of that process, and the improvements evaluated by Entergy are discussed in this 

17 section. 

18 F.3.1 Process for Identifying Potential Plant Improvements

19 Entergy’s process for identifying potential plant improvements consisted of the following 

20 elements: 

21 • review of SAMAs identified in industry documents, specifically NEI 05-01A

22 (NEI 2005)

23 • review of SAMA analyses for other BWR plants

24 • review of potential plant improvements identified in the RBS IPE and IPEEE

25 • review of the risk-significant events in the current RBS PRA Level 1 and Level 2

26 models

27 Based on this process, Entergy identified an initial set of 206 candidate SAMAs, referred to as 

28 Phase I SAMAs. In Phase I of the evaluation, Entergy performed a qualitative screening of the 

29 initial list of SAMAs and eliminated various SAMAs from further consideration using the 

30 following criteria: 

31 • the SAMA modifies features not applicable to RBS

32 • the SAMA has already been implemented at RBS

33 • the SAMA is similar in nature and could be combined with another SAMA candidate

34 • the SAMA has an excessive implementation cost (in excess of the modified

35 maximum averted cost-risk)

36 • the SAMA is expected to have a very low benefit (related to a non-risk-significant

37 system)

38 Based on this screening, 158 of the Phase I SAMA candidates were screened out. One of the 

39 remaining SAMA candidates was divided into three different SAMAs leaving 50 for further 

40 evaluation. These remaining SAMAs, referred to as Phase II SAMAs, are listed in Table D.2-1 

41 of Attachment D to the applicant’s ER (Entergy 2017a). In Phase II, a detailed evaluation was 
F-26

1 performed for each of the 50 remaining SAMA candidates, as discussed in Sections F.4 and F.6 

2 below.

3 F.3.2 Review of Entergy’s Process

4 The initial SAMA list was developed primarily from a review of generic industry SAMAs 

5 (NEI 2005), as well as consideration of cost-beneficial SAMAs from 12 previous BWR license 

renewal applications3 6 . While the RBS IPE and IPEEE did not identify any vulnerabilities 

7 requiring enhancements, two fire-related SAMA candidates that were potentially cost-beneficial at 

8 other plants were retained for further evaluation because they were applicable to fire areas identified 

9 as top contributors in the IPEEE. Finally, a review of the RBS PRA Level 1 and Level 2 LERF

10 results was performed to identify any additional SAMAs and confirm that all important events 

11 had been addressed. Three additional SAMA candidates were added as a result of this review 

12 (Entergy 2017b).

13 The NRC staff reviewed the Phase I identification and screening of SAMA candidates during the 

14 November 2017 audit. This review resulted in a number of questions concerning this process.

15 • The discussion for two SAMAs involving heating ventilation and air conditioning

16 (HVAC) identifies a recent analysis of the control building that shows reduced HVAC

17 importance and that these SAMAs do not consider the control building loss of HVAC.

18 In response to an NRC staff request to provide more information regarding this

19 analysis (NRC 2017a), Entergy indicated that recent control building HVAC analyses

20 included revised control building heat-up calculations as well as revised equipment

21 survivability assessments (Entergy 2017b). The studies demonstrated that the most

22 limiting equipment in a specific room would function for the room temperature profiles

23 resulting from a loss of room cooling. An interim PRA model was used to evaluate

24 the changes in the control building HVAC requirements. This model demonstrated

25 significantly lower risk with a single division of chillers or control building HVAC out of

26 service due to realistic treatment of equipment survivability and the limited actions

27 required to recover switchgear room cooling. Incorporation of the above changes

28 into the SAMA PRA model would result in a much lower control building HVAC

29 contribution to risk such that any related SAMAs would not be cost beneficial

30 (Entergy 2017b). As discussed above, incorporation of the results of these studies

3 In response to an NRC staff RAI, Entergy indicated that the ER statement regarding the results of the SAMA

analysis of 13 BWR plants were reviewed was incorrect. It was found that the analysis for one of the 13 plants 

listed in the ER had not been reviewed. Entergy concluded that since so many SAMAs had already been 

considered, the review of this added plant would not be expected to add a new retained SAMA (Entergy 2017b).
F-27

1 into the Revision 6 PRA is a contributor to the significant reduction in the CDF for

2 that model.

3 • The discussion of SAMA 120, to install a hardened containment vent, cites a

4 containment vent study. In response to a request to provide more information

5 regarding this study (NRC 2017a), Entergy described the study's assessment of

6 three different venting strategies in the event of loss of all containment decay heat

7 removal (Entergy 2017b). The study indicated that use of a 3-inch containment

8 purge vent would not prevent containment failure, while venting through containment

9 airlock deflated inner seals would be successful. These vent paths are included in

10 the RBS Emergency Operating Procedures (Entergy 2017b). While the Revision 5A

11 PRA used for the SAMA analysis does not take credit for containment venting, the

12 Revision 6 update does include a model for venting through deflated containment

13 airlock inner door seals, which contributes to a significant reduction in CDF resulting

14 from the loss of all containment decay heat removal.

15 • The discussion of SAMA 170, to increase the seismic ruggedness of plant

16 components already installed, is based on RBS having identified components whose

17 seismic ruggedness could be improved in the IPEEE. The NRC staff noted in an RAI

18 that the RBS IPEEE does not identify any such components (NRC 2017a). In

19 response to the RAI, Entergy indicated that the IPEEE concluded that the RBS

20 components are seismically rugged based on reviewing design documents and

21 performance of a seismic walkdown (Entergy 2017b). Furthermore, Entergy’s

22 response to the NRC staff’s RAI dated March 26, 2014 (Entergy 2014b) concluded

23 that further seismic risk evaluations were not required. As described in ER

24 Section D.1.3.5, an external event multiplier of 7 (rounded up from the calculated

25 value of 6.9) was used in the SAMA analyses to account for the risk contribution from

26 external events in the SAMA evaluations. Given the above discussion, Entergy

27 concluded that improving the seismic ruggedness of selected components would not

28 significantly reduce seismic risk nor change the SAMA evaluation results

29 (Entergy 2017b).

30 In Table D.1-2 of the ER (Entergy 2017a), Entergy provided a tabular listing of the Level 1 PRA 

31 basic events having CDF importance down to a risk reduction worth (RRW) of 1.005. SAMAs 

32 affecting these basic events would have the greatest potential for reducing risk. An RRW of 

33 1.005 corresponds to a reduction in CDF of approximately 0.5 percent, given 100 percent 

34 reliability of the SAMA. Based on the maximum averted cost risk including external events and 

35 uncertainty (see Section F.6.1 below), this equates to a benefit of approximately $36,000. This 

36 is below the minimum cost of a simple procedure change with associated training as given by 

37 Entergy (see Section F.5 below), and therefore SAMAs below this value may be screened out 

38 as not cost-beneficial. All basic events in the Level 1 listing were reviewed to identify potential 

39 SAMAs and the listing was then annotated to indicate which of the Phase II SAMAs mitigate the 

40 failure associated with the basic event. All basic events were addressed by one or more 

41 Phase II SAMAs from the list based on the generic industry SAMAs or RBS specific SAMAs 

42 (Entergy 2017a).

43 The NRC staff’s review of the information in Table D.1-2 of the ER led to a number of RAIs as 

44 follows:

45 • Event E12-MDP-MA-C002A, "RHR [residual heat removal] pump A is unavailable

46 due to maintenance," is addressed by a number of SAMAs that are either not

47 applicable to this event (SAMAs 79 and 198) or involve costly new systems

48 (SAMAs 110, 115, and 120). Entergy was asked to consider other alternatives to
F-28

1 mitigate this event such as eliminating or reducing on-line maintenance of the RHR 

2 pump or adding an additional standby pump (NRC 2017a). Entergy replied that 

3 reducing on-line maintenance would lower the risk but there are substantial costs

4 associated with moving the required maintenance to an outage, including extended 

5 outage time and cost of replacement power (Entergy 2017b). In addition, the RRW

6 of this event in the recently completed Revision 6 PRA (1.0009) is significantly lower 

7 than its importance in the Revision 5A model (1.143). The difference in importance 

8 is primarily due to the addition of a venting path (personnel air lock) for removal of 

9 decay heat from the containment in the R6 PRA model, as well as including credit for 

10 FLEX equipment and procedures for suppression pool cooling under extended loss 

11 of AC power (ELAP) conditions. Thus, Entergy concluded that any potential benefit 

12 associated with SAMAs for event E12-MDP-MA-C002A has been reduced by recent 

13 improvements in plant procedures in combination with FLEX strategies

14 (Entergy 2017b).

15 • Event FPW-XHE-LO-T2SBO, "operator fails to follow attachment 2 for SBO," is

16 addressed by several hardware modifications. Because this event is given a failure

17 probability of 0.5 and has a fairly high RRW of 1.117, Entergy was asked to discuss

18 the potential for a SAMA to improve the procedure or training for injection of fire

19 water for SBO (NRC 2017a). In response to the RAI, Entergy noted that the 0.5

20 probability for this event is a screening value that is applied during initial

21 quantification (Entergy 2017b). After quantification, recovery rules are applied and

22 the actual failure probability for this event, when alone in a cutset, is 0.1. Entergy

23 evaluated a new SAMA to improve the procedures and training on injection with the

24 fire water system (Entergy 2017b). The evaluation of this SAMA is discussed further

25 in Section F.6.2.

26 • Event IE-T3C, "Initiator, Inadvertent opening of SRV [safety relief valve]," is

27 addressed by SAMA 108 - Improve SRV and main steam isolation valve (MSIV)

28 pneumatic components and SAMA 160 - Increase SRV reseat reliability. Because it

29 was not clear to the NRC staff that either of these SAMAs address this event,

30 Entergy was asked to discuss the potential for other SAMAs that address or mitigate

31 this event (NRC 2017a). In response to the RAI, Entergy stated that the disposition

32 of initiator IE-T3C incorrectly referenced SAMA 108, and that SAMA 160 is

33 applicable to IE-T3C (Entergy 2017b). The initiating event, although named

34 "Inadvertent opening of SRV," also includes the fact that the SRV subsequently

35 sticks open (does not reseat). Table F–6 describes the PRA model changes made

36 to evaluate the risk reduction for this SAMA. No additional SAMAs were identified by

37 Entergy to mitigate this initiating event (Entergy 2017b).

38 • Because the NRC staff noted that Table D.1-2 of the ER includes a number of

39 standby service water (SSW) pumps B and D failure events but not any events for

40 failure of SSW pumps A or C, Entergy was asked to explain the reasons for this

41 difference and to discuss if the reasons suggest any potential SAMAs (NRC 2017a).

42 In response, Entergy stated that the SSW system is divided into two trains of two

43 pumps each wherein Train A SSW contains pumps A and C while Train B SSW

44 contains pumps B and D (Entergy 2017b). Due to differences in flow requirements

45 for the different trains, because of the additional Train B flow required for the

46 component cooling water pump system, failure of either pump B or D causes failure

47 of Train B SSW whereas failures of both pumps A and C are needed to fail Train A

48 SSW. SAMA 80, to add a SSW pump, addresses the SSW train asymmetry. To

49 remove the asymmetry, while ensuring redundancy and allowing for maintenance,

50 both Train B pumps would have to be replaced with larger pumps capable of

51 providing sufficient flow. That modification would cost more than SAMA 80 and
F-29

1 would not be cost-beneficial. Other SAMAs, such as SAMA 21 and SAMA 22, which 

2 provide backup diesel cooling, and SAMA 17, which provides backup flow to the 

3 RHR heat exchanger, also mitigate failures of the SSW pumps. No additional 

4 SAMAs were identified by Entergy to address the asymmetry between Train A and 

5 Train B SSW (Entergy 2017b).

6 • Event SWP-MOV-CC-F055A, "motor operated valve 1SWP*MOV55A fails to open

7 on demand" is stated in the ER to be addressed by SAMAs 75 and 80, both of which

8 pertain to the service water pumps. Entergy was asked in an NRC staff RAI to

9 discuss the potential for a SAMA for the operator to manually open the valve

10 (NRC 2017a). In response to the RAI, Entergy explained that the RBS model

11 includes an operator action (SWP-XHE-FO-F055A) to manually open valve

12 SWP-MOV55A if it fails due to loss of power (Entergy 2017b). This action is needed

13 for SBO accident sequences because valve SWP-AOV599, which provides the initial

14 HPCS diesel service water return path to the cooling towers, has a 4-hour air supply.

15 The time window for completing the action (opening SWP-MOV55A) is 4 hours to

16 ensure continued operation of the HPCS diesel. For non-SBO LOSP conditions

17 (where random failure of valve 1SWP*MOV55A to open is important) the time

18 window is much shorter. The operating diesels will overheat in one to three minutes

19 on a loss of cooling. In calculating the non-recovery probability, the RBS PRA

20 assumes a median response time of 30 minutes for the operator action to manually

21 open SWP-MOV55A, including travel time to its location in the piping tunnels and the

22 time to manually open this 30-inch valve. This assumed time greatly exceeds the

23 three minutes that would be available for this action under situations in which power

24 is available before the diesels overheat. Thus, in LOSP but non-SBO sequences, an

25 action to manually open SWP-MOV-55A is not feasible. For non-SBO, non-LOSP

26 sequences the risk impact of SWP-MOV-55A failing to open is very small (a Fussell

Vesely importance of 4.71 × 10-4 27 ). Thus, Entergy concluded that an operator action

28 to manually open this valve under these conditions would not be cost-beneficial

29 (Entergy 2018).

30 • For Event ADS-XHE-FO-INDIV, "operator fails to start [Automatic Depressurization

31 System] ADS by opening individual ADS valves or SRVs,” Entergy was asked to

32 consider improvements in procedures and training (NRC 2017a). Entergy responded

33 to the RAI stating that a new SAMA case was performed to evaluate the potential

34 benefit from improvements in procedures and training for this event. The evaluation

35 of this SAMA is discussed further in Section F.6.2.

36 The NRC staff noted in an RAI that from the information in ER Tables D.1-1 and D.1-2, the 

37 frequency of initiating event IE-TNSW, “Failure of the Normal Service Water (NSW)/Service 

38 Water Cooling (SWC) System,” is input into the internal events PRA as a value rather than as a 

39 fault tree model. The basic events that contribute to this frequency will therefore not appear in 

40 the list of risk significant terms in Table D.1-2. Entergy was asked to describe NSW and SWC 

41 systems, their operation, and modeling in the PRA, particularly with respect to operation in hot 

42 weather, and to discuss the identification of candidate SAMAs, other than SAMA 197, 

43 “Generation Risk Assessment implementation into plant activities,” that would mitigate the risk 

44 of this initiator (NRC 2017a). Entergy indicated the service water system contains two 

45 interconnected subsystems, the NSW sub-system and the SSW sub-system. The modeling of 

46 the SWC system was described and it was stated that failure of the SWC system is included in 

47 the TNSW initiator frequency since failure of SWC is expected to result in a loss of NSW. The 

48 event with the highest RRW in the IE-TNSW cutsets is SWC-PHN-DN-SCHOT, "Summer 

49 Temperatures require four of five fans to run to maintain SWC temps." This is followed by 

50 mechanical failure events and maintenance events for SWC fans and NSW pumps. Entergy 
F-30

1 concluded that only large-cost SAMAs, such as adding fans or pumps, would have a significant 

2 impact on this initiator and therefore, no additional SAMAs are proposed to mitigate this initiator 

3 (Entergy 2017b). 

4 In Tables D.1-4 and D.1-5 of the ER (Entergy 2017a), Entergy also provided and reviewed the 

5 basic events having LERF and large late release (STCs 6, 9, 10,13 and 14) frequency, 

6 respectively, down to an RRW of 1.005. All basic events were reviewed to identify potential 

7 SAMAs and all were addressed by one or more Phase II SAMAs, except those that were split 

8 fractions for which Entergy stated no SAMA needed to be correlated. The NRC staff noted in an 

9 RAI that while these split fraction events are in some cases related to deterministic 

10 phenomenological analysis or assumptions and not hardware or other failures, they do indicate 

11 the importance of a number of these events and the associated assumptions. Also, as indicated 

12 by the base case risk results, STCs 9 and 10 dominate the risk and involve penetration failures 

13 with and without scrubbing in the auxiliary building. It therefore appeared to the staff that steps 

14 which could be taken to reduce the impact of these STCs should be considered. Entergy was 

15 asked to discuss this particular example and a more general question addressing potential 

16 SAMAs suggested by review of the Level 2 split fractions (NRC 2017a). In response to the RAI, 

17 Entergy indicated split fractions are used to represent the likelihood of various 

18 phenomenological events from the deterministic analysis of the physical processes for the 

19 spectrum of severe accident progressions (Entergy 2017b). In general, Entergy explained that 

20 SAMAs do not need to be correlated for split fractions because split fractions add up to 1.0 and 

21 result in cutsets that are duplicates except for the split fraction events themselves. Reducing 

22 one part of the fraction necessitates increasing the other part of the fraction. Therefore, to 

23 mitigate cutsets containing split fractions, other event(s) in the cutsets should be mitigated. 

24 However, these split fractions are in cutsets with hardware failures and human action failures 

25 and the dominant hardware failures and human action failures also show up in the RRW tables. 

26 Since SAMAs have been evaluated for all of the important hardware and human action failure 

27 events, there is no need to evaluate SAMAs for the split fraction events (Entergy 2017b).

28 In response to this same RAI, Entergy also discussed the potential for a SAMA to impact the 

29 effectiveness of auxiliary building scrubbing. In a sensitivity analysis, Entergy showed that 

30 taking additional credit for auxiliary building scrubbing has the potential to significantly reduce 

31 the large releases in the Level 2 model. However, Entergy concluded that there was no 

32 defensible basis for the credited reduction in fission produce releases and that developing a 

33 defensible basis would necessitate additional modeling or testing. Also, since the actual 

34 location of releases into the auxiliary building is unknown and there would be negative 

35 consequences from using a spray system in the auxiliary building to scrub the releases, both 

36 from spraying safety-related components at power and from flood risk, Entergy identified no 

37 potential SAMAs for evaluation (Entergy 2017b).

38 The NRC staff’s review of the generic list of SAMA candidates in NEI 05-01A observed that the 

39 list includes a number of potential SAMA candidates addressing external events with some 

40 included in the RBS Phase II analysis, but none of the generic list are specific to RBS. In an 

41 RAI, the NRC staff noted that based on the best available information, the CDF for each of the 

42 external events (seismic, internal fire and internal floods) is approximately equal to, or greater 

43 than, the internal events CDF, and the staff asked Entergy to discuss the steps taken to identify 

44 potential SAMAs that would mitigate the RBS specific risks due to these hazards (NRC 2017a). 

45 Entergy addressed the identification of SAMAs for each of these hazards as follows.

46 • The RBS IPEEE used a limited-scope seismic margins assessment, which provided

47 neither quantitative risk information nor deterministic seismic capacities for specific
F-31

1 RBS systems, structures, or components. The IPEEE did not identify any seismic 

2 vulnerabilities, and RBS is in a region of low seismicity. Also, as discussed above, 

3 additional reviews of the impact of seismic events to RBS were undertaken following 

4 the accident at the Fukushima Dai-ichi Nuclear Power Plant. The NRC staff 

5 concluded that the licensee, through the implementation of the walkdown guidance 

6 activities and, in accordance with plant processes and procedures, verified the plant 

7 configuration with the current seismic licensing basis; addressed degraded, 

8 nonconforming, or unanalyzed seismic conditions; and verified the adequacy of 

9 monitoring and maintenance programs for protective features (Entergy 2017b). 

10 • The Phase I list of SAMA candidates included several that mitigate fire related risk

11 from the generic and other SAMA analysis sources. Ten were considered, but were

12 either not applicable or were not judged to be necessary to mitigate fire risk at RBS.

13 Three fire-related Phase I SAMAs were combined into one SAMA and, along with

14 one additional SAMA, were retained for the Phase II cost-benefit evaluation. Further,

15 the dominant contributors to fire risk were examined for possible mitigation, but no

16 additional SAMAs were postulated (Entergy 2017b).

17 • Four generic SAMA candidates for mitigating internal flood risk were considered in

18 Phase I, but were not judged to be necessary to mitigate internal flood risk. One

19 SAMA, to improve internal flooding procedures was retained for evaluation. Further,

20 the dominant contributors to internal flood risk in the model used for the SAMA

21 analysis were examined for possible mitigation, but no additional SAMAs were

22 postulated (Entergy 2017b).

23 As discussed above in Section F.2.2.2, the RBS external flooding focused evaluation 

24 demonstrated that there was adequate physical margin for the LIP hazard and the PMF hazards 

25 on West Creek and the Mississippi River. Considering that permanent, passive protection is in 

26 place at RBS for these conservatively analyzed floods, the contribution to CDF from external 

27 flooding is negligible (Entergy 2017b). Furthermore, the NRC staff notes that the need for any 

28 mitigating action for external floods is being addressed as part of the NRC Order EA-12-049 

29 program as a current operating issue, and no additional external flooding SAMAs need to be 

30 considered for license renewal.

31 The NRC staff questioned the applicant about additional potentially lower cost alternatives to a 

32 number of the SAMAs as follows:

33 • SAMA 34 – “Provide alternate feeds to essential loads directly from an alternate

34 emergency bus” is evaluated using a plant-specific cost estimate of $2.3M. Case 4

35 evaluating this SAMA is stated in ER Section D.2.3 to assume an added independent

36 AC power source to each safety 4160VAC bus. Entergy was asked to clarify the

37 scope of the design used for the cost estimate (NRC 2017a). Entergy stated in the

38 RAI response that the SAMA 34 implementation cost estimate was for a power

39 supply from an alternate bus to a single safety-related 4160VAC bus

40 (Entergy 2017b).

41 • SAMAs 80, 110, 115, and 120 all involve major new systems to mitigate loss of

42 cooling events and are cited for a large number of significant basic events in

43 Table D.1-2 including, for example: SWP-XHE-FO-RETRN, "Operator fails to open

44 SWP manual isolation valve before containment over pressurization failure,"

45 SWP-XHE-RE-F055A, "operator fails to restore XOV downstream of F055A,” and

46 E12-MOV-OO-F048A, "water diverted from RHR A HXS because bypass valve

47 MOV F048A fails to close." Entergy was asked to describe these and other similar

48 events and to consider the possibility of lower cost alternatives such as simpler
F-32

1 hardware changes, changes in system operation so that fewer changes in valve 

2 position are necessary, procedure improvements, and training improvements 

3 (NRC 2017a). Entergy described the function of each of the valves in these events 

4 and noted that, while these valves are important for loss of decay heat scenarios in 

5 the Revision 5A model, the core damage contribution for the valves is significantly 

6 reduced in the Revision 6 model (by as much as two orders of magnitude) 

7 (Entergy 2017b). The difference is primarily due to addition of a venting path 

8 (personnel air lock) for removal of decay heat from containment in the Rev 6 model, 

9 as well as credit for FLEX equipment and procedures for Suppression Pool Cooling 

10 under ELAP conditions. Based on this, Entergy concluded that lower cost 

11 alternatives such as those suggested are not viable mitigation alternatives. Entergy 

12 further explained that changes in system operation, such that fewer changes in valve 

13 position would be necessary, are not applicable since the manual valves are typically 

14 operated only for required testing and maintenance. The RHR valve is typically 

15 stroked during testing and maintenance or when the heat exchanger is needed for 

16 heat removal. Procedure and training improvements would provide very limited 

17 benefit since manual operation of valves is simple and within the skill of the 

18 personnel’s craft. Hardware modifications that would reduce the risk associated with 

19 these valve modifications are relatively complex since they would also require 

20 electrical power and control circuits in addition to the piping modifications and, 

21 therefore, would not be cost-beneficial. For the reasons cited above, less 

22 complicated hardware changes were not identified by Entergy (Entergy 2017b).

23 The staff notes that the set of SAMAs submitted is not necessarily all-inclusive, because 

24 additional, possibly even less expensive, alternatives can always be proposed. However, the 

25 staff concludes that the benefits of any additional modifications are unlikely to exceed the 

26 benefits of the modifications evaluated, and that the alternative improvements likely would not 

27 cost less than the least expensive alternatives evaluated when the subsidiary costs associated 

28 with maintenance, procedures, and training are considered. 

29 The staff concludes that Entergy used a systematic and comprehensive process for identifying 

30 potential plant improvements for RBS, which included reviewing a list of generic industry 

31 SAMAs (NEI 2005), reviewing insights from the RBS plant specific risk studies, including

32 internal initiating events as well as fire, seismic and other external initiated events, considering 

33 cost-beneficial plant improvements from previous SAMA analyses, and satisfactorily addressing 

34 the NRC staff’s questions regarding the SAMA identification process. The staff further 

35 concludes that the set of SAMAs evaluated in the ER, together with those evaluated in response 

36 to staff inquiries, is reasonably comprehensive and acceptable. 

37 F.4 Risk Reduction Potential of Plant Improvements

38 In the ER, and in response to the staff’s RAIs, the applicant evaluated the risk-reduction 

39 potential of the 50 SAMAs that were not screened out in the Phase I analysis and were retained 

40 for the Phase II evaluation. The applicant’s SAMA evaluations were generally performed using 

41 conservative assumptions (e.g., the SAMA is assumed to completely eliminate the associated 

42 risk). 

43 Table F-6 lists the assumptions considered to estimate the risk reduction for each of the 

44 evaluated SAMAs; the estimated risk reduction in terms of percent reduction in CDF, PDR, and 

45 OECR; the estimated total benefit (present value) of the averted risk, and the estimated 

46 implementation cost. The estimated benefits reported in Table F-6 reflect the combined benefit 
F-33

1 in both internal and external events. The determination of the implementation costs and 

2 benefits for the various SAMAs is further discussed in Sections F.5 and F.6, respectively. The 

3 SAMAs identified in bold in Table F-6 were found to be potentially cost-beneficial; the other 

4 listed SAMAs were determined not to be potentially cost-beneficial, which is further discussed in 

5 Section F.6.

6 With the exception of one SAMA associated with internal floods and two SAMAs associated with 

7 internal fires, Entergy used model re-quantification to determine the potential benefits for each

8 SAMA. The CDF, PDR, and OECR were estimated using the RBS R5A PRA model for the non9 flood and non-fire SAMAs. The changes made to the model to quantify the impact of SAMAs 

10 are detailed in Section D.2.3 of Attachment D to the ER (Entergy 2017a). Bounding evaluations 

11 (or analysis cases) were performed to address specific SAMA candidates or groups of similar 

12 SAMA candidates. 

13 For the internal flood related SAMA, SAMA 169 (Case 14), the benefit was determined by 

14 estimating the reduction in CDF using the 2012 internal flood analysis PRA model. Entergy

15 assumed that this SAMA (to improve the internal flooding procedures) eliminated the CDF of the 

16 top ten internal flooding scenarios that make up 48 percent of the total internal flood CDF. The 

17 benefit of completely eliminating the internal flood CDF was then assumed to be the ratio of the

18 total internal flooding CDF to the total internal events CDF multiplied by the total present dollar 

19 value equivalent associated with completely eliminating severe accidents from internal events at 

20 RBS, which is discussed in Section F.6.1. The benefit of SAMA 169 is then determined by 

21 completely eliminating the CDF of the top ten internal flooding scenarios, which is 48 percent of 

22 the benefit of completely eliminating the internal flood CDF.

23 For the internal fire related SAMAs, SAMA 183 (Case 36) and SAMA 185 (Case 37), the benefit 

24 was estimated using the results of the IPEEE fire analysis to eliminate the risk associated with 

25 the fire zone impacted by the SAMA. For SAMA 183, addition of incipient detection and 

26 suppression to the Division 1 Switchgear Room, it was assumed that the SAMA eliminated the 

27 CDF of the Division 1 Switchgear Room, which makes up 21 percent of the total fire CDF (see 

28 Table F-4 above). For SAMA 185, upgrade the Alternate Shutdown System (ASDS) panel to 

29 include additional system controls for the opposite division, it was assumed that the SAMA 

30 eliminated the CDF of the control room and (as stated in response to an NRC staff RAI 

31 (Entergy 2017b)) the control room ventilation room, which combined make up 42 percent of the 

32 total fire CDF (see Table F-4 above). The benefit resulting from complete elimination of the 

33 internal fire CDF was first calculated by multiplying the ratio of the total internal fire CDF to the

34 total internal events CDF by the total present dollar value equivalent associated with completely 

35 eliminating severe accidents from internal events at RBS, which is discussed in Section F.6.1.

36 The benefit of SAMAs 183 and 185 was then calculated by multiplying the benefit of completely 

37 eliminating the internal fire CDF by the percentage of the total internal fire CDF that each SAMA 

38 is assumed to eliminate. For the evaluation of these two fire-related SAMAs, the total internal 

39 fire CDF is taken to be a factor of 2.5 less than that from the IPEEE, which is the same as was 

40 used in determining the external events multiplier discussed in Section F.2.2.2 above.

41 Case 37, Reduce Risk from Fires That Require Control Room Evacuation, was used to evaluate 

42 the benefit for SAMA 185 by assuming this SAMA eliminated control room fires from the RBS 

43 fire CDF. The NRC staff noted in an RAI that fires other than in the control room may require 

44 control room evacuation and could benefit from the upgrade of the ASDS panel. Entergy was 

45 asked in an NRC staff RAI to identify the other control room abandonment areas and discuss 

46 the impact on the cost-benefit analysis of SAMA 185 from crediting the risk reduction benefit of 

47 this SAMA for the identified abandonment areas (NRC 2017a). In response to the RAI, Entergy 
F-34

1 indicated that, upon further review, fires in one other area in the control building have the 

2 potential to result in control room evacuation (Entergy 2017b). Smoke generated from fires in 

3 Fire Area C-17, Control Room Ventilation Room, could be transferred to the control room and 

4 ultimately require evacuation because of low visibility. A bounding analysis was performed by 

5 eliminating the CDF associated with these two rooms, which is 42 percent of the total fire CDF 

6 (see Table F-4 above). Entergy calculated a revised benefit using the same method as that 

7 described for Case 37, which is reported in Table F-6 (Entergy 2017b), and concluded that 

8 SAMA 185 is potentially cost-beneficial.

9 The benefit for these two fire-related cases (i.e., Cases 36 and 37) was determined based on 

10 the assumption that the percentage reduction in PDR and OECR is the same as the percentage 

11 reduction in CDF. An examination of the results for the risk reductions given in ER Table D.2-1 

12 indicates that this assumption is not necessarily conservative. Depending on the case, the 

13 reduction in OECR is often a factor of 1.1 to 1.4 times the CDF reduction. For Case 17, the 

14 OECR reduction is 2.4 times the CDF reduction. In response to an RAI to discuss the impact of 

15 this assumption on the cost-benefit analyses of SAMAs 183 and 185 (NRC 2017a), Entergy

16 determined that the PDR reductions in Table D.2-1 range from 0.6 to 3.8 times the CDF 

17 reduction, with an average of 1.4 (Entergy 2017b). Also, the OECR reductions range from 0.8 

18 to 3.7 times the CDF reduction, with an average of 1.3. If the benefit values for SAMA 183 are 

19 increased by a factor of 1.4, the 95th percentile benefit is $970,000 versus a cost of $1,100,000 

20 and SAMA 183 remains not cost-beneficial (Entergy 2017b). As noted above, SAMA 185 was 

21 found to be cost-beneficial in a revised analysis.

22 The NRC staff’s review of the assumptions and risk reduction potential for the SAMAs led to an 

23 additional RAI as discussed below.

24 Case 19 evaluates the benefit of SAMA 87, "Install digital feedwater upgrade," by setting the 

25 loss of feedwater system initiating event (IE-T3B) to false in the base model Level 1 and Level 2 

26 cutsets. Entergy was asked to discuss the potential for the additional benefit of the upgrade 

27 resulting from the reduction in the potential for loss of feedwater following other initiators

28 (NRC 2017a). Entergy re-evaluated Case 19 assuming that feedwater also does not fail 

29 following other initiators, and concluded that SAMA 87 remains not cost-beneficial 

30 (Entergy 2017b).

31 The NRC staff has reviewed Entergy’s bases for calculating the risk reduction for the various 

32 plant improvements and finds that the rationale and assumptions for estimating risk reduction 

33 are reasonable, generally conservative (i.e., the estimated risk reduction is higher than what 

34 would actually be realized), and acceptable for the SAMA analysis. The staff concludes that, 

35 with the above clarifications, the consideration of risk reduction potential of plant improvements 

36 by Entergy is sufficient and appropriate for use in the SAMA evaluation because it is technically 

37 sufficient and meets the guidance provided in NEI 05-01A.
F-35

Table F-6. SAMA Cost/Benefit Analysis for River Bend Station Unit 1a

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction Intern

and 

Exter

BeneCDF PDR

OEC

R

Case 1. DC Power 

Assumption: Eliminates battery-related failures 

(Analysis Case for SAMA Nos. 1, 2)

1—Provide additional battery capacity $2,130,000

2—Replace lead-acid batteries with fuel cells $4,080,000

8 8 8 $143,

Case 2. Improve Charger Reliability 

Assumption: Eliminates failure of battery chargers

(Analysis Case for SAMA No. 43)

43—Modify portable station generator to automatically align 

to 125 V DC battery chargers $400,000

2 7 7 $92,6

Case 3. Increase Availability of On-Site Alternating Current (AC) Power 

Assumption: Eliminates failure of on-site power feeds to safety related 

buses

(Analysis Case for SAMA No. 3)

3—Install a gas turbine generator with tornado protection $10,006,000

36 45 45 $753,

Case 4. Improve AC Power

Assumption: Adds independent power source to the 4160 VAC buses

(Analysis Case for SAMA No. 34)

34—Provide alternate feeds to essential loads directly from 

an alternate emergency bus $2,324,000

20 28 28 $457,
F-36

Case 5. Reduce Loss of Off-Site Power during Severe Weather

Assumption: Eliminates the severe weather contribution to loss of offsite 

power

(Analysis Case for SAMA No. 14)

14—Install an additional, buried off-site power source $2,500,000

21 22 21 $382,

Case 6. Provide Backup Emergency Diesel Generator (EDG) Cooling 

Assumption: Eliminates failure of SSW cooling to the EDGs

(Analysis Case for SAMA Nos. 21, 22)

21—Use fire water system as a backup source for diesel 

cooling $1,344,000

22—Add a new backup source of diesel cooling $2,000,000

3 5 5 $78,8

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

 CDF PDR 

OECR

Intern

and 

Extern

Benef

Case 7. Increase EDG Reliability 

Assumption: Eliminates failure of EDG fuel supply

(Analysis Case for SAMA Nos. 30, 204)

30—Provide a portable EDG fuel transfer pump $1,477,000

204—Added capability to cross-tie fuel oil supply to 

emergency diesel generators $200,000

3 3 3 $48,7

Case 8. Improve Diesel Generator Reliability

Assumption: Eliminates common cause failure of failure to start EDGs

0 <1 <1 $6,50
F-37

(Analysis Case for SAMA No. 33)

33—Provide a diverse swing diesel generator air start 

compressor $100,000

Case 9. Reduce Plant Centered Loss of Off-site Power 

Assumption: Eliminates failure of switchyard transformers and main power 

feeds from the switchyard

(Analysis Case for SAMA No. 38)

38—Protect service transformers from failure$9,998,000

57 51 51 $946,

0 

Case 10. Improve Service Water Cooling (SWC) Fans

Assumption: Eliminates failure of the SWC to the NSW system

(Analysis Case for SAMA No. 206) 

206—Improve flow capacity of SWC fans for summer 

conditions$200,000

233 $43,6

Case 11. High Pressure Injection System

Assumption: Include independent injection train

(Analysis Case for SAMA No. 44) 

44—Install an independent active or passive high pressure 

injection system$8,800,000

17 14 15 $279,

0 
F-38

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

CDF PDR 

OECR

Inter

and 

Exte

Bene

Case 12. Extend Reactor Core Isolation Cooling (RCIC) Operation

Assumption: Eliminates RCIC turbine failure to run events

(Analysis Case for SAMA No. 46)

46—Raise RCIC backpressure set points $100,000

<1 1 <1 $16,8

Case 13. Improve Automatic Depressurization System (ADS)

Assumption: Eliminates failure of air supplies to all ADS Safety Relief Valve 

accumulators

(Analysis Case for SAMA No. 51)

51—Modify automatic depressurization system components 

to improve reliability $1,177,000

0 <1 <1 $3,20

Case 14. Improve Internal Flooding Procedures 

Assumption: Eliminates contribution from the top 10 internal flooding 

scenarios

(Analysis Case for SAMA No. 169)

169—Improve internal flooding procedures $200,000

n/a n/a n/a $219

0 

Case 15. Revise FLEX Procedures for Non-ELAP (Extended Loss of AC 

Power) Conditions

Assumption: Eliminates failure of the RCIC pump, power supply, suction 

paths, and sensor signals

(Analysis Case for SAMA No. 205)

205—Revise FLEX procedures to allow use of FLEX 

equipment in non-ELAP conditions $200,000

47 56 56 $949

0 

Case 16. Emergency Core Cooling System (ECCS) Low Pressure Interlock

Assumption: Eliminates low pressure coolant injection (LPCI) and low 

pressure core spray (LPCS) permissives and interlock failures

(Analysis Case for SAMA No. 71) 

71—Modify procedures to allow operators to defeat the low 

reactor pressure interlock circuitry that inhibits opening the 

LPCI or LPCS injection valves following sensor or logic 

failures that prevent all low pressure injection valves from 

opening $50,000

0 <1 0 $2,10
F-39

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

CDF PDR 

OECR

Intern

and 

Extern

Benef

Case 17. Residual Heat Removal (RHR) Heat Exchangers

Assumption: Eliminates failure of SSW to provide cooling water to the heat 

exchangers

(Analysis Case for SAMA No. 79)

79—Implement modifications to allow manual alignment of 

the fire water system to RHR heat exchangers $1,960,000

4 10 10 $150,

Case 18. Service Water System Reliability 

Assumption: Eliminates SSW pump common cause failures, fail-to-start 

events, fail-to-run events and maintenance events

(Analysis Case for SAMA Nos. 75, 80)

75—Add redundant DC control power for SSW pumps

80—Add another SSW pump

$2,188,000

$5,900,000

29 29 29 $517,

Case 19. Main Feedwater System Reliabilityb

Assumption: Eliminates loss of main feedwater as an accident initiator and 

in response to other initiators

(Analysis Case for SAMA No. 87)

87—Install digital feedwater upgrade $900,000

n/a n/a n/a $57,4

Case 20. Increases Availability of Room Cooling

Assumption: Eliminates failure of room cooling for ECCS and RCIC rooms 

in the Auxiliary Building

(Analysis Case for SAMA No. 93) 

93—Provide a redundant train or means of ventilation $2,200,000

13 14 14 $242,

Case 21. Increase Availability of Diesel Generator Systems through 

Heating, Ventilation, and Cooling (HVAC) Improvements

Assumption: Eliminates failure of cooling to the three EDG rooms

(Analysis Case for SAMA Nos. 100, 101, 102)

100—Diverse EDG HVAC logic

101—Install additional fan and louver pair for EDG HVAC

102—Operator procedure revisions to provide additional 

space cooling to the EDG room via the use of portable 

equipment

$1,148,000

$6,000,000

$150,000

3 3 3 $51,0
F-4

0

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

CDF PDR 

OECR

Intern

and 

Exter

Benef

Case 22a. Procedures for Loss of Room Cooling (HPCS)

Assumption: Eliminates failure of cooling to high pressure core spray 

(HPCS) pump room

(Analysis Case for SAMA No. 94a)

94a—Enhance procedures for actions on loss of HVAC 

(HPCS) $100,000

5 5 5 $93,7

Case 22b. Procedures for Loss of Room Cooling (RHR B/C)

Assumption: Eliminates failure of cooling to RHR B and C pump rooms

(Analysis Case for SAMA No. 94b)

94b—Enhance procedures for actions on loss of HVAC 

(RHR B/C) $150,000

3 4 3 $56,7

Case 22c. Procedures for Loss of Room Cooling (LPCS, RHR A)

Assumption: Eliminates failure of cooling to the LPCS and RHR A pump 

rooms

(Analysis Case for SAMA No. 94c)

94c— Enhance procedures for actions on loss of HVAC 

(LPCS, RHR A) $150,000

5 6 6 $103,

Case 23. Trip/Shutdown Risk 

Assumption: Reduces all initiating event frequencies except those for loss 

of coolant accidents (LOCAs), pipe breaks, and LOSP by 10 percent

(Analysis Case for SAMA No. 197)

197—Generation Risk Assessment implementation into 

plant activities (trip/shutdown risk modeling) $500,000

3 4 3 $55,1

Case 24. Improve Availability of SRVs and Main Steam Isolation Valves 

(MSIVs) 

Assumption: Eliminates failure of SRV air supply, SRV common cause 

events, and MSIVs

(Analysis Case for SAMA No. 108)

108—Improve SRV and MSIV pneumatic components $1,500,000

0 <1 <1 $3,70
F-41

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

CDF PDR 

OECR

Intern

and 

Exter

Benef

Case 25. Improve Suppression Pool Cooling 

Assumption: Eliminates failure of suppression pool cooling

(Analysis Case for SAMA No. 110)

110—Install an independent method of suppression pool 

cooling $5,800,000

57 64 64 $1,10

0 

Case 26. Increase Availability of Containment Heat Removal

Assumption: Eliminates failure of safety related containment unit coolers

(Analysis Case for SAMA Nos. 115, 120) 

115—Install a passive containment spray system

120—Install an unfiltered hardened containment vent

$5,800,000

$13,000,000

53 62 62 $1,05

0 

Case 27. Containment Filtered Vent for ATWS 

Assumption: Same as Case 26 plus reduces population dose for each 

release category by a factor of 5

(Analysis Case for SAMA No. 162)

162—Install an ATWS sized filtered containment vent to 

remove decay heat $40,000,000

53 92 62 $1,23

0 

Case 28. Control Rod Drive (CRD) Improvements 

Assumption: Eliminates CRD injection events and loss of CRD as an 

initiator

(Analysis Case for SAMA No. 59)

59—Implement ability to cross-tie safety related power to 

CRD pumps for vessel injection during LOSP $656,000

2 1 3 $32,4

Case 29. Increase Recovery Time of ECCS upon Loss of SSW

Assumption: Eliminates failure of room cooling for the LPCI and LPCS 

pump rooms

(Analysis Case for SAMA Nos. 97, 198) 

97—Perform study and analysis to add steps to trip 

unneeded ECCS pumps on loss of HVAC

198—Develop a procedure for alternating operation of low 

pressure ECCS pumps for loss of SSW

$100,000

$200,000

8 9 9 $153,
F-4

2

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

CDF PDR 

OECR

Intern

and 

Extern

Benef

Case 30. Reduce Hydrogen Ignition 

Assumption: Eliminates failure of igniters

(Analysis Case for SAMA Nos. 128, 138)

128—Provide post-accident containment inerting system

138—Install passive hydrogen system

$2,665,000

$760,000

0 1 1 $12,0

Case 31. Improve RHR Heat Exchanger Availability 

Assumption: Eliminates failure of SSW supply to the RHR heat exchanger

(Analysis Case for SAMA No. 201)

201—Add a bypass around the RHR Hx (heat exchanger) 

outlet valves $2,832,000

4 4 4 $75,8

Case 32. Improve RCIC Lube Oil Cooling 

Assumption: Eliminates failure to cool RCIC lube oil

(Analysis Case for SAMA No. 202)

202—Add a redundant RCIC lube oil cooling path $1,803,000

<1 <1 <1 $8,00

Case 33. MSIV Design to Decrease Containment Bypass Scenarios

Assumption: Eliminates failure of the MSIVs to close

(Analysis Case for SAMA No. 147)

147—Improve MSIV design to decrease likelihood of 

containment bypass scenarios $1,000,000

0 <1 0 $2,10

Case 34. Standby Liquid Control (SLC) System 

Assumption: Eliminates failure of the SLC system

(Analysis Case for SAMA Nos. 156, 158) 

156—Increase boron concentration in the SLC system

158—Provide ability to use CRD or reactor water cleanup 

(RWCU) for alternate boron injection

$50,000

$100,000

0 <1 <1 $7,60

Case 35. SRV Seat

Assumption: Eliminates SRV inadvertent opening initiator and basic events 

for stuck open SRVs

(Analysis Case for SAMA No. 160) 

160—Increase safety relieve valve (SRV) reseat reliability $3,200,000

36 42 41 $710,
F-4

3

Table F-6. SAMA Cost/Benefit Analysis for River Bend Station Unit 1a (continued)

Analysis Case, Analysis Assumption, Individual SAMAs, and Cost Estimates

% Risk Reduction

CDF PDR 

OECR

Intern

and 

Exter

Bene

Case 36. Add Fire Suppression Systemc

Assumption: Eliminates contribution from Division 1 

Switchgear Room fires

(Analysis Case for SAMA No. 183)

183—Add automatic fire suppression [Specifically, addition 

of incipient detection and suppression to Division 1 

Switchgear Room] $1,100,000

n/a n/a n/a $242,

Case 37. Reduce Risk from Fires that Require Control Room Evacuationd

Assumption: Eliminates contribution from Control Room fires and Control 

Room Ventilation Room fires

(Analysis Case for SAMA No. 185)

185—Upgrade the Alternate Shutdown System (ASDS) 

panel to include additional system controls for opposite 

division $790,000

n/a n/a n/a $346,

Case 38. Large Break LOCA 

Assumption: Eliminates all large and medium LOCA initiating events

(Analysis Case for SAMA No. 190)

190—Install digital large break LOCA protection system $13,000,000

0 <1 <1 $7,80

Case 5.b.ii. Reduce Risk of Event FPW-XHE-LO-T2SBOe

Assumption: Reduces failure to align firewater for injection event ZHE-FOFPWSTARTSB by 50 percent; also reduces by 50 percent the failure of 

associated dependent HFEs, including Event FPW-XHE-LO-T2SBO

(Analysis Case for SAMA No. 5.b.ii) 

5.b.ii—Improve Procedures and Training on Injection with

the Fire Water System $100,000

n/a n/a n/a $73,3

n/a – not applicable or not available

a SAMAs in bold are potentially cost-beneficial.

b Analysis Case assumptions and benefit estimates were updated in response to NRC staff RAI 6.b. Revised risk reduction estimate

(Entergy 2017b). 

c Risk reduction and benefit estimates were updated in response to NRC staff RAI 6.c.ii (Entergy 2017b). 

d Analysis Case assumptions, risk reduction estimates, and benefit estimates were updated in response to NRC staff RAI 6.c.i (Enter

e New SAMA evaluated in response to NRC staff RAI 5.b.ii (Entergy 2017b).
F-44

1 F.5 Cost Impacts of Candidate Plant Improvements

2 As enumerated in Table F-6, Entergy estimated the costs of implementing the 50 Phase II 

3 SAMAs using other applicants’ estimates for similar improvements and the development of 

4 site-specific cost estimates, where appropriate. Entergy provided cost estimates for 

5 implementation of the RBS SAMAs in Table D.2-1 of Attachment D to the ER (Entergy 2017a). 

6 Entergy stated in the ER that the cost ranges shown in Table F-7 below were used based on its

7 review of previous SAMA applications (Entergy 2017a).

8 Table F-7. Estimated Cost Ranges for SAMA Applications

9 Entergy also stated in the ER that in most cases the development of detailed cost estimates 

10 was not necessary, particularly in the case of hardware modifications, because the cost of the 

11 modification clearly exceeded the benefit. When required, the RBS site-specific cost estimates 

12 were based on the engineering judgment of project engineers experienced in performing design 

13 changes at the facility. These estimates were compared, where possible, to estimates 

14 developed and used at plants of similar design and vintage.

15 The staff reviewed the applicant’s cost estimates, presented in Table D.2-1 of Attachment D to 

16 the ER (Entergy 2017a). For certain improvements, the staff also compared the cost estimates 

17 to estimates developed elsewhere for similar improvements, including estimates developed as 

18 part of other licensees’ analyses of SAMAs for operating reactors. The NRC staff also reviewed 

19 the basis for the cost estimates during the NRC audit of the SAMA analysis (NRC 2017a).

20 The benefit for Case 9 (Reduce Plant Centered Loss of Off-site Power) was evaluated by 

21 eliminating the plant centered events contribution to the LOSP initiator and removal of 

22 transformer failures. This case was used for the cost-benefit assessment of SAMA 38 - Protect 

23 service transformers from failure. The RBS specific cost estimate is almost $10,000,000. In an 

24 NRC staff RAI, Entergy was asked to describe what changes/modifications are associated with 

25 the implementation of this SAMA (NRC 2017a). In response to the RAI, Entergy indicated the 

26 scope of the modification for SAMA 38 is construction of structures that would provide protection 

27 (from hurricane or tornado flying debris and from explosion of a nearby transformer) for 

28 transformers and associated cabling and buses running from the transformers into nearby 

29 buildings (Entergy 2017b). The protection methods are to include walls, metal caging, or other 

30 suitable barriers. Protection is provided for three normal transformers and four preferred 

31 transformers. Failure of any of the seven service transformers has the potential to trip the plant, 

32 so all are protected. Power feed lines from offsite to the transformers are not protected by this 

33 SAMA. The conceptual design to address this SAMA included design and construction of two 

34 buildings that provide protection from high wind missiles and explosions from nearby 

35 transformers. Entergy did not identify any other lower cost alternative designs that satisfied the 

36 SAMA's objectives (Entergy 2017b).

Type of Change Estimated Cost Range

Procedural only $50K

Procedural change with engineering or training required $50K–$200K

Procedural change with engineering and testing or 

training required

$200K–$300K

Hardware modification $100K to > $1000K
F-45

1 The staff concludes that the cost estimates provided by Entergy are reasonable and sufficient 

2 for use in the SAMA evaluation because economic viability of the proposed modification could 

3 be adequately gauged and the process meets the guidance provided in NEI 05-01A.

4 F.6 Cost-Benefit Comparison

5 Entergy’s cost-benefit analysis and the staff’s review are described in the following sections.

6 F.6.1 Entergy’s Evaluation

7 The methodology used by Entergy was based primarily on NRC’s guidance for performing 

8 cost-benefit analyses, NUREG/BR–0184 (NRC 1997a) which is referenced in the guidance 

9 provided in NEI 05-01A. As described in Sections 4.15.1.3 and D.1.5.4 of the ER 

10 (Entergy 2017a), the net value was determined for each SAMA according to the following 

11 formula:

12 Net Value = (APE + AOC + AOE + AOSC) – COE 

13 where, 

14 APE (averted public exposure) = present value of APE costs ($)

15 AOC (averted offsite property damage costs) = present value of AOC ($)

16 AOE (averted occupational exposure) = present value of AOE costs ($)

17 AOSC (averted onsite costs) = present value of AOSC ($)

18 COE = cost of enhancement ($)

19 If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 

20 benefit associated with the SAMA, and it is not considered to be cost beneficial. Entergy’s 

21 derivation of each of the associated costs is summarized next.

22 NEI 05-01A states that two sets of estimates should be developed for discount rates of 

23 7 percent and 3 percent (NEI 2005). Entergy provided a base set of results using a discount 

24 rate of 7 percent and a 29-year analysis period with a sensitivity case at 3 percent. 

25 F.6.1.1 Averted Public Exposure (APE) Costs

26 Entergy defined annual off-site exposure risk, or averted public exposure (APE), as the 

27 monetary value of accident risk avoided from population doses after discounting 

28 (Entergy 2017a). The APE costs were calculated using the following formula:

29 APE = Annual reduction in public exposure (Δ person-rem per year)

30 × monetary equivalent of unit dose ($5,500 per person-rem)

31 × present value conversion (NRC 1997a)
F-46

1 The monetary equivalent of unit dose of $5,500 per person-rem was determined using the 

2 methodology in NUREG-1530, Rev. 1 (NRC 2015b). The annual reduction in public exposure 

3 was calculated according to the following formula: 

4 Annual reduction in public exposure = (Accident frequency without modification ×

5 accident population dose without modification) – (Accident frequency with 

6 modification × accident population dose with modification)

7 As stated in NUREG/BR–0184 (NRC 1997a), it is important to note that the monetary value of 

8 the public health risk after discounting does not represent the expected reduction in public 

9 health risk due to a single accident. Rather, it is the present value of a stream of potential 

10 losses extending over the remaining lifetime (in this case, the 20-year renewal period plus the 

11 nine years remaining on the current operating license at the time the analysis was performed) of 

12 the facility. Thus, it reflects the expected annual loss due to a single accident, the possibility 

13 that such an accident could occur at any time over the analysis period, and the effect of 

14 discounting these potential future losses to present value. For a discount rate of 7 percent and 

a 29-year analysis period with a CDF of 2.8 × 10−6 15 per reactor-year and a monetary equivalent 

16 of unit dose of $5,500 per person-rem, the applicant calculated an APE cost of approximately 

17 $82,600 for internal events (Entergy 2017a).

18 F.6.1.2 Averted Offsite Property Damage Costs (AOC)

19 Entergy defined annual offsite economic cost risk, or averted offsite property damage costs 

20 (AOC), as the monetary value of risk avoided from offsite property damage after discounting 

21 (Entergy 2017a). The AOC values were calculated using the following formula, consistent with 

22 the guidance in NUREG/BR–0184 (NRC 1997a): 

23 AOC = Annual reduction in offsite property damage × present value conversion 

24 The annual reduction in offsite property damage was calculated according to the 

25 following formula:

26 Annual reduction in offsite property damage = (Accident frequency without 

27 modification × accident property damage without modification) – (Accident 

28 frequency with modification × accident property damage with modification)

For a discount rate of 7 percent and a 29-year analysis period with a CDF of 2.8 × 10−6 29 per year, 

30 the applicant calculated an AOC of approximately $91,000 for internal events (Entergy 2017a).

31 F.6.1.3 Averted Occupational Exposure (AOE) Costs

32 Entergy defined annual on-site or occupational exposure risk, or AOE, as the avoided onsite 

33 exposure (Entergy 2017a). Similar to the APE calculations, the applicant calculated costs for 

34 immediate onsite exposure. Long-term onsite exposure costs were calculated consistent with 

35 guidance in NUREG/BR–0184 (NRC 1997a).

36 Entergy derived the values for averted occupational exposure from information provided in 

37 Section 5.7.3 of NUREG/BR–0184 (NRC 1997a). Best estimate values provided for immediate 

38 occupational dose (3,300 person-rem) and long-term occupational dose (20,000 person-rem 

39 over a 10-year clean-up period) were used. The present value of these doses was calculated 

40 using the equations provided in the NUREG/BR–0184 handbook with a monetary equivalent of 
F-47

1 unit dose of $5,500 per person-rem, a real discount rate of 7 percent, and an analysis period of 

2 29 years to represent the remaining life of RBS. Immediate and long-term onsite exposure 

costs were summed to determine AOE cost. For a CDF of 2.8 × 10−6 3 per year, the applicant 

4 calculated an AOE cost of approximately $3,400 for internal events (Entergy 2017a).

5 F.6.1.4 Averted Onsite Costs (AOSC)

6 Averted Onsite Costs (AOSC) includes averted cleanup and decontamination costs and averted 

7 power replacement costs. Repair and refurbishment costs are considered for recoverable 

8 accidents only and not for severe accidents. The applicant derived the values for AOSC based 

9 on information provided in Section 5.7.6 of NUREG/BR–0184 (NRC 1997a). This cost element 

10 was divided into two parts: the onsite cleanup and decontamination cost, also commonly 

11 referred to as averted cleanup and decontamination costs; and the replacement power cost 

12 (RPC).

13 Averted cleanup and decontamination costs (ACC) were calculated using the following formula:

14 ACC = Annual CDF reduction

15 × present value of clean-up costs per core damage event

16 × present value conversion factor

17 The total cost of clean-up and decontamination subsequent to a severe accident is estimated in 

NUREG/BR–0184 to be $1.5 × 109 18 (undiscounted). This value was converted to present costs 

19 spread over a 10-year clean-up period and integrated over the term of the proposed license 

20 extension. For a discount rate of 7 percent and a 29-year remaining RBS life with a CDF of 

2.8 × 10−6 21 per year, Entergy calculated an ACC of approximately $37,300 from internal events 

22 (Entergy 2017a).

23 Long-term RPCs were calculated using the following formula: 

24 RPC = Annual CDF reduction

25 × present value of replacement power for a single event

26 × factor to account for remaining service years for which replacement power

27 is required

28 × reactor power scaling factor

29 The applicant based its calculations on a net electric output of 967 megawatts-electric (MWe) 

30 and scaled up from the 910 MWe reference plant in NUREG/BR-0184 (NRC 1997a). Therefore, 

31 the applicant applied a power-scaling factor of 1.06 (967 / 910) to determine the RPC. For a 

discount rate of 7 percent and a 29-year remaining RBS life with a CDF of 2.8 × 10−6 32 per year, 

33 Entergy calculated an RPC of $41,300 from internal events (Entergy 2017a). AOSC, the 

34 summation of ACC and RPC, is therefore approximately $78,600 from internal events for the 

35 29-year analysis period and a discount rate of 7 percent.
F-48

1 Using the above equations, Entergy estimated the total present dollar value equivalent 

2 associated with completely eliminating severe accidents due to internal events at RBS to be 

3 about $255,700 (Entergy 2017a, Table D.1-31).

4 Entergy multiplied the internal events estimated benefit by a factor of 7 to account for the risk 

5 contributions from external and internal flooding events to yield the internal and external benefit 

6 or Maximum Averted Cost Risk (MACR) (Entergy 2017a). Additionally, the internal and external 

7 benefits were multiplied by a factor of 4 to account for uncertainties in the CDF calculation 

8 (Entergy 2017a).

9 F.6.1.5 Entergy’s Results

10 In Entergy’s analysis, if the implementation costs for a candidate SAMA exceeded the 

11 calculated benefit, the SAMA was determined not cost beneficial. If the benefit exceeded the 

12 estimated cost, the SAMA candidate was considered cost beneficial. In the analysis, 10 SAMA 

13 candidates were found to be potentially cost beneficial (Entergy 2017a, Entergy 2017b). The 

14 results of the cost-benefit evaluation are presented in Table F-6. 

15 The potentially cost-beneficial SAMAs are:

16 • SAMA No. 94a—Enhance procedures for actions on loss of HVAC (HPCS)

17 • SAMA No. 94b—Enhance procedures for actions on loss of HVAC (RHR B/C)

18 • SAMA No. 94c—Enhance procedures for actions on loss of HVAC (LPCS, RHR A)

19 • SAMA No. 97—Perform study and analysis to add steps to trip unneeded ECCS

20 pumps on loss of HVAC

21 • SAMA No. 102—Operator procedure revisions to provide additional space cooling to

22 the EDG room via the use of portable equipment

23 • SAMA No. 169—Improve internal flooding procedures

24 • SAMA No. 185—Upgrade the Alternate Shutdown System (ASDS) panel to include

25 additional system controls for opposite division

26 • SAMA No. 198—Develop a Procedure for Alternating Operation of Low Pressure

27 ECCS Pumps for Loss of SSW

28 • SAMA No. 205—Revise FLEX procedures to allow use of FLEX equipment in non29 ELAP conditions

30 • SAMA No. 5.b.ii—Improve Procedures and Training on Injection with the Fire Water

31 System

32 Entergy stated in ER Section 4.15.1.4, and in response to RAIs, that each of these potentially 

33 cost-beneficial SAMAs have been entered into the action tracking process at RBS to be 

34 evaluated for implementation (Entergy 2017a, Entergy 2017b).

35 F.6.2 Review of Entergy’s Cost-Benefit Evaluation

36 Based primarily on NUREG/BR–0184 (NRC 1997a) and NEI guidelines on discount rates 

37 (NEI 2005), the staff determined the cost-benefit analysis performed by Entergy was consistent 

38 with the guidance. Three SAMA candidates (i.e., SAMAs 97, 169, and 205) were found to be 

39 potentially cost beneficial based on the benefit from internal and external events, assuming an 

40 external events multiplier of 7 (Entergy 2017a).

41 The applicant considered possible increases in benefits from analysis uncertainties on the 

42 results of the SAMA assessment. In the ER (Entergy 2017a), Entergy stated that the 
F-49

95th 1 percentile value of the RBS CDF was a factor of 3.58 greater than the mean CDF. 

2 A multiplication factor of 4 was selected by the applicant to account for uncertainty. Five 

3 additional SAMA candidates (i.e., SAMAs 94a, 94b, 94c, 102, and 198) were determined to be 

4 potentially cost-beneficial as a result of the uncertainty analysis (Entergy 2017a).

5 The NRC staff considers the multipliers of 4 to account for uncertainty and 7 to account for 

6 external events provide adequate margin and are acceptable for the SAMA analysis.

7 In the ER, Entergy analyzed the sensitivity of the cost-benefit analysis results to a lower 

8 discount rate of 3 percent. This sensitivity analysis was performed applying the external events 

9 multiplier of 7 to account for external events. No additional cost-beneficial SAMAs were 

10 identified as a result of this sensitivity analysis (Entergy 2017a).

11 As discussed in Section F.2 above Entergy performed additional sensitivity analyses on MACCS 

12 input parameters for faster and slower evacuation speeds, for higher and lower percentages of 

13 the population that are assumed to evacuate, for a delay in the declaration of the general 

14 emergency, and for a longer decontamination time and higher non-farm decontamination costs. 

15 No additional cost-beneficial SAMAs were identified as a result of these sensitivity analyses 

16 (Entergy 2017a).

17 As discussed in Section F.4 above, Case 37, Reduce Risk From Fires That Require Control 

18 Room Evacuation, was used to evaluate the benefit for SAMA 185 by assuming this SAMA 

19 eliminated control room fires from the RBS fire CDF. Entergy was asked in an NRC staff RAI to 

20 identify the other control room abandonment areas and discuss the impact on the cost-benefit 

21 analysis of SAMA 185 from crediting the risk reduction benefit of this SAMA for the identified 

22 abandonment areas (NRC 2017a). In response to the RAI, Entergy explained that smoke 

23 generated from fires in Fire Area C-17, Control Room Ventilation Room, could be transferred to 

24 the control room and ultimately require evacuation because of low visibility (Entergy 2017b). A 

25 bounding analysis was performed by eliminating the CDF associated with these two rooms, 

26 which is 42 percent of the total fire CDF (see Table F-4 above). Entergy calculated a revised 

27 benefit using the same method as that described for Case 37 in Section F.4, which is reported 

28 in Table F–6. Based on the result of the baseline evaluation, SAMA 185 was determined not to 

be cost-beneficial. However, based on the result of the 95th 29 percentile CDF uncertainty 

30 analysis, SAMA 185 was nonetheless determined to be potentially cost-beneficial. Entergy 

31 stated that SAMA 185 will be entered into the RBS action tracking system to be evaluated for 

32 further implementation (Entergy 2017b).

33 As discussed in Section F.3.2 above, Event FPW-XHE-LO-T2SBO, "operator fails to follow 

34 attachment 2 for SBO," is addressed by several hardware modifications. Entergy was asked in 

35 an NRC staff RAI to discuss the potential for a SAMA to improve the procedure or training for 

36 injection of fire water for SBO (NRC 2017a). In response to the RAI, Entergy evaluated a new 

37 SAMA to improve the procedures and training on injection with the fire water system. This 

38 evaluation assumed that the failure to align firewater for injection event is reduced by 

50 percent. This resulted in a baseline internal and external event benefit of $73,300 and a 95th 39

40 percentile CDF benefit of $293,000. Since this SAMA requires both procedure and training 

41 improvements, the implementation cost was estimated to be $100,000 (see Table F–7). Based 

42 on these results, Entergy concluded that this SAMA is potentially cost-beneficial as a result of 

43 the uncertainty analysis. Entergy stated that this SAMA will be entered into the RBS action 

44 tracking system to be evaluated for further implementation (Entergy 2017b). This SAMA is 

45 included in Table F–6 as SAMA RAI 5.b.ii, under Case 5.b.ii.
F-50

1 As discussed in Section F.3.2 above, for Event ADS-XHE-FO-INDIV, "operator fails to start ADS 

2 by opening individual ADS valves or SRVs,” Entergy was asked in an NRC staff RAI to consider 

3 improvements in procedures and training (NRC 2017a). Entergy responded to the RAI that a

4 new SAMA case was performed to evaluate the potential benefit from improvements in 

5 procedures and training for this event. The case assumes the improvements reduce the failure 

6 probability of ADS-XHE-FO-INDIV (and also dependent events including this event) by a 

7 conservative value of 50 percent. The baseline internal and external benefit was found to be 

$16,000 and the 95th 8 percentile CDF uncertainty benefit was found to be $64,000. Because this 

9 SAMA requires both procedure and training improvements, the implementation cost was 

10 estimated to be $100,000 (see Table F-7). Based on these results, Entergy concluded that this 

11 SAMA would not be cost-beneficial (Entergy 2017b).

12 The staff concludes that the cost-benefit results provided by Entergy are reasonable and 

13 sufficient for use in the SAMA evaluation because the process and methodology for estimating 

14 the MACR, and for performing uncertainty and sensitivity analyses, meets the guidance 

15 provided in NEI 05-01A (NEI 2005) and NUREG/BR–0184 (NRC 1997a). 

16 F.7 Conclusions

17 Entergy considered 206 candidate SAMAs based on NRC and industry documentation of 

18 potential plant improvements, its review of SAMA analyses for other BWR plants, RBS IPE and 

19 IPEEE assessments, and risk-significant contributors at RBS from plant-specific probabilistic 

20 risk assessment models. Phase I screening reduced the list to 48 unique SAMA candidates by 

21 eliminating SAMAs that were not applicable to RBS, had already been implemented at RBS, or 

22 were combined into a more comprehensive or plant-specific SAMA. One of these SAMA 

23 candidates was subdivided into three SAMA candidates, increasing the number of Phase II 

24 SAMA candidates to 50. 

25 For these remaining SAMA candidates, Entergy performed a cost-benefit analysis with results 

26 shown in Table F–6 above. The cost-benefit analysis identified eight potentially cost-beneficial 

27 SAMAs (Phase II SAMA Nos. 94a, 94b, 94c, 97, 102, 169, 198, and 205). Sensitivity cases 

28 were analyzed for the present value discount rate and the MACCS input parameters. In 

29 response to an NRC staff RAI concerning potential lower cost alternatives; Entergy identified 

30 two additional potentially cost-beneficial SAMA (i.e., SAMA 5.b.ii and SAMA 185).

31 The staff reviewed the Entergy SAMA analysis and concludes that, as discussed above, the 

32 methods used and implementation of the methods were reasonable. Based on the applicant’s 

33 treatment of SAMA benefits and costs, the staff finds that the SAMA evaluations performed by 

34 Entergy are reasonable and sufficient for the license renewal submittal.

35 The staff agrees with Entergy’s conclusion that the 10 candidate SAMAs discussed in this 

36 section are potentially cost beneficial, which was based on a conservative treatment of costs, 

37 benefits, and uncertainties. This conclusion of a small number of potentially cost-beneficial 

38 SAMAs is consistent with the low residual level of risk indicated in the RBS PRA and the fact 

39 that Entergy has already implemented the plant improvements identified from the IPE and 

40 IPEEE. Because the potentially cost-beneficial SAMAs do not relate to aging management 

41 during the period of extended operation, they do not need to be implemented as part of license 

42 renewal in accordance with Title 10 of the Code of Federal Regulations, Part 54. Nevertheless, 

43 Entergy stated that each of these potentially cost beneficial SAMAs has been entered into the 

44 RBS action tracking system to further evaluate their implementation.
F-51

1 F.8 References

2 [ASME/ANS] American Society of Mechanical Engineers/American Nuclear Society. 2009. 

3 "Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency 

4 Probabilistic Risk Assessment for Nuclear Power Plant Applications." ASME/ANS RA-Sa-2009.

5 February 2, 2009.

6 [EPRI] Electric Power Research Institute. 1992. “Fire-Induced Vulnerability Evaluation (FIVE),” 

7 TR-100370. Professional Loss Control, Inc. Palo Alto, CA. April 1992.

8 [EPRI] Electric Power Research Institute. 1994. “EPRI Fire PRA Implementation Guide.” 

9 EPRI Report Project 3385–01. Draft, Parkinson, W.J., et al. Palo Alto, CA. January 1994.

10 [EPRI] Electric Power Research Institute. 2012. “Seismic Evaluation Guidance.” EPRI Report 

11 1025287. Palo Alto, CA. November 2012. ADAMS No. ML12333A170.

12 [EPRI] Electric Power Research Institute. 2014. Letter from Stuart Lewis, EPRI, to 

13 Anthony R. Petrangelo, Nuclear Energy Institute. Subject: Fleet Seismic Core Damage 

14 Frequency Estimates for Central and Eastern U.S. Nuclear Power Plants Using New Site15 Specific Seismic Hazard Estimates. March 11, 2014. ADAMS No. ML14083A586

16 [Entergy] Entergy Operations, Inc. 1993. Letter from W. H. Odel, Entergy to U.S. NRC 

17 Document Control Desk. Subject: River Bend Station - Unit 1, Docket No. 50-458. February 1, 

18 1993. ADAMS Accession No. ML080140384 (nonpublic document) 

19 [Entergy] Entergy Operations, Inc. 1995. Letter from John R. McGaha, Jr., Entergy to U.S. 

20 NRC Document Control Desk. Subject: River Bend Station - Unit 1, Docket No. 50-458, License 

21 No. NPF-47, Supplemental Response to Generic Letter 88-20. June 30, 1995. ADAMS 

22 Accession No. ML080140054 (nonpublic document) 

23 [Entergy] Entergy Operations, Inc. 2014a. Letter from Eric W. Olsen, Entergy, to U.S. Nuclear 

24 Regulatory Commission Document Control Desk. Subject: Response to NRC Request for 

25 Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term 

26 Task Force Review of Insights from the Fukushima Dai-ichi Accident, River Bend Station Unit 1, 

27 Docket Number 50-458, License No. NPF-47. March 12, 2014. ADAMS Accession 

28 No. ML14073A648.

29 [Entergy] Entergy Operations, Inc. 2014b. Letter from Willis F. Mashburn, Entergy, to U.S. 

30 Nuclear Regulatory Commission Document Control Desk. Subject: Entergy Operations Inc. 

31 Seismic Hazard and Screening Report (CEUS Sites), Response NRC Request for Information 

32 Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force 

33 Review of Insights from the Fukushima Dai-ichi Accident, River Bend Station - Unit 1, Docket 

34 No. 050-458, License No. NPF-47. March 26, 2014. ADAMS Accession No. ML14091A426.

35 [Entergy] Entergy Operations, Inc. 2016a. Letter from William F. Maguire, Entergy, to 

36 U.S. Nuclear Regulatory Commission Document Control Desk. Subject: Seismic Mitigating

37 Strategies Assessment, River Bend Station Unit - 1, Docket Number 50-458, License No. 

38 NPF-47. August 31, 2016. ADAMS Accession No. ML16251A069.

39 [Entergy] Entergy Operations, Inc. 2016b. Letter from William F. Maguire, Entergy, to 

40 U.S. Nuclear Regulatory Commission Document Control Desk. Subject: Mitigating Strategies

41 Assessment (MSA) for Flooding, River Bend Station Unit - 1, Docket Number 50-458, License 

42 No. NPF-47. October 24, 2016. ADAMS Accession No. ML16302A158.
F-52

1 [Entergy] Entergy Operations, Inc. 2017a. River Bend Station, Unit 1, Redacted License 

2 Renewal Application, Appendix E, Applicant’s Environmental Report. West Feliciana Parish, 

3 LA. May 2017. 859 p. ADAMS Accession No. ML17174A531. 

4 [Entergy] Entergy Operations, Inc. 2017b. Letter from William F. Maguire, Entergy, to 

5 U.S. Nuclear Regulatory Commission Document Control Desk. Subject: Response to License

6 Renewal Application (LRA) NRC Request for Additional Information, Severe Accident Mitigation 

7 Alternatives River Bend Station, Unit 1, Docket No. 50-458, License No. NPF-47. December 5, 

8 2017. ADAMS Accession No. ML17339A795.

9 [Entergy] Entergy Operations, Inc. 2017c. Letter from Steven P. Vercelli, Entergy, to 

10 U.S. Nuclear Regulatory Commission Document Control Desk. Subject: Focused Evaluation of

11 External Flooding, River Bend Station - Unit 1, Docket No. 50-458, License No. NPF-47. 

12 June 28, 2017. ADAMS Accession No. ML17207A105.

13 [Entergy] Entergy Operations, Inc. 2018. Letter from William F. Maguire, Entergy, to 

14 U.S. Nuclear Regulatory Commission Document Control Desk. Subject: Response to License

15 Renewal Application NRC Request for Additional Information - Clarification, Severe Accident 

16 Mitigation Alternatives, River Bend Station, Unit 1, Docket No. 50-458, License No. NPF-47. 

17 January 24, 2018. ADAMS Accession No. ML18025B711.

18 [NEI] Nuclear Energy Institute. 2005. “Severe Accident Mitigation Alternative (SAMA) Analysis 

19 Guidance Document.” NEI 05–01, Revision A. Washington, DC. November 2005. ADAMS 

20 Accession No. ML060530203.

21 [NEI] Nuclear Energy Institute. 2008. "Process for Performing Internal Events PRA Peer 

22 Reviews Using the ASME/ANS PRA Standard, Revision 2." NEI 05-04, Revision 2. 

23 Washington, DC. November 2008. ADAMS Accession No. ML083430462.

24 [NRC] U.S. Nuclear Regulatory Commission. 1988. “Individual Plant Examination for Severe 

25 Accident Vulnerabilities.” Generic Letter 88–20. November 23, 1988. ADAMS Accession 

26 No. ML031470299.

27 [NRC] U.S. Nuclear Regulatory Commission. 1990. Severe Accident Risks: An Assessment 

28 for Five U.S. Nuclear Power Plants. NUREG–1150. Washington, DC. ADAMS Accession 

29 Nos. ML040140729 and ML120960691.

30 [NRC] U.S. Nuclear Regulatory Commission. 1991a. “Individual Plant Examination of External 

31 Events (IPEEE) for Severe Accident Vulnerabilities.” Generic Letter 88–20, Supplement 4. 

32 Washington, DC. June 28, 1991. ADAMS Accession No. ML031150485.

33 [NRC] U.S. Nuclear Regulatory Commission. 1991b. Procedural and Submittal Guidance for 

34 the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities. 

35 NUREG–1407. Washington, DC. May 1991. ADAMS Accession No. ML063550238.

36 [NRC] U.S. Nuclear Regulatory Commission. 1996. Memorandum from Wayne Hodges, NRC, 

37 to Steven A. Varga, NRC. Subject: Review of River Bend Station Unit 1 Individual Plant 

38 Examination (IPE) Submittal - Internal Events. May 20, 1996. ADAMS Accession 

39 No. ML18025A682 (nonpublic document).

40 [NRC] U.S. Nuclear Regulatory Commission. 1997a. Regulatory Analysis Technical Evaluation 

41 Handbook. NUREG/BR–0184. Washington, DC. ADAMS Accession No. ML050190193.

42 [NRC] U.S. Nuclear Regulatory Commission. 1997b. Individual Plant Examination Program: 

43 Perspectives on Reactor Safety and Plant Performance Parts 2–5, Final Report.”
F-53

1 NUREG–1560, Vol. 2. Washington, DC. December 31, 1997. ADAMS Accession

2 No. ML0635550228 (nonpublic document).

3 [NRC] U.S. Nuclear Regulatory Commission. 2001. Letter from Robert E. Moody, NRC, to 

4 Randall K. Edington, Entergy. Subject: “River Bend Station, Unit 1 – Review of the River Bend 

5 Station Individual Plant Examination of External Events (IPEEE) Submittal, (TAC No. M83667). 

6 June 13, 2001. ADAMS Accession No. ML011640678 (nonpublic document).

7 [NRC] U.S. Nuclear Regulatory Commission. 2009. “An Approach for Determining the 

8 Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities.” 

9 Regulatory Guide 1.200, Revision 2. March 2009. ADAMS Accession No. ML090410014.

10 [NRC] U.S. Nuclear Regulatory Commission. 2010. “NRC Information Notice 2010–18: 

11 Generic Issue 199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central 

12 and Eastern United States on Existing Plants.” Washington, DC. September 2, 2010. ADAMS 

13 Accession No. ML101970221.

14 [NRC] U.S. Nuclear Regulatory Commission. 2012a. “Electric Power Research Institute; 

15 Seismic Evaluation Guidance.” NRC-2013-0038. February 15, 2013. ADAMS Accession No. 

16 ML12324A198.

17 [NRC] U.S. Nuclear Regulatory Commission. 2012b. Letter from Eric J. Leeds, NRC, and 

18 Michael R. Johnson, NRC, to All Power Reactor Licensees and Holders of Construction 

19 Permits in Active or Deferred Status. Subject: Request for Information Pursuant to Title 10 of 

20 the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the 

21 Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Nuclear Power Plant 

22 Accident. March 12, 2012. ADAMS Accession No. ML12053A340.

23 [NRC] U.S. Nuclear Regulatory Commission. 2012c. Letter from Eric J. Leeds, NRC, and 

24 Michael R. Johnson, NRC, to All Power Reactor Licensees and Holders of Construction 

25 Permits in Active or Deferred Status. Subject: Issuance of Order to Modify Licenses with 

26 Regard to the Requirements for Mitigation Strategies for Beyond-Design-Basis External Events. 

27 March 12, 2012. ADAMS Accession No. ML12054A735. 

28 [NRC] U.S. Nuclear Regulatory Commission (NRC). 2013. “Preparation Of Environmental 

29 Reports For Nuclear Power Plant License Renewal Applications.” Regulatory Guide 4.2, 

30 Supplement 1, Rev. 1, Washington, D.C., June 2013, ADAMS Accession No ML13067A354.

31 [NRC] U.S. Nuclear Regulatory Commission. 2014a. Letter from Alan Wang, NRC, to Vice 

32 President, Operations, Entergy. Subject: River Bend Station, Unit 1 – Staff Assessment of the 

33 Seismic Walkdown Report Supporting Implementation of Near-Term Task Force

34 Recommendation 2.3 Related to the Fukushima Dai-ichi Nuclear Power Plant Accident (TAC 

35 No. MF0167). May 1, 2014. ADAMS Accession No. ML14073A548. 

36 [NRC] U.S. Nuclear Regulatory Commission. 2014b. Letter from Alan Wang, NRC, to Vice 

37 President, Operations, Entergy. Subject: River Bend Station, Unit 1 – Staff Assessment of the 

38 Flooding Walkdown Report Supporting Implementation of Near-Term Task Force 

39 Recommendation 2.3 Related to the Fukushima Dai-ichi Nuclear Power Plant Accident (TAC 

40 No. MF0272). June 20, 2014. ADAMS Accession No. ML14148A150.

41 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Letter from Frankie Vega, NRC, to Vice 

42 President, Operations, Entergy. Subject: River Bend Station, Unit 1 – Staff Assessment of 
F-54

1 Information Provided Pursuant to Title 10 Code of Federal Regulations Part 50, Section 

2 50.54(f), Seismic Hazard Reevaluations for Recommendation 2.1 of the Near-Term Task Force 

3 Review of Insights from the Fukushima Dai-ichi Nuclear Power Plant Accident (TAC No. 

4 MF3706). November 3, 2015. ADAMS Accession No. ML15295A186. 

5 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Reassessment of NRC’s Dollar per 

6 Person-Rem Conversion Factor Policy (Draft Report for Comment). NUREG–1530, Revision 1. 

7 Washington, DC. August 2015. ADAMS Accession No. ML15237A211.

8 [NRC] U.S. Nuclear Regulatory Commission. 2016a. Letter from Stephen Wyman, NRC, to 

9 Vice President, Operations, Entergy. Subject: Staff Review High Frequency Confirmation 

10 Associated with Reevaluated Seismic Hazard Response to March 12, 2012 50.54(f) Request for 

11 Information. February 18, 2016. ADAMS Accession No. ML15364A544. 

12 [NRC] U.S. Nuclear Regulatory Commission. 2016b. Letter from Stephen Wyman, NRC, to 

13 Vice President, Operations, Entergy, Subject: River Bend Station, Unit 1 – Staff Review of 

14 Mitigation Strategies Assessment Report of the Impact of the Reevaluated Seismic Hazard 

15 Developed in Response to the March 12, 2012, 50.54(f) Letter. September 29, 2016. ADAMS 

16 Accession No. ML16259A362.

17 [NRC] U.S. Nuclear Regulatory Commission. 2016c. Letter from Robert Bernardo, NRC, to 

18 William F. Maguire, Entergy. Subject: River Bend Station, Unit 1 – Staff Assessment of 

19 Response to 10 CFR 50.54(f) Information Request - Flood-Causing Mechanisms Reevaluation 

20 (CAC No.MF3675). August 31, 2016. ADAMS Accession No. ML16204A207.

21 [NRC] U.S. Nuclear Regulatory Commission. 2016d. Memorandum and Order CLI-16-07. 

22 May 4, 2016. Accessible at ADAMS No. ML16125A150. 

23 [NRC] U.S. Nuclear Regulatory Commission. 2017a. NRC email: River Bend Station, Unit 1, 

24 Request for Additional Information, RBS Severe Accident Mitigation Alternatives - License 

25 Renewal Application - dated November 9,2017. ADAMS Accession No. ML17317A002. 

26 [NRC] U.S. Nuclear Regulatory Commission. 2017b. Letter from Joseph Sebrosky, NRC, to 

27 Vice President, Operations, Entergy. Subject: River Bend Station, Unit 1 – Flood Hazard 

28 Mitigation Strategies Assessment (CAC No.MF7968). May 2, 2017. ADAMS Accession 

29 No. ML17075A059. 

30 [NRC] U.S. Nuclear Regulatory Commission. 2017c. Letter from Joseph Sebrosky, NRC, to 

31 Vice President, Operations, Entergy. Subject: River Bend Station, Unit 1 – Staff Assessment of 

32 Flooding Focused Evaluation (CAC No.MF9899). August 23, 2017. ADAMS Accession 

33 No. ML17220A113. 
NUREG-1437 

Supplement 58

See Chapter 7 of the report.

Division of Materials and License Renewal

Office Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

D. Drucker

Same as 8 above.

The U.S. Nuclear Regulatory Commission (NRC) staff prepared this draft supplemental environmental impact 

statement (SEIS) in response to Entergy Louisiana, LLC and Entergy Operations, Inc.’s application to renew the 

operating license for River Bend Station, Unit 1 (RBS) for an additional 20 years. This draft SEIS includes the NRC 

staff’s preliminary analysis that evaluates the environmental impacts of the proposed action and alternatives to the 

proposed action. Alternatives considered include: (1) new nuclear power generation, (2) supercritical pulverized 

coal, (3) natural gas combined cycle, and (4) a combination of natural gas combined-cycle, biomass, and demandside management. The NRC staff’s preliminary recommendation is that the adverse environmental impacts of 

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

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

• the analysis and findings in NUREG–1437, “Generic Environmental Impact Statement for License Renewal of

Nuclear Plants”

• the environmental report submitted by Entergy

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

• the NRC staff’s independent environmental review

• the NRC staff’s consideration of public comments

River Bend Station, Unit 1; RBS; Supplement to the Generic Environmental Impact 

Statement; License Renewal; DSEIS; GEIS; National Environmental Policy Act; 

NEPA

May 2018

Technical

Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants Supplement 58 Regarding River Bend Station, Unit 1

Draft Report for Comment


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