Generic Environmental Impact 

Statement for License 

Renewal of Nuclear Plants

Supplement 46

Regarding

Seabrook Station

Second Draft Report for Comment

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 46
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Generic Environmental Impact 

Statement for License Renewal 

of Nuclear Plants

Supplement 46

Regarding 

Seabrook Station

Second Draft Report for Comment

Manuscript Completed: March 2013

Date Published: April 2013

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 46
 

 

Proposed Action Issuance of renewed operating license NPF-86 for Seabrook Station in 

the city of Seabrook, Rockingham County, New Hampshire 

Type of Statement Supplement to Draft Supplemental Environmental Impact Statement 

Agency Contact Lois M. James 

Office of Nuclear Reactor Regulation 

Mail Stop O-11F1 

U.S. Nuclear Regulatory Commission 

Washington, D.C. 20555-0001 

Telephone: 301-415-3306 

E-mail: lois.james@nrc.gov

Comments Any interested party may submit comments on this supplement to the 

draft supplemental environmental impact statement (DSEIS). Please 

specify NUREG-1437, Supplement 46, Volume 2, draft supplement to 

draft, in your comments. Comments must be received by June 30, 2013. 

Comments received after the expiration of the comment period will be 

considered if it is practical to do so, but the U.S. Nuclear Regulatory 

Commission (NRC) cannot assure that consideration of late comments 

will be given. Comments may be submitted electronically by searching 

for docket ID NRC-2010-0206 at the Federal rulemaking Web site, 

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

following address: 

Chief, Rules, Announcements, and Directives Branch 

Division of Administrative Services 

Office of Administration 

Mail Stop: TWB-05-B01M 

U.S. Nuclear Regulatory Commission 

Washington, D.C. 20555-0001 

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 

ABSTRACT 

This document supplements the draft supplemental environmental impact statement (DSEIS) 

which had been prepared in response to an application submitted by NextEra Energy Seabrook, 

LLC (NextEra) to renew the operating license for Seabrook Station (Seabrook) for an additional 

20 years. This supplement incorporates new information that the U.S. Nuclear Regulatory 

Commission (NRC) staff has obtained since the publication of the DSEIS in August 2011. 

This supplement to the DSEIS includes the NRC staff evaluation of revised information provided 

by NextEra pertaining to the severe accident mitigation alternatives (SAMA) analysis for 

Seabrook. 

In addition, the NRC is taking the opportunity to (1) update the Uranium Fuel Cycle section in 

light of the June 8, 2012, U.S. Court of Appeals for the District of Columbia Circuit (New York v. 

NRC, 681 F.3d 471 (D.C. Cir. 2012)) decision to vacate the NRC’s Waste Confidence Decision 

Rule (WCD) (75 Federal Register (FR) 81032, 75 FR 81037) and (2) to provide information on 

its analysis of new NEPA issues and associated environmental impact findings for license 

renewal. 
 
 

 v 

TABLE OF CONTENTS 

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

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

LIST OF TABLES ......................................................................................................................... vii 

EXECUTIVE SUMMARY ............................................................................................................. ix 

ABBREVIATIONS AND ACRONYMS ......................................................................................... xiii 

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

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

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

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

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

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

4.3 Geologic Environment ........................................................................................ 4-1 

4.3.1 Geology and Soils ............................................................................... 4-1 

4.4 Surface Water Resources .................................................................................. 4-2 

4.5 Groundwater Resources .................................................................................... 4-2 

4.5.1 Generic Groundwater Issues ............................................................... 4-2 

4.5.2 Groundwater Use Conflicts .................................................................. 4-2 

4.5.3 Radionuclides Released to Groundwater ............................................ 4-2 

4.6 Aquatic Resources ............................................................................................. 4-4 

4.6.1 Exposure of Aquatic Organisms to Radionuclides............................... 4-5 

4.6.2 Generic Aquatic Ecology Issues .......................................................... 4-5 

4.6.3 Entrainment and Impingement ............................................................ 4-5 

4.6.4 Thermal Shock .................................................................................... 4-5 

4.6.5 Mitigation ............................................................................................. 4-5 

4.6.6 Combined Impacts ............................................................................... 4-5 

4.7 Terrestrial Resources ......................................................................................... 4-5 

4.7.1 Generic Terrestrial Resource Issues ................................................... 4-6 

4.7.2 Effects on Terrestrial Resources (Non-cooling System Impacts) ........ 4-7 

4.8 Protected Species and Habitats ......................................................................... 4-7 

4.9 Human Health .................................................................................................... 4-8 

4.9.1 Generic Human Health Issues ............................................................. 4-8 

4.9.2 Microbiological Organisms .................................................................. 4-9 

4.9.3 Electromagnetic Fields—Acute Shock................................................. 4-9 

4.9.4 Electromagnetic Fields—Chronic Effects ............................................ 4-9 

4.10 Socioeconomics ................................................................................................. 4-9 

4.11 Evaluation of New and Potentially Significant Information ............................... 4-10 

4.12 Cumulative Impacts .......................................................................................... 4-10 

4.13 References ....................................................................................................... 4-10 

5.0 ENVIRONMENTAL IMPACTS OF POSTULATED ACCIDENTS ....................................... 5-1 

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

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

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

5.3.1 Risk Estimates for Seabrook ............................................................... 5-4 

5.3.2 Adequacy of Seabrook PRA for SAMA Evaluation .............................. 5-7 

5.3.3 Potential Plant Improvements ............................................................ 5-12 

5.3.4 Cost-Beneficial SAMAs ..................................................................... 5-14 

5.3.5 Conclusions ....................................................................................... 5-22 

5.4 References ....................................................................................................... 5-23 

6.0 ENVIRONMENTAL IMPACTS OF THE URANIUM FUEL CYCLE, SOLID WASTE 

MANAGEMENT, AND GREENHOUSE GAS ............................................................................ 6-1 

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

6.2 Greenhouse Gas Emissions ............................................................................... 6-3 

6.3 References ......................................................................................................... 6-3 

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

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

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

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

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

THE SUPPLEMENTAL ENVIRONMENTAL IMPACT STATEMENT ARE SENT .................... 11-1 

APPENDIX A COMMENTS RECEIVED ON THE SEABROOK STATION 

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

APPENDIX B NATIONAL ENVIRONMENTAL POLICY ACT ISSUES FOR LICNESE 

RENEWAL OF NUCLEAR POWER PLANTS .......................................................................... B-1 

APPENDIX C APPLICABLE REGULATIONS, LAWS, AND AGREEMENTS .......................... C-1 

APPENDIX D CONSULTATION CORRESPONDENCE ......................................................... D-1 

APPENDIX E CHRONOLOGY OF ENVIRONMENTAL REVIEW ........................................... E-1 

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

SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR SEABROOK STATION UNIT 1 

IN SUPPORT OF LICENSE RENEWAL APPLICATION REVIEW ............................................ F-1 

F.1 Introduction ......................................................................................................... F-1 

F.2 Estimate of Risk for Seabrook ............................................................................ F-3 

F.3 Potential Plant Improvements........................................................................... F-25 

F.4 Risk Reduction Potential of Plant Improvements ............................................. F-33 

F.5 Cost Impacts of Candidate Plant Improvements .............................................. F-44 

F.6 Cost-Benefit Comparison ................................................................................. F-46 

F.7 Conclusions ...................................................................................................... F-63 

F.8 References ....................................................................................................... F-64 
 LIST OF TABLES 

 vii 

LIST OF TABLES 

Table 4.5-1. Groundwater use and quality issues ..................................................................... 4-2 

Table 4.6-1. Aquatic resources issues ...................................................................................... 4-4 

Table 4.7-1. Terrestrial resources issues .................................................................................. 4-6 

Table 4.9-1. Human health issues ............................................................................................ 4-8 

Table 4.9-2. Category 1 issues applicable to radiological impacts of normal operations 

during the renewal term ............................................................................................................. 4-9 

Table 5.1-1. Issues related to postulated accidents .................................................................. 5-1 

Table 5.3-1. Seabrook CDF for internal and external events .................................................... 5-4 

Table 5.3-2. Breakdown of population dose by containment release mode ............................. 5-6 

Table 5.3-3. SAMA cost benefit Phase II analysis for Seabrook ............................................ 5-14 

Table 6.1-1. Issues related to the uranium fuel cycle and solid waste management. ............... 6-1 

 

 

 ix 

EXECUTIVE SUMMARY 

Background 

By letter dated May 25, 2010, NextEra Energy Seabrook, LLC (NextEra) submitted an 

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

license for Seabrook Station (Seabrook) for an additional 20-year period. 

Pursuant to Title 10, Part 51.20(b)(2) of the U.S. 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 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. 

The NRC published its draft supplemental environmental impact statement (DSEIS) for 

Seabrook in August 2011. Subsequent to the issuance of the DSEIS, by letter dated 

March 19, 2012, NextEra notified the NRC of significant changes that were made to the severe 

accident mitigation alternatives (SAMA) analysis related to the Seabrook license renewal 

application (LRA). 

To address this new information, the NRC staff has prepared this supplement to the DSEIS in 

accordance with 10 CFR 51.72(a)(2) and (b), which address preparation of a supplement to a 

final environmental impact statement for proposed actions that have not been taken, under the 

following conditions: 

 There are significant new circumstances or information relevant to environmental 

concerns and bearing on the proposed action or its impacts. 

 It is the opinion of the NRC staff that preparation of a supplement will further the 

purposes of the National Environmental Policy Act of 1969 (NEPA). 

In addition, the NRC is taking the opportunity to update the Uranium Fuel Cycle section in light 

of the June 8, 2012, U.S. Court of Appeals for the District of Columbia Circuit (New York v. 

NRC, 681 F.3d 471 (D.C. Cir. 2012)) decision to vacate the NRC’s Waste Confidence Decision 

Rule (WCD) (75 Federal Register (FR) 81032, 75 FR 81037). In response to the court’s ruling, 

the Commission (NRC 2012a) determined that it would not issue licenses dependent upon the 

WCD, until the issues identified in the court’s decision are appropriately addressed. The 

Commission also noted that this determination extends only to final license issuance; all current 

licensing reviews and proceedings should continue to move forward. 

Further, the NRC is also taking the opportunity to provide information on its analysis of new 

NEPA issues and associated environmental impact findings for license renewal. This is the 

result of NRC having recently completed, through its rulemaking process, an update and reevaluation of the potential environmental impacts associated with the renewal of an operating 

license for a nuclear power reactor for an additional 20 years. A revised Generic Environmental 

Impact Statement for License Renewal of Nuclear Plants (GEIS), which updates the 1996 GEIS 

(NRC 1996), provides the technical basis for the revised rule, including the list of NEPA issues 

and findings contained in Table B-1 in Appendix B to Subpart A of the revised 10 CFR Part 51. 
 x 

Proposed Action 

The proposed action remains the same as that stated in the DSEIS (page 1-1): 

[NextEra] initiated the proposed Federal action by submitting an application for 

license renewal [for Seabrook], for which the existing license, NPF-86, expires on 

March 15, 2030. The NRC’s Federal action is the decision whether to renew the 

license for an additional 20 years. 

Purpose and Need for Action 

The purpose and need for action remains the same as stated in the DSEIS (page 1-1): 

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

to provide an option that allows for baseload power generation capability beyond 

the term of the current nuclear power plant operating license to meet future 

system generating needs. Such needs may be determined by other 

energy-planning decisionmakers, such as State, utility, and, where authorized, 

Federal agencies (other than 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 or findings in the National Environmental Policy Act 

(NEPA) 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 of whether a particular nuclear power plant should continue to operate. 

If the renewed license is issued, the appropriate energy-planning 

decisionmakers, along with NextEra, will ultimately decide if the plant will 

continue to operate based on factors such as the need for power. If the 

operating license is denied, then the facility must be shut down on or before the 

expiration date of the current operating license, March 15, 2030. 

Environmental Impacts of License Renewal 

The changes to this section are highlighted in redline and strikeout. 

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

criteria: 
 Executive Summary 

 xi 

 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 draft SEIS unless 

new and significant information is identified. Chapter 4 of this report 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 criterion 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. 

Recently, the NRC approved a revision to its environmental protection regulation, 10 CFR 

Part 51, which governs environmental impact reviews of nuclear power plant operating 

license renewals. The NRC, through its rulemaking process, has completed an update 

and re-evaluation of the potential environmental impacts associated with the renewal of 

an operating license for a nuclear power reactor for an additional 20 years. A revised 

GEIS, which updates the 1996 GEIS, provides the technical basis for the revised rule. 

The revised GEIS specifically supports the revised list of NEPA issues and associated 

environmental impact findings for license renewal contained in Table B-1 in Appendix B 

to Subpart A of the revised 10 CFR Part 51. The revised rule consolidates similar 

Category 1 and 2 issues, changes some Category 2 issues into Category 1 issues and 

consolidates some of those issues with existing Category 1 issues. The revised rule also 

adds new Category 1 and 2 issues. 

The revised rule is expected to be published in 2013; it will become effective 30 days 

after publication in the Federal Register. Compliance by license renewal applicants will 

not be required until one year from the date of publication (i.e., license renewal 

environmental reports submitted later than one year after publication must be compliant 

with the new rule). Nevertheless, under NEPA, the NRC must now consider and analyze, 

in its license renewal SEISs, the potential significant impacts described by the revised 

rule’s new Category 2 issues, and to the extent there is any new and significant 

information, the potential significant impacts described by the revised rule’s new 

Category 1 issues. 

Table ES-1 summarizes the Category 2 issues applicable to Seabrook, as well as 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, stand. 

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. 
 xii 

Table ES-1. Summary of NRC conclusions relating to site-specific impact of license 

renewal 

Resource Area Relevant Category 2 Issues Impacts 

Land Use None SMALL 

Air Quality None SMALL 

Surface Water Resources None SMALL 

Groundwater Resources Radionuclides released to groundwater

None

SMALL 

Aquatic Resources Impingement 

Entrainment 

Heat shock 

SMALL to LARGE 

Terrestrial Resources NoneEffects on terrestial resources (noncooling system impact) 

SMALL 

Protected Species and Habitats Threatened or endangered species SMALL to LARGE 

Human Health Electromagnetic fields—acute effects 

(electric shock) 

SMALL 

Socioeconomics Housing Impacts 

Public services (public utilities) 

Offsite land use 

Public services (public transportation) 

Historic and archaeological resources 

SMALL 

Cumulative Impacts Aquatic resources

All other resource areas 

MODERATE to LARGE

SMALL 

No further changes were made to the Executive Summary. 
 

 xiii 

ABBREVIATIONS AND ACRONYMS 

°F degree(s) Fahrenheit 

 

AC alternating current 

ACC averted cleanup and contamination costs 

ADAMS Agencywide Documents Access and Management System 

AEA AEA Technology PLC 

AOC averted offsite property damage cost 

AOE averted offsite occupational exposure 

AOSC averted onsite costs 

AOV air-operated valve 

ASME American Society of Mechanical Engineers 

APE averted public exposure 

ATWS anticipated transient without scram 

 

CBS containment building spray 

CCW component cooling water 

CDF core damage frequency 

CEQ Council on Environmental Quality 

CET containment event tree 

CFR U.S. Code of Federal Regulations 

CIV containment isolation valve 

CLB current licensing basis 

CMR Code of Massachusetts Regulations 

COE cost of enhancement 

CR control rod 

CS core spray 

CST condensate storage tank 

 

DBA design-basis accident 

DC direct current 

DG diesel generator 

DSEIS draft supplemental environmental impact statement 

 

ECCS emergency core cooling system 

EDG emergency diesel generator 

EFW emergency feedwater 

EGCA East Coast Greenway Alliance 

EIS environmental impact statement 

EOP emergency operating procedure 
 xiv 

EPA U.S. Environmental Protection Agency 

EPRI Electric Power Research Institute 

EPZ emergency planning zone 

ER Environmental Report 

 

F&O facts and observations 

FIVE fire-induced vulnerability evaluation 

FPLE Florida Power and Light Energy Seabrook, LLC 

FR Federal Register 

FSEIS final supplemental environmental impact statement 

FWS U.S. Fish and Wildlife Service 

 

g gram 

GEIS NUREG-1437, Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants

GI generic issue 

GIS geographic information system 

GL generic letter 

 

HCLPF high confidence low probability of failure 

HELB high-energy line break 

HEP human error probability 

HFO high winds, floods, and other external events 

HPI high-pressure injection 

HRA human reliability analysis 

HVAC heating, ventilation, and air conditioning 

 

IAEA International Atomic Energy Agency 

IEEE Institute of Electrical and Electronics Engineers 

in. inch 

IPE individual plant examination 

IPEEE individual plant examination of external events 

ISLOCA interfacing system loss-of-coolant accident 

 

K thousand 

km kilometer 

kV kilovolt 

 

LERF large early release frequency 

LHSI low-head safety injection 

LL-5 large late containment basemat failure 
 Abbreviations and Acronyms 

 xv 

LLNL Lawrence Livermore National Laboratory 

LOCA loss-of-coolant accident 

LOOP loss of offsite power 

LOSP loss of system pressure 

LRA license renewal application 

 

m meter 

M million 

MAAP Modular Accident Analysis Program 

MAB Maximum Attainbale Benefit 

MACCS2 MELCOR Accident Consequences Code System 2 

MACR maximum averted cost risk 

MDFW Massachusetts Division of Fisheries and Wildlife 

MELCOR Methods for Estimation of Leakages and Consequences of Releases 

MFGD Massachusetts Fish and Game Department 

MFW main feedwater 

MG motor generator 

mi mile 

MIT Massachusetts Institute of Technology 

MOV motor-operated valve 

mph miles per hour 

mps meters per second 

MSSV steam safety valve 

MW megawatt 

MWe megawatt electric 

MWt megawatt thermal 

 

NAESC North Atlantic Energy Service Corp. 

NAI Normandeau Associates, Inc. 

NEA Nuclear Energy Agency 

NEI Nuclear Energy Institute 

NEPA National Environmental Policy Act of 1969 

NextEra NextEra Energy Seabrook, LLC 

NHDES New Hampshire Department of Environmental Services 

NHDHR New Hampshire Division of Historical Resources 

NHDRED New Hampshire Department of Resources and Economic 

Development 

NHFGD New Hampshire Fish and Game Department 

NHNHB New Hampshire Natural Heritage Bureau 

NHY New Hampshire Yankee 

NIEHS National Institute of Environmental Health Sciences 
 xvi 

NMFS National Marine Fisheries Service 

NPDES National Pollutant Discharge Elimination System 

NRC U.S. Nuclear Regulatory Commission 

NRR Office of Nuclear Reactor Regulation 

NUSCO Northeast Utilities Service Company 

 

PAB primary auxiliary building 

PCC primary component cooling 

PCCW primary component cooling water system 

PNNL Pacific Northwest National Laboratory 

PORV power-operated relief valve 

POST Parliamentary Office of Science and Technology 

PRA probabilistic risk assessment 

PWR pressurized-water reactor 

psia pounds per square inch absolute 

 

RAI request for additional information 

RCP reactor coolant pump 

RCS reactor coolant system 

RHR residual heat removal 

ROW right-of-way 

RPC replacement power costs 

RRW risk reduction worth 

RSCS Radiation Safety & Control Services, Inc. 

RSP remote shutdown panel 

RWST reactor water storage tank 

 

SAMA severe accident mitigation alternatives 

SAMG severe accident mitigation guideline 

SAR safety analysis report 

SBO station blackout 

SE-3 small early containment penetration failure to isolate 

Seabrook Seabrook Station 

SEIS supplemental environmental impact statement 

SELL small early containment penetration failure to isolate and large late 

containment basemat failure 

SEPS supplemental electrical power system 

SG steam generator 

SGTR steam generator tube rupture 

SI safety injection 

SLOCA small break LOCA 
 Abbreviations and Acronyms 

 xvii 

SRM staff requirements memorandum 

SRP Standard Review Plan 

SUFP startup feed pump 

Sv Sievert 

SW service water 

SWGR switchgear 

SWS service water system 

 

TDAFW turbine-driven auxiliary feedwater 

TDEFW turbine-driven emergency feedwater 

the Court U.S. Court of Appeals for the District of Columbia Circuit 

TIBL thermal internal boundary layer 

TMDL total maximum daily load 

 

UHS uniform hazard spectrum 

USCB U.S. Census Bureau 

USGCRP U.S. Global Change Research Program 

USGS U.S. Geological Survey 

 

WCD Waste Confidence Decision and Rule 

WOG Westinghouse Owner’s Group 
 
 

1.0 INTRODUCTION 

The U.S. Nuclear Regulatory Commission (NRC) staff prepared this supplement to the draft 

supplemental environmental impact statement (DSEIS) in accordance with Title 10, 

Parts 51.72(a)(2) and (b) of the U.S. Code of Federal Regulations (10 CFR 51.72(a)(2) and (b)), 

which address preparation of a supplement to an environmental impact statement for proposed 

actions that have not been taken, under the following conditions: 

 There are significant new circumstances or information relevant to environmental 

concerns and bearing on the proposed action or its impacts. 

 It is the opinion of the NRC staff that preparation of a supplement will further the 

purposes of the National Environmental Policy Act of 1969 (NEPA). 

The NRC staff prepared this supplement to the DSEIS because, subsequent to the issuance of 

the DSEIS, NextEra Energy Seabrook, LLC (NextEra) (2012) notified the NRC of significant 

changes that were made to the severe accident mitigation alternatives (SAMA) analysis related 

to the Seabrook Station (Seabrook) license renewal application (LRA). Specifically, NextEra 

identified many changes to its SAMA analysis, based on various plant and probabilistic risk 

assessment (PRA) model changes, that were sufficiently different from what was published in 

the NRC staff’s August 2011 DSEIS to warrant the issuance of this supplement. 

In addition, the NRC is taking the opportunity to update the Uranium Fuel Cycle section in light 

of the June 8, 2012, U.S. Court of Appeals for the District of Columbia Circuit (New York v. 

NRC, 681 F.3d 471 (D.C. Cir. 2012)) decision to vacate the NRC’s Waste Confidence Decision 

Rule (WCD) (75 Federal Register (FR) 81032, 75 FR 81037). In response to the court’s ruling, 

the Commission (NRC 2012a) determined that it would not issue licenses dependent upon the 

WCD, until the issues identified in the court’s decision are appropriately addressed. The 

Commission also noted that this determination extends only to final license issuance; all current 

licensing reviews and proceedings should continue to move forward. 

Further, on December 6, 2012, the Commission affirmed a decision to publish in the Federal 

Register an amendment that would revise its environmental protection regulation, 10 CFR Part 

51, which governs environmental impact reviews of nuclear power plant operating license 

renewals (NRC 2012b). Specifically, the revised rule will update and re-evaluate the potential 

environmental impacts associated with the renewal of an operating license for a nuclear power 

reactor for an additional 20 years. A revised GEIS, which updates the 1996 GEIS, provides the 

technical basis for the revised rule. The revised GEIS specifically supports the revised list of 

NEPA issues and associated environmental impact findings for license renewal contained in 

Table B-1 in Appendix B to Subpart A of the revised 10 CFR Part 51. The revised GEIS and 

rule reflect lessons learned and knowledge gained during previous license renewal 

environmental reviews. In addition, public comments received on the draft revised GEIS and 

rule and during previous license renewal environmental reviews were re-examined to validate 

existing environmental issues and identify new ones. 

The revised rule identifies 78 environmental impact issues, of which 17 will require plant-specific 

analysis. The revised rule consolidates similar Category 1 and 2 issues, changes some 

Category 2 issues into Category 1 issues and consolidates some of those issues with existing 

Category 1 issues. The revised rule also adds new Category 1 and 2 issues. The new 

Category 1 issues include geology and soils, exposure of terrestrial organisms to radionuclides, 
Purpose and Need 

 2 

exposure of aquatic organisms to radionuclides, human health impact from chemicals, and 

physical occupational hazards. Radionuclides released to groundwater, effects on terrestrial 

resources (non-cooling system impacts), minority and low-income populations (i.e., 

environmental justice), and cumulative impacts were added as new Category 2 issues. 

The revised rule is expected to be published in 2013; it will become effective 30 days after 

publication in the Federal Register. Compliance by license renewal applicants will not be 

required until one year from the date of publication (i.e., license renewal environmental reports 

submitted later than one year after publication must be compliant with the new rule). 

Nevertheless, under NEPA, the NRC must now consider and analyze, in its license renewal 

SEISs, the potential significant impacts described by the revised rule’s new Category 2 issues, 

and to the extent there is any new and significant information, the potential significant impacts 

described by the revised rule’s new Category 1 issues. 

Where appropriate, bold text indicates specific text corrections or additions to the DSEIS and 

strikeout indicates deletions from the DSEIS text. This supplement to the DSEIS, and any 

changes made to it based on public comments, will be incorporated back into the main 

supplemental environmental impact statement (SEIS) prior to publishing the final document. 
 2-1 

2.0 AFFECTED ENVIRONMENT 

No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

August 2011. 
 
 3-1 

3.0 ENVIRONMENTAL IMPACTS OF REFURBISHMENT 

No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

August 2011. 
 
 4-1 

1 4.0 ENVIRONMENTAL IMPACTS OF OPERATION 

2 This chapter addresses potential environmental impacts related to the period of extended 

3 operation of Seabrook Station (Seabrook). These impacts are grouped and presented 

4 according to resource. Generic issues (Category 1) rely on the analysis provided in the generic 

5 environmental impact statement (GEIS) (NRC 1996, 1999) and are discussed briefly. Site6 specific issues (Category 2) have been analyzed for Seabrook and assigned a significance level 

7 of SMALL, MODERATE, or LARGE, accordingly. Some remaining issues are not applicable to 

8 Seabrook because of site characteristics or plant features. 

9 4.1 Land Use

10 No changes from the draft supplemental environmental impact statement (DSEIS) issued 

11 in August 2011.

12 4.2 Air Quality

13 No changes from the DSEIS issued in August 2011.

14 4.3 Geologic Environment

15 4.3.1 Geology and Soils 

16 As described in Section 1.0 of this supplement, the U.S. Nuclear Regulatory Commission 

17 (NRC) has approved a revision to its environmental protection regulation, Title 10 of the 

18 Code of Federal Regulations, Part 51 (10 CFR Part 51). With respect to the geologic 

19 environment of a plant site, the revised rule amends Table B-1 in Appendix B, Subpart A, 

20 to 10 CFR Part 51 by adding a new Category 1 issue, “Geology and soils.” This new 

21 issue has an impact level of SMALL. This new Category 1 issue considers geology and 

22 soils from the perspective of those resource conditions or attributes that can be affected 

23 by continued operations during the renewal term. An understanding of geologic and soil 

24 conditions has been well established at all nuclear power plants and associated 

25 transmission lines during the current licensing term, and these conditions are expected 

26 to remain unchanged during the 20-year license renewal term for each plant. The impact 

27 of these conditions on plant operations and the impact of continued power plant 

28 operations and refurbishment activities on geology and soils are SMALL for all nuclear 

29 power plants and not expected to change appreciably during the license renewal term. 

30 Operating experience shows that any impacts to geologic and soil strata would be 

31 limited to soil disturbance from construction activities associated with routine 

32 infrastructure renovation and maintenance projects during continued plant operations. 

33 Implementing best management practices would reduce soil erosion and subsequent 

34 impacts on surface water quality. Information in plant-specific SEISs prepared to date, 

35 and GEIS reference documents have not identified these impacts as being significant. 

36 Section 2.2.3 of this SEIS describes the local and regional geologic environment relevant 

37 to Seabrook. The NRC staff did not identify any new and significant information with 

38 regard to this Category 1 (generic) issue based on review of the Environmental Report 

39 (ER) (NextEra 2010), the public scoping process, or as a result of the environmental site 

40 audit. As discussed in Chapter 3 of this SEIS and as identified in the ER (NextEra 2010), 

41 NextEra Energy Seabrook, LLC. (NextEra) has no plans to conduct refurbishment or 
Environmental Impacts of Operation 

 4-2 

1 construction of new facilities during the license renewal term. Further, it is anticipated 

2 that routine plant operation and maintenance activities would continue in areas 

3 previously disturbed by construction activities, including existing transmission line 

4 rights-of-way (ROWs). Based on this information, it is expected that any incremental 

5 impacts on geology and soils during the license renewal term would be SMALL. 

6 4.34.4 Surface Water Resources

7 No changes to the text from the DSEIS issued in August 2011.

8 4.44.5 Groundwater Resources

9 The groundwater issues applicable to Seabrook are listed in Table 4.5-1Table 4.5-1 (also see 

10 Table B-1 of Appendix B of 10 CFR Part 51). Groundwater use and water quality relative to 

11 Seabrook are described in Sections 2.1.7.2 and 2.2.5 of this SEIS, respectively. 

12 Table 4.5-1. Groundwater use and quality issues 

Issues GEIS sections Category 

Groundwater use conflicts (potable & service water; 

plants that use <100 gallons per minute) 

4.8.1.1 1 

Groundwater quality degradation (saltwater intrusion) 4.8.2.1 1 

Radionuclides released to groundwater To be determined(a) 2

(a)

NRC 2012, since the revised GEIS has not been finalized 

and approved by the Commission, the revised GEIS ssection 

can not be referenced in this table. 

13 4.5.1 Generic Groundwater Issues 

14 No changes to the text from the DSEIS issued in August 2011. 

15 4.5.2 Groundwater Use Conflicts 

16 No changes to the text from the DSEIS issued in August 2011. 

17 4.5.3 Radionuclides Released to Groundwater 

18 With respect to groundwater quality, the revised rule amends Table B–1 in Appendix B, 

19 Subpart A, to 10 CFR Part 51 by adding a new Category 2 issue, “Radionuclides released 

20 to groundwater,” with an impact level range of SMALL to MODERATE, to evaluate the 

21 potential impact of discharges of radionuclides from plant systems into groundwater. 

22 This new Category 2 issue has been added to evaluate the potential impact to 

23 groundwater quality from the discharge of radionuclides from plant systems, piping, and 

24 tanks. This issue was added because, within the past several years, there have been 

25 events at nuclear power reactor sites that involved unknown, uncontrolled, and 

26 unmonitored releases of radioactive liquids into the groundwater. A discussion of 

27 groundwater quality concerns at Seabrook is included in Section 2.2.5 of the 

28 August 2011 DSEIS, and an assessment of the significance of groundwater quality 

29 degradation due to tritium contamination is presented in Section 4.10 of the August 2011 

30 DSEIS. 
 Environmental Impacts of Operation 

 4-3 

1 As detailed in Section 2.2.5 of the August 2011 DSEIS, the NRC staff indicated that 

2 groundwater with elevated tritium activity concentrations was detected in the annular 

3 space around the Unit 1 containment structure in September 1999. In response to the 

4 elevated tritium concentrations, NextEra initiated a leak investigation which identified a 

5 leak source associated with the cask loading area and transfer canal adjacent to the 

6 spent fuel pool. In addition, NextEra has undertaken leak source elimination efforts and 

7 other corrective actions, which ultimately involved installation of a groundwater 

8 dewatering and pumping system to mitigate contaminated groundwater. An extensive 

9 groundwater monitoring network was also installed to provide surveillance of 

10 groundwater quality across the Seabrook site. 

11 NextEra has monitored the dewatering system since 2000, the results of which were 

12 reviewed by NRC staff in support of the preparation of the August 2011 DSEIS. The 

13 highest tritium levels (up to 3,500,000 picocuries per liter (pCi/L) in 2003) were found in 

14 water removed from around the Unit 1 containment enclosure ventilation area (CEVA). 

15 Since monitoring began, NextEra has found that the tritium levels are trending down. 

16 Based on the most recent (2011) dewatering system monitoring data available for the 

17 site, tritium concentrations in the CEVA have ranged from 2,150 up to 50,000 pCi/L 

18 (NextEra 2011a). 

19 NextEra continues to conduct groundwater monitoring as part of its participation in the 

20 Nuclear Energy Institute’s Groundwater Protection Initiative (NextEra 2010). Monitoring 

21 results obtained through the onsite Groundwater Protection Program are reported in 

22 NextEra's radioactive effluent release reports, which are submitted to the NRC. Based on 

23 monitoring results from Seabrook’s network of 27 groundwater monitoring wells through 

24 the end of 2011, the highest concentration of tritium detected was 2,850 pCi/L in well SW25 1, a shallow aquifer well located near the Unit 1 containment structure. EPA’s drinking 

26 water standard (or Maximum Contaminant Level) is 20,000 pCi/L. Several other nearby 

27 wells had lower tritium levels, while samples from most wells yielded no tritium above 

28 analytical detection limits. Monitoring results from a line of perimeter wells located 

29 south and downgradient of the tritium leak source have shown no tritium detections. 

30 Finally, NextEra reported no unplanned, unanticipated, or abnormal releases of liquid 

31 effluents from the site to unrestricted areas during 2010 and 2011 (NextEra, 2010a, 2011b, 

32 2012). 

33 As noted above and further discussed in the August 2011 DSEIS, the Unit 1 groundwater 

34 dewatering system, in combination with pumping from beneath the incomplete Unit 2 

35 containment building, functions at Seabrook to remove and provide hydraulic 

36 containment of the tritium-contaminated groundwater by reversing the hydraulic gradient 

37 and flow of groundwater offsite. No offsite migration of tritium in groundwater has been 

38 observed to date. Further, the only drinking water wells (Town of Seabrook) are located 

39 hydraulically upgradient from the Seabrook site, and there is no drinking water pathway 

40 onsite. 

41 While tritium continues to be detected above background levels at several onsite 

42 locations, the applicant is actively monitoring and controlling the tritium concentrations 

43 on site. The tritium-impacted groundwater is sent to the facility’s main outfall to the 

44 ocean, where it is released in compliance with National Pollutant Discharge Elimination 

45 System (NPDES) and NRC’s radiological limits. Tritium concentrations in groundwater 

46 as measured in onsite monitoring wells have remained well below EPA's 20,000 pCi/L 

47 drinking water standard. Based on the information presented above and in 

48 Sections 2.2.5 and 4.10 of the August 2011 DSEIS, the NRC concludes that inadvertent 

49 releases of tritium have not substantially impaired site groundwater quality or affected 
Environmental Impacts of Operation 

 4-4 

1 groundwater use downgradient of the Seabrook site. The NRC staff further concludes 

2 that groundwater quality impacts would remain SMALL during the license renewal term. 

3 4.54.6 Aquatic Resources

4 Section 2.1.6 of this SEIS describes Seabrook’s cooling-water system, and Section 2.2.6 

5 describes the aquatic resources. Category 1 issues in 10 CFR Part 51, Subpart A, 

6 Appendix B, Table B–1, which are applicable to the operation of Seabrook’s cooling7 water systems during the renewed license term, are listed in Table 4.6-1. The NRC staff 

8 did not find any new and significant information during the review of the ER 

9 (NextEra 2010), the site audit, the scoping process, or the evaluation of other available 

10 information; therefore, the NRC staff concludes that there are no impacts related to 

11 aquatic resource issues beyond those discussed in the GEIS (NRC 1996) and the revised 

12 rule (NRC 2012). Consistent with the GEIS and the revised rule, the NRC staff concludes 

13 that the impacts are SMALL, and additional site-specific mitigation measures are unlikely 

14 to be sufficiently beneficial to warrant implementation. 

15 Table 4.6-1. Aquatic resources issues 

Issues GEIS sections Category 

For all plants 

Accumulation of contaminants in sediments or biota 4.2.1.2.4 1 

Entrainment of phytoplankton & zooplankton 4.2.2.1.1 1 

Cold shock 4.2.2.1.5 1 

Thermal plume barrier to migrating fish 4.2.2.1.6 1 

Distribution of aquatic organisms 4.2.2.1.6 1 

Premature emergence of aquatic insects 4.2.2.1.7 1 

Gas supersaturation (gas bubble disease) 4.2.2.1.8 1 

Low dissolved oxygen in the discharge 4.2.2.1.9 1 

Losses from predation, parasitism, & disease among organisms 

exposed to sublethal stresses 

4.2.2.1.10 1 

Stimulation of nuisance organisms 4.2.2.1.11 1 

Exposure of aquatic organisms to radionuclides To be determined(a) 1

For plants with once-through dissipation systems 

Entrainment of fish & shellfish in early life stages 4.1.2 2 

Impingement of fish & shellfish 4.1.3 2 

Heat shock 4.1.4 2 

Table source (61 FR 28467): Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51. 

(a) NRC 2012, since the revised GEIS has not been finalized and approved by the Commission, the revised GEIS ssection can 

not be referenced in this table.NRC 2012
 Environmental Impacts of Operation 

 4-5 

1 4.5.14.6.1 Exposure of Aquatic Organisms to Radionuclides 

2 As described in Section 1.0 of this SEIS, the NRC has approved a revision to its 

3 environmental protection regulation, 10 CFR Part 51. With respect to the aquatic 

4 organisms, the revised rule amends Table B-1 in Appendix B, Subpart A, to 

5 10 CFR Part 51 by adding a new Category 1 issue, “Exposure of aquatic organisms to 

6 radionuclides,” among other changes. This new Category 1 issue considers the impacts 

7 to aquatic organisms from exposure to radioactive effluents discharged from a nuclear 

8 power plant during the license renewal term. An understanding of the radiological 

9 conditions in the aquatic environment from the discharge of radioactive effluents within 

10 NRC regulations has been well established at nuclear power plants during their current 

11 licensing term. Based on this information, the NRC concluded that the doses to aquatic 

12 organisms are expected to be well below exposure guidelines developed to protect these 

13 organisms and assigned an impact level of SMALL. 

14 The NRC staff has not identified any new and significant information related to the 

15 exposure of aquatic organisms to radionuclides during its independent review of 

16 Seabrook’s ER, the site audit, and the scoping process. Section 2.1.2 of this SEIS 

17 describes the applicant’s Radioactive Waste Management Program to control radioactive 

18 effluent discharges to ensure that they comply with NRC regulations in 10 CFR Part 20. 

19 Section 4.9.3 of this SEIS contains the NRC staff’s evaluation of Seabrook’s Radioactive 

20 Effluent and Radiological Environmental Monitoring programs. Seabrook’s Radioactive 

21 Effluent and Radiological Environmental Monitoring programs provide further support 

22 for the conclusion that the impacts of aquatic organisms from radionuclides are SMALL. 

23 The NRC staff concludes that there would be no impacts to aquatic organisms from 

24 radionuclides beyond those impacts contained in Table B-1 in Appendix B, Subpart A, to 

25 10 CFR Part 51 of the revised rule; therefore, the impacts to aquatic organisms from 

26 radionuclides are SMALL. 

27 4.5.24.6.2 Generic Aquatic Ecology Issues 

28 No changes to the text from the DSEIS issued in August 2011. 

29 4.5.34.6.3 Entrainment and Impingement 

30 No changes to the text from the DSEIS issued in August 2011. 

31 4.5.44.6.4 Thermal Shock 

32 No changes to the text from the DSEIS issued in August 2011. 

33 4.5.54.6.5 Mitigation 

34 No changes to the text from the DSEIS issued in August 2011.

35 4.5.64.6.6 Combined Impacts 

36 No changes to the text from the DSEIS issued in August 2011.

37 4.7 Terrestrial Resources 

38 The issues related to terrestrial resources The Category 1 (generic) and Category 2 (site39 specific) terrestrial resources issues applicable to Seabrook are listed in Table 4.7-1. 

40 There are no Category 2 issues related to terrestrial resources. The NRC staff did not identify 
Environmental Impacts of Operation 

 4-6 

1 any new and significant information during the review of the applicant’s ER (NextEra, 2010), the 

2 NRC staff’s site audit, the scoping process, or the evaluation of other available information. 

3 Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. 

4 For these issues, the GEIS concluded that the impacts are SMALL, and additional site-specific 

5 mitigation measures are not likely to be sufficiently beneficial to warrant implementation.

6 Table 4.7-1. Terrestrial resources issues 

7 Section 2.2.7 provides a description of the terrestrial resources at Seabrook and in the 

8 surrounding area. 

Issues GEIS section Category 

Cooling tower impacts on crops & ornamental vegetation 4.3.4 1 

Cooling town impacts on native plants 4.3.5.1 1 

Bird collisions with cooling towers 4.3.5.2 1 

Powerline ROW management (cutting herbicide application) 4.5.6.1 1 

Bird collisions with powerlines 4.5.6.1 1 

Impacts of electromagnetic fields on flora and fauna (plants, 

agricultural crops, honeybees, wildlife, livestock) 4.5.6.3 1 

Floodplains & wetland on powerline ROW 4.5.7 1 

Exposure of terrestrial organisms to radionuclides To be determined(a) 1 

Effects on terrestrial resources (non-cooling system impacts) To be determined(a) 2 

(a) NRC 2012, since the revised GEIS has not been finalized and approved 

by the Commission, the revised GEIS ssection can not be referenced in 

this table. 

9 4.7.1 Generic Terrestrial Resource Issues 

10 For the Category 1 terrestrial resources issues listed in Table 4.7-1, the NRC staff did not 

11 identify any new and significant information during the review of the ER (NextEra 2010), 

12 the NRC staff’s site audit, the scoping process, or the evaluation of other available 

13 information. Therefore, there are no impacts related to these issues beyond those 

14 discussed in the GEIS and the revised rule (NRC 2012). For these issues, the GEIS and 

15 the revised rule concluded that the impacts are SMALL, and additional site-specific 

16 mitigation measures are unlikely to be sufficiently beneficial to warrant implementation. 

17 4.7.1.1 Exposure of Terrestrial Organisms to Radionuclides 

18 As described in Section 1.0 of this SEIS, the NRC has approved a revision to its 

19 environmental protection regulation, 10 CFR Part 51. With respect to the terrestrial 

20 organisms, the revised rule amends Table B-1 in Appendix B, Subpart A, to 

21 10 CFR Part 51 by adding a new Category 1 issue, “Exposure of terrestrial organisms to 

22 radionuclides,” among other changes. This new issue has an impact level of SMALL. 

23 This new Category 1 issue considers the impacts to terrestrial organisms from exposure 

24 to radioactive effluents discharged from a nuclear power plant during the license renewal 

25 term. An understanding of the radiological conditions in the terrestrial environment from 

26 the discharge of radioactive effluents within NRC regulations has been well established 

27 at nuclear power plants during their current licensing term. Based on the revision to the 

28 environmental protection guidance and the staff's understanding of radiological 

29 conditions, the NRC concluded that the doses to terrestrial organisms are expected to be 
 Environmental Impacts of Operation 

 4-7 

1 well below exposure guidelines developed to protect these organisms and assigned an 

2 impact level of SMALL. 

3 The NRC staff has not identified any new and significant information related to the 

4 exposure of terrestrial organisms to radionuclides during its independent review of 

5 Seabrook’s ER, the site audit, and the scoping process. Section 2.1.2 of this SEIS 

6 describes the applicant’s Radioactive Waste Management Program to control radioactive 

7 effluent discharges to ensure that they comply with NRC regulations in 10 CFR Part 20. 

8 Section 4.9.3 of this SEIS contains the NRC staff’s evaluation of Seabrook’s Radioactive 

9 Effluent and Radiological Environmental Monitoring programs. Seabrook’s Radioactive 

10 Effluent and Radiological Environmental Monitoring programs provide further support 

11 for the conclusion that the impacts from radioactive effluents are SMALL. 

12 Therefore, the NRC staff concludes that there would be no impact to terrestrial 

13 organisms to radionuclides beyond those impacts contained in Table B-1 in Appendix B, 

14 Subpart A, to 10 CFR Part 51 of the revised rule; therefore, the impacts to terrestrial 

15 organisms from radionuclides are SMALL. 

16 4.7.2 Effects on Terrestrial Resources (Non-cooling System Impacts) 

17 As described in Section 1.0 of this supplement, the NRC has approved a revision to its 

18 environmental protection regulation, 10 CFR Part 51. With respect to the terrestrial 

19 organisms, the revised rule amends Table B-1 in Appendix B, Subpart A, to 

20 10 CFR Part 51 by expanding the Category 2 issue, “Refurbishment impacts,” among 

21 others, to include normal operations, refurbishment, and other supporting activities 

22 during the license renewal term. This issue remains a Category 2 issue with an impact 

23 level range of SMALL to LARGE; however, the revised rule renames this issue “Effects 

24 on terrestrial resources (non-cooling system impacts).” 

25 Section 2.2.7 of this SEIS describes the terrestrial resources on and in the vicinity of the 

26 Seabrook site, and Section 2.2.8 describes protected species and habitats. During the 

27 construction of Seabrook, approximately 22 percent of the plant site (194 ac (79 ha)) was 

28 cleared for buildings, parking lots, roads, and other infrastructure. By 2014, NextEra 

29 plans to have returned approximately 32 ac (13 ha), which are currently occupied by 

30 excavation spoil, to its natural state. The remaining terrestrial habitats have not changed 

31 significantly since construction. As discussed in Chapter 3 of this SEIS and according to 

32 the applicant’s ER (NextEra 2010), NextEra has no plans for refurbishment or other 

33 license renewal-related construction activities. Further, it is anticipated that routine plant 

34 operation and maintenance activities would continue in areas previously disturbed by 

35 construction activities, including existing transmission line ROWs. Based on the staff’s 

36 independent review, the staff concurs that operation and maintenance activities that 

37 NextEra might undertake during the renewal term, such as maintenance and repair of 

38 plant infrastructure (e.g., roadways, piping installations, onsite transmission lines, 

39 fencing and other security infrastructure), would likely be confined to previously -

40 disturbed areas of the plant site or along the in-scope transmission line corridors. 

41 Therefore, the staff expects non-cooling system impacts on terrestrial resources during 

42 the license renewal term to be SMALL.

43 4.64.8 Protected Species and Habitats

44 No changes to the text from the DSEIS issued in August 2011.
Environmental Impacts of Operation 

 4-8 

1 4.74.9 Human Health

2 The human health issues applicable to Seabrook are discussed below and listed in 

3 Table 4.9-1Table 4.9-1 for Category 1, Category 2, and uncategorized issues. 

4 Table 4.9-1. Human health issues 

5 Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 contains more information on these 

6 issues. 

Issues GEIS section Category 

Radiation exposures to the public during refurbishment 3.8.1(a) 1 

Occupational radiation exposures during refurbishment 3.8.2(a) 1 

Microbiological organisms (occupational health) 4.3.6 1 

Microbiological organisms (public health, for plants using lakes or 

canals or discharging small rivers) 4.3.6(b) 2 

Noise 4.3.7 1 

Radiation exposures to public (license renewal term) 4.6.2 1 

Occupation radiation exposures (license renewal term) 4.6.3 1 

Electromagnetic fields—acute effects (electric shock) 4.5.4.1 2 

Electromagnetic fields—chronic effects 4.5.4.2 Uncategorized 

Human health impact from chemicals To be determined(c) 1

Physical occupational hazards To be determined(c) 1

(a) Issues apply to refurbishment, an activity that Seabrook does not plan to undertake. 

(b) Issue applies to plant features such as cooling lakes or cooling towers that discharge to small rivers. The issue does not apply to 

Seabrook.

(a)NRC 2012, since the revised GEIS has not been finalized and approved by the Commission, the revised GEIS ssection can 

not be referenced in this table.

7 4.7.14.9.1 Generic Human Health Issues 

8 Category 1 issues in 10 CFR Part 51, Subpart A, Appendix B, Table B-1, applicable to 

9 Seabrook in regard to radiological impacts, are listed in Table 4.9-2Table 4.9-2. NextEra stated 

10 in its ER (NextEra 2010) that it was aware of one new radiological issue associated with the 

11 renewal of the Seabrook operating license—elevated tritium concentrations in groundwater 

12 adjacent to Unit 1. The groundwater monitoring for tritium is discussed later in this section. The 

13 NRC staff determined that the issue, while new, is not significant. Section 4.10 contains the 

14 discussion of this issue. The NRC staff has not identified any new and significant information, 

15 beyond this issue identified by the applicant, during its independent review of NextEra’s ER, the 

16 site visit, the scoping process, or its evaluation of other available information.

17 4.9.1.1 New Category 1 Human Health issues 

18 As described in Section 1.4 of this SEIS, the NRC has approved a revision to its 

19 environmental protection regulation, 10 CFR Part 51. With respect to the human health, 

20 the revised rule amends Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 by adding 

21 two new Category 1 issues, “Human health impact from chemicals” and “Physical 

22 occupational hazards.” The first issue considers the impacts from chemicals to plant 

23 workers and members of the public. The second issue only considers the non24 radiological occupational hazards of working at a nuclear power plant. An 
 Environmental Impacts of Operation 

 4-9 

1 understanding of these non-radiological hazards to nuclear power plant workers and 

2 members of the public have been well established at nuclear power plants during the 

3 current licensing term. The impacts from chemical hazards are expected to be minimized 

4 through the applicant’s use of good industrial hygiene practices as required by permits 

5 and Federal and State regulations. Also, the impacts from physical hazards to plant 

6 workers will be of small significance if workers adhere to safety standards and use 

7 protective equipment as required by Federal and State regulations. The impacts to 

8 human health for each of these new issues from continued plant operations are SMALL. 

9 The NRC staff has not identified any new and significant information related to these 

10 non-radiological issues during its independent review of NextEra’s ER, the site audit, and 

11 the scoping process. Therefore, the NRC staff concludes that there would be no impact 

12 to human health from chemicals or physical hazards beyond those impacts described in 

13 Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 of the revised rule; therefore, the 

14 impacts are SMALL.

15 Table 4.9-2. Category 1 issues applicable to radiological impacts of normal operations 

16 during the renewal term 

Issue—10 CFR Part 51, Subpart A, Appendix B, Table B-1 GEIS section 

Human health 

Radiation exposures to public (license renewal term) 4.6.2 

Occupational radiation exposures (license renewal term) 4.6.3 

17 According to the GEIS, the impacts to human health are SMALL, and additional plant-specific 

18 mitigation measures are unlikely to be sufficiently beneficial to be warranted (Category 1 

19 issues). These impacts are expected to remain SMALL through the license renewal term. 

20 4.7.1.14.9.1.2 Radiological Impacts of Normal Operations 

21 No changes to the text from the DSEIS issued in August 2011. 

22 4.7.1.24.9.1.3 Seabrook Radiological Environmental Monitoring Program 

23 No changes to the text from the DSEIS issued in August 2011. 

24 4.7.1.34.9.1.4 Seabrook Radioactive Effluent Release Program 

25 No changes to the text from the DSEIS issued in August 2011. 

26 4.7.24.9.2 Microbiological Organisms 

27 No changes to the text from the DSEIS issued in August 2011. 

28 4.7.34.9.3 Electromagnetic Fields—Acute Shock 

29 No changes to the text from the DSEIS issued in August 2011.

30 4.7.44.9.4 Electromagnetic Fields—Chronic Effects 

31 No changes to the text from the DSEIS issued in August 2011. 

32 4.84.10 Socioeconomics

33 No changes to the text from the DSEIS issued in August 2011. 
Environmental Impacts of Operation 

 4-10 

1 4.94.11 Evaluation of New and Potentially Significant Information

2 No changes to the text from the DSEIS issued in August 2011.

3 4.104.12 Cumulative Impacts

4 No changes to the text from the DSEIS issued in August 2011. 

5 4.114.13 References

6 Boesch, D.F., 1977, “Application of Numerical Classification in Ecological Investigations of 

7 Water Pollution,” EPA, Ecological Research Report Agency. 

8 Brousseau, D.J., 1978, “Population dynamics of the soft-shell clam Mya arenaria,” Marine 

9 Biology. 50:63–71, 1978. 

10 Clifford, H.T., and W. Stephenson, 1975, An Introduction to Numerical Classification, Academic 

11 Press, New York. 

12 Code of Massachusetts Regulations (CMR), “Massachusetts Endangered Species Act,” Part 

13 300, Chapter 1, Title 10, “Division of Fisheries and Wildlife.” 

14 Collette, B.B. and G. Klein-MacPhee, eds., 2002, Bigelow and Schroeder’s Fish of the Gulf of 

15 Maine, Smithsonian Institution Press, Washington, D.C., 3rd Edition. 

16 Council on Environmental Quality (CEQ), 1997, Environmental Justice: Guidance Under the 

17 National Environmental Policy Act, December 10, 1997, Available URL: 

18 http://ceq.hss.doe.gov/nepa/regs/ej/justice.pdf. 

19 Dominion Resources Services, 2010, “Annual Report 2009—Monitoring the Marine Environment 

20 of Long Island Sound at Millstone Power Station Waterford, Connecticut,” Millstone 

21 Environmental Laboratory. 

22 East Coast Greenway Alliance (EGCA), 2010, “Welcome to the New Hampshire Seacoast 

23 Greenway: the EGC in NH,” Available URL: http://www.greenway.org/nh.aspx (accessed 

24 December 20, 2010). 

25 Eberhardt, A.L. and D.M. Burdick, 2009, “Hampton-Seabrook Estuary Habitat Restoration 

26 Compendium,” Report to the Piscataqua Region Estuaries Partnership and the New Hampshire 

27 Coastal Program, Durham and Portsmouth, NH. 

28 Entergy Nuclear-Pilgrim Station, 2010, “Marine Ecology Studies, Pilgrim Nuclear Power 

29 Station,” Report No. 70, Report Period: January 2009–December 2009. 

30 Florida Power and Light Energy Seabrook, LLC (FPLE), 2006, “2005 Annual Radioactive 

31 Effluent Release Report,” Seabrook, NH, Agencywide Documents Access and Management 

32 System (ADAMS) Accession No. ML061250364. 

33 FPLE, 2006a, “2005 Annual Radiological Environmental Monitoring Report,” Seabrook, NH, 

34 ADAMS Accession No. ML061210428. 

35 FPLE, 2007, “2006 Annual Radioactive Effluent Release Report,” Seabrook, NH, 2007, ADAMS 

36 Accession No. ML071220456. 

37 FPLE, 2007a, “2006 Annual Radiological Environmental Monitoring Report,” Seabrook, NH, 

38 ADAMS Accession No. ML072990335. 
 Environmental Impacts of Operation 

 4-11 

1 FPLE, 2008, “2007 Annual Radioactive Effluent Release Report,” Seabrook, NH, ADAMS 

2 Accession No. ML081570602. 

3 FPLE, 2008a, “2007 Annual Radiological Environmental Monitoring Report,” Seabrook, NH, 

4 ADAMS Accession No. ML093160352. 

5 FPLE, 2008b, “Ichthyoplankton Entrainment Sampling,” Seabrook Station Regulatory 

6 Compliance Procedure, ZN1120.1, Revision 01, Change 03. 

7 FPLE, 2008c, “Seabrook Station Updated Final Safety Analysis Report,” Revision 12, August 1. 

8 Fogarty, M.J., 1988, “Time Series Models of the Maine Lobster Fishery: The Effect of 

9 Temperature,” Canadian Journal of Fisheries and Aquatic Sciences, 451145–1153, 1988. 

10 Glude, J.B., 1955, “The Effects of Temperature and Predators on the Abundance of the 

11 Softshell Clam, Mya arenaria, in New England,” Transactions of the American Fisheries Society, 

12 84:13–26, 1955. 

13 Haley and Aldrich, Inc., 2009, “Annual Groundwater Monitoring Report, Vehicle Maintenance 

14 Facility, Seabrook Nuclear Power Station,” prepared for NextEra, December 16, 2009. 

15 Hampton (The Town of Hampton), 2007, “Hampton Beach Area Master Plan,” The Town of 

16 Hampton, NH, NH Department of Resources and Economic Development, Division of Parks and 

17 Recreation, November 7, 2001, Available URL: 

18 http://www.hampton.lib.nh.us/hampton/town/masterplan/index.htm (accessed September 30, 

19 2010). 

20 Incze, L.S., et al., 2000, “Neustonic Postiarval Lobsters, Homarus americanus, in the Western 

21 Gulf of Maine,” Canadian Journal of Fisheries and Aquatic Sciences, 57(4):755–765, 2000. 

22 Institute of Electrical and Electronics Engineers (IEEE) Safety Code, 2007, National Electric 

23 Safety Code. 

24 Johnson, M.R., et al., 2008, “Impacts to Marine Fisheries Habitat from Nonfishing Activities in 

25 the Northeastern United States,” NOAA Technical Memorandum NMFS-NE-209, NMFS, 

26 Northeast Regional Office, Gloucester, MA. 

27 Link, J.S. and L.P. Garrison, 2002, “Changes in Piscivory Associated with Fishing Induced 

28 Changes to the Finfish Community on Georges Bank,” Fisheries Research, 55: 71–86, 2002. 

29 Massachusetts Division of Fisheries and Wildlife (MDFW), 2008, “Massachusetts List of 

30 Endangered, Threatened and Special Concern Species,” Available URL: 

31 http://www.mass.gov/dfwele/dfw/nhesp/species_info/mesa_list/mesa_list.htm (accessed 

32 January 28, 2011). 

33 MDFW, 2009, French, T.W., Assistant Director, MDFW, letter to M.D. O’Keefe, FPLE Seabrook 

34 Station, “Transmission Lines Associated with the Seabrook Station Nuclear Power Plant,” June 

35 11, 2009, ADAMS Accession No. ML101590089. 

36 Menzie, C., et al., 1996, “Report of the Massachusetts Weight-of-Evidence Workshop: A 

37 Weight-of-Evidence Approach for Evaluating Ecological Risks,” Human and Ecological Risk 

38 Assessment, 2:227–304, 1996. 

39 Massachusetts Fish and Game Department (MFGD), 2010, Holt, E., Endangered Species 

40 Review Assistant, Massachusetts Fish and Game Department, e-mail to J. Susco, Project 

41 Manager, NRC, “Reply to MA State-listed Rare Species in Seabrook Station Transmission Line 

42 ROWs,” August 18, 2010, ADAMS Accession No. ML102360545. 
Environmental Impacts of Operation 

 4-12 

1 National Institute of Environmental Health Sciences (NIEHS), 1999, NIEHS Report on Health 

2 Effects from Exposure to Power-Line Frequency Electric and Magnetic Fields, Publication No. 

3 99-4493, 1999, Available URL: http://www.niehs.nih.gov/health/docs/niehs-report.pdf (accessed 

4 September 3, 2010). 

5 National Marine Fisheries Service (NMFS), 1998, “Final Recovery Plan for Shortnose Sturgeon 

6 (Acipenser brevirostrum),” Prepared by the Shortnose Sturgeon Recovery Team for the NMFS, 

7 Silver Spring, MD, December 1998. 

8 NMFS, 2002, Allen, L., NMFS, Office of Protected Resources, letter to A. Legendre, FPLE 

9 Seabrook Station, “Withdrawal of Application for Incidental Take Authorization,” May 7, 2004. 

10 NMFS, 2009, “Ecosystem Assessment Report for the Northeast U.S. Continental Shelf Large 

11 Marine Ecosystem,” Northeast Fisheries Science Center Reference Document 09-11, Northeast 

12 Fisheries Science Center, Ecosystem Assessment Program. 

13 NMFS, 2010, Kurkul, Patricia A., Regional Administration, NMFS, letter to Bo Pham, Chief, 

14 NRC, “Response to Renewal application of Seabrook Station, Seabrook, New Hampshire,” 

15 August 5, 2010, ADAM Accession No. ML02240108 

16 NMFS, 2010a, “Endangered and Threatened Wildlife and Plants; Proposed Listings for Two 

17 Distinct Population Segments of Atlantic Sturgeon (Acipenser oxyrinchus oxyrinchus) in the 

18 Southeast,” Federal Register, Vol. 75, No. 193., pp. 61904–61929. 

19 NMFS, 2011, “Ocean Acidification: The Other Carbon Dioxide Problem,” Available URL: 

20 http://www.pmel.noaa.gov/co2/story/Ocean+Acidification (accessed on February 22, 2011). 

21 National Oceanic and Atmospheric Administration (NOAA), 1995, “Status of the Fishery 

22 Resources off of the Northeastern United States for 1994,” NOAA Technical Memorandum 

23 NFMS-NE-108. NMFS, Conservation and Utilization Division, Northeast Fisheries Science 

24 Center, January 1995. 

25 New Hampshire Department of Environmental Services (NHDES), 2004, “Total Maximum Daily 

26 Load (TMDL) Study for Bacteria in Hampton/Seabrook Harbor,” State of New Hampshire, 

27 Department of Environmental Services, Water Division, Watershed Management Bureau, May 

28 2004. 

29 NHDES, 2009, “The New Hampshire Climate Action Plan,” March 2009, Available URL: 

30 http://des.nh.gov/organization/divisions/air/tsb/tps/climate/action_plan/

31 nh_climate_action_plan.htm (accessed January 20, 2011). 

32 NHDES, 2010, Heirtzler, P., Administrator, Wastewater Engineering Bureau, NHDES, letter to 

33 A. Legendre, NextEra Energy Seabrook, LLC., “Letter of Deficiency No. WD WWEB/C 10-002, 

34 CEI NextEra Energy Seabrook, LLC (Seabrook Station), NPDES Permit No. NH0020338,” June 

35 15, 2010. 

36 NHDES, 2010a, Heirtzler, P., Administrator, Wastewater Engineering Bureau, NHDES, letter to 

37 A. Legendre, NextEra Energy Seabrook, LLC., “Letter of Compliance for Letter of Deficiency 

38 No. WD WWEB/C 10-002, CEI, NextEra Energy Seabrook, LLC (Seabrook Station), NPDES 

39 Permit No. NH0020338,” July 20, 2010. 

40 New Hampshire Department of Resources and Economic Development (NHDRED), 2010, “Best 

41 Management Practices Manual for Utility Maintenance In and Adjacent to Wetlands and 

42 Waterbodies in New Hampshire,” January 2010, Available URL: 

43 http://www.nhdfl.org/library/pdf/Publications/DESUtilityBMPrev3.pdf (accessed October 8, 

44 2010). 
 Environmental Impacts of Operation 

 4-13 

1 New Hampshire Division of Historical Resources (NHDHR), 2010, E. Feighner, Review 

2 Compliance Coordinator, letter to B. Pham, Branch Chief, NRC, “Seabrook Station License 

3 Renewal Application Review (R&C #863),” ADAMS Accession No. ML102160299. 

4 New Hampshire Fish and Game Department (NHFGD), 2005, “New Hampshire Wildlife Action 

5 Plan,” October 1, 2005. 

6 NHFGD, 2010, “Estuarine Juvenile Finfish Survey for 2009,” Available URL: 

7 http://wildlife.state.nh.us/marine/marine_PDFs/Estuarine_Juvenile_Finfish_2009.pdf (accessed 

8 January 5, 2011) 

9 New Hampshire Natural Heritage Bureau (NHNHB), 2009, Coppola, M., Environmental 

10 Information Specialist, NHNHB, memo to S. Barnum, Normandeau Associates, “Database 

11 Search for Rare Species and Exemplary Natural Communities Along Seabrook Station 

12 Transmission Corridors,” NHB File ID: NHB09-0508, March 18, 2009, ADAMS Accession 

13 No. ML101590089. 

14 NHNHB, 2010, Coppola, M., Environmental Information Specialist, NHNHB, memo to J. Susco, 

15 Project Manager, “NH Natural Heritage Bureau Review of Seabrook Station Transmission 

16 Lines,” September 13, 2010, ADAMS Accession No. ML102600341. 

17 NHNHB, 2011, Rare Plants, Rare Animals, and Exemplary Natural Communities in New 

18 Hampshire Towns, 2011, Available URL: 

19 http://www.nhdfl.org/library/pdf/Natural%20Heritage/Townlist.pdf (Accessed January 5, 2011). 

20 NextEra Energy Seabrook, LLC (NextEra), 2009, “Stormwater Pollution Prevention Plan for 

21 NextEra Energy Seabrook LLC.,” Revision 41, July 1, 2009. 

22 NextEra, 2009a, “2008 Annual Radioactive Effluent Release Report,” Seabrook, NH, ADAMS 

23 Accession No. ML091330634. 

24 NextEra, 2009b, “2008 Annual Radiological Environmental Monitoring Report,” Seabrook, NH, 

25 ADAMS Accession No. ML091260453. 

26 NextEra, 2010, “Applicant’s Environmental Report—Operating License Renewal Stage,” Docket 

27 No. 050-443, Appendix E, May 2010, ADAMS Accession Nos. ML101590092 and 

28 ML101590089. 

29 NextEra, 2010a, “2009 Annual Radioactive Effluent Release Report,” Seabrook, NH, ADAMS 

30 Accession No. ML101310304. 

31 NextEra, 2010b, “2009 Annual Radiological Environmental Monitoring Report,” Seabrook, NH, 

32 ADAMS Accession No. ML101260140. 

33 NextEra, 2010c, Freeman, P., Site Vice President, NextEra Energy Seabrook, LLC (NextEra), 

34 letter to U.S. NRC Document Control Desk, “Seabrook Station Response to Request for 

35 NextEra Energy Seabrook License Renewal Environmental Report,” SBK-L-10185, Docket 

36 No. 50-443, November 23, 2010, ADAMS Accession No. ML103350639. 

37 Normandeau Associates, Inc. (NAI), 1998, “Seabrook Station 1996 Environmental Monitoring in 

38 the Hampton-Seabrook Area: A Characterization of Environmental Conditions,” Prepared for 

39 Northeast Utilities Service Company. 

40 NAI, 2001, “Seabrook Station Essential Fish Habitat Assessment. R-18900.009,” Prepared for 

41 North Atlantic Energy Service Corporation, August 2001. 

42 NAI, 2010, “Seabrook Station 2009 Environmental Monitoring in the Hampton-Seabrook Area: A 

43 Characterization of Environmental Conditions,” Prepared for NextEra. 
Environmental Impacts of Operation 

 4-14 

1 NAI and ARCADIS (NAI and ARCADIS), 2008, “Seabrook Nuclear Power Station EPA 316(b) 

2 Phase II Rule Project, Revised Proposal for Information Collection,” Prepared for FPLE, Section 

3 7.0, June 2008. 

4 Northeast Utilities Service Company (NUSCO), 1988, “Fish ecology studies—Monitoring the 

5 marine environment of Long Island Sound at Millstone Nuclear Power Station,” Three-Unit 

6 Operational Studies 1986–1987, Waterford, CT. 

7 Nye, J., 2010, “Climate Change and Its Effect on Ecosystems, Habitats, and Biota: State of the 

8 Gulf of Maine Report,” Gulf of Maine Council on the Marine Environment and NOAA, June 2010. 

9 Padmanabhan M. and Hecker, GE., 1991, “Comparative Evaluation of Hydraulic Model and 

10 Field Thermal Plume Data, Seabrook Nuclear Power Station,” Alden Research Laboratory, Inc. 

11 Radiation Safety & Control Services, Inc. (RSCS), 2009, “2009 Site Conceptual Ground Water 

12 Model for Seabrook Station,” Revision 01, TSD #09-019, June 10, 2009. 

13 RSCS, 2009a, “Tritium Distribution and Ground Water Flow at Seabrook Station,” Revision 00, 

14 TSD #09-039, August 31, 2009. 

15 Ropes, J.W., 1969, “The Feeding Habits of the Green Crab Carcinus maenas (L.),” Fishery 

16 Bulletin, FWS, 67:183–203, 1969. 

17 Sosebee, K., et al., 2006, “Aggregate Resource and Landings Trends,” Available URL: 

18 http://www.nefsc.noaa.gov/sos/agtt/archives/AggregateResources_2006.pdf (accessed January 

19 25, 2011). 

20 Thompson, C., 2010, “The Gulf of Maine in Context, State of the Gulf of Maine Report,” Gulf of 

21 Maine Council on the Marine Environment, Fisheries and Oceans Canada, June 2010. 

22 U.S. Census Bureau (USCB), 2003, “LandView 6—Census 2000 Profile of General 

23 Demographic Characteristics DP-1 (100%) and Census Profile of Selected Economic 

24 Characteristics DP-3, Summary of Census Block Groups in a 50-mile radius around the 

25 Seabrook Station (42.898561 Lat., -70.849094 Long.),” December 2003. 

26 USCB, 2011, “American FactFinder, Census 2000 and State and County QuickFacts 

27 information and 2009 American Community Survey 1-Year Estimates and Data Profile 

28 Highlights information on Maine, Massachusetts, and New Hampshire, and Rockingham and 

29 Strafford Counties,” Available URLs: http://factfinder.census.gov and 

30 http://quickfacts.census.gov (accessed January 2011). 

31 U.S. Code of Federal Regulations (CFR), “Standards for Protection Against Radiation,” Part 20, 

32 Title 10, “Energy.” 

33 CFR, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory 

34 Function,” Part 51, Title 10, “Energy.” 

35 U.S. Energy Information Administration (EIA), 2008, “Electricity Generating Capacity: Existing 

36 Electric Generating Units in the United States, 2008,” Available URL: 

37 http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html (accessed December 20, 

38 2010). 

39 U.S. Environmental Protection Agency (EPA), 1977, Guidance for Evaluating the Adverse 

40 Impact of Cooling Water Intake Structures on Aquatic Environment: Section 316(b) P.L. 92-500, 

41 Office of Water Enforcement, Permits Division, Washington, D.C., Draft, May 1, 1977. 

42 EPA, 1998, Guidelines for Ecological Risk Assessment, Risk Assessment Forum, Washington, 

43 D.C., EPA/630/R-95/002F. 
 Environmental Impacts of Operation 

 4-15 

1 EPA, 1999, “Consideration of Cumulative Impacts in EPA Review of NEPA Documents,” Office 

2 of Federal Activities (2252A), Washington, D.C., EPA-315-R-99-002. 

3 EPA, 1999a, “Memorandum of Understanding with North Atlantic Energy Service Organization 

4 regarding SF6 Emissions Reduction Partnership for Electric Power Systems,” April 6, 1999. 

5 EPA, 2002, “Authorization to Discharge Under the National Pollutant Discharge Elimination 

6 System (NPDES),” Permit No. NH0020338, transferred to FPLE, December 24, 2002. 

7 EPA, 2002a, “Case Study Analysis for the Proposed Section 316(b) Phase II Existing Facilities 

8 Rule,” Office of Water, Washington, D.C., EPA-821-R-02-002. 

9 EPA, 2007, Puleo, S.B., Environmental Protection Specialist, Municipal Assistance Unit, EPA, 

10 letter to G. St. Pierre, Site Vice President, FPLE Seabrook LLC., “NPDES Application 

11 No. NH0020338—FPL[E] Seabrook LLC.,” May 25, 2007. 

12 EPA, 2010, “AirData: Access to Air Pollution Data,” Available URL: http://www.epa.gov/oar/data/

13 (accessed December 20, 2010). 

14 EPA, 2010a, “Enforcement & Compliance History Online (ECHO),” Detailed Facility Report, 

15 Available URL: 

16 http://www.epa-echo.gov/cgi-bin/get1cReport.cgi?tool=echo&IDNumber=110001123061

17 (accessed October 1, 2010). 

18 EPA, 2010b, “Sole Source Aquifer Program,” Available URL: 

19 http://www.epa.gov/region01/eco/drinkwater/pc_solesource_aquifer.html (accessed December 

20 21, 2010). 

21 EPA, 2011, “eGRID,” eGRID2007, Version 1.1, Available URL: 

22 http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html (accessed January 18, 

23 2011). 

24 EPA, 2011a, “State CO2 Emissions from Fossil Fuel Combustion, 1990–2007,” Available URL: 

25 http://www.epa.gov/statelocalclimate/documents/pdf/CO2FFC_2007.pdf (accessed January 18, 

26 2011). 

27 EPA, 2011b, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2008,” EPA 

28 430-R-10-006, April 15, 2011, Available URL: http://www.epa.gov/climatechange/emissions/

29 (accessed January 20, 2011). 

30 U.S. Fish and Wildlife Service (USFWS), 2010, Chapman, T., Supervisor, New England Field 

31 Office, USFWS, letter to B. Pham, Branch Chief, NRC, “Reply to Request for List of Protected 

32 Species Within the Area Under Evaluation for the Seabrook Station License Renewal 

33 Application Review,” September 1, 2010, ADAMS Accession No. ML10263018. 

34 U.S. Global Change Research Program (USGCRP), 2009, Global Climate Change Impacts in 

35 the United States, Cambridge University Press, Cambridge, MA, Available URL: 

36 http://downloads.globalchange.gov/usimpacts/pdfs/climate-impacts-report.pdf (accessed 

37 January 20, 2011). 

38 U.S. Nuclear Regulatory Commission (NRC), 1982, “Final Environmental Statement Related to 

39 the Operation of Seabrook Station, Units 1 and 2, Docket Nos. 50-443 and 50-444,” 

40 NUREG-0895, Washington, D.C., December 1982, ADAMS Accession No. ML102290543. 

41 NRC, 1996, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” 

42 NUREG-1437, Washington, D.C., Volumes 1 and 2, May 1996, ADAMS Accession 

43 Nos. ML040690705 and ML040690738. 
Environmental Impacts of Operation 

 4-16 

1 NRC, 1999, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” 

2 NUREG-1437, Volume 1, Addendum 1, Section 6.3, “Transportation,” Table 9.1, “Summary of 

3 Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final Report,” 

4 August 31, 1999, ADAMS Accession No. ML040690720. 

5 NRC, 2005, “Final Supplemental Environmental Impact Statement Regarding Millstone Power 

6 Station Units 2 and 3,” NUREG-1437, Office of Nuclear Reactor Regulation, Washington, D.C., 

7 Supplement 22, 2005, ADAMS Accession Nos. ML051960295 and ML051960299. 

8 NRC, 2007, “Final Supplemental Environmental Impact Statement Regarding Pilgrim Nuclear 

9 Power Station,” NUREG-1437, Office of Nuclear Reactor Regulation, Washington, D.C., 

10 Supplement 29, 2007, ADAMS Accession Nos. ML071990020 and ML071990027. 

11 NRC, 2010, Pham, B., Branch Chief, NRC, letter to M. Moriarty, Regional Director, USFWS, 

12 “Request for List of Protected Species Within the Area Under Evaluation for the Seabrook 

13 Station License Renewal Application Review,” July 16, 2010, ADAMS Accession 

14 No. ML101790278. 

15 NRC, 2010a, Pham, B., Branch Chief, NRC, letter to the Abenaki Nation of New Hampshire, 

16 Cowasuck Band of Pennacook-Abenaki People, Abenaki Nation of Missisquoi, and Wampanoag 

17 Tribe of Gay Head-Aquinnah, “Request for Scoping Comments Concerning the Seabrook 

18 Station License Renewal Application Review,” 2010 (2010a), ADAMS Accession 

19 No. ML102730657. 

20 NRC, 2010b, Pham, B., Branch Chief, NRC, letter to E. Muzzey, SHPO, State of New 

21 Hampshire, Division of Historical Resources, “Seabrook Station License Renewal Application 

22 Review,” 2010 (2010b), ADAMS Accession No. ML101790273. 

23 NRC, 2010c, “Final Supplemental Environmental Impact Statement Regarding Indian Point 

24 Generating Unit Nos. 2 and 3,” NUREG-1437, Office of Nuclear Reactor Regulation, 

25 Washington, D.C., Supplement 38, 2010, ADAMS Accession Nos. ML1033350405, 

26 ML103350438, ML103360209, ML103360212, and ML103350442. 

27 Zhang, Y. and Y. Chen, 2007, “Modeling and Evaluating Ecosystem in 1980s and 1990s for 

28 American Lobster (Homarus americanus) in the Gulf of Maine,” Ecological Modeling, 203: 475–

29 489, 2007.

30 NRC, 2012, Staff Requirements, SECY-12-0063-Final Rule: Revisions to Environmental 

31 Review for Renewal of Nuclear Power Plant Operating Licenses (10 CFR Part 51; RIN 

32 3150–AI42). December 6, 2012. ADAMS Accession No. ML12341A134. 

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

34 NextEra, 2011a, Freeman, P., Site Vice President, NextEra, letter to NRC Document 

35 Control Desk, “Seabrook Station NextEra Energy Seabrook Comments on NUREG-1437 

36 Supplement 46 Seabrook Station Draft Supplemental Environmental Impact Statement,” 

37 SBK-L-11218, 

38 Docket No. 50-443, October 27, 2011, ADAMS Accession No. ML11307A235. 

39 NextEra, 2011b, "Seabrook Station Replacement Submittal of 2010 Annual Radioactive 

40 Effluent Release Report," Seabrook, NH, October 3, 2011, ADAMS Accession 

41 No. ML11285A142. 

42 NextEra, 2012, “Seabrook Station 2011 Annual Radioactive Effluent Release Report,” 

43 Seabrook, NH, April 26, 2012, ADAMS Accession No. ML12123A039
 

 5-1 

1 5.0 ENVIRONMENTAL IMPACTS OF POSTULATED ACCIDENTS 

2 This chapter describes the environmental impacts from postulated accidents that Seabrook 

3 Station (Seabrook) might experience during the period of extended operation. A more detailed 

4 discussion of the severe accident mitigation alternative (SAMA) assessment is provided in 

5 Appendix F. The term “accident” refers to any unintentional event outside the normal plant 

6 operational envelope that results in a release or the potential for release of radioactive materials 

7 into the environment. Two classes of postulated accidents are evaluated in the Generic 

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

9 by the U.S. Nuclear Regulatory Commission (NRC) (NRC 1996), as listed in Table 5.1-1. These 

10 two classes include the following design-basis accidents (DBAs) and severe accidents. 

11 Table 5.1-1. Issues related to postulated accidents 

12 Two issues related to postulated accidents are evaluated under the National Environmental 

13 Policy Act of 1969 (NEPA) in the license renewal review—DBAs and severe accidents. 

Issues GEIS sections Category 

DBAs 5.3.2; 5.5.1 1 

Severe accidents 5.3.3; 5.3.3.2; 5.3.3.3; 5.3.3.4; 5.3.3.5; 5.4; 5.5.2 2 

14 5.1 Design-Basis Accidents

15 In order to receive NRC approval to operate a nuclear power facility, an applicant for an initial 

16 operating license must submit a safety analysis report (SAR) as part of its application. The SAR 

17 presents the design criteria and design information for the proposed reactor and comprehensive 

18 data on the proposed site. The SAR also discusses various hypothetical accident situations and 

19 the safety features that prevent and mitigate accidents. The NRC staff reviews the application 

20 to determine if the plant design meets the NRC’s regulations and requirements and includes, in 

21 part, the nuclear plant design and its anticipated response to an accident. 

22 DBAs are those accidents that both the applicant and the NRC staff evaluate to ensure that the 

23 plant can withstand normal and abnormal transients and a broad spectrum of postulated 

24 accidents, without undue hazard to the health and safety of the public. Many of these 

25 postulated accidents are not expected to occur during the life of the plant but are evaluated to 

26 establish the design basis for the preventative and mitigative safety systems of the facility. 

27 Title 10, Part 50, of the U.S. Code of Federal Regulations (10 CFR Part 50) and 

28 10 CFR Part 100 describe the acceptance criteria for DBAs. 

29 The environmental impacts of DBAs are evaluated during the initial licensing process, and the 

30 ability of the plant to withstand these accidents is demonstrated to be acceptable before 

31 issuance of the operating license. The results of these evaluations are found in license 

32 documentation such as the applicant’s final safety analysis report, the NRC staff’s safety 

33 evaluation report, the final environmental statement, and Section 5.1 of this supplement to the 

34 draft supplemental environmental impact statement (DSEIS). An applicant is required to 

35 maintain the acceptable design and performance criteria throughout the life of the plant, 

36 including any extended-life operation. The consequences for these events are evaluated for the 

37 hypothetical maximum exposed individual. Because of the requirements that continuous 

38 acceptability of the consequences and aging management programs be in effect for license 
Environmental Impacts of Postulated Accidents 

 5-2 

1 renewal, the environmental impacts, as calculated for DBAs, should not differ significantly from 

2 initial licensing assessments over the life of the plant, including the license renewal period. 

3 Accordingly, the design of the plant, relative to DBAs during the extended period, is considered 

4 to remain acceptable; therefore, the environmental impacts of those accidents were not 

5 examined further in the GEIS. 

6 The NRC has determined that the environmental impacts of DBAs are of SMALL significance for 

7 all plants because the plants were designed to successfully withstand these accidents. 

8 Therefore, for the purposes of license renewal, DBAs are designated as a Category 1 issue in 

9 10 CFR Part 51, Subpart A, Appendix B, Table B-1. The early resolution of the DBAs makes 

10 them a part of the current licensing basis (CLB) of the plant. The CLB of the plant is to be 

11 maintained by the applicant under its current license; therefore, under the provisions of 

12 10 CFR 54.30, it is not subject to review under license renewal. 

13 No new and significant information related to DBAs was identified during the review of the 

14 NextEra Energy Seabrook (NextEra) Environmental Report (ER), the site visit, the scoping 

15 process, or the NRC staff’s evaluation of other available information. Therefore, there are no 

16 impacts related to DBAs beyond those discussed in the GEIS. 

17 5.2 Severe Accidents

18 Severe nuclear accidents are those that are more severe than DBAs because they could result 

19 in substantial damage to the reactor core, whether or not there are serious offsite 

20 consequences. In the GElS, the staff assessed the impacts of severe accidents during the 

21 license renewal period, using the results of existing analyses and information from various sites 

22 to predict the environmental impacts of severe accidents for plants during the renewal period. 

23 Severe accidents initiated by external phenomena—such as tornadoes, floods, earthquakes, 

24 fires, and sabotage—have not traditionally been discussed in quantitative terms in the final 

25 environmental impact statements and were not specifically considered for the Seabrook site in 

26 the GElS (NRC 1996). The GEIS, however, did evaluate existing impact assessments 

27 performed by the NRC staff and by the industry at 44 nuclear plants in the U.S. It segregated all 

28 sites into six general categories and then estimated that the risk consequences calculated in 

29 existing analyses bound the risks for all other plants within each category. The GElS further 

30 concluded that the risk from beyond design-basis earthquakes at existing nuclear power plants 

31 is designated as SMALL. The Commission believes that NEPA does not require the NRC to 

32 consider the environmental consequences of hypothetical terrorist attacks on NRC-licensed 

33 facilities. However, the NRC staff’s GElS for license renewal contains a discretionary analysis 

34 of terrorist acts in connection with license renewal. The conclusion in the GElS is that the core 

35 damage and radiological release from such acts would be no worse than the damage and 

36 release to be expected from internally initiated events. In the GEIS, the NRC staff concludes 

37 that the risk from sabotage and beyond design-basis earthquakes at existing nuclear power 

38 plants is designated as SMALL and that the risks from other external events are adequately 

39 addressed by a generic consideration of internally initiated severe accidents (NRC 1996). 

40 Based on information in the GEIS, the staff found the following to be true: 

41 The generic analysis...applies to all plants and that the probability-weighted 

42 consequences of atmospheric releases, fallout onto open bodies of water, 

43 releases to groundwater, and societal and economic impacts of severe accidents 

44 are of small significance for all plants. However, not all plants have performed a 

45 site-specific analysis of measures that could mitigate severe accidents. 

46 Consequently, severe accidents are a Category 2 issue for plants that have not 
 Environmental Impacts of Postulated Accidents 

 5-3 

1 performed a site-specific consideration of severe accident mitigation and 

2 submitted that analysis for Commission review. 

3 The staff identified no new and significant information related to postulated accidents during the 

4 review of NextEra’s ER, the site audit, the scoping process, or evaluation of other available 

5 information. Therefore, there are no impacts related to postulated accidents beyond those 

6 discussed in the GEIS. In accordance with 10 CFR 51.53(c)(3)(ii)(L), however, the NRC staff 

7 has reviewed SAMAs for Seabrook. Review results are discussed in Section 5.3. 

8 5.3 Severe Accident Mitigation Alternatives

9 Under 10 CFR 51.53(c)(3)(ii)(L), license renewal applicants must consider alternatives to 

10 mitigate severe accidents if the staff has not previously evaluated SAMAs for the applicant’s 

11 plant in an environmental impact statement (EIS) or related supplement or in an environmental 

12 assessment. The purpose is to ensure that potentially cost-beneficial, aging-related plant 

13 changes (i.e., hardware, procedures, and training) with the potential for improving severe 

14 accident safety performance are identified and evaluated. SAMAs have not been previously 

15 considered by NextEra, for Seabrook; therefore, the remainder of Section 5.3 addresses those 

16 alternatives. 

17 NextEra submitted an assessment of SAMAs for Seabrook as part of the ER (NextEra 2010), 

18 based on the most recently available Seabrook probabilistic risk assessment (PRA). This 

19 assessment is supplemented by a plant-specific offsite consequence analysis performed using 

20 the Methods for Estimation of Leakages and Consequences of Releases (MELCOR) Accident 

21 Consequence Code System 2 (MACCS2) computer code and insights from the Seabrook 

22 individual plant examination (IPE) (NHY 1991) and individual plant examination of external 

23 events (IPEEE) (North Atlantic Energy Service Corp. (NAESC) 1992). In identifying and 

24 evaluating potential SAMAs, NextEra considered SAMAs that addressed the major contributors 

25 to core damage frequency (CDF) and large early release frequency (LERF) at Seabrook, as well 

26 as a generic list of SAMA candidates for pressurized-water reactor (PWR) plants identified from 

27 other industry studies. In the original ER, NextEra identified 191 potential SAMA candidates. 

28 This list was reduced to 74 SAMA candidates by eliminating SAMAs for the following reasons: 

29  Seabrook has a different design. 

30  The SAMA has already been implemented at Seabrook. 

31  The intent of the SAMA has already been met at Seabrook. 

32  The SAMA has been combined with another SAMA candidate that is similar in nature. 

33  Estimated implementation costs would exceed the dollar value associated with 

34 eliminating all severe accident risk at Seabrook. 

35  The SAMA would be of very low benefit as it is related to a non-risk significant system. 

36 NextEra assessed the costs and benefits associated with each of these 74 potential SAMAs and 

37 concluded in the ER that several of the candidate SAMAs evaluated are potentially cost 

38 beneficial. 

39 Based on its review, the NRC staff issued requests for additional information (RAIs) to NextEra 

40 (NRC 2010a, 2011b). NextEra’s responses addressed the NRC staff’s concerns and resulted in 

41 the identification of additional potentially cost-beneficial SAMAs (NextEra 2011a, 2011b; 

42 NRC 2011a). 
Environmental Impacts of Postulated Accidents 

 5-4 

1 Subsequent to the RAI responses, NextEra submitted a supplement to the ER that 

2 incorporated updates to the PRA model (NextEra 2012a). NextEra identified four 

3 additional SAMA candidates that could be cost beneficial. The supplement to the ER 

4 assessed the costs and benefits of these additional SAMA candidates and reassessed 

5 the costs and benefits of the previously-identified SAMA candidates. The result of this 

6 analysis and reassessment is one additional potentially cost-beneficial SAMA. Based on 

7 its review of this supplement, the NRC staff issued RAIs to NextEra (NRC 2012a). 

8 NextEra’s responses addressed the NRC staff’s concerns (NextEra 2012b; NRC 2012b). 

9 5.3.1 Risk Estimates for Seabrook 

10 NextEra combined two distinct analyses to form the basis for the risk estimates used in the 

11 SAMA analysis—(1) the Seabrook Level 1 and 2 PRA model, which is an updated version of the 

12 IPE (NHY 1991), and (2) a supplemental analysis of offsite consequences and economic 

impacts (essentially a Level 3 PRA model) developed specifically for the SAMA analysis.1 13 The 

14 SAMA analysis is based on the most recent Seabrook Level 1 and Level 2 PRA models 

15 available at the time of the ER, referred to as SSPSS-2011 (the model-of-record used to support 

16 SAMA evaluation). The scope of this Seabrook PRA includes both internal and external events. 

17 Table 5.3-1 indicates the Seabrook CDF, based on initiating events, for internal events (plus 

18 internal and external flooding and severe weather), fires, and seismic events 

19 (NextEra 2012a, 2012b). 

20 Table 5.3-1. Seabrook CDF for internal and external events 

Initiating event CDF 

(per year)(a)

% Contribution to 

total CDF(ab)

Loss of offsite power (LOOP)—due to weather(e) 6.810-7 1.510-6 6 10

Flood in relay room from high- energy line break (HELB)(e) 5.910-7 9.510-7 5 6

Steam generator tube rupture (SGTR) 5.710-7 5 

Reactor trip—condenser available 5.410-7 9.310-7 4 6

Medium loss-of-coolant accident (LOCA) 5.310-7 4 

LOOP due to grid-related events 4.510-79.010-7 4 6

Flood in yard due to service water (SW) common return 

rupture(e) 

4.110-78.110-7

3 5

Loss of essential alternating current (AC) power 4 kV bus 3.210-77.310-7 3 5

Steam generator tube rupture (SGTR) 5.910-7 4 

Loss of primary component cooling water system (PCCW) B train 3.010-75.310-7 3 4

Loss of PCCW system A train 2.310-73.910-7 2 3

 

1

 The NRC uses PRA to estimate risk by computing real numbers to determine what can go wrong, how likely is it, and what are its

consequences. Thus, PRA provides insights into the strengths and weaknesses of the design and operation of a nuclear power 

plant. For the type of nuclear plant currently operating in the U.S., a PRA can estimate three levels of risk. A Level 1 PRA 

estimates the frequency of accidents that cause damage to the nuclear reactor core. This is commonly called CDF. A Level 2 PRA, 

which starts with the Level 1 core damage accidents, estimates the frequency of accidents that release radioactivity from the nuclear 

power plant. A Level 3 PRA, which starts with the Level 2 radioactivity release accidents, estimates the consequences in terms of 

injury to the public and damage to the environment. (http://www.nrc.gov/about-nrc/regulatory/risk-informed/pra.html) 
 Environmental Impacts of Postulated Accidents 

 5-5 

Initiating event CDF 

(per year)(a)

% Contribution to 

total CDF(ab)

Major flood, rupture of SW Train A in primary auxiliary 

building (PAB)(e)

2.210-73.510-7

2 

LOOP due to switchyard 2.110-7 3.410-7 2 

Large flood, rupture SW Train A piping in PAB(e)

 2.010-7 3.410-7 2 

Large flood, rupture SW Train B piping in PAB(e)

 2.010-73.310-7 2 

Major flood, rupture of SW Train B in PAB(e)

 2.010-72.510-7 2 

Major flood, rupture of fire protection piping in turbine 

building impacting offsite power(e) 

1.810-72.510-7

2 

Loss of Train B essential AC Power (4 kV Bus E6) 1.610-71.910-7 1 

Large flood, rupture of SW common return piping in PAB(e) 1.410-71.710-7 1 

Large LOCA 3.410-7 2 

Other internal events(bc) 1.610-61.010-6 13 7

Total internal events CDF(eb) 7.810-61.110-5 64 70

Fire Initiating Event 

Fire in control room—power- operated relief valve (PORV) 

LOCA 

3.610-73.710-7 3 2

Fire in switchgear (SWGR) room B—loss of Bus E6 3.510-73.710-7 3 2

Fire SWGR room A—loss of Bus E5 3.110-72.110-7 2 1

Fire control room—AC power loss 1.810-71.410-7 1 

Other fire events(c) 3.810-72.310-7 2 

Total fire events CDF(d) 1.410-61.310-6 11 9

Seismic Initiating Event 

Seismic 0.7 g transient event 9.310-79.210-7 8 6

Seismic 1.0 g transient event 8.910-78.710-7 7 6

Seismic 1.4 g transient event 3.610-7 3 2

Seismic 1.0 g anticipated transient without scram (ATWS) 1.110-7 1

Seismic 1.4 g large LOCA 1.110-7 1

Seismic 0.7 g ATWS 1.010-7 1

Seismic 1.0 g large LOCA 8.910-8 1

Other seismic events(df) 8.810-74.910-7 7 3

Total seismic events CDF(d) 3.110-6 25 21

Total CDF (internal and external events)(g) 1.2×10–51.5×10–5 100 
Environmental Impacts of Postulated Accidents 

 5-6 

Initiating event CDF 

(per year)(a)

% Contribution to 

total CDF(ab)

[References were revised, and only new text is provided below.] 

(a) Individual percent contributions may not sum exactly to subtotals due to round off. 

(b) Obtained by subtracting the sum of the internal initiating event contributors to internal event CDF from the total internal 

events CDF. 

(c) Obtained by subtracting the sum of the fire initiating event contributors to fire event CDF from the total fire events CDF.

(d) Obtained by subtracting the sum of the seismic initiating event contributors to seismic event CDF from the total seismic 

events CDF.

(e) NextEra explained in response to an RAI the difference in the frequencies reported for many initiating events for the 2006 

and 2011 PRA models. The total internal events CDF in the 2011 model decreased slightly as a result of model 

enhancements, the internal flooding CDF increased as result of a more detailed flooding analysis, and the severe weather 

CDF decreased primarily due to the incorporation of more recent data (NextEra 2012b).

1 The Level 2 Seabrook PRA model that forms the basis for the SAMA evaluation is an updated 

2 version of the Level 2 IPE model (New Hampshire Yankee (NHY1991) and IPEEE model 

3 (NAESC 1992), using a single containment event tree (CET) to address both phenomenological 

4 and systemic events. The Level 1 core damage sequences are linked directly with the CET, for 

5 which the quantified sequences are binned into a set of 2114 release categories, which are 

6 subsequently grouped into 1310 source term categories that provide the input to the Level 3 

7 consequence analysis (NextEra 2012a). Source terms were developed using the results of 

8 Modular Accident Analysis Program (MAAP), Version 4.0.7 computer code calculations. The 

9 offsite consequences and economic impact analyses use the MACCS2 code to determine the 

10 offsite risk impacts on the surrounding environment and public. Inputs for these analyses 

11 include plant-specific and site-specific input values for core radionuclide inventory, source term 

12 and release characteristics, site meteorological data, projected population distribution within an 

13 50-mi (80-km) radius for the year 2050, emergency response evacuation planning, and 

14 economic parameters. The core radionuclide inventory corresponds to the end-of-cycle values 

15 for Seabrook operating at 3,659 MWt, which is slightly above the current licensed power level of 

16 3,648 MWt. The magnitude of the onsite impacts (in terms of cleanup and decontamination 

17 costs and occupational dose) is based on information provided in NUREG/BR-0184 

18 (NRC 1997a). NextEra estimated the dose to the population within 80 km (50 mi) of the 

19 Seabrook site to be approximately 37.8 10.7 person-rem (0.378 107 person-Sievert (Sv)) per 

20 year, as shown in Table 5.3-2 (NextEra 2012a). 

21 Table 5.3-2. Breakdown of population dose by containment release mode 

Containment release mode Population dose (Person-rem(a) per year) % Contribution 

Small early releases 1.7 5.3 5 49

Large early releases 1.7 1.6 4 15

Large late releases(b) 34.4 3.8 91 36

Intact containment negligible negligible 

Total 37.8 10.7 100 

(a) One person-rem = 0.01 person-Sv

(b) Includes small early containment penetration failure to isolate and large late containment basemat failure (SELL).
 Environmental Impacts of Postulated Accidents 

 5-7 

1 5.3.2 Adequacy of Seabrook PRA for SAMA Evaluation 

2 The first Seabrook PRA was completed in December 1983 to provide a baseline risk 

3 assessment and an integrated plant and site model for use as a risk management tool. This 

4 model was subsequently updated in 1986, 1989, and 1990, with the last update used to support 

5 the IPE. Based on its review of the Seabrook IPE, as described in an NRC report dated 

6 March 1, 1992 (NRC 1992), the NRC staff concluded that the IPE submittal met the intent of 

7 generic letter (GL) 88-20, “Individual Plant Examination for Severe Accident Vulnerabilities” 

8 (NRC 1988). Although no severe accident vulnerabilities were identified in the Seabrook IPE, 

9 14 potential plant improvements were identified. Four of the improvements have been 

10 implemented. Each of the 10 improvements not implemented is addressed by a SAMA in the 

current evaluation. The internal events CDF value from the 1991 Seabrook IPE (6.110-5 11 per 

12 year) is near the average of the range of the CDF values reported in the IPEs for Westinghouse 

four-loop plants, which ranges from about 310-6 per year to 210-4 13 per year, with an average 

CDF for the group of 610-5 14 per year (NRC 1997b). It is recognized that plants have updated 

15 the values for CDF subsequent to the IPE submittals to reflect modeling and hardware changes. 

16 Based on CDF values reported in the SAMA analyses for LRAs, the internal events CDF result 

for Seabrook used for the SAMA analysis (7.810-6 1.110-5 17 per year, including internal and 

18 external flooding) is somewhat lower than that for most other plants of similar vintage and 

19 characteristics. 

20 There have been 1110 revisions to the IPE model since the 1991 IPE submittal, and 3 revisions 

21 to the PRA model, from the original 1983 PRA model to the 1990 update used to support the 

22 IPE submittal. The SSPSA-2011 model was used for the SAMA analysis. NextEra identified 

23 the major changes in each revision of the PRA, with the associated change in internal and 

24 external event CDF (NextEra 2010, 2011a, 2012a). A comparison of the internal events CDF 

25 between the 1991 IPE and the 2011 PRA model used for the SAMA evaluation indicates a 

decrease of approximately 8782 percent (from 6.110-5 per year to 7.810-61.110-5 26 per year). 

27 The external events CDF has increased by approximately 25 percent since the 1993 IPEEE 

(from 3.610-5 per year to 4.510-5 28 per year). 

29 The Seabrook PRA model is an integrated internal and external events model that has 

30 integrated seismic-initiated, fire-initiated, and external flooding-initiated events with internal 

31 events since the initial 1983 PRA (NextEra 2011a). The external events models used in the 

32 SAMA evaluation are essentially those used in the IPEEE, with the exception of the seismic 

33 PRA model, which underwent a major update for the SSPSA-2005 model. The Seabrook 

34 IPEEE was submitted on October 2, 1992 (NAESC 1992), in response to Supplement 4 of 

35 GL 88-20 (NRC 1991). The submittal used the same PRA as was used for the IPE 

36 (i.e., SSPSA-1990) except for updates to the external events. No fundamental weaknesses or 

37 vulnerabilities to severe accident risk with regard to external events were identified. 

38 Improvements that have already been realized as a result of the IPEEE process minimized the 

39 likelihood of there being cost-beneficial enhancements as a result of the SAMA analysis, 

40 especially with the inclusion of a multiplier to account for the additional risk of seismic events. In 

41 a letter dated May 2, 2001, the NRC staff concluded that the submittal met the intent of 

42 Supplement 4 to GL 88-20, and the applicant’s IPEEE process is capable of identifying the most 

43 likely severe accidents and severe accident vulnerabilities (NRC 2001). 

44 Internal Events CDF 

45 NextEra identified three peer reviews that have been performed on the PRA—a 

46 1999 Westinghouse Owner’s Group (WOG) certification peer review, a 2005 focused peer 
Environmental Impacts of Postulated Accidents 

 5-8 

1 review against the American Society of Mechanical Engineers (ASME) PRA standard 

2 (ASME 2003; NextEra 2010) and a 2009 peer review of the internal flood model against the 

3 ASME PRA standard (ASME 2009; NextEra 2012a). None of the peer reviews included 

4 examination of external flooding, fire, or seismic hazards. The 1999 certification peer review 

5 identified 30 Category A and B facts and observations (F&O), and the 2005 focused peer review 

identified 4 Category A and B F&Os.2 6 NextEra provided the resolution of each of the 34 F&Os 

7 and stated that all have been dispositioned and implemented in the PRA model (NextEra 2010). 

8 NextEra also stated that there were no Category A and three Category B F&Os from the 

9 2009 peer review, all of which were resolved and implemented in the PRA model 

10 (NextEra 2012a). NextEra explained that many other internal reviews including 

11 vendor-assisted reviews have been performed on specific model updates and that comments 

12 from these reviews, along with plant changes and potential model enhancements, are tracked 

13 through a model change database to ensure that the comments are addressed in the periodic 

14 update process (NextEra 2011a).

15 Consistent with the requirements of the ASME 2009 PRA standard (ASME 2009), NextEra 

16 maintains PRA quality control at Seabrook via an existing administrative procedure that defines 

17 the quality control process for PRA updates and ensures that the PRA model accurately reflects 

18 the current Seabrook plant design, operation, and performance (NextEra 2011a). The quality 

19 control process includes monitoring PRA inputs for new information, recording new applicable 

20 information, assessing significance of new information, performing PRA revisions, and 

21 controlling computer codes and models. NextEra also stated that the PRA training qualification 

22 is performed as part of the Engineering Support Personnel Training Program. Given that the 

23 Seabrook internal events PRA model has been peer-reviewed, and the peer review findings 

24 were all addressed, and that NextEra has satisfactorily addressed NRC staff questions 

25 regarding the PRA, the NRC staff concludes that the internal events Level 1 PRA model is of 

26 sufficient quality to support the SAMA evaluation. 

27 Seismic CDF 

28 The Seabrook IPEEE seismic analysis used a seismic PRA following NRC guidance 

29 (NRC 1991). The seismic PRA included the following: 

30  a seismic hazard analysis (based on the EPRI (1988) and the Lawrence Livermore 

31 National Laboratory (LLNL) (NRC 1994) hazard curves), 

32  a seismic fragility assessment, 

33  seismic quantification to yield initiating event frequencies and conditional system failure 

34 probabilities, and 

35  plant model assembly to integrate seismic initiators and seismic-initiated component 

36 failures with random hardware failures and maintenance unavailabilities. 

The seismic CDF resulting from the Seabrook IPEEE was calculated to be 1.210-5 37 per year 

using a site-specific seismic hazard curve, with sensitivity analyses yielding 1.310-4 38 per year 

using the LLNL seismic hazard curve and 6.110-6 39 per year using the EPRI seismic hazard 

40 curve. The Seabrook IPEEE did not identify any vulnerability due to seismic events but did 

41 identify two plant improvements to reduce seismic risk. Neither of the two improvements has 

 

2

 Now termed a “Finding,” a Category A or B F&Os is an “observation (an issue or discrepancy) that is necessary to address to 

ensure: [1] the technical adequacy of the PRA ... [2] the capability/robustness of the PRA update process, or [3] the process for 

evaluating the necessary capability of the PRA technical elements (to support applications).” (Nuclear Energy Institute (NEI) 05-04, 

“Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard,” Revision 2, 2008) 
 Environmental Impacts of Postulated Accidents 

 5-9 

1 been implemented. Each of the two improvements is addressed by a SAMA in the current 

2 evaluation. 

3 Subsequent to the IPEEE, NextEra updated the seismic PRA analysis. These updates included 

4 expanding fragility analysis, with additional components; using the more current EPRI uniform 

5 hazard spectrum (UHS); and improving modeling and documentation of credited operator 

6 actions. 

7 NextEra stated that extensive internal technical reviews of the seismic PRA analysis were 

8 performed for the original 1983 PRA and again when the seismic analysis was revised for the 

9 IPEEE and when the seismic analysis was revised for the SSPSA-2005 PRA model update. No 

10 significant comments were documented from these reviews, and no formal peer reviews have 

11 been conducted on the seismic PRA model (NextEra 2011a). In response to an NRC staff 

12 request to assess the impact on the SAMA evaluation of updated seismic hazard curves 

13 developed by the U.S. Geological Survey (USGS) in 2008 (USGS 2008), NextEra provided a 

14 revised SAMA evaluation using a multiplier of 2.1 to account for the maximum estimated 

seismic CDF for the Seabrook of 2.2×10–5 15 per year. This was noted in the attachments to NRC 

Information Notice 2010-18 16 , generic issue (GI) 199, “Implications of Updated Probabilistic 

17 Seismic Hazard Estimates in Central and Eastern United States on Existing Plants” 

18 (NRC 2010a, 2010b; NextEra 2011a, 2011b, 2012a). Note that, in the process of estimating an 

appropriate multiplier, NextEra considered that the estimated seismic CDF of 2.210–5 19 per year 

20 did not credit the installation of the supplemental electrical power system (SEPS) diesel 

21 generators (DGs) in 2004, which, based on a subsequent PRA estimate, reduced seismic CDF 

by 26 percent. Therefore, in estimating the multiplier, NextEra first reduced the 2.210–5 22 per 

year estimate for seismic CDF by 26 percent to 1.6 x 10–5 23 per year. Using a seismic CDF 

of 1.6 x 10-5 per year, the total CDF equates to 2.5 x 10-5 24 per year or 2.1 times the total 

CDF from Table 5.3-1 (1.2 x 10-5 25 per year). 

26 The NRC staff concludes that the seismic PRA model, in combination with the use of a seismic 

27 events multiplier of 2.1, provides an acceptable basis for identifying and evaluating the benefits 

28 of SAMAs. This conclusion is based on the fact that the Seabrook seismic PRA model is 

29 integrated with the internal events PRA, the seismic PRA has been updated to include 

30 additional components and to extend the fragility screening threshold, the SAMA evaluation was 

31 updated using a multiplier to account for a potentially higher seismic CDF, and NextEra has 

32 satisfactorily addressed NRC staff RAIs regarding the seismic PRA. 

33 Fire CDF 

34 The Seabrook IPEEE fire analysis employed EPRI’s fire-induced vulnerability evaluation (FIVE) 

35 methodology (Electric Power Research Institute (EPRI) 1992) based on definitions of 

36 Appendix R fire areas for Seabrook. Qualitative and quantitative screening was performed to 

37 determine that 13 of the 73 fire areas contained important equipment (pumps, valves, and 

38 cabling, etc.). These were further assessed. Final quantification used the Seabrook IPE PRA 

model to calculate a fire-induced CDF of 1.210-5 39 per year. While no physical plant changes 

40 were found to be necessary as a result of the IPEEE fire analysis, potential plant improvements 

41 to reduce fire risk were identified—of which, four have been implemented. The one 

42 improvement not implemented is addressed by a SAMA in the current evaluation. 

43 NextEra updated the fire PRA, subsequent to the IPEEE, in support of the SSPSS-2004 PRA 

44 update. NextEra stated that the fire analysis methodology used was essentially the same, with 

45 some variations, as that described previously for the IPEEE fire analysis (NextEra 2011a). 
Environmental Impacts of Postulated Accidents 

 5-10 

1 NextEra stated that extensive internal technical reviews of the fire PRA analysis were 

2 performed for the original 1983 PRA and, again, when the fire analysis was revised for the 

3 IPEEE and when the fire analysis was revised for the SSPSS-2005 PRA model update. No 

4 significant comments were documented from these reviews, and no formal peer reviews have 

5 been conducted on the fire PRA model (NextEra 2011a). Considering that the Seabrook fire 

6 PRA model is integrated with the internal events PRA, that the fire PRA has been updated to 

7 include more current data, and that NextEra has satisfactorily addressed NRC staff RAIs 

8 regarding the fire PRA, the NRC staff concludes that the fire PRA model provides an acceptable 

9 basis for identifying and evaluating the benefits of SAMAs. 

10 “Other” External Event CDF 

11 The Seabrook IPEEE analysis of “other” external events included high winds, external floods, 

12 transportation accidents, etc. (HFO events), and it followed the screening and evaluation 

13 approaches specified in Supplement 4 to GL 88-20 (NRC 1991), concluding that Seabrook met 

14 the 1975 Standard Review Plan (SRP) criteria (NRC 1975b). The following external event 

frequencies exceeded the 1.010-6 15 per year screening criterion (NAESC 1992): 

16  flooding resulting from a storm surge caused by a hurricane, which is modeled in the 

PRA (NextEra 2010) and reported to contribute 210-8 17 per year to the total Seabrook 

18 CDF, and 

19  a truck crash into the SF6 transmission lines, which has been mitigated by the 

20 installation of jersey barriers and guard rails and that, as a result, has been screened 

21 from the PRA model (NextEra 2011a). 

22 While no physical plant changes were found to be necessary as a result of the IPEEE HFO 

23 analysis, one plant improvement based on HFO analysis was recommended, but this has 

24 already been implemented (NextEra 2011a). The Seabrook IPEEE submittal also stated that, 

25 as a result of the Seabrook IPE, cost-benefit analyses were being performed for many potential 

26 plant improvements, which may also collaterally reduce external event risk. Four of these five 

27 potential plant improvements have been implemented, and the fifth is addressed by a SAMA in 

28 the current evaluation. 

29 Level 2 and LERF 

30 To translate the results of the Level 1 PRA into containment releases, as well as the results of 

31 the Level 2 analysis, NextEra significantly revised the 2005 PRA update (i.e., PRA model 

32 SSPSS-2005) from that used in the IPE to reflect the Seabrook plant as designed and operated 

33 as of 2006. NextEra explained that the quantification of the Level 1 and Level 2 models is done 

34 using a linked event tree method approach that does not employ plant damage states 

35 (NextEra 2011a). Therefore, all Level 1 sequences are evaluated by the CET. The Level 2 

36 model is a single CET and evaluates the phenomenological progression of all the Level 1 

37 sequences including internal, fire, and seismically initiated events. It has 37 branching events, 

38 for each of which the split fraction is determined based on the type of event. End states 

39 resulting from the combinations of the branches are then assigned to one of 2116 release 

40 categories based on characteristics that determine the timing and magnitude of the release, 

41 whether or not the containment remains intact, and isotopic composition of the released 

42 material. The quantified CET sequences are subsequently grouped into 1013 source term 

43 categories by grouping those that occur due to different phenomena but for which the 

44 consequence is essentially the same. Eight of the release categories were mapped 

45 one-to-one into a corresponding source term category while 13 release categories were 
 Environmental Impacts of Postulated Accidents 

 5-11 

1 mapped into five combined source term categories. These 13 source term categories

2 provide the input to the Level 3 consequence analysis. 

3 Source terms were developed for each of the source term categories. The release fractions and 

4 timing for 5 of the 10 source term categories are based on the results of plant-specific 

5 calculations using the MAAP Version 4.0.7. NextEra generally selected the representative 

6 MAAP case based on that which resulted in the most realistic timing and source term release. 

7 For four of the combined source term categories, the source term for the release 

8 category having the highest (dominant) release frequency was used as the source term 

9 for the combined category. In the fifth combined source term category, one of the 

10 contributors had the most significant source term and the highest frequency so it was 

11 selected as the representative case. 

12 The current Seabrook Level 2 PRA model is an update of that used in the IPE, which did not 

13 identify any severe accident vulnerabilities associated with containment performance. The NRC 

14 staff’s review of the IPE back-end (i.e., Level 2) model concluded that it appeared to have 

15 addressed the severe accident phenomena normally associated with large dry containments, 

16 that it met the IPE requirements, and that there were no obvious or significant problems or 

17 errors. The LERF model was included in the 1999 industry peer review. All F&Os from this 

18 review have been dispositioned and implemented in the PRA model. NextEra explained that 

the apparently very low LERF for Seabrook (1.210-7 19 per year in the SSPSS-2006 model, which 

20 is less than 1 percent of the CDF) results from the very large-volume and strong containment 

21 building in comparison to most other nuclear power plant containment designs (NextEra 2011a), 

22 such that there are no conceivable severe accident progression scenarios that result in 

23 catastrophic failure early in the accident sequence. The NRC staff considers NextEra’s 

24 explanation reasonable. Based on the NRC staff’s review of the Level 2 methodology, the NRC 

25 staff concludes that NextEra has adequately addressed NRC staff RAIs, that the LERF model 

26 was reviewed in more detail as part of the 1999 WOG certification peer review, and that all 

27 F&Os have been resolved. Therefore, the NRC staff concludes that the Level 2 PRA provides 

28 an acceptable basis for evaluating the benefits associated with various SAMAs. 

29 Level 3—Population Dose 

30 NextEra extended the containment performance (Level 2) portion of the PRA to assess offsite 

31 consequences (essentially a Level 3 PRA) via Version 1.13.1 of the MACCS2 code, including 

32 consideration of the source terms used to characterize fission product releases for the 

33 applicable containment release categories and the major input assumptions used in the offsite 

34 consequence analyses (NRC 1998). Plant-specific input to the code included the following: 

35  the source terms for each release category, 

36  the reactor core radionuclide inventory, 

37  site-specific meteorological data for the year 2005, 

38  projected population distribution within an 80-km (50-mi) radius for the year 2050, based 

39 on year 2000 census data from SECPOP2000 (NRC 2003), 

40  emergency evacuation planning, using only 95 percent of the population (conservative 

41 relative to NUREG-1150, which assumed 99.5 percent (NRC 1990)), and 

42  economic parameters including agricultural production. 

43 Multiple sensitivity cases were run, including the following: 
Environmental Impacts of Postulated Accidents 

 5-12 

1  releases at ground level and 25 percent, 50 percent, and 75 percent of the containment 

2 building height (baseline is release at the top of containment), 

3  release plumes with 1 and 10 MW heat release, 

4  factor-of-two scaling of containment building wake effects, 

5  annual meteorological data from 2004 through 2008, 

6  variations in evacuation parameters, such as percent of population, evacuation speed, 

7 and delay time, and 

8  variations in sea-breeze circulation assumptions. 

9 NextEra’s results showed only minor variations from the baseline for these sensitivities, which is 

10 consistent with previous SAMA analyses. The NRC staff concludes that the methodology used 

11 by NextEra to estimate the offsite consequences for Seabrook provides an acceptable basis 

12 from which to proceed with an assessment of risk reduction potential for candidate SAMAs. 

13 Accordingly, the NRC staff based its assessment of offsite risk on the CDF and offsite doses 

14 reported by NextEra. 

15 5.3.3 Potential Plant Improvements 

16 NextEra’s process for identifying potential plant improvements (SAMAs) consisted of the 

17 following elements: 

18  review of the most significant basic events from the 2011 plant-specific PRA, which was 

19 the most current PRA model at the time the SAMA evaluation was performed, 

20  review of potential plant improvements identified in the Seabrook IPE and IPEEE, 

21  review of other industry documentation discussing potential plant improvements, and 

22  insights from Seabrook personnel. 

23 Based on this process, an initial set of 195 191 candidate “Phase I” SAMAs was identified, for 

24 which NextEra performed a qualitative screening to eliminate ones from further consideration 

25 using the following criteria: 

26  The SAMA is not applicable to Seabrook due to design differences (19 SAMAs 

27 screened). 

28  The SAMA has already been implemented at Seabrook or the Seabrook meets the intent 

29 of the SAMA (87 SAMAs screened). 

30  The SAMA is similar to another SAMA under consideration (11 SAMAs screened). 

31  The SAMA has estimated implementation costs that would exceed the dollar value 

32 associated with eliminating all severe accident risk at Seabrook (no SAMA screened). 

33  The SAMA was determined to provide very low benefit (no SAMA screened). 

34 Based on this screening, 117 SAMAs were eliminated, leaving 78 74 for detailed evaluation in 

35 Phase II. In Phase II, a detailed evaluation was performed for each of the remaining 78 SAMA 

36 candidates. NextEra accounted for the potential risk reduction benefits associated with each 

37 SAMA by quantifying the benefits using the integrated internal and external events PRA model. 
 Environmental Impacts of Postulated Accidents 

 5-13 

1 The NRC staff reviewed NextEra’s process for identifying and screening potential SAMA 

2 candidates, as well as the methods for quantifying the benefits associated with potential risk 

3 reduction. This included reviewing insights from the plant-specific risk studies, reviewing plant 

4 improvements considered in previous SAMA analyses, and explicitly treating external events 

5 in the SAMA identification process. The NRC staff concludes that NextEra used a systematic 

6 and comprehensive process for identifying potential plant improvements for Seabrook, and the 

7 set of SAMAs evaluated in the ER, together with those evaluated in response to NRC staff 

8 inquiries, is reasonably comprehensive; therefore, it is acceptable. 

9 5.3.3.1 Risk Reduction 

10 NextEra evaluated the risk-reduction potential of the 78 SAMAs retained for the Phase II 

11 evaluation, which includes the risk-reduction potential of additional SAMAs identified in 

12 the 2012 SAMA supplement (NextEra 2012a) and in response to NRC staff RAIs 

13 (NextEra 2012b). NextEra used model re-quantification to determine the potential benefits 

14 based on the SSPSS-2011 PRA model. The majority of the SAMA evaluations were performed 

15 in a bounding fashion in that the SAMA was assumed to eliminate the risk associated with the 

16 proposed enhancement. On balance, such calculations overestimate the benefit and are 

17 conservative. The NRC staff reviewed NextEra’s bases for calculating the risk reduction for the 

18 various plant improvements and concludes that the rationale and assumptions are reasonable 

19 and generally conservative (i.e., the estimated risk reduction is higher than what would actually 

20 be realized). Accordingly, the NRC staff based its estimates of averted risk for the various 

21 SAMAs on NextEra’s risk reduction estimates. 

22 5.3.3.2 Cost Impacts 

23 NextEra developed plant-specific costs of implementing the 78 Phase II candidate SAMAs using 

24 an expert panel—composed of senior plant staff from the PRA group, the design group, 

25 operations, and license renewal—with experience in developing and implementing modifications 

26 at Seabrook. In most cases, detailed cost estimates were not developed because of the large 

27 margin between the estimated SAMA benefits and the estimated implementation costs 

28 (NextEra 2011a). The cost estimates, conservatively, did not specifically account for inflation, 

29 contingencies, implementation obstacles, or replacement power costs (RPC). The NRC staff 

30 reviewed the bases for the applicant’s cost estimates and, for certain improvements, compared 

31 the cost estimates to estimates developed elsewhere for similar improvements, including 

32 estimates developed as part of other applicants’ analyses of SAMAs for operating reactors and 

33 advanced light-water reactors. The NRC staff concludes that the cost estimates provided by 

34 NextEra are sufficient and appropriate for use in the SAMA evaluation. 

35 5.3.3.3 Cost-Benefit Comparison 

36 The methodology used by NextEra was based primarily on NRC’s guidance for performing 

37 cost-benefit analysis (i.e., NUREG/BR-0184, Regulatory Analysis Technical Evaluation 

38 Handbook (NRC 1997a)). The guidance involves determining the net value for each SAMA 

39 according to the following formula: 

40 Net Value = (APE + AOC + AOE + AOSC) – COE 

41 where: 

42 APE = present value of averted public exposure ($) 

43 AOC = present value of averted offsite property damage costs ($) 
Environmental Impacts of Postulated Accidents 

 5-14 

1 AOE = present value of averted occupational exposure costs ($) 

2 AOSC = present value of averted onsite costs ($) 

3 COE = cost of enhancement ($) 

4 If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 

5 benefit associated with the SAMA, and it is not considered cost beneficial. Present values for 

6 both a 3 percent and 7 percent discount rate were considered. Using the NUREG/BR-0184 

7 methods, NextEra estimated the total present dollar value equivalent associated with eliminating 

8 severe accidents from internal and external events at Seabrook to be about $3.05 million

9 819,000. Use of a multiplier of 2.1 to account for the additional risk from seismic events 

10 in the sensitivity analysis increases the value to $6.4 million. This represents the dollar 

11 value associated with completely eliminating all internal and external event severe 

12 accident risk at Seabrook, and it is also referred to as the maximum averted cost risk 

13 (MACR). 

14 If the implementation costs for a candidate SAMA exceeded the calculated benefit, the SAMA 

15 was considered not to be cost beneficial. In the baseline analysis (using a 7 percent discount 

16 rate), NextEra identified three one potentially cost-beneficial SAMAs (SAMA 157, 165, and 192, 

17 see Table 5.3-3). Based on the consideration of analysis uncertainties, NextEra identified three

18 one additional potentially cost-beneficial SAMAs (SAMA 164, 172, and 193195, see 

19 Table 5.3-3). In addition, as a result of the sensitivity analysis using a multiplier of 2.1 to 

20 account for the additional risk from seismic events, NextEra identified one additional cost21 beneficial SAMA (SAMA 193, see Table 5.3-3). 

22 The seven four potentially cost-beneficial SAMAs are discussed in Section 5.3.4. The NRC 

23 staff notes that these are included within the set of SAMAs that NextEra plans to enter into the 

24 Seabrook long-range plan development process for further implementation consideration. The 

25 NRC staff concludes that, with the exception of the seven four potentially cost-beneficial 

26 SAMAs, the costs of the other SAMAs evaluated would be higher than the associated benefits. 

27 5.3.4 Cost-Beneficial SAMAs 

28 Highlighted in bold italics in Table 5.3-3 are the potentially cost-beneficial SAMAs (157, 164, 

29 165, 172, 192, 193, and 195). 

30 Table 5.3-3. SAMA cost-benefit Phase-II analysis for Seabrook 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No station blackout 

(SBO): 

Six Five SAMAs 

analyzed 

Eliminate failure 

of the emergency 

diesel generators 

(EDGs) 

22

27

6 12 220K (470K) 

160K (330K

525K 

(1.1M) 

300K (620K

1.75M >1.0M

(minimum of six) 
 Environmental Impacts of Postulated Accidents 

 5-15 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No LOOP: 

Three Five SAMAs 

analyzed 

Eliminate LOOP 

events 

18

42

17 36 530K (1.2M) 

340K (700K

1.2M (2.7M)

640K 

(1.3M)

>3M 2.4M (minimum 

of three) 

No loss of 4 kV in-feed 

breakers: 

#21—Develop 

procedures to repair or 

replace failed 4 kV 

breakers 

Eliminate failure 

of the 4 kV bus 

in-feed breakers 

1 <1 8K (17K) 15K (32K) Screened 

No loss of high-pressure 

injection (HPI): 

Two Three SAMAs 

analyzed 

Eliminate failure 

of the HPI system

22

68

34 52 1.1M (2.3M) 

470K (980K

2.5M (5.3M) 

890K (1.9M

8.8M>5.0M (minimum 

of boththree) 

No loss of low-pressure 

injection: 

#28—Add a diverse 

low-pressure injection 

system 

Eliminate failure 

of the lowpressure injection 

system 

2 11 2 29 68K (140K) 

160K (340K

160K 

(340K) 

300K (640K

>1M 1.0M

No depletion of reactor 

water storage tank 

(RWST): 

Two SAMAs analyzed 

Eliminate RWST 

running out of 

water 

13

28

10 12 310K (655K) 

160K (330K

730K 

(1.5M) 

300K (630K

>3M 1.0M (minimum 

of both) 

Reduce common cause 

failure of the safety 

injection (safety 

injectionSI) system: 

#39—Replace two of 

the four electric SI 

pumps with dieselpowered pumps 

Eliminate 

dependency of 

the existing 

intermediate 

head SI pump 

trains on AC 

power 

<1 0 <1K (<1K) <1K (<1K) >5M 

No small LOCAs: 

#41—Create a reactor 

coolant depressurization 

system 

Eliminate all 

small LOCA 

events 

2 7 1 2 27K (57K) 

33K (70K

64K (130K) 

63K

>1M 1.0M

No direct current (DC) 

dependence for SW: 

#43—Add redundant DC 

control power for SW 

pumps 

Eliminate the 

dependence of 

the SW pumps 

on DC power 

<2 1 0 1 11K (24K) 

10K (21K

26K (55K) 

19K (40K

>100K 
Environmental Impacts of Postulated Accidents 

 5-16 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No loss of component 

cooling water (CCW): 

#44—Replace 

emergency core 

cooling system ( ECCS) 

pump motors with aircooled motors 

Eliminate failure 

of the CCW 

pumps 

14 31 920K (1.9M) 2.15M

(4.6M) 

>6M 

No failure of support 

systems for core spray 

(CS) division B of HPI:

SixTwo SAMAs analyzed 

Eliminate 

failures of 

support 

systems (e.g., 

AC and DC 

power, cooling) 

for division B of 

HPI

28

25

34 23 1.0M (2.2M) 

180K (380K

2.45M

(5.2M) 

350K (730K

>6.4M 1.0M (minimum 

of six both) 

No CCW pump failure 

when AC/DC power 

available: 

#59—Install a digital 

feed water upgrade 

Eliminate CCW 

pump failure 

when AC and 

DC power 

support is 

available 

4 11 335K (700K) 785K 

(1.7M) 

>6.1M 

No plant risk

TwoSeven SAMAs 

analyzed 

Eliminate all 

plant risk

100

11

100 12 3.05M (6.4M) 

92K (170K

7.15M 

(15M) 180K 

(370K

>15M 500K

(minimum of two

seven) 

No PORV failures: 

#79—Install bigger pilot 

operated relief valve so 

only one is required 

Eliminate all 

PORV failures 

<1

12

0 7 1.7K (4K) 

73K (150K

4.1K (9K) 

140K (290K

>2.7M 1.0M

No heating, ventilation, 

and air conditioning 

(HVAC) dependence for 

CS, SI, RH, & 

containment building 

spray (CBS): 

#80—Provide a 

redundant train or means 

of ventilation 

Eliminate the 

dependence of 

CS, SI, residual 

heat removal 

(RHR), & CBS 

pumps on HVAC 

3 8 5 1 150K (320K) 

32K (67K

360K 

(750K) 61K 

(130K

>1M 500K

No HVAC dependence 

for emergency feedwater 

(EFW): 

#84—Switch for EFW 

room fan power supply to 

station batteries 

Eliminate loss of 

EFW ventilation 

<1 0 <1 <1K (<2K 1K) <2K 1K

(<4K 2K) 

>250K 
 Environmental Impacts of Postulated Accidents 

 5-17 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No CBS support system 

or common cause 

failures: 

Two SAMAs analyzed 

Eliminate CBS 

power, signal, 

and cooling 

support system 

failures, and 

common cause 

failure among 

similar 

components for 

one division of 

CBS 

0 58 1.7M (3.5M) 4.0M (8.3M) >10M (minimum of 

two) 

No failure of human 

action to vent 

containment: 

#93—Install an 

unfiltered hardened 

containment vent Four 

SAMAs analyzed

Eliminate 

allfailure of the 

human action to 

vent containment 

0 1 36 39K (82K) 

160K (340K

92K (190K) 

310K (650K

>3M 3.0M (minimum 

of six)

No release from 

containment venting 

and reduced release 

from basemat meltthrough: 

#94—Install a filtered 

containment vent to 

remove decay heat 

Eliminate 

release category 

LL3 

(containment 

vent) and 

prevent 80 

percent of 

release category 

LL5 (basemat 

melt-through) 

0 69 2.0M (4.1M) 4.6M (9.7M) >20M 

Reduced likelihood of 

non-recovery off offsite power: 

#99—Strengthen 

primary & secondary 

containment (e.g., add 

ribbing to containment 

shell) 

Reduce by a 

factor of 10 the 

non-recovery of 

off-site power 

before late 

containment 

pressure failure 

occurs 

0 4 120K (245K) 270K 

(570K) 

11.5M 

Reduced failure of CBS: 

#107—Install a 

redundant containment 

spray system 

Add redundant 

train of CBS 

0 1 29K (62K) 69K (140K) >10M 

No hydrogen burns or 

detonations: 

Three SAMAs analyzed 

Eliminate all 

hydrogen ignition 

and burns 

0 1 0 18K (39K) 

<1K (<1K

43K (90K) 

<1K (<1K

>100K (minimum of 

three) 
Environmental Impacts of Postulated Accidents 

 5-18 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No failure of operator 

action to transfer to longterm recirculation 

following large LOCA: 

#105—Delay 

containment spray 

actuation after a large 

LOCA 

Eliminate the 

human failure to 

complete/ ensure 

the RHR/lowhead safety 

injection (LHSI) 

transfer to longterm recirculation 

during large 

LOCA events 

3 2 0 <1 12K (25K) 

7.2K (15K

27K (58K) 

14K (29K

>100K 

No high- pressure core 

ejection: 

#110—Erect a barrier 

that would provide 

enhanced protection of 

the containment walls 

(shell) from ejected 

core debris following a 

core melt scenario at 

high pressure 

Eliminate highpressure core 

ejection 

occurrences 

0 0 <1K (<1K) 1K (2K) >10M 

No containment 

isolation valve (CIV) 

failures: 

Two SAMAs analyzed 

Eliminate CIV 

failures 

0 6 19 115K (240K) 

100K (220K

270K 

(570K) 

200K (420K

>1M 500K (minimum 

of both) 

Reduce ISLOCA risk by 

half

Reduce ISLOCA 

event risk by 50%

1 3 14K (30K) 27K (60K) >100K

No interfacing system 

loss-of-coolant accidents 

(ISLOCAs): 

Three TwoSAMAs 

analyzed 

Eliminate all 

ISLOCAs 

<1 2 3 7 48K (100K) 

28K (60K

110K

(240K) 53K

>500 190K (minimum 

of boththree) 

No SGTRs: 

Five SAMAs analyzed 

Eliminate all 

SGTR events 

5 3 2 17 67K (140K) 

86K (180K

160K 

(330K345K) 

>500K (minimum of 

five) 

No anticipated transient 

without scrams 

(ATWSs): 

Four SAMAs analyzed 

Eliminate all 

ATWS events 

4 3 2 11 60K (130K) 

70K (150K

140K 

(290K) 

130K (280K

>500K (minimum of 

four) 

No piping system LOCAs: 

#147—Install digital large 

break LOCA protection 

system 

Eliminate all 

piping failure 

LOCAs 

9 10 2 12 77K (160K) 

100K (220K

180K 

(380K) 

200K (410K

>500K 
 Environmental Impacts of Postulated Accidents 

 5-19 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No secondary side 

depressurization from 

stem line break upstream 

of main steam isolation 

valves: 

#153—Install secondary 

side guard pipes up to 

the main steam isolation 

valves 

Eliminate all 

steam line break 

events 

<1 0 0 <1 5K (11K) 3K 

(7K

11K (24K) 

6K (13K

>500K 

No operator error when 

aligning & loading SEPS 

DGs: 

#154—Modify SEPS 

design to accommodate: 

(a) automatic bus 

loading, (b) automatic 

bus alignment 

Eliminate failure 

of all operator 

actions to align 

and load the 

SEPS DGs 

8

NP*

2 NP 64K (135K) 

33K (68K

150K 

(320K) 62K 

(130K

>750K 

Provide independent AC 

power to battery 

chargers: 

#157—Provide 

independent AC power 

source for battery 

chargers; for example, 

provide portable 

generator to charge 

station battery 

Eliminate failure 

of operator 

action to shed 

DC loads to 

extend batteries 

to 12 hours & 

eliminate failure 

to recover 

offsite power for 

plant-related, 

grid-related, & 

weather-related 

LOOP events 

<2 4 1 2 34K (72K) 

23K (48K

80K (170K) 

45K (95K 30K 

#159—Install additional 

batteries 

 >1.0M 

No depletion of 

condensate storage: 

#162—Increase the 

capacity margin of the 

condensate storage 

tank (CST) Two SAMAs 

analyzed

#164—Modify 10" 

condensate filter flange 

to have a 2-1/2"-inch

female fire hose 

adapter with isolation 

valve

Eliminate CST 

running out of 

water 

<2 1 1 35K (73K) 9K 

(18K

81K (170K) 

16K (34K >2.5M 

>40K (minimum of 

both)
Environmental Impacts of Postulated Accidents 

 5-20 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No loss of turbine-driven 

auxiliary feedwater 

(TDAFW): 

#163—Install third EFW 

pump (steam-driven) 

Eliminate failure 

of the TDAFW 

train 

5 19 12 9 360K (750K) 

100K (210K

835K 

(1.8M) 

190K (400K

>2.0M 

Guaranteed success of 

RWST long-term makeup 

without recirculation: 

#165—RWST fill from 

firewater during 

containment injection—

Modify 6" RWST Flush 

Flange to have a 21⁄2" 

female fire hose 

adapter with isolation 

valve 

Guaranteed 

success of 

RWST makeup 

for long-term 

sequences 

where 

recirculation is 

not available 

5 10 2 8 57K (120K) 

75K (160K

130K 

(280K) 

120K (300K

50K 

No loss of reactor 

coolant pump (RCP) 

seal cooling and no 

failure of RCP seals 

following a plant 

transient: 

#172—Evaluate 

installation of a 

“shutdown seal” in the 

RCPs being developed 

by Westinghouse

Eliminate failure 

of RCP seal 

cooling 

initiating event 

and RCP seal 

failures 

subsequent to a 

plant transient 

34 49 1.5M (3.2M) 2.5M (7.4M) >2M 

No fire in turbine building 

at west wall or relay 

room: 

#175—Improve fire 

detection in turbine 

building relay room 

This SAMA has been implemented (NextEra 2011b) 

No failure of operator 

action to close PORV 

block valve during a 

control room fire:

#179—Fire- induced 

LOCA response 

procedure from alternate 

shutdown panel 

Eliminate operator 

failure to close PORV 

block valve during a 

control room fire 

0 1 0

<1

<1K (<1K) 4K 

(8K

<1K (<2K) 

7K (15K

>20K 

No failures due to seismic 

relay chatter: 

#181—Improve relay 

chatter fragility 

Eliminate all seismic 

relay chatter failures 

12

9

3

12

87K (180K) 

100K (210K

200K 

(470K410K) 

>600K 
 Environmental Impacts of Postulated Accidents 

 5-21 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No seismic-induced loss 

of DGs or turbine-driven 

emergency feedwater 

(TDEFW): 

#182—Improve seismic 

capacity of EDGs & 

steam-driven EFW pump 

Eliminate all seismic 

failures of EDGs or 

TDEFW 

<1

0

0 2.4K (6K) 

<1K (<1K

5.6K (12K) 

<1K (<1K

>500K 

Containment purge 

valves are always closed: 

#184—Control/reduce 

time that the containment 

purge valves are in open 

position 

Eliminate possibility of 

containment purge 

valves being open at 

the time of an event 

0 ≈0 <1K (<1K) <1K 

(<2K1K) 

>20K 

No CDF contribution from 

pre-existing containment 

leakage: 

#186—Install 

containment leakage 

monitoring system 

Eliminate all CDF 

contribution from preexisting containment 

leakage 

0

NP

0

NP

4.4K (12K) 

11K (23K

10K (27K) 

20K (43K

>500K 

Benefits of SEPS 

success criteria change, 

from two of two SEPS 

DGs to one of two SEPS 

DGs: 

#189—Modify or analyze 

SEPS capability; one of 

two SEPS for loss of 

system pressure (LOSP) 

non-SI loads, two of two 

for LOSP SI loads 

Modify fault tree so that 

one of two SEPS DGs 

are required rather than 

both SEPS DGs being 

required 

6 7 2 1 63K (130K) 

30K (60K

150K 

(310K) 60K 

(120K

>2M 300K

No inadvertent failures of 

redundant temperature 

logic during loss of 

PCCW: 

#191—Remove the 

135 oF temperature trip of 

the PCCW pumps 

Eliminate inadvertent 

failure of the redundant 

temperature 

element/logic of the 

associated primary 

component cooling 

(PCC) division for both 

loss of PCCW initiating 

events & loss of PCCW 

mitigative function 

<1 0

<1

<1K (<1K) <1K (<2K

1K) 

>100K 
Environmental Impacts of Postulated Accidents 

 5-22 

Analysis case & 

applicable SAMAs 

(where multiples, only 

number & minimum 

cost are listed) 

Modeling 

assumptions 

% Risk 

reduction Total benefit ($) 

Cost ($) 

CDF Pop. 

dose 

Baseline (with 2.1 

multiplier) 

Internal + 

External 

with 

uncertainty 

No flooding in control 

building due to fire 

protection system 

actuation: 

#192—Install a globe 

valve or flow limiting 

orifice upstream in the 

fire protection system 

Eliminate control 

building fire 

protection flooding 

initiators 

24

25

11

6

470K (990K) 

160K (340K

1.1M (2.3M) 

310K (640K

370K 200K

No failure of operator 

action to close CIV 

CS-V-167:

#193—Hardware 

change to eliminate 

motor-operated valve 

(MOV) AC power 

dependency 

Eliminate operator 

failure to close CIV 

CS-V-167 

0 5

35

86K (180K) 

190K (400K

200K 

(420K) 

365K (770K

300K 

No failure of main 

steam safety valves 

(MSSVs) to reseat: 

#194—Purchase or 

manufacture a 

“gagging device” that 

could be used to close 

a stuck-open steam 

generator safety valve 

Eliminate failure of 

MSSVs to reseat

0 0 <1K (<1K) <1K (<2K) >30K

No failure of 

temperature elements 

for PCC Trains A and B: 

#195—Make 

improvements to PCCW 

temperature control 

reliability

Eliminate failure of 

temperature control 

and modulation for 

PCC Trains A and B 

that could fail PCCW 

3 5 140K (300K) 340K 

(710K) 

300K 

1 5.3.5 Conclusions 

2 NextEra compiled a list of 191 SAMAs in the ER and 4 additional SAMAs in the 2012 SAMA 

3 supplement (NextEra 2012a) based on a review of the most significant basic events from the 

4 plant-specific PRA, insights from the plant-specific IPE and IPEEE, review of other industry 

5 documentation, and insights from Seabrook personnel. Of these, 117 SAMAs were eliminated 

6 qualitatively, leaving 78 candidate SAMAs for evaluation. These underwent more detailed 

7 design and cost estimates to show that threetwo were potentially cost beneficial in the baseline 

8 analysis (SAMAs 157, 165, and 192). NextEra also performed additional analyses to evaluate 

9 the impact of parameter choices and uncertainties, resulting in three additional potentially 

10 cost-beneficial SAMAs (SAMAs 164, 172, and 195). In addition, NextEra performed a 
 Environmental Impacts of Postulated Accidents 

 5-23 

1 sensitivity analysis accounting for the additional risk of seismic events and identified one

2 additional SAMA (SAMA 193) as being potentially cost beneficial. NextEra has indicated that all 

3 sevenfour potentially cost-beneficial SAMAs will be entered into the Seabrook long-range plan 

4 development process for further implementation consideration. 

5 The NRC staff reviewed the NextEra analysis and concludes that the methods used and their 

6 implementation were acceptable. The treatment of SAMA benefits and costs support the 

7 general conclusion that the SAMA evaluations performed by NextEra are reasonable and 

8 sufficient for the license renewal submittal. 

9 The NRC staff agrees with NextEra’s identification of areas in which risk can be further 

10 reduced in a potentially cost-beneficial manner through the implementation of the 

11 identified, potentially cost-beneficial SAMAs. Given the potential for cost-beneficial risk 

12 reduction, the NRC staff agrees that further evaluation of these SAMAs by NextEra is 

13 warranted. However, the applicant stated that the sevenfour potentially cost-beneficial 

14 SAMAs are not aging-related in that they do not involve aging management of passive, 

15 long-lived systems, structures, or components during the period of extended operation. 

16 Therefore, the NRC staff concludes that they need not be implemented as part of license 

17 renewal pursuant to 10 CFR Part 54. 

18 5.4 References

19 American Society of Mechanical Engineers (ASME), 2003, “Addenda to ASME RA-S-2002, 

20 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications,” 

21 ASME RA-Sa-2003, December 5, 2003. 

22 ASME, 2009, “Addenda to ASME RA-S-2008, Standard for Level 1/Large Early Release 

23 Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications,” 

24 ASME RA-Sa-2009, February 2, 2009. 

25 Electric Power Research Institute (EPRI), 1992, “Fire-Induced Vulnerability Evaluation (FIVE),” 

26 EPRI TR-100370, Revision 0, Palo Alto, CA, April 1992. 

27 EPRI, 1988, “A Methodology for Assessment of Nuclear Power Plant Seismic Margin,” 

28 EPRI NP-6041, Revision 0, Palo Alto, CA, August 1988. 

29 New Hampshire Yankee (NHY), 1991, “Individual Plant Examination Report for Seabrook 

30 Station,” March 1, 1991. 

31 NextEra Energy Seabrook, LLC. (NextEra), 2010, “Seabrook Station—License Renewal 

32 Application, Applicant’s Environmental Report, Operating License Renewal Stage,” 

33 May 25, 2010, Agencywide Documents Access and Management System (ADAMS) Accession 

34 Nos. ML101590092 and ML101590089. 

35 NextEra, 2011a, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control Desk, 

36 Subject: “Seabrook Station, Response to Request for Additional Information, NextEra Energy 

37 Seabrook License Renewal Application,” Seabrook, NH, January 13, 2011, ADAMS Accession 

38 No. ML110140810. 

39 NextEra, 2011b, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control Desk, 

40 Subject: “Seabrook Station, Response to Request for Additional Information, NextEra Energy 
Environmental Impacts of Postulated Accidents 

 5-24 

1 Seabrook License Renewal Application,” Seabrook, NH, April 18, 2011, ADAMS Accession 

2 No. ML11122A075. 

3 NextEra, 2012a, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control 

4 Desk. Subject: “Seabrook Station, Supplement 2 to Severe Accident Mitigation 

5 Alternatives Analysis, NextEra Energy Seabrook License Renewal Application,” 

6 Seabrook, NH, March 19, 2012, ADAMS Accession No. ML12080A137. 

7 NextEra, 2012b, Letter from Kevin T. Walsh, NextEra, to U.S. NRC Document Control 

8 Desk. Subject: “Seabrook Station, Supplement 3 to Severe Accident Mitigation 

9 Alternatives Analysis, Response to RAI Request dated July 16, 2012, NextEra Energy 

10 Seabrook License Renewal Application,” Seabrook, NH, September 13, 2012, ADAMS 

11 Accession No. ML12262A513. 

12 North Atlantic Energy Service Corp. (NAESC), 1992, “Individual Plant Examination External 

13 Events Report for Seabrook Station,” October 2, 1992, ADAMS Accession No. ML080100029. 

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

15 Licensing and Related Regulatory Functions,” Part 50, Chapter 1, Title 10, “Energy.” 

16 U.S. Geologic Survey (USGS), 2008, “2008 NSHM Gridded Data, Peak Ground Acceleration,” 

17 Available URL: http://earthquake.usgs.gov/hazards/products/conterminous/2008/data/. 

18 U.S. Nuclear Regulatory Commission (NRC), 1975a, “Reactor Safety Study: An Assessment of 

19 Accident Risks in U.S. Commercial Nuclear Power Plants,” WASH-1400 (NUREG-75/014), 

20 Washington, D.C., October 1975. 

21 NRC, 1975b, “Standard Review Plan for the Review of Safety Analysis Report for Nuclear 

22 Power Plants,” NUREG-0800, Washington, D.C., November 1975. 

23 NRC, 1988, GL 88-20, “Individual Plant Examination for Severe Accident Vulnerabilities,” 

24 November 23, 1988. 

25 NRC, “Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants,” 

26 NUREG-1150, Washington, D.C., December 1990. 

27 NRC, 1991, GL 88-20 “Individual Plant Examination of External Events (IPEEE) for Severe 

28 Accident Vulnerabilities,” Washington, D.C., Supplement 4, June 28, 1991. 

29 NRC, 1992, Letter from Gordon E. Edison, U.S. NRC, to Ted C. Feigenbaum, NHY, Subject: 

30 “Staff Evaluation of Seabrook Individual Plant Examination (IPE)—Internal Events, GL 88-20 

31 (TAC No. M74466),” Washington, D.C., February 28, 1992. 

32 NRC, 1994, “Revised Livermore Seismic Hazard Estimates for Sixty-Nine Nuclear Power Plant 

33 Sites East of the Rocky Mountains,” NUREG-1488, April 1994. 

34 NRC, 1996, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” 

35 NUREG-1437, Volumes 1 and 2, May 31, 1996, ADAMS Accession Nos. ML040690705 and 

36 ML040690738. 

37 NRC, 1997a, Regulatory Analysis Technical Evaluation Handbook, NUREG/BR-0184, 

38 Washington, D.C., January 1997, ADAMS Accession No. ML050190193. 
 Environmental Impacts of Postulated Accidents 

 5-25 

1 NRC, 1997b, “Individual Plant Examination Program: Perspectives on Reactor Safety and Plant 

2 Performance,” NUREG-1560, Washington, D.C., December 1997. 

3 NRC, 1998, Code Manual for MACCS2: Volume 1, User’s Guide, NUREG/CR-6613, 

4 Washington, D.C., May 1998. 

5 NRC, 1999, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” 

6 NUREG-1437, Volume 1, Addendum 1, Section 6.3, “Transportation,” Table 9.1, “Summary of 

7 Findings on NEPA Issues for License Renewal of Nuclear Power Plants, Final Report,” 

8 August 31, 1999, ADAMS Accession No. ML040690720. 

9 NRC, 2001, Letter from Victor Nerses, U.S. NRC, to Ted C. Feigenbaum, NAESC, Subject: 

10 “Seabrook Station, Unit No. 1—Individual Plant Examination of External Events (IPEEE) (TAC 

11 No. M83673),” Washington, D.C., May 2, 2001, ADAMS Accession No. ML010320252. 

12 NRC, 2003, “Sector Population, Land Fraction, and Economic Estimation Program,” SECPOP: 

13 NUREG/CR-6525, Washington D.C., April 2003 

14 NRC, 2010a, Letter from Michael Wentzel, U.S. NRC, to Paul Freeman, NextEra, Subject: 

15 “Request for Additional Information for the Review of the Seabrook Station License Renewal 

16 Application-SAMA Review (TAC No. ME3959),” Washington, D.C., November 16, 2010, 

17 ADAMS Accession No. ML103090215. 

18 NRC, 2010b, NRC Information Notice 2010-18: GI-199, “Implications of Updated Probabilistic 

19 Seismic Hazard Estimates in Central and Eastern United States on Existing Plants,” 

20 Washington, D.C., September 2, 2010, ADAMS Accession No. ML101970221. 

21 NRC, 2011a, Memorandum to NextEra from Michael J. Wentzel, U.S. NRC, Subject: “Summary 

22 of Telephone Conference Calls held on February 15, 2011, between the U.S. Nuclear 

23 Regulatory Commission and NextEra Energy Seabrook, LLC, to Clarify the Responses to the 

24 Requests for Additional Information Pertaining to the Severe Accident Mitigation Alternatives 

25 Review of the Seabrook Station License Renewal Application (TAC No. ME3959),” 

26 Washington, D.C., February 28, 2011, ADAMS Accession No. ML110490165. 

27 NRC, 2011b, Letter from Bo Pham, U.S. NRC, to Paul Freeman, NextEra, Subject: “Schedule 

28 Revision and Request for Additional Information for the Review of the Seabrook Station License 

29 Renewal Application Environmental Review (TAC Number ME3959),” Washington, D.C., 

30 March 4, 2011, ADAMS Accession No. ML110590638.

31 NRC, 2012a, Letter from Micheal Wentzel, U.S. NRC, to Kevin Walsh, NextEra. Subject: 

32 “Request for Additional Information for the Review of the Seabrook Station License 

33 Renewal Application Environmental Review—SAMA Review (TAC Number ME3959),” 

34 Washington, D.C., July 16, 2012, ADAMS Accession No. ML12180A355. 

35 NRC, 2012b, Memorandum to File. Subject: “Summary of Telephone Conference Call 

36 held on October 3, 2012, between the U.S. Nuclear Regulatory Commission and NextEra 

37 Energy Seabrook, LLC, Clarifying Responses to Requests for Additional Information 

38 Pertaining to the Seabrook Station License Renewal Application Environmental Review 

39 (TAC. No. ME3959),” dated November 1, 2012, ADAMS Accession No. ML12278A250. 

40 
 
 

 6-1 

1 6.0 ENVIRONMENTAL IMPACTS OF THE URANIUM FUEL CYCLE, 

2 SOLID WASTE MANAGEMENT, AND GREENHOUSE GAS 

3 6.1 The Uranium Fuel Cycle

4 This section addresses issues related to the uranium fuel cycle and solid waste management 

5 during the period of extended operation (listed in Table 6.1-1). The uranium cycle includes 

6 uranium mining and milling, the production of uranium hexafluoride, isotopic enrichment, fuel 

7 fabrication, reprocessing of irradiated fuel, transportation of radioactive materials, and 

8 management of low-level wastes and high-level wastes related to uranium fuel cycle activities. 

9 The generic potential impacts of the radiological and nonradiological environmental impacts of 

10 the uranium fuel cycle and transportation of nuclear fuel and wastes are described in detail in 

11 the Generic Environmental Impact Statement (GEIS) (NRC 1996, 1999). They are based, in 

12 part, on the generic impacts provided in Title 10, Part 51.51(b) of the Code of Federal 

13 Regulations (10 CFR 51.51(b)), Table S-3, “Table of Uranium Fuel Cycle Environmental Data,” 

14 and in 10 CFR 51.52(c), Table S-4, “Environmental Impact of Transportation of Fuel and Waste 

15 to and from One Light-Water-Cooled Nuclear Power Reactor.” 

16 Table 6.1-1. Issues related to the uranium fuel cycle and solid waste management. 

17 There are nine generic issues related to the fuel cycle and waste management. There are no 

18 site-specific issues. 

Issues GEIS Sections Category 

Offsite radiological impacts (individual effects from other 

than the disposal of spent fuel and & high-level waste) 

6.1; 6.2.1; 6.2.2.1; 6.2.2.3; 6.2.3; 6.2.4; 

6.6 

1 

Offsite radiological impacts (collective effects) 6.1; 6.2.2.1; 6.2.3; 6.2.4; 6.6 1 

Offsite radiological impacts (spent fuel and & high-level 

waste disposal) 

6.1; 6.2.2.1; 6.2.3; 6.2.4; 6.6 1 

Nonradiological impacts of the uranium fuel cycle 6.1; 6.2.2.6; 6.2.2.7; 6.2.2.8; 6.2.2.9; 

6.2.3; 6.2.4; 6.6 

1 

Low-level waste storage and & disposal 6.1; 6.2.2.2;6.4.2; 6.4.3; 6.4.3.1; 

6.4.3.2; 6.4.3.3; 6.4.4; 6.4.4.1; 6.4.4.2; 

6.4.4.3; 6.4.4.4; 6.4.4.5; 6.4.4.5.1; 

6.4.4.5.2; 6.4.4.5.3; 6.4.4.5.4; 

6.4.4.6;6.6 

1 

Mixed waste storage and & disposal 6.4.5.1; 6.4.5.2; 6.4.5.3; 6.4.5.4; 

6.4.5.5; 6.4.5.6; 6.4.5.6.1; 6.4.5.6.2; 

6.4.5.6.3; 6.4.5.6.4; 6.6 

1 

Onsite spent fuel 6.1; 6.4.6; 6.4.6.1; 6.4.6.2; 6.4.6.3; 

6.4.6.4; 6.4.6.5; 6.4.6.6; 6.4.6.7; 6.6 

1 

Nonradiological waste 6.1; 6.5; 6.5.1; 6.5.2; 6.5.3; 6.6 1 

Transportation 6.1; 6.3.1; 6.3.2.3; 6.3.3; 6.3.4; 6.6, 

Addendum 1 

1 

 

19 The U.S. Nuclear Regulatory Commission (NRC) staff’s evaluation of the environmental 

20 impacts associated with spent nuclear fuel is addressed in two issues in Table 6-1, 

21 “Offsite radiological impacts (spent fuel and high-level waste disposal)” and “Onsite 

22 spent fuel.” However, as explained later in this section, the scope of the evaluation of 
Environmental Impacts of the Uranium Fuel Cycle, Solid Waste Management, and Greenhouse 

Gas 

 6-2 

1 these two issues in this supplemental environmental impact statement (SEIS) has been 

2 revised. The issue, “Offsite radiological impacts (spent fuel and high-level waste 

3 disposal),” is not evaluated in this SEIS. In addition, the issue, “Onsite spent fuel,” only 

4 evaluates the environmental impacts during the license renewal term. 

5 For the term of license renewal, the staff did not find any new and significant information 

6 related to the remaining uranium fuel cycle and solid waste management issues listed in 

7 Table 6–1 during its review of the Seabrook Station Environmental Report (ER) 

8 (NextEra 2010), the site visit, and the scoping process. Therefore, there are no impacts 

9 related to these issues beyond those discussed in the GEIS. For these Category 1 

10 issues, the GEIS concludes that the impacts are SMALL, except for the issue, “Offsite 

11 radiological impacts (collective effects),“ which the NRC has not assigned an impact 

12 level. This issue assesses the 100-year radiation dose to the U.S. population (i.e., 

13 collective effects or collective dose) from radioactive effluents released as part of the 

14 uranium fuel cycle for a nuclear power plant during the license renewal term compared to 

15 the radiation dose from natural background exposure. It is a comparative assessment 

16 for which there is no regulatory standard to base an impact level.

17 For the offsite radiological impacts resulting from spent fuel and high-level waste 

18 disposal and the on-site storage of spent fuel, which will occur after the reactors have 

19 been permanently shutdown, the NRC’s Waste Confidence Decision and Rule 

20 represented the Commission’s generic determination that spent fuel can continue to be 

21 stored safely and without significant environmental impacts for a period of time after the 

22 end of the licensed life for operation. This generic determination meant that the NRC did 

23 not need to consider the storage of spent fuel after the end of a reactor’s licensed life for 

24 operation in NEPA documents that support its reactor and spent fuel storage application 

25 reviews. 

26 The NRC first adopted the Waste Confidence Decision and Rule in 1984. The NRC 

27 amended the decision and rule in 1990, reviewed them in 1999, and amended them again 

28 in 2010 (49 FR 34694; 55 FR 38474; 64 FR 68005; and 75 FR 81032 and 81037). The Waste 

29 Confidence Decision and Rule are codified in 10 CFR 51.23. 

30 On December 23, 2010, the Commission published in the Federal Register a revision of 

31 the Waste Confidence Decision and Rule to reflect information gained from experience in 

32 the storage of spent fuel and the increased uncertainty in the siting and construction of a 

33 permanent geologic repository for the disposal of spent nuclear fuel and high-level waste 

34 (75 FR 81032 and 81037). In response to the 2010 Waste Confidence Decision and Rule, 

35 the States of New York, New Jersey, Connecticut, and Vermont along with several other 

36 parties challenged the Commission’s NEPA analysis in the decision, which provided the 

37 regulatory basis for the rule. On June 8, 2012, the United States Court of Appeals, 

38 District of Columbia Circuit in New York v. NRC, 681 F.3d 471 (D.C. Cir. 2012) vacated the 

39 NRC’s Waste Confidence Decision and Rule, after finding that it did not comply with 

40 NEPA. 

41 In response to the court’s ruling, the Commission, in CLI-12-16 (NRC 2012a), in which the 

42 Commission determined that it would not issue licenses that rely upon the Waste 

43 Confidence Decision and Rule, until the issues identified in the court’s decision are 

44 appropriately addressed by the Commission. In CLI-12-16, the Commission also noted 

45 that the decision not to issue licenses only applied to final license issuance; all licensing 

46 reviews and proceedings should continue to move forward. 

47 In addition, the Commission directed in SRM-COMSECY-12-0016 (NRC 2012b) that the 

48 NRC staff proceed with a rulemaking that includes the development of a generic EIS to 
Environmental Impacts of the Uranium Fuel Cycle, Solid Waste Management, and Greenhouse 

Gas 

 6-3 

1 support a revised Waste Confidence Decision and Rule and to publish both the EIS and 

2 the revised decision and rule in the Federal Register within 24 months (by 

3 September 6, 2014). The Commission indicated that both the EIS and the revised Waste 

4 Confidence Decision and Rule should build on the information already documented in 

5 various NRC studies and reports, including the existing environmental assessment that 

6 the NRC developed as part of the 2010 Waste Confidence Decision and Rule. The 

7 Commission directed that any additional analyses should focus on the issues indentified 

8 in the court’s decision. The Commission also directed that the NRC staff provide ample 

9 opportunity for public comment on both the draft EIS and the proposed Waste 

10 Confidence Decision and Rule. 

11 The revised rule and supporting EIS are expected to provide the necessary NEPA 

12 analyses of waste confidence-related human health and environmental issues. As 

13 directed by the Commission, the NRC will not issue a renewed license before the 

14 resolution of waste confidence-related issues. This will ensure that there would be no 

15 irretrievable or irreversible resource commitments or potential harm to the environment 

16 before waste confidence impacts have been addressed. 

17 If the results of the Waste Confidence Decision and Rule and supporting EIS identify 

18 information that requires a supplement to this SEIS, the NRC staff will perform any 

19 appropriate additional NEPA review for those issues before the NRC makes a final 

20 licensing decision. 

21 6.2 Greenhouse Gas Emissions

22 No changes from the draft supplemental environmental impact statement (DSEIS) issued 

23 in August 2011. 

24 6.3 References

25 AEA Technology (AEA), 2006, “Carbon Footprint of the Nuclear Fuel Cycle, Briefing Note,” 

26 Prepared for British Energy, March 2006. 

27 Andseta et al., 1998, “CANDU Reactors and Greenhouse Gas Emissions,” Canadian Nuclear 

28 Association, 11th Pacific Basin Nuclear Conference, Banff, Alberta, Canada, May 1998. 

29 Dones, R., 2007, “Critical Note on the Estimation by Storm Van Leeuwen J.W., and Smith P. of 

30 the Energy Uses and Corresponding CO2 Emissions for the Complete Nuclear Energy Chain,” 

31 Paul Sherer Institute, April 2007. 

32 Fritsche, U.R., 2006, “Comparison of Greenhouse-Gas Emissions and Abatement Cost of 

33 Nuclear and Alternative Energy Options from a Life-Cycle Perspective,” Oko-Institut, Darmstadt 

34 Office, January 2006. 

35 Fthenakis, V.M. and H.C. Kim, 2007, “Greenhouse-Gas Emissions From Solar-Electric And 

36 Nuclear Power: A Life Cycle Study,” Energy Policy, Volume 35, Number 4, 2007. 

37 Hagen, R.E., J.R. Moens, and Z.D. Nikodem, 2001, “Impact of U.S. Nuclear Generation on 

38 Greenhouse Gas Emissions,” International Atomic Energy Agency, Vienna, Austria, November 

39 2001. 

40 International Atomic Energy Agency (IAEA), 2000, “Nuclear Power for Greenhouse Gas 

41 Mitigation under the Kyoto Protocol: The Clean Development Mechanism (CDM),” November 

42 2000. 
Environmental Impacts of the Uranium Fuel Cycle, Solid Waste Management, and Greenhouse 

Gas 

 6-4 

1 Keepin, B., 1988, “Greenhouse Warming: Efficient Solution of Nuclear Nemesis?,” Rocky 

2 Mountain Institute, Joint Hearing on Technologies for Remediating Global Warming, 

3 Subcommittee on Natural Resources, Agriculture Research and Environment and 

4 Subcommittee on Science, Research and Technology, U.S. House of Representatives, June 

5 1988. 

6 Massachusetts Institute of Technology (MIT), 2003, “The Future of Nuclear Power: An 

7 Interdisciplinary MIT Study,” 2003. 

8 Mortimer, N., 1990, “World Warms to Nuclear Power,” SCRAM Safe Energy Journal, December 

9 1989 and January 1990, Available URL: 

10 http://www.no2nuclearpower.org.uk/articles/mortimer_se74.php (accessed July 15, 2010). 

11 NextEra Energy Seabrook, LLC (NextEra), 2010, “License Renewal Application, Seabrook 

12 Station,” Appendix E, “Applicant’s Environmental Report, Operating License Renewal Stage,” 

13 May 25, 2010, Agencywide Documents Access and Management System (ADAMS) Accession 

14 Nos. ML101590092 and ML101590089. 

15 Nuclear Energy Agency (NEA), 2002, Nuclear Energy and the Kyoto Protocol, Organization for 

16 Economic Co-Operation and Development, 2002. 

17 Parliamentary Office of Science and Technology (POST), 2006, “Carbon Footprint of Electricity 

18 Generation,” Postnote, Number 268, October 2006. 

19 Schneider, M., 2000, Climate Change and Nuclear Power, World Wildlife Fund for Nature, April 

20 2000. 

21 Spadaro, J.V., L. Langlois, and B. Hamilton., 2000, “Greenhouse Gas Emissions of Electricity 

22 Generation Chains: Assessing the Difference,” IAEA Bulletin 42/2/2000, Vienna, Austria, 2000. 

23 Storm van Leeuwen, J.W. and P. Smith, 2005, Nuclear Power—The Energy Balance, August 

24 2005. 

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

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

27 CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 

28 Title 10, “Energy.” 

29 U.S. Nuclear Regulatory Commission (NRC), “Generic Environmental Impact Statement for 

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

31 ADAMS Accession Nos. ML040690705 and ML040690738. 

32 NRC, 1999, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 

33 Main Report,” NUREG-1437, Washington, D.C., Volume 1, Addendum 1, Section 6.3, Table 9.1, 

34 1999, ADAMS Accession No. ML040690720. 

35 Weisser, D., 2006, “A Guide to Life-Cycle Greenhouse Gas (GHG) Emissions from Electric 

36 Supply Technologies,” 2006, Available URL: 

37 http://www.iaea.org/OurWork/ST/NE/Pess/assets/GHG_manuscript_pre-print_versionDanielWei

38 sser.pdf (accessed November 24, 2010).

39 75 FR 81032. U.S. Nuclear Regulatory Commission. Consideration of environmental 

40 impacts of temporary storage of spent fuel after cessation of reactor operation. Federal 

41 Register 75(246):81032-81037. December 23, 2010. 

42 75 FR 81037. U.S. Nuclear Regulatory Commission. Waste confidence decision update. 

43 Federal Register 75(246):81037-81076. December 23, 2010. 
Environmental Impacts of the Uranium Fuel Cycle, Solid Waste Management, and Greenhouse 

Gas 

 6-5 

1 NRC, 2012a, “Commission, Memorandum and Order CLI-12-16.” August 7, 2012. ADAMS 

2 Accession No. ML12220A094. 

3 NRC, 2012b, “SRM-COMSECY-12-0016–Approach for Addressing Policy Issues Resulting 

4 from Court Decision To Vacate Waste Confidence Decision and Rule.” September 6, 

5 2012. ADAMS Accession No. ML12250A032.
 
 7-1 

7.0 ENVIRONMENTAL IMPACTS OF DECOMMISSIONING 

No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

August 2011. 
 
 8-1 

8.0 ENVIRONMENTAL IMPACTS OF ALTERNATIVES 

No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

August 2011. 
 
 9-1 

9.0 CONCLUSION 

No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

August 2011. 
 
 

 10-1 

1 10.0 LIST OF PREPARERS 

2 Members of the U.S. Nuclear Regulatory Commission’s (NRC’s) Office of Nuclear Reactor 

3 Regulation (NRR) prepared this supplemental environmental impact statement (SEIS) 

4 with assistance from other NRC organizations, as well as contract support from the 

5 Pacific Northwest National Laboratory (PNNL). Table 10-1 identifies each contributor’s 

6 name, affiliation, and function or expertise. 

7 Table 10-1. List of Preparers 

Name Affiliation Function or Expertise 

NRC 

Dave Wrona NRR Branch Chief

Melanie Wong NRR Branch Chief

Lois James NRR Project Manager

John Parillo NRR Severe accident mitigation 

alternatives (SAMA) 

Ray Gallucci NRR SAMA

Contractor 

Steve M Short PNNL SAMA

Bruce E Schmitt PNNL SAMA

Garill A Coles PNNL SAMA

8 
 
 

 11-1 

11.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM 

COPIES OF THE SUPPLEMENTAL ENVIRONMENTAL IMPACT 

STATEMENT ARE SENT 

Name & Title Company & Address 

Max Abramson 

Commenter 

David Agnew 

Commenter 

Cape Downwinders 

173 Morton Road 

South Chatham, MA 02659 

Ilse Andrews 

Commenter 

Seacoast Anti Pollution League (SAPL) 

Jeffrey Andrews New Hampshire Department of Environmental 

Services (NHDES) 

Wastewater Engineering Bureau 

29 Hazen Drive 

Concord, NH 03301 

Steven Athearn 

Commenter 

Robert Backus 

Commenter 

Paul Blanch 

Commenter 

Doug Bogen 

Commenter 

SAPL 

Marcia Bowen Normandeau Associates 

Mary Broderick 

Commenter 

K. Allen Brooks 

Chief, Environmental Protection Bureau 

New Hampshire Department of Justice (NHDOJ) 

Environmental Protection Bureau 

33 Capitol Street 

Concord, NH 03301 

Gilbert Brown 

Commenter 

Thomas Burack 

Commissioner 

NHDES 

29 Hazen Drive 

Concord, NH 03302 

Ed Carley 

License Renewal Environmental Engineer 

NextEra Energy Seabrook, LLC (NextEra) 

P.O. Box 300 

Seabrook, NH 03874 

Joe Casey 

Commenter 

New Hampshire Building & Construction Trades 

Council 

Chair Rockingham County Board of Commissioners 

119 North Road 

Brentwood, NH 03883 
List of Agencies, Organizations, and Persons 

 11-2 

Name & Title Company & Address 

Chairman Town of Seabrook Board of Selectmen 

99 Lafayette Road 

P.O. Box 456 

Seabrook, NH 03874 

Richard Cliche 

License Renewal Project Manager 

NextEra 

P.O. Box 300 

Seabrook, NH 03874 

Peter Colosi 

Assistant Regional Administrator for Habitat 

Conservation 

National Marine Fisheries Service 

Northeast Region 

55 Great Republic Drive 

Gloucester, MA 01930 

Melissa Coppola 

Environmental Information Specialist 

New Hampshire Natural Heritage Bureau 

Department of Resources and Economic 

Development 

172 Pembroke Road 

PO Box 1856 

Concord, NH 03301-1856 

Jim Cotter 

Commenter 

Patricia DeTuillo 

Director 

Amesbury Public Library 

149 Main Street 

Amesbury, MA 01913 

Josephine Donovan 

Commenter 

Timothy Drew 

Administrator 

NHDES 

29 Hazen Drive 

Concord, NH 03302 

EIS Filing Section U.S. Environmental Protection Agency (EPA) 

1200 Pennsylvania Avenue NW 

Washington, DC 20004 

EIS Review Coordinator EPA, Region 1 

5 Post Office Square, Suite 100 

Boston, MA 02109-3912 

Joseph Fahey 

Commenter 

Town of Amesbury, Office of Community & 

Economic Development 

Kevin Fleming 

Commenter 

Paul Freeman 

Site Vice President 

NextEra 

P.O. Box 300 

Seabrook, NH 03874 

Sandra Gavutis 

Executive Director 

C-10 Research and Education Foundation 

44 Merrimac Street 

Newburyport, MA 01950 

Filson Glanz 

Commenter 

Shirley Glanz 

Commenter 
 List of Agencies, Organizations, and Persons 

 11-3 

Name & Title Company & Address 

Debbie Grinnell 

Commenter 

C-10 Research & Education Foundation 

Doug Grout 

Chief of Marine Fisheries 

New Hampshire Fish and Game Department 

225 Main Street 

Durham, NH 03824-4732 

Janet Guen 

Commenter 

United Way of the Greater Seacoast 

Paul Gunter 

Commenter 

Beyond Nuclear 

William Harris 

Commenter 

Emily Holt 

Endangered Species Review Assistant 

Massachusetts Division of Fisheries and Wildlife 

Natural Heritage and Endangered Species Program

1 Rabbit Hill Road 

Westborough, MA 01581 

Joyce Kemp 

Commenter 

Susan Kepner 

Commenter 

Randall Kezar 

Commenter 

Phyllis Killam-Abell 

Commenter 

Richard Knight 

Commenter 

Sandra Koski 

Commenter 

Patricia Kurkul 

Regional Administrator 

National Oceanic and Atmospheric Administration 

(NOAA) Fisheries Service 

Northeast Regional Office 

55 Great Republic Drive 

Gloucester, MA 01930 

Mary Lampert 

Commenter 

Robert McDowell 

Commenter 

Scott Medford 

Commenter 

Marvin Moriarty 

Regional Officer 

U.S. Fish and Wildlife Service 

Northeast Regional Office 

300 Westgate Center Drive 

Hadley, MA 01035 

Herbert Moyer 

Commenter 

SAPL 
List of Agencies, Organizations, and Persons 

 11-4 

Name & Title Company & Address 

Elizabeth Muzzey 

State Historic Preservation Officer (SHPO) 

New Hampshire Division of Historical Resources 

19 Pillsbury Street 

2nd Floor 

Concord, NH 03301 

Reid Nelson 

Director 

Advisory Council on Historic Preservation 

Office of Federal Agency Programs 

1100 Pennsylvania Avenue NW, Suite 803 

Washington, DC 20004 

Tim Noonis 

Commenter 

Hampton Area Chamber of Commerce 

Chris Nord 

Commenter 

C-10 Research & Education Foundation 

NRC Regional Administrator U. S. Nuclear Regulatory Commission (NRC) 

Region I 

475 Allendale Road 

King of Prussia, PA 19406 

NRC Senior Resident NRC 

P.O. Box 300 

Seabrook, NH 03874 

Dennis O’Dowd 

Administrator 

New Hampshire Department of Health & Human 

Services 

Division of Public Services 

Radiological Health Section 

29 Hazen Drive 

Concord, NH 03301-6504 

Michael O’Keefe 

Licensing Manager 

NextEra 

P.O. Box 300 

Seabrook, NH 03874 

John Parker SAPL 

Thomas Popik 

Commenter 

Foundation for Resilient Societies 

52 Technology Way 

Nashua, NH 03060 

Andrew Port 

Commenter 

City of Newburyport, Office of Planning & 

Development 

Russell Prescott 

Senator, District 23 

State of New Hampshire Senate 

Robin Read 

Representative, District 16 

State of New Hampshire House of Representatives 

Lee Roberts 

Commenter 

Ann Robinson 

Director 

Seabrook Library 

25 Liberty Lane 

Seabrook, NH 03874 

Peter C.L. Roth 

Senior Assistant Attorney General 

NHDOJ 

Environmental Protection Bureau 

33 Capitol Street 

Concord, NH 03301 
 List of Agencies, Organizations, and Persons 

 11-5 

Name & Title Company & Address 

Thomas Saporito 

Commenter 

Saprodani Associates 

177 U.S. Highway 1 North 

Unit 212 

Tequesta, FL 33469 

Michael Schidlovsky 

Commenter 

Exeter Area Chamber of Commerce 

Peter Schmidt 

Representative, District 4 

State of New Hampshire House of Representatives 

Raymond Shadis 

Commenter 

New England Coalition 

Friends of the Coast 

PO Box 98 

Edgecomb, ME 04556 

Brona Simon 

SHPO 

Massachusetts Historical Commission 

220 Morrissey Boulevard 

Boston, MA 02125 

Peter Somssich 

Commenter 

Donald Tilbury 

Commenter 

Dennis Wagner 

Commenter 

David Webster 

NPDES Permit Branch Chief 

EPA, Region 1 

Water Quality Management Unit 

5 Post Office Square, Suite 100 

Boston, MA 02109-3912 

Christian Williams 

Federal Consistency Coordinator 

NHDES 

New Hampshire Coastal Program 

222 International Drive, Suite 175 

Pease Tradeport 

Portsmouth, NH 03801 

Robin Willits 

Commenter 

Cathy Wolff 

Commenter 
 
APPENDIX A. 

COMMENTS RECEIVED ON THE 

SEABROOK STATION 

ENVIRONMENTAL REVIEW 

Appendix A 

 A-1 

1 A. COMMENTS RECEIVED ON THE SEABROOK STATION 

2 ENVIRONMENTAL REVIEW 

3 

4 No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

5 August 2011. 
 
APPENDIX B. 

NATIONAL ENVIRONMENTAL POLICY ACT ISSUES FOR LICENSE 

RENEWAL OF NUCLEAR POWER PLANTS 

 B-1 

1 B. NATIONAL ENVIRONMENTAL POLICY ACT ISSUES FOR 

2 LICENSE RENEWAL OF NUCLEAR POWER PLANTS 

3 

4 No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

5 August 2011.
 
APPENDIX C. 

APPLICABLE REGULATIONS, LAWS, AND AGREEMENTS

 C-1 

1 C. APPLICABLE REGULATIONS, LAWS, AND AGREEMENTS 

2 No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

3 August 2011. 
 
APPENDIX D. 

CONSULTATION CORRESPONDENCE

D-1 

1 D. CONSULTATION CORRESPONDENCE 

2 No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

3 August 2011. 
 
APPENDIX E. 

CHRONOLOGY OF ENVIRONMENTAL REVIEW

 E-1 

1 E. CHRONOLOGY OF ENVIRONMENTAL REVIEW 

2 CORRESPONDENCE 

3 No changes from the draft supplemental environmental impact statement (DSEIS) issued in 

4 August 2011. 
 
 

 

APPENDIX F 

U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR SEABROOK 

STATION UNIT 1 IN SUPPORT OF LICENSE RENEWAL APPLICATION 

REVIEW 

 
 

 
 Appendix F 

 F-1 

1 F U.S. NUCLEAR REGULATORY COMMISSION STAFF 

2 EVALUATION OF SEVERE ACCIDENT MITIGATION 

3 ALTERNATIVES FOR SEABROOK STATION UNIT 1 IN SUPPORT 

4 OF LICENSE RENEWAL APPLICATION REVIEW 

5 F.1 Introduction 

6 NextEra Energy Seabrook, LLC (NextEra), submitted an assessment of severe accident 

7 mitigation alternatives (SAMAs) for the Seabrook Station (Seabrook), Unit 1, as part of its 

8 Environmental Report (ER) (NextEra 2010). This assessment was based on the most recent 

9 Seabrook probabilistic risk assessment (PRA) available at that time, a plant-specific offsite 

10 consequence analysis performed using the Methods for Estimation of Leakages and 

11 Consequences of Releases (MELCOR) Accident Consequence Code System 2 (MACCS2) 

12 computer code (NRC 1998a), and insights from the Seabrook individual plant examination (IPE) 

13 (New Hampshire Yankee (NHY) 1991) and individual plant examination of external events 

14 (IPEEE) (North Atlantic Energy Service Corp. (NAESC) 1992). In identifying and evaluating 

15 potential SAMAs, NextEra considered SAMA candidates that addressed the major contributors 

16 to core damage frequency (CDF) and large early release frequency (LERF) at Seabrook, as well 

17 as a generic list of SAMA candidates for pressurized-water reactor (PWR) plants identified from 

18 other industry studies. In the initial ER, NextEra identified 191 potential SAMA candidates. 

19 This list was reduced to 74 SAMA candidates by eliminating SAMAs for the following reasons: 

20  Seabrook has a different design. 

21  The SAMA has already been implemented at Seabrook. 

22  The intent of the SAMA has already been met at Seabrook. 

23  The SAMA has been combined with another SAMA candidate that is similar in nature. 

24  Estimated implementation costs would exceed the dollar value associated with 

25 eliminating all severe accident risk at Seabrook. 

26  The SAMA would be of very low benefit as it is related to a non-risk significant system. 

27 NextEra assessed the costs and benefits associated with each of these 74 potential SAMAs and 

28 concluded in the ER that several of the candidate SAMAs evaluated are potentially cost 

29 beneficial. 

30 Based on a review of the SAMA assessment, the U.S. Nuclear Regulatory Commission (NRC) 

31 issued requests for additional information (RAIs) to NextEra by letters dated November 16, 2010 

32 (NRC 2010a), and March 4, 2011 (NRC 2011b). Key questions in these RAIs concerned the 

33 following: 

34  additional details regarding the plant-specific PRA model and changes to internal and 

35 external event CDF and LERF since the IPE, 

36 
Appendix F 

 F-2 

1  the process used to map Level 1 PRA results into the Level 2 analysis and group 

containment event tree (CET) end states into release categories,1 2 

3  the process for selecting the representative Modular Accident Analysis Program (MAAP) 

4 case for each release category and the release characteristics of each representative 

5 case, 

6  changes to the fire and seismic PRA models since the IPEEE, 

7  the impact of updated seismic hazard curves, 

8  the sensitivity of the SAMA results to assumptions used in the Level 3 analysis, 

9  the use of Level 2 importance analysis and industry SAMA analyses in identifying 

10 plant-specific SAMAs, and 

11  further information on the cost-benefit analysis of several specific candidate SAMAs and 

12 low-cost alternatives. 

13 NextEra submitted additional information to the NRC by letters dated January 13, 2011 

14 (NextEra 2011a), and April 18, 2011 (NextEra 2011b). NextEra provided additional information 

15 in a telephone conference call with the NRC staff on February 15, 2011 (NRC 2011a). In 

16 response to the RAIs, NextEra provided the following: 

17  the internal and external event contribution to CDF and LERF for each version of the 

18 Seabrook PRA model and model changes that most impacted CDF and LERF, 

19  a description of the CET and the process for determining the frequency of each release 

20 category, 

21  a description of the process for selecting representative MAAP cases for each release 

22 category and the characteristics of each plume in each release category, 

23  changes to the fire and seismic PRA models since the IPEEE, 

24  a sensitivity analysis of the impact on the SAMA analysis from updated seismic hazard 

25 curves, 

26  the results of the sensitivity analyses performed on the assumptions used in the Level 3 

27 analysis, 

28  listings of the important basic events for the most risk-significant release categories, 

29  evaluation of additional SAMA candidates based on basic events important to CDF 

30 and release frequency, 

31  a review of the applicability of industry cost-effective SAMA candidates to Seabrook, and 

32  additional information regarding several specific SAMAs. 

 

1

 The NRC uses PRA to estimate risk by computing real numbers to determine what can go wrong, how likely is it, and what are its

consequences. Thus, PRA provides insights into the strengths and weaknesses of the design and operation of a nuclear power 

plant. For the type of nuclear plant currently operating in the U.S., a PRA can estimate three levels of risk. A Level 1 PRA 

estimates the frequency of accidents that cause damage to the nuclear reactor core. This is commonly called CDF. A Level 2 PRA, 

which starts with the Level 1 core damage accidents, estimates the frequency of accidents that release radioactivity from the nuclear 

power plant. A Level 3 PRA, which starts with the Level 2 radioactivity release accidents, estimates the consequences in terms of 

injury to the public and damage to the environment. 

(http://www.nrc.gov/about-nrc/regulatory/risk-informed/pra.html) 
 Appendix F 

 F-3 

1 NextEra’s responses addressed the NRC staff’s concerns and resulted in the identification of 

2 additional potentially cost-beneficial SAMAs. 

3 Subsequent to the RAI responses, NextEra submitted a supplement to the ER that 

4 incorporates updates made to the PRA model (NextEra 2012a). NextEra identified 

5 additional SAMA candidates, assessed the costs and benefits of these SAMAs, and 

6 reassessed the costs and benefits of the previously-identified SAMA candidates, which 

7 resulted in additional potentially cost-beneficial SAMAs. 

8 The NRC staff reviewed this supplement and issued RAIs to NextEra by letter dated 

9 July 16, 2012 (NRC 2012a). Key questions in these RAIs concerned the following: 

10  additional initiating event contributors to total CDF, 

11  additional basic events presented in the CDF and release category importance 

12 lists, 

13  justification for the implementation cost estimates for certain SAMAs, and 

14  clarification of apparent inconsistencies in the risk reduction and cost-benefit 

15 evaluation of certain SAMAs. 

16 NextEra submitted additional information to the NRC by letter dated September 13, 2012 

17 (NextEra 2012b). NextEra also provided additional information in a telephone conference 

18 call with the NRC staff on October 3, 2012 (NRC 2012b). In response to the RAIs, NextEra 

19 provided the following: 

20  initiating events that contribute one percent and greater to CDF, 

21  additional risk-significant release category basic events and evaluation of SAMA 

22 candidates for each, 

23  justification for the increase in the implementation costs for selected SAMAs 

24 since the ER and original RAI responses were submitted to the NRC, and 

25  additional information regarding the cost-benefit evaluation of certain SAMAs. 

26 NextEra’s responses addressed the NRC staff’s concerns. 

27 The NRC staff notes that many of the original RAIs asked regarding the SAMA analysis in 

28 the ER, and associated RAI responses, were superseded by the updated information 

29 provided in the 2012 SAMA supplement (NextEra 2012a). For this reason, many of the 

30 RAI responses on the original ER submittal are not specifically discussed in this review 

31 since they were determined to not be needed to support the conclusions presented in 

32 Section F.7. 

33 An assessment of SAMAs for Seabrook is presented below. 

34 F.2 Estimate of Risk for Seabrook 

35 NextEra’s estimates of offsite risk at Seabrook are summarized in Section F.2.1. The summary 

36 is followed by the NRC staff’s review of NextEra’s risk estimates in Section F.2.2. 
Appendix F 

 F-4 

1 F.2.1 NextEra’s Risk Estimates 

2 Two distinct analyses are combined to form the basis for the risk estimates used in the SAMA 

3 analysis—(1) the Seabrook Level 1 and 2 PRA model, which is an updated version of the IPE 

4 (NHY 1991), and (2) a supplemental analysis of offsite consequences and economic impacts 

5 (essentially a Level 3 PRA model) developed specifically for the SAMA analysis. The SAMA 

6 analysis is based on the most recent Seabrook Level 1 and Level 2 PRA models available, 

7 model SSPSS-2006 for the ER (NextEra 2010) updated by model SSPSS-2011 in the 2012

8 SAMA supplement (NextEra 2012a). The scope of this Seabrook PRA includes both internal 

9 and external events. 

The Seabrook CDF is approximately 1.210-51.510-5 10 per year for both internal and external 

11 events, as determined from quantification of the Level 1 PRA model. A truncation level of 

110-14 per year was used when quantifying event trees, and a truncation value of 110-12 12 per 

13 year was used when quantifying fault trees, except for the service water system (SWS) 

14 (NextEra 2011a). The SWS was divided into two trains, which were each solved at a truncation 

level of 110-8 15 per year. The CDF is based on the risk assessment for internally initiated events, 

16 which include internal flooding, and external events, which include fire and seismic events. The 

internal events CDF is approximately 7.8 10-61.110-5 17 per year (internal events modeling 

18 includes external flooding), and the external events CDF (fire and seismic events) is 

approximately 4.510-6 19 per year (NextEra 2012a). 

20 The breakdown of CDF by initiating event is provided in Table F-1 and includes internal, fire, 

21 and seismic initiating events. As shown in Table F-1, the largest single contributor to the total 

22 CDF is loss of offsite power (LOOP) due to weather. NextEra clarified in response to an NRC 

23 staff RAI (NextEra 2012a) that station blackout (SBO) contributes approximately 

3.310-65.310-6 24 per year, or 2735 percent, and anticipated transients without scram (ATWS) 

contribute approximately 4.710-74.610-7 25 per year, or 43 percent, to the total internal and 

26 external events CDF. 

27 The Level 2 Seabrook PRA model that forms the basis for the SAMA evaluation is an updated 

28 version of the Level 2 IPE model (NHY 1991) and IPEEE model (NAESC 1992). The current 

29 Level 2 model uses a single CET that is used to address internal, fire, and seismic events. The 

30 CET addresses both phenomenological and systemic events. The Level 1 core damage 

31 sequences are linked directly with the CET, so all Level 1 sequences are evaluated by the CET 

32 (NRC 2011a). The CET probabilistically evaluates the progression of the damaged core with 

33 respect to release to the environment. CET nodes are evaluated using supporting fault trees 

34 and logic rules. The CET end states are then examined for considerations of timing and 

35 magnitude of release and assigned to release categories. 
 Appendix F 

 F-5 

1 Table F-1. Seabrook CDF for internal and external events 

Internal initiating event CDF 

(per year) 

% contribution to 

total CDF (a)

LOOP due to weather(e) 6.810-71.510-6 6 10

Flood in relay room from high- energy line break (HELB)(e) Loss 

of essential alternating current (AC) power 4 kilovolt (kV) bus

5.910-79.510-7 5 6

Steam generator tube rupture (SGTR) 5.710-7 5 

Reactor trip—condenser available 5.410-79.310-7 4 6

Medium loss-of-coolant accident (LOCA) 5.310-7 4 

LOOP due to grid-related events 9.010-7 4 6

Flood in yard due to service water (SW) common return 

rupture(e) LOOP due to hardware or maintenance

4.110-78.110-7 3 5

Loss of essential alternating current (AC) power 4 kilovolt (kV ) 

bus Flood in turbine building

3.210-77.310-7 3 5

Steam generator tube rupture (SGTR) 5.910-7 4

Loss of primary component cooling water system (CS)PCCW) B

train 

3.010-75.310-7 3 4

Loss of PCCW system A train Loss of essential direct current (DC) 

power 125V DC bus

2.310-73.910-7 2 3

Major flood, rupture of SW Train A in PAB(e) Reactor trip—during 

shutdown

2.210-73.510-7 2 

LOOP due to switchyard Interfacing systems loss-of-coolant 

accident (ISLOCA)

2.110-73.410-7 2 

Large flood, rupture SW Train A piping in primary auxiliary 

building (PAB)(e) Large loss-of-coolant accident (LOCA)

2.010-73.410-7 2 

Large flood, rupture SW Train B piping in PAB(e) Medium LOCA 2.010-73.310-7 2 

Major flood, rupture of SW Train B in PAB(e) Excessive LOCA 2.010-72.510-7 2 

Major flood, rupture of fire protection piping in turbine building 

impacting offsite power(e) Inadvertent safety injection (SI)

1.810-72.510-7 2 

Loss of Train B Essential AC Power (4 kV Bus E6) Small LOCA 1.610-71.910-7 1 

Large flood, rupture of SW common return piping in PAB(e)

Reactor trip with no condenser cooling

1.410-71.710-7 1 

Large LOCA 3.410-7 2 

Other internal events(b) 1.610-61.010-6 13 7

Total internal events CDF(ec) 7.810-61.110-5 64 70

Fire initiating event 

Fire in control room—power- operated relief valve (PORV) LOCA

Fire switchgear (SWGR) room B—loss of bus E6

3.610-73.710-7 3 2

Fire in switchgear (SWGR) room B—loss of Bus E6Fire SWGR 

room A—loss of bus E5

3.510-73.710-7 3 2
Appendix F 

 F-6 

Fire SWGR room A—loss of Bus E5Fire control room—AC power 

loss

3.110-72.110-7 2 1

Fire control room—AC power-operated relief valve (PORV) LOCA

loss

1.810-71.410-7 1 

Other fire events(cd) 3.810-72.310-7 2 

Total fire events CDF(e) 1.410-61.310-6 11 9

Seismic initiating event 

Seismic 0.7 g transient event 9.310-79.210-7 8 6

Seismic 1.0 g transient event 8.910-78.710-7 7 6

Seismic 1.4 g transient event 3.610-7 3 2

Seismic 1.0 g ATWS 1.110-7 1

Seismic 1.4 g large LOCA 1.110-7 1

Seismic 0.7 g ATWS 1.010-7 1

Seismic 1.0 g large LOCA 8.910-8 1

Other seismic events(df) 8.810-74.910-7 7 3

Total seismic events CDF(e) 3.110-6 25 21

Total CDF (internal and external events)(g) 1.2×10–51.5×10–5 100 

(a) MayIndividual percent contributions may not totalsum exactly to 100 percentsubtotals due to round off.

(b) Obtained by subtracting the sum of the internal initiating event contributors to internal event CDF from the total internal events 

CDF.

(c) Obtained from percentage contribution of internal events provided in response to RAI 1.b.1 (NextEra, 2011a) times the total 

internal and external events CDF

(d (c)

 Obtained by subtracting the sum of the fire initiating event contributors to fire event CDF from the total fire events CDF. 

(e) Provided in response to conference call clarification #2 (NRC, 2011a)

(f (d)

 Obtained by subtracting the sum of the seismic initiating event contributors to seismic event CDF from the total seismic events 

CDF.

(g) Provided in response to RAI 1.b.1 (NextEra, 2011a) (e) NextEra explained in response to an RAI the difference in the 

frequencies reported for many initiating events for the 2006 and 2011 PRA models. The total internal events CDF in the 

2011 model decreased slightly as a result of model enhancements, the internal flooding CDF increased as results of a 

more detailed flooding analysis, and the severe weather CDF decreased primarily due to the incorporation of more recent 

data (NextEra , 2012b).

1 Per the 2012 SAMA supplement (NextEra 2012a), the quantified CET sequences are binned 

2 into a set of 21 14 release categories, which are subsequently grouped into 13 10 source term 

3 categories that provide the input to the Level 3 consequence analysis (NextEra 2012a). The 

4 frequency of each source term category was obtained by summing the frequency of the 

5 individual accident progression CET endpoints, or release categories, assigned to each source 

6 term category. Source terms were developed using the results of MAAP Version 4.0.7

7 computer code calculations (NextEra 2012a). 

8 The offsite consequences and economic impact analyses use the MACCS2 code to determine 

9 the offsite risk impacts on the surrounding environment and public. Inputs for these analyses 

10 include plant-specific and site-specific input values for core radionuclide inventory, source term 

11 and release characteristics, site meteorological data, projected population distribution within an 

12 80-km (50-mi) radius for the year 2050, emergency response evacuation planning, and 
 Appendix F 

 F-7 

1 economic parameters. The core radionuclide inventory corresponds to the end-of-cycle values 

2 for Seabrook operating at 3,659 MWt, which is slightly above the current licensed power level of 

3 3,648 MWt. The magnitude of the onsite impacts (in terms of cleanup and decontamination 

4 costs and occupational dose) is based on information provided in NUREG/BR-0184 

5 (NRC 1997a). 

6 In the 2012 SAMA supplement (NextEra 2012a), NextEra estimated the dose to the 

7 population within 80 km (50 mi) of the Seabrook site to be approximately 0.378 person-Sievert 

8 (Sv) (37.8 person-rem) per year. The breakdown of the total population dose by containment 

9 release mode is summarized in Table F-2, below, and in Table F-2 of the SAMA supplement

10 (NextEra 2012a). The large late releases are the dominant contributors to population dose risk 

11 at Seabrook. 

12 Table F-2. Breakdown of population dose by containment release mode 

Containment release mode Population dose (person-rem(a) per year) % contribution 

Small early releases 1.7 5.3 5 49

Large early releases 1.71.6 4 15

Large late releases (b) 34.4 3.8 91 36

Intact containment negligible negligible 

Total 37.8 10.7 100 

(a)

 One person-rem = 0.01 person-Sv

(b) Includes small early containment penetration failure to isolate and large late containment basemat failure 

(SELL). 

13 F.2.2 Review of NextEra’s Risk Estimates 

14 NextEra’s determination of offsite risk at Seabrook is based on the following major elements of 

15 analysis: 

16  the Level 1 and 2 risk models that form the bases for the 1991 IPE submittal (NHY 1991) 

17 and the external event analyses of the 1992 IPEEE submittal (NAESC 1992), 

18  the major modifications to the IPE and IPEEE models that have been incorporated in the 

19 Seabrook PRA, including a complete revision of the Level 2 risk model, and 

20  the MACCS2 analyses performed to translate fission product source terms and release 

21 frequencies from the Level 2 PRA model into offsite consequence measures (essentially 

22 this equates to a Level 3 PRA). 

23 Each of these analyses was reviewed to determine the acceptability of the Seabrook risk 

24 estimates for the SAMA analysis, as summarized below. 

25 The first Seabrook PRA was completed in December 1983, its purpose being to provide a 

26 baseline risk assessment and an integrated plant and site model for use as a risk management 

27 tool. This model was subsequently updated in 1986, 1989, and 1990, with the last update used 

28 to support the IPE. 

29 The NRC staff’s review of the Seabrook IPE is described in an NRC report dated March 1, 1992 

30 (NRC 1992). Based on a review of the original IPE submittal and responses to RAIs, the NRC 
Appendix F 

 F-8 

1 staff concluded that the IPE submittal met the intent of generic letter (GL) 88-20 (NRC 1988). 

2 That is, the applicant demonstrated an overall appreciation of severe accidents, had an 

3 understanding of the most likely severe accident sequences that could occur at Seabrook, and 

4 had gained a quantitative understanding of core damage and fission product release. Although 

5 no severe accident vulnerabilities were identified in the Seabrook IPE, 14 potential plant 

6 improvements were identified. Four of the improvements have been implemented. Each of the 

7 10 improvements not implemented is addressed by a SAMA in the current evaluation and is 

8 discussed further in Section F.3.2. 

The internal events CDF value from the 1991 Seabrook IPE (6.110-5 9 per year) is near the 

10 average of the range of the CDF values reported in the IPEs for Westinghouse four-loop plants. 

11 Figure 11.6 of NUREG-1560 shows that the IPE-based internal events CDF for these plants 

range from about 310-6 per year to 210-4 12 per year, with an average CDF for the group of 

610-5 13 per year (NRC 1997b). It is recognized that plants have updated the values for CDF 

14 subsequent to the IPE submittals to reflect modeling and hardware changes. Based on CDF 

15 values reported in the SAMA analyses for license renewal applications (LRAs), the internal 

events CDF result for Seabrook used for the SAMA analysis (7.810-6 1.110-5 16 per year, 

17 including internal and external flooding) is somewhat lower than that for most other plants of 

18 similar vintage and characteristics. 

19 There have been 1110 revisions to the IPE model since the 1991 IPE submittal, and 4

20 3 revisions to the PRA model, as discussed previously, from the original 1983 PRA model to the 

21 1990 update used to support the IPE submittal. The SSPSS-2006 model was used for the 

22 SAMA analysis presented in the ER (NextEra 2010) but was updated by the SSPSS-2011 

23 model used in the 2012 SAMA supplement (NextEra 2012a). A listing of the major changes 

24 in each revision of the PRA, and the associated change in internal and external event CDF, was 

25 provided in the ER (NextEra 2010) in response to an NRC staff RAI (NextEra 2011a), in the 

26 2012 SAMA supplement (NextEra 2012a), and is summarized in Table F-3. A comparison of 

27 the internal events CDF between the 1991 IPE and the 2011 PRA model used for the 2012 

SAMA supplement indicates a decrease of approximately 87 82 percent (from 6.110-5 28 per 

year to 7.810-61.110-5 29 per year). This decrease results from the significant changes shown, 

30 while the external events CDF has increased by approximately 25 percent since the 1993 

IPEEE (from 3.610-5 per year to 4.510-5 31 per year). 

32 Table F-3. Seabrook PRA historical summary 

PRA 

version Summary of significant changes from prior model(a) Total CDF (per year) 

Internal 

events CDF 

(per year)(b)

External 

events 

CDF 

(per 

year)(b)

SSPSAPLG-0300 

(1983) 

Original model—includes internal, fire, and seismic events 2.310-4 1.8x10-4 4.6x10-5

SSPSS1986 

 Updated allowed outage times to reflect current 

technical specifications 

 Revised models of the inservice test pump test 

frequency; turbine driven emergency feedwater (EFW) 

pump atmospheric relief valves; boron injection tank, 

pump, and lines; enclosure building air handling system; 

reactor trip breakers; & reactor coolant pump (RCP) 

thermal barrier core spray (CS) 

2.910-4 Not provided Not 

provided 
 Appendix F 

 F-9 

PRA 

version Summary of significant changes from prior model(a) Total CDF (per year) 

Internal 

events CDF 

(per year)(b)

External 

events 

CDF 

(per 

year)(b)

 Improved quantification traceability & documentation 

 Updated seismic fragilities 

 Expanded common cause treatment 

SSPSS1989 

 Updated initiating event frequencies 

 Updated common cause & maintenance distributions 

 Revised electric power recovery model using current 

data 

 Added recovery actions into event model 

1.410-4 9.5x10-5

 4.5x10-5

SSPSS1990 IPE submittal 

 Added modeling of ATWS mitigation system 

 Updated electric power recovery model 

 Updated RCP seal LOCA analysis 

 Added new recovery actions 

 Revised CET to explicitly model induced SGTR & direct 

containment heating 

1.110-4 6.110-5 5.010-5

SSPSS1993 IPEEE submittal 

 Added plant-specific data for main safety pumps & 

diesel generators (DGs) 

 Improved fire event modeling, including modeling 

operator actions & addition of new fire hazard initiating 

events 

 Revised startup feed pump (SUFP) model to 

conservatively require manual startup 

 Improved modeling of high-pressure injection (HPI) and 

event tree logic 

8.010-5 4.410-5 3.610-5

SSPSS1996 

 Improved common cause modeling of primary 

component cooling (PCC) with opposite PCC train 

failure 

 Updated ATWS model to account for change from an 

18-month to 24-month fuel cycle 

 Increased use of plant-specific data 

 Changed definition of LERF to include steam leak from 

SGTR 

 Increased failure likelihood for small containment 

penetrations in seismic sequences 

 Added credit for manual operator action to close RCP 

seal return line motor-operated valve (MOV) 

4.310-5 2.110-5 2.210-5

SSPSS1999 

 Updated LOCA initiator frequencies 

 Updated ATWS model to account for change from a 24-

4.610-5 2.710-5 1.910-5
Appendix F 

 F-10 

PRA 

version Summary of significant changes from prior model(a) Total CDF (per year) 

Internal 

events CDF 

(per year)(b)

External 

events 

CDF 

(per 

year)(b)

month to an 18-month fuel cycle & to use more current 

failure rates 

 Updated event tree to explicitly incorporate RCP seal 

LOCA model & related power recovery models 

 Changed emergency diesel generator (EDG) mission 

time from 6 hours to 24 hours for weather-related LOOP 

& similar initiators 

 Moved LOOP & internal flooding models from external 

to internal events model 

 Modified common cause factors & mission times for 

PCC system & SWS 

 Updated human error probability (HEP) event tree rules 

& quantification 

SSPSS2000 

 Transitioned PRA software from DOS-based 

RISKMAN 9.2 to Windows-based RISKMAN 3.0 

4.610-5 2.710-5 1.910-5

SSPSS2001 

 Changed system initiator models 4.810-5 2.810-5 2.010-5

SSPSS2002 

 Integrated shutdown & low power risk models into allmodes model 

4.810-5 2.510-5 2.010-5

SSPSS2004 

 Updated the human reliability analysis (HRA) 

 Added credit for the supplemental electric power system 

(SEPS) DG 

 Updated the LERF model to include consequential 

SGTR 

3.010-5 1.710-5 1.310-5

SSPSS2005 

 Revised success criteria & operator timing 

 Updated the seismic PRA 

 Updated DG failure rate & unavailability data 

 Updated the Level 2 analysis including modeling of 

severe accident management guideline (SAMG) actions 

1.410-5 9.510-6 4.510-6

SSPSS2006(c)  Updated the Mode 4, 5, & 6 shutdown model 

 Revised modeling of PCC & SWS initiators 

1.510-5 1.110-5 4.510-6

SSPSS2009 

 Updated plant-specific data & generic data distributions 

 Incorporated electric power convolution model 

 Expanded the steam generator (SG) model to include 

condenser cooling, circulating water, & condenser 

steam dump 

 Revised operator action modeling 

1.210-5 7.110-6 4.910-6

SSPSS2011(c)  Updated the internal flood model to incorporate 

plant changes, EPRI data and guidance, and to meet 

current PRA standards for internal flooding(d) 

1.210-5 7.810-6 4.510-6
 Appendix F 

 F-11 

PRA 

version Summary of significant changes from prior model(a) Total CDF (per year) 

Internal 

events CDF 

(per year)(b)

External 

events 

CDF 

(per 

year)(b)

 Revised release category and source term based on 

more detailed modeling using MAAP 4.0.7 

 Added new breakers and buses to reflect a 

switchyard upgrade 

(a) Summarized from information provided in the ER and in response to an NRC staff RAI (NextEra 2011a). 

(b) Estimated from percent contribution to total CDF provided in response to an NRC staff RAI (NextEra 2011a). 

(c) PRA model revision used in the 2012 SAMA supplement (NextEra 2012a). 

(d) NextEra confirmed in response to an RAI that flow orifices installed in the plant and credited in the internal flooding model 

passed startup acceptance testing (NextEra 2012b).

1 The NRC staff considered the peer reviews performed for the Seabrook PRA and the potential 

2 impact of the review findings on the SAMA evaluation. In the ER (NextEra 2010), NextEra 

3 identifies two peer reviews that have been performed on the PRA—a 1999 Westinghouse 

4 Owner’s Group (WOG) certification peer review and a 2005 focused peer review against the 

5 American Society of Mechanical Engineers (ASME) PRA standard (ASME 2003). The 2012 

6 SAMA supplement (NextEra 2012a) identifies an additional peer review—a 2009 peer 

7 review of the internal flood model against the ASME PRA standard (ASME 2009). There 

8 were no Category A facts and observations (F&Os) from that 2009 focused peer review, 

9 and the three Category B F&Os were addressed in the SSPSS-2011 PRA model update. 

10 In response to an NRC staff RAI, NextEra clarified the scope of these 1999 and 2005 peer 

11 reviews. The 1999 review provided a full review of the technical elements of the Level 1 and 2 

12 LERF internal events models, including internal flooding and the 2005 peer review providing a 

13 focused scope examination of Level 1 internal events accident sequences, success criteria, 

14 post-initiating event HRA, and configuration control (NextEra 2011a). Neither the 1999 nor the 

15 2005 peer review included examination of external flooding, fire, or seismic hazards. The 

16 1999 certification peer review identified 30 Category A and B F&Os, and the 2005 focused peer 

review identified 4 Category A and B F&Os.2 17 The applicant provides the resolution of each of 

18 the 34 F&Os in the ER and states that all have been dispositioned and implemented in the PRA 

19 model. 

20 The NRC staff requested that NextEra clarify how the resolution to F&O 3 (aggressive load 

21 shedding and the available cross tie can extend battery life from 8 to 12 hours) addresses the 

22 F&O. The NRC asked NextEra to assess the ability of the operators to successfully cool the 

23 core using the EFW pump without underfeeding the SGs (NRC 2010a). In response to the RAI, 

24 NextEra clarified that during an extended SBO condition, the normal control instrumentation and 

25 procedures for which operators are trained and with which they are familiar would be used to 

26 maintain long-term control of SG water level (NextEra 2011a). 

27 The NRC staff asked NextEra to summarize the scope and unresolved findings from any other 

28 reviews performed on the Seabrook PRA (NRC 2010a). In response to the RAI, NextEra 

29 explained that many other internal reviews—including vendor-assisted reviews—have been 

 

2

 Now termed a “Finding,” a Category A or B F&Os is an “observation (an issue or discrepancy) that is necessary to address to 

ensure: [1] the technical adequacy of the PRA ... [2] the capability/robustness of the PRA update process, or [3] the process for 

evaluating the necessary capability of the PRA technical elements (to support applications).” (NEI 05-04, “Process for Performing 

Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard,” Revision 2, 2008) 
Appendix F 

 F-12 

1 performed on specific model updates, and comments from these reviews—along with plant 

2 changes and potential model enhancements—are tracked through a model change database to 

3 assure that the comments are addressed in the periodic update process (NextEra 2011a). 

4 NextEra specifically explains in the 2012 SAMA supplement (NextEra 2012a) that the 

5 source term analysis was performed by the PRA group and reviewed by industry experts 

6 from a vendor, and the Level 3 model was prepared by experts from a vendor and 

7 independently reviewed. 

8 The NRC staff asked NextEra to identify any changes to the plant, including physical and 

9 procedural modifications, since the SSPSS-2006 PRA model that could have a significant 

10 impact on the results of the SAMA analysis (NRC 2010a). In response to the RAI, NextEra 

11 stated that there have been no major plant changes since PRA model SSPSS-2006 was issued 

12 that could significantly impact the SAMA analysis but did identify specific plant and model 

13 changes made to the PRA model that resulted in the 2009 periodic update of the model, 

14 referred to as PRA model SSPSS-2009 (NextEra 2011a). NextEra explained that the model 

15 changes resulted in a total CDF decrease of about 19 percent but resulted in no significant shift 

16 in the relative importance of initiating events or components. Since then, NextEra has 

17 updated the SSPSS-2011 PRA model, which uses source estimates based on more 

18 detailed MAAP modeling and meets the internal flooding requirements in the ASME PRA 

19 standard (ASME 2009). The 2012 SAMA supplement (NextEra 2012a) is based on the 

20 SSPSS-2011 model and calculates an increase in the CDF, compared to the SSPSS-2009 

21 model, by about 5 percent. 

22 The NRC staff asked NextEra to describe the PRA quality control process used at Seabrook 

23 (NRC 2010a). NextEra responded that an existing administrative procedure defines the quality 

24 control process for updates to the Seabrook PRA, and the process is consistent with 

25 requirements of the ASME 2009 PRA standard (ASME 2009) and ensures that the PRA model 

26 accurately reflects the current Seabrook plant design, operation, and performance 

27 (NextEra 2011a). The quality control process includes monitoring PRA inputs for new 

28 information, recording new applicable information, assessing the significance of new 

29 information, performing PRA revisions, and controlling computer codes and models. NextEra 

30 also stated that the PRA training qualification is performed as part of the Engineering Support 

31 Personnel Training Program. 

32 Given that the Seabrook internal events PRA model has been peer-reviewed and the peer 

33 review findings were all addressed, and that NextEra has satisfactorily addressed NRC staff 

34 questions regarding the PRA, the NRC staff concludes that the internal events Level 1 PRA 

35 model is of sufficient quality to support the SAMA evaluation. 

36 The Seabrook PRA model is an integrated internal and external events model in that it includes 

37 seismic-initiated, fire-initiated, and external flooding-initiated events as well as internal initiating 

38 events. The external events models have been integrated with the internal events model since 

39 the initial 1983 PRA (NextEra 2011a). The external events models used in the SAMA 

40 evaluation are essentially those used in the IPEEE, with the exception of the seismic PRA 

41 model, which underwent a major update for the SSPSS-2005 model. The updated external 

42 events CDF results are described in a response to an NRC staff RAI (NextEra 2011a) and are 

43 included in Table F-3 along with the internal events results. 

44 The Seabrook IPEEE was submitted October 2, 1992 (NAESC 1992), in response to 

45 Supplement 4 of GL 88-20 (NRC 1991). The submittal used the same PRA as was used for the 

46 IPE (i.e., SSPSS-1990) except for updates to the external events. No fundamental weaknesses 
 Appendix F 

 F-13 

1 or vulnerabilities to severe accident risk in regard to the external events were identified. 

2 Improvements that have already been realized as a result of the IPEEE process minimized the 

3 likelihood of there being cost-beneficial enhancements as a result of the SAMA analysis, 

4 especially with the inclusion of a multiplier to account for the additional risk of seismic events. In 

5 a letter dated May 2, 2001, the NRC staff concluded that the submittal met the intent of 

6 Supplement 4 to GL 88-20 and the applicant’s IPEEE process is capable of identifying the most 

7 likely severe accidents and severe accident vulnerabilities (NRC 2001). 

8 The Seabrook IPEEE seismic analysis used a seismic PRA following NRC guidance 

9 (NRC 1991a). The seismic PRA included a seismic hazard analysis, a seismic fragility 

10 assessment, seismic quantification to yield initiating event frequencies and conditional system 

11 failure probabilities, and plant model assembly to integrate seismic initiators and 

12 seismic-initiated component failures with random hardware failures and maintenance 

13 unavailabilities. 

14 The seismic hazard analysis estimated the annual frequency of exceeding different levels of 

15 ground motion. Seabrook seismic CDFs were determined for site-specific, Electric Power 

16 Research Institute (EPRI) (EPRI 1989) and Lawrence Livermore National Laboratory (LLNL) 

17 (NRC 1994) hazard curves. The seismic fragility assessment was performed by walkdowns that 

18 were conducted at the time of the original seismic PRA in 1982 through 1983, walkdowns 

19 performed for a revised fragility analysis in 1986, and supplemental walkdowns performed in 

20 1991 for the IPEEE, using procedures and screening caveats in EPRI’s seismic margin 

21 assessment methodology (EPRI 1988). Fragility calculations were made for about 

22 82 components using a screening criterion of median peak ground acceleration of 2.0 g, which 

23 corresponds to a high confidence (95 percent) low probability (5 percent) of failure (HCLPF) 

24 capacity. A total of 15 components and 2 sets of relay groups were further assessed. Fragility 

25 calculations were also made for eight buildings and structures, and HCLPF values were 

26 determined. The seismic systems analysis defined the potential seismic induced structure and 

27 equipment failure scenarios that could occur after a seismic event and lead to core damage. 

28 The Seabrook IPE event tree and fault tree models were used as the starting point for the 

29 seismic analysis. Quantification of the seismic models consisted of convoluting the seismic 

30 hazard curve with the appropriate structural and equipment seismic fragility curves to obtain the 

31 frequency of the seismic damage state. The conditional probability of core damage, given each 

32 seismic damage state, was then obtained from the IPE models with appropriate changes to 

33 reflect the seismic damage state. The CDF was given based on the product of the seismic 

34 damage state probability and the conditional core damage probability. 

35 Quantification of the seismic CDF for Seabrook was performed in nine discrete ground 

36 acceleration ranges between 0.1 g to 2.0 g. The seismic CDF resulting from the Seabrook 

IPEEE was calculated to be 1.210-5 37 per year using a site-specific seismic hazard curve, with 

sensitivity analyses yielding 1.310-4 38 per year using the LLNL seismic hazard curve and 

6.110-6 39 per year using the EPRI seismic hazard curve. The Seabrook IPEEE did not identify 

40 any vulnerability due to seismic events but did identify two plant improvements to reduce 

41 seismic risk. Neither of the two improvements has been implemented. Each of the two 

42 improvements is addressed by a SAMA in the current evaluation and is discussed further in 

43 Section F.3.2. 

44 Subsequent to the IPEEE, NextEra updated the seismic PRA analysis. The NRC staff asked 

45 NextEra to describe the changes to the seismic analysis incorporated in the PRA model 

46 SSPSS-2005 update and to explain the reasons for any significant changes to the seismic CDF 

47 (NRC 2011a). In response to the RAI, NextEra stated that the most significant changes to the 
Appendix F 

 F-14 

1 IPEEE seismic model made in the SSPSS-2005 update of the Seabrook PRA were as follows 

2 (NextEra 2011a): 

3  The fragility analysis was updated to extend the fragility screening of equipment from 

4 greater than 2.0 g to the range from 2.0 g to 2.5 g and greater than 2.5 g to better 

5 capture seismic risk. 

6  The EPRI hazard curve was adopted and used to update the equipment fragilities. The 

7 site-specific hazard curve was replaced with the EPRI hazard curve because the EPRl 

8 uniform hazard spectrum (UHS) developed for the Seabrook site is more current and 

9 realistic than that used in the original 1983 and the IPEEE PRA. In response to a 

10 followup NRC staff RAI, NextEra further clarified that the EPRI UHS was judged to be 

11 more realistic and representative of the best estimate hazard because of overall general 

12 improvement in seismic technology from the early 1980s to 1989, when the EPRI hazard 

13 curve was developed (NextEra 2011b). The probabilistic estimates of seismic capacity 

14 of structures and components were updated to reflect component-specific fragility 

15 information and the EPRI UHS. 

16  Several new component fragilities were added to the seismic PRA model, including 

17 seismic fragilities for the SEPS DGs, which had been added to the plant since the 

18 IPEEE. 

19  Modeling and documentation of operator actions credited in the seismic PRA were 

20 improved. 

21 NextEra stated that the most recognizable conservatism in the seismic model is the use of 

22 complete correlation of the fragility between identical components, such as both EDGs are 

23 assumed to fail at the same seismic hazard level (NextEra 2011a). NextEra further stated that 

24 extensive internal technical reviews of the seismic PRA analysis were performed for the original 

25 1983 PRA, when the seismic analysis was revised for the IPEEE, and when the seismic 

26 analysis was revised for the SSPSS-2005 PRA model update. No significant comments were 

27 documented from these reviews, and no formal peer reviews have been conducted on the 

28 seismic PRA model (NextEra 2011a). 

29 The NRC staff noted that, in the attachments to NRC Information Notice 2010-18, generic 

30 issue (GI) 199 (NRC 2010b), the NRC staff estimated a seismic CDF for Seabrook of between 

5.9×10-6 per year and 2.2×10–5 31 per year using updated seismic hazard curves developed by the 

32 U.S. Geological Survey (USGS) in 2008 (USGS 2008). The NRC staff asked that NextEra 

33 provide an assessment of the impact of the updated USGS seismic hazard curves on the SAMA 

34 evaluation (NRC 2010a). In response to the RAI, NextEra provided a revised SAMA evaluation

using multipliers of 2.1 and 2.6 to account for the maximum GI-199 seismic CDF of 2.2×10–5 35 per 

36 year, which is discussed further below (NextEra 2011a, 2011b). The 2012 SAMA supplement 

37 (NextEra 2012a) uses a multiplier of 2.1 to account for a higher seismic hazard than 

38 assessed in the PRA. 

39 Considering the following points, the NRC staff concludes that the seismic PRA model, in 

40 combination with the use of a seismic events multiplier, provides an acceptable basis for 

41 identifying and evaluating the benefits of SAMAs: 

42  The Seabrook seismic PRA model is integrated with the internal events PRA. 

43  The seismic PRA has been updated to include additional components and to extend the 

44 fragility-screening threshold. 
 Appendix F 

 F-15 

1  The SAMA evaluation was updated using a multiplier to account for a potentially higher 

2 seismic CDF. 

3  NextEra has satisfactorily addressed NRC staff RAIs regarding the seismic PRA. 

4 The Seabrook IPEEE fire analysis, which was significantly updated from the original fire 

5 analysis completed in 1983, employed EPRI’s FIVE methodology (EPRI 1992) to calculate area 

6 fire frequencies, quantitatively screen areas, and provide hazards analysis for resulting critical 

7 areas. The quantification of CDF was obtained by propagating fire-induced initiating events 

8 through the PRA used for the IPE. 

9 The IPEEE fire areas were based on definitions of Appendix R fire areas for Seabrook. 

10 Qualitative screening was performed using a spatial database specifically developed for the 

11 IPEEE fire analysis that identified equipment important in initiating or mitigating an accident. Of 

12 the 73 fire areas, 13 were determined to contain important equipment (pumps, valves, and 

13 cabling, etc.) and were further assessed. Quantitative screening used industry fire data and the 

14 assumption that a fire in a compartment damaged all equipment and cables in the compartment. 

15 The resulting fire-initiating events are propagated through the appropriate event tree models. 

16 Using fire frequencies and conditional core damage probabilities from the internal events PRA, 

all but eight fire areas were screened as contributing less than 110-6 17 per year to the CDF. 

18 Based on the FIVE fire methodology analysis, the unscreened areas were assessed by 

19 considering possible targets, fire sources and combustibles, possible fire scenarios 

20 (e.g., target-in-plume), and detection and suppression systems to determine the probability of 

21 damage given a fire. Credit was explicitly taken for automatic and manual fire suppression. 

22 Calculation of automatic fire suppression unavailability was supported by fault tree modeling. 

23 Calculation of manual suppression unavailability was supported by HRA. Consideration of fires 

24 on containment performance was also addressed. Final quantification used the Seabrook IPE 

25 PRA model to determine plant responses and CDFs. The resulting fire-induced CDF was 

calculated to be 1.210-5 26 per year. While no physical plant changes were found to be necessary 

27 as a result of the IPEEE fire analysis, fire potential plant improvements to improve fire risk were 

28 identified. Four of the plant improvements have been implemented. The one improvement not 

29 implemented is addressed by a SAMA in the current evaluation and is discussed further in 

30 Section F.3.2. 

31 NextEra updated the fire PRA subsequent to the IPEEE. The NRC staff asked NextEra to 

32 describe the changes to the fire analysis since the IPEEE and to explain the reasons for any 

33 significant changes to the fire CDF (NRC 2011a). In response to the RAI, NextEra explained 

34 that the most recent update of the fire PRA was in support of the SSPSS-2004 PRA update, and 

35 the fire analysis methodology used is essentially the same, with some variations, as that 

36 described previously for the IPEEE fire analysis (NextEra 2011a). Specific changes made to 

37 the Seabrook fire PRA since the IPEEE are listed below: 

38  including current plant data and procedures, 

39  performing detailed walkdowns to verify locations of the major fire sources and important 

40 targets, 

41  updating data to the EPRI fire database that includes fire records through 

42 December 2000, 

43  developing updated severity factors for cabinets, pumps, control room panels, and 

44 transients, 
Appendix F 

 F-16 

1  revisiting the quantitative screening results, 

2  using new data on cabinet heat release rates, and 

3  quantitatively evaluating the total area heat-up rate. 

4 NextEra stated that the most significant conservatism in the fire analysis is the assumption that 

5 small fires, typical of the generic fire events database, are assumed to grow to cause the 

6 maximum damage (NextEra 2010). However, because these fire sequences have such low 

7 frequencies and large uncertainties, NextEra claimed that the impact of this conservatism on the 

8 overall fire CDF is difficult to determine (NextEra 2011a). NextEra further stated that extensive 

9 internal technical reviews of the fire PRA analysis were performed for the original 1983 PRA, 

10 when the fire analysis was revised for the IPEEE and when the fire analysis was revised for the 

11 SSPSS-2005 PRA model update. No significant comments were documented from these 

12 reviews, and no formal peer reviews have been conducted on the fire PRA model 

13 (NextEra 2011a). 

14 In a followup RAI, the NRC staff asked NextEra to clarify if fire-induced failures of components 

15 and human actions credited with mitigating the initiator were assessed and to describe how hot 

16 short probabilities were considered in the fire analysis (NRC 2011b). In response to the RAI, 

17 NextEra clarified that, for fire initiators that are not screened and are evaluated in detail, the 

18 probability of fire damage to components due to the fire is included in the analysis and that this 

19 probability is dependent upon the presence of combustible material and the success of 

20 suppression (NextEra 2011b). NextEra stated that the probability of additional failures needed 

21 for core damage was also evaluated, including unavailability of redundant systems and 

22 components and failure of operator actions, and component failures not impacted by the fire are 

23 modeled as random. Regarding the hot short probability question, NextEra explained that a hot 

24 short probability of 0.1 was used in the screening evaluation for important valves and 

25 components. NextEra also described the results of an evaluation to assess the sensitivity of the 

26 SAMA results to using a hot short probability of 0.6. This evaluation determined that the fire 

27 event screening evaluation is insensitive to this increase in the potential for hot shorts and that, 

28 while the contribution to CDF does increase due to the higher probability, the contribution 

29 compared to the CDF contribution of similarly modeled internal events remains relatively low. 

30 Specifically, NextEra evaluated 18 fire events and determined that 3 of the events contributed in 

31 the range of 10 to 20 percent of the corresponding internal events CDF, and the remaining 

32 15 fire events contributed less than 10 percent. Based on this result, NextEra determined that 

33 the increase in hot short potential does not have a significant effect on the SAMA analysis 

34 (NextEra 2011b). 

35 The NRC staff noted that the fire ignition frequencies for a fire in SWGR room B—Loss of 

Bus E6 and SWGR room A—Loss of Bus E5, which were reported to be about 1.010-3 36 per year 

37 each, appeared to be low unless the fire only involved the associated buses. The NRC staff 

38 asked that NextEra justify these values (NRC 2010a). NextEra responded that the ignition 

39 frequency for SWGR room B—Loss of Bus E6 includes the cumulative fire ignition frequencies 

40 for 21 Bus E6 cabinets and 170 other electrical cabinets. SWGR room A—Loss of Bus E5 

41 similarly includes the cumulative fire ignition frequencies for 21 Bus E5 cabinets and 86 other 

electrical cabinets (NextEra 2011a). NextEra explained that the cited value of 1.010-3 42 per year 

was more than just “frequency” (i.e., it included not only fire ignition frequency of 4.610-5 43 per 

44 year per cabinet but also a severity factor of 0.2 and a manual non-suppression probability of 

45 0.1 for fires in the other electrical cabinets). Therefore, the calculated total fire ignition 

46 frequency for each of the two SWGR rooms is the same as that reported in the ER. The NRC 

47 staff considers NextEra’s assumptions reasonable. 
 Appendix F 

 F-17 

1 Considering that the Seabrook fire PRA model is integrated with the internal events PRA, that 

2 the fire PRA has been updated to include more current data, and that NextEra has satisfactorily 

3 addressed NRC staff RAIs regarding the fire PRA, the NRC staff concludes that the fire PRA 

4 model provides an acceptable basis for identifying and evaluating the benefits of SAMAs. 

5 The Seabrook IPEEE analysis of high winds, tornadoes, external floods, and other (HFO) 

6 external events followed the screening and evaluation approaches specified in Supplement 4 to 

7 GL 88-20 (NRC 1991) and concluded that Seabrook meets the 1975 Standard Review Plan 

(SRP) criteria (NRC 1975). Two external event frequencies exceeded the 1.010-6 8 per year 

9 screening criterion (NAESC 1992). One of these events is flooding resulting from a storm surge 

10 caused by a hurricane, which is modeled in the PRA and described in the ER (NextEra 2010) as 

11 event EXFLSW in which the SW pumps are flooded. This sequence was reported in the ER to 

contribute just 210-8 12 per year to the total Seabrook CDF. The second event is an external 

13 initiating event involving a truck crash into the SF6 transmission lines. In response to an NRC 

14 staff RAI, NextEra explained that this event has been mitigated by the installation of jersey 

15 barriers and guard rails that further limit the possibility of a truck crash impacting the 

16 transmission lines and that, as a result, this initiating event has been screened from the PRA 

17 model (NextEra 2011a). 

18 While no physical plant changes were found to be necessary as a result of the IPEEE HFO 

19 analysis, one plant improvement based on HFO analysis was recommended—modify several 

20 exterior doors so that they will be able to withstand the design pressure differential resulting 

21 from high winds. NextEra clarified in response to an NRC staff RAI that this suggested 

22 improvement has been implemented (NextEra 2011a). 

23 The NRC staff noted that while the risk of flooding resulting from a storm surge caused by a 

24 hurricane is included in the PRA, the impact of hurricane-force winds does not appear to be 

25 addressed, and the staff requested that NextEra provide an assessment of the risk of this event 

26 on the Seabrook site (NRC 2010a). In response to the RAI, NextEra explained that the high 

27 winds associated with a hurricane that might accompany a storm surge are screened from 

28 consideration because the site design basis criteria for high winds and tornadoes meets the 

29 1975 SRP criteria (NextEra 2011a). The NRC staff considered this explanation acceptable. 

30 The Seabrook IPEEE submittal also stated that as a result of the Seabrook IPE, cost-benefit 

31 analyses are being performed for many potential plant improvements, which may also reduce 

32 external event risk because they address functional failures. Five potential plant improvements 

33 to improve internal event risk that may also reduce external event risk were identified. Four of 

34 the plant improvements have been implemented. The one improvement not implemented is 

35 addressed by a SAMA in the current evaluation and is discussed further in Section F.3.2. 

36 NextEra estimated the benefits for both internal and external events using the integrated 

37 Seabrook PRA model. However, as discussed previously, an NRC staff assessment of the 

38 USGS 2008 seismic hazard curves yielded an upper bound seismic CDF for Seabrook of 

2.210-5 per year, which is substantially greater than the 3.110-6 39 per year seismic CDF used in 

40 the SAMA evaluation. The NRC staff requested that NextEra provide an assessment of the 

41 impact of this higher seismic CDF on the SAMA evaluation (NRC 2010a, 2011b). In response 

42 to the RAIs, NextEra noted that the NRC staff’s estimate of the seismic CDF using the USGS 

43 2008 seismic hazard curves did not include credit for the SEPS DGs installed at Seabrook in 

44 2004, which have a median seismic fragility of 1.23 g (NextEra 2011b). NextEra stated that the 

45 SEPS DGs were modeled in the Seabrook seismic PRA in 2005 and reduced the seismic CDF 

46 by approximately 26 percent by avoiding SBO sequences, and a corresponding reduction in the 
Appendix F 

 F-18 

NRC staff estimate of the seismic CDF using the USGS 2008 seismic hazard curves to 1.610-5 1 

2 per year would be expected. NextEra also provided a sensitivity analysis using a multiplier of 

3 2.1 to account for the revised higher seismic CDF. This multiplier is based on an increased 

seismic CDF of 1.310-5 per year (upper bound seismic CDF of 1.610-5 4 per year minus seismic 

CDF of 3.110-6 per year used in the SAMA evaluation) and a total estimated CDF of 1.210-5 5 

6 per year for PRA model SSPSS-2009 (NextEra 2011b). The NRC staff agrees that a seismic 

CDF of 1.610-5 7 per year for Seabrook is reasonable and agrees that the applicant’s use of a 

8 multiplier of 2.1, which was used in the 2012 SAMA supplement (NextEra 2012a), to account 

9 for the additional risk from seismic events is reasonable for the purposes of the SAMA 

10 evaluation. This is discussed further in Section F.6.2. 

11 The NRC staff reviewed the general process used by NextEra to translate the results of the 

12 Level 1 PRA into containment releases, as well as the results of the Level 2 analysis, as 

13 described in the ER and in response to NRC staff RAIs (NextEra, 2011a). The Level 2 model 

14 was significantly revised in the 2005 PRA update (i.e., PRA model SSPSS-2005) from that used 

15 in the IPE and reflects the Seabrook plant as designed and currently operated. In response to 

16 an NRC staff RAI (NextEra 2010), NextEra identified the following major changes to the PRA 

17 that most impacted the LERF (NextEra 2011a): 

18  change in definition of LERF to include steam leak from a SGTR, 

19  higher failure likelihood for small containment penetrations in seismic sequences, 

20  update to credit manual operator action to close the RCP seal return line MOV, 

21  expansion of the LERF model by adding a steam line break to SGTR and consideration 

22 of ATWS sequences, 

23  updates to the Level 2 analysis to reflect current state of knowledge including SAMGs, 

24  revisions to incorporate plant-specific data, 

25  update of data distributions, and 

26  revisions to operator action modeling. 

27 No Level 2 design or plant changes were identified in the 2012 SAMA supplement 

28 (NextEra 2012a). 

29 In response to an NRC staff RAI, NextEra explained that the quantification of the Level 1 and 

30 Level 2 models is done using a linked event tree method approach and does not employ plant 

31 damage states (NextEra 2011a). Therefore, all Level 1 sequences are evaluated by the CET, 

32 making it unnecessary to summarize and group similar sequences into Level 1 plant damage 

33 states before they are input to the CET. The Level 2 model is a single CET and evaluates the 

34 phenomenological progression of all the Level 1 sequences including internal, fire, and 

35 seismically initiated events. In response to another NRC staff RAI, NextEra clarified that the 

36 CET has 37 branching events, which include 10 hardware-related, 13 human action-related, and 

37 13 phenomena-related events, along with a single mapping event (NextEra 2011a). CET 

38 branch point split fraction numerical values are determined based on the type of event. The 

39 CET event success criterion is defined, and split fraction logic rules are used to apply the 

40 correct event split fraction values during CET quantification. Included in the response to the 

41 NRC staff RAI, NextEra provided a description of each of the 37 CET branching events. End 

42 states resulting from the combinations of the branches are then assigned to one of 16 release 

43 categories based on characteristics that determine the timing and magnitude of the release, 
 Appendix F 

 F-19 

1 whether or not the containment remains intact, and isotopic composition of the released 

2 material. In response to another NRC staff RAI, NextEra clarified that the frequency of each 

3 release category was obtained by summing the frequency of the individual accident progression 

4 CET end states binned into the release category (NextEra 2011a). 

5 The quantified CET sequences binned into the 2116 release categories are subsequently 

6 grouped into 1310 source term categories that provide the input to the Level 3 consequence 

7 analysis (NextEra 2012a). In response to an NRC staff RAI, NextEra explained that the 16 

8 release categories were reduced to 10 source term categories by grouping release categories 

9 that occur due to different phenomena, but the consequence is essentially the same 

10 (e.g., thermally induced SGTR and pressure-induced SGTR) (NextEra 2011a). Eight of the 

11 release categories were mapped one-to-one into a corresponding source term category. 

12 For three of the source term categories, three release categories were binned together to 

13 form the combined source term category, and for two of the source term categories, two 

14 release categories were binned together to form the combined source term category. 

15 Source terms were developed for each of the source term categories. In the 2012 SAMA 

16 supplement, NextEra explains that the release fractions and timing for source term categories 

17 are based on the results of plant-specific calculations using the MAAP Version 4.0.7 and 

18 represent more realism and an upgrade from the source terms presented in the ER

19 (NextEra 2010). NextEra generally selected the representative MAAP case based on that which 

20 resulted in the most realistic timing and source term release. In four of the combined source 

21 term categories, the source term for the release category having the highest (dominant)

22 release frequency was used as the source term for the combined category. The 

23 consequences from the contributors were considered similar. In one of the four 

24 categories, the total frequency was very low (approximately 1E-9 per year). In the fifth 

25 combined source term category (i.e., SELL), one of the contributors had the most 

26 significant source term and the highest frequency so it was selected as the 

27 representative case. The source term categories and their frequencies and release 

28 characteristics are presented in tables on pages 12, 13, and 18 of the 2012 SAMA 

29 supplement (NextEra 2012a). 

30 As indicated above, the current Seabrook Level 2 PRA model is an update of that used in the 

31 IPE. The IPE did not identify any severe accident vulnerabilities associated with containment 

32 performance. Risk-related insights and improvements discussed in the IPE submittal were 

33 discussed previously. The NRC staff review of the IPE back-end (i.e., Level 2) model concluded 

34 that it appeared to have addressed the severe accident phenomena normally associated with 

35 large dry containments, it met the IPE requirements, and there were no obvious or significant 

36 problems or errors. 

37 The LERF model was included in the 1999 industry peer review discussed previously. Seven of 

38 the F&Os from this review addressed the LERF analysis. The applicant provides in the ER the 

39 resolution of each of the seven F&Os and states that all have been dispositioned and 

40 implemented in the PRA model. NextEra noted that the Seabrook radiological source terms 

41 were significantly revised for the SSPSS-2005 PRA model based on Level 2 analysis by 

42 Westinghouse Electric Company. In addition, NextEra noted that the source terms were further 

43 revised during the SSPSS-2011 PRA model and are reflected in the 2012 SAMA supplement 

44 (NextEra 2012a). 

45 The NRC staff noted that the LERF reported for Seabrook is less than 1 percent of the CDF and 

46 asked NextEra to explain this apparently very low LERF (NRC 2010a). In response to the RAI, 
Appendix F 

 F-20 

1 NextEra explained that Seabrook has a very large-volume and strong containment building in 

2 comparison to most other nuclear power plant containment designs (NextEra 2011a). As a 

3 result of the containment design median failure pressure of 187 pounds per square inch 

4 absolute (psia) (dry) and 210 psia (wet), there are no conceivable severe accident progression 

5 scenarios that result in catastrophic failure early in the accident sequence. The NRC staff 

6 considers NextEra’s explanation reasonable. 

7 The NRC staff requested that NextEra explain how fire-induced interfacing system 

8 loss-of-coolant accidents (ISLOCAs) and fire-induced containment impacts are addressed in the 

9 fire analysis (NRC 2010a, 2011b). In response to the RAIs, NextEra explained that containment 

10 performance was evaluated in three areas: (1) containment structure, (2) containment response 

11 to a core damage event, and (3) containment isolation failure (NextEra 2011a). Fires were 

12 determined to have no impact on containment structure integrity. Fire-initiated core damage 

13 events were determined to have the same impact on containment response as internal-initiated 

14 events; thus, they are handled through the CET. The potential for containment isolation failure 

15 was assessed by evaluating the potential for fire-induced failure of important isolation valves, as 

16 follows: 

17  Because the containment isolation valves (CIVs) are located both inside and outside 

18 containment, NextEra concluded that only a fire in the control room or cable spreading 

19 room could affect CIVs both inside and outside containment and that, in this event, 

20 important CIVs could be controlled locally at the valve or from the remote shutdown 

21 panel (RSP). CIVs located outside containment could be controlled both locally at the 

22 valve and from the RSP, CIVs located inside containment could be controlled from the 

23 RSP, and no credit is taken for local control of valves inside containment 

24 (NextEra 2011b). 

25  Because the letdown system has three normally open, air-operated valves (AOVs) in 

26 series, NextEra concluded that hot shorting in all three valves is not credible. NextEra 

27 clarified that failure to isolate the letdown system for an extended period of time is 

28 judged to not be credible for the following reasons (NextEra 2011b): 

29 – There are three AOVs inside containment and one AOV outside containment. 

30 – All four AOVs fail to the closed position upon loss of air or control power. 

31 – Shorts to ground in the control cables for these AOVs will also result in the AOVs 

32 failing to the closed position. 

33 – There are two MOVs inside containment that are available to provide isolation. 

34  The potential for fire-induced failures of several other potential isolation pathways was 

35 also evaluated (e.g., large residual heat removal (RHR) suction line MOVs, RCP seal 

36 return line isolation valves, and containment on-line purge valves) and determined to not 

37 be credible. 

38 Based on the information above, NextEra concluded that the only credible impact of fires on 

39 containment performance is to fail a single train of isolation. For isolation failure of one or more 

40 valves in a single train, either redundant isolation would be available or the ability to remove 

41 power from fail closed valves to provide isolation is available (NextEra 2011a). NextEra further 

42 clarified that, since Seabrook is designed with divisional cable separation, power to the fail 

43 closed valves can be removed, if necessary, by removing its divisional power supply, thus 

44 ensuring that the valves fail closed and are prevented from being failed opened due to hot 

45 shorting (NextEra 2011b). NextEra further concluded that the frequency of fires that could 
 Appendix F 

 F-21 

1 cause this level of damage is sufficiently low compared to hardware failures that this scenario 

2 does not contribute significantly to containment isolation failure and that, as a result, no fire 

3 impacts on containment isolation components are included in the PRA (NextEra 2011a). 

4 Based on the NRC staff’s review of the Level 2 methodology, the NRC staff concludes that 

5 NextEra has adequately addressed NRC staff RAIs, that the LERF model was reviewed in more 

6 detail as part of the 1999 WOG certification peer review, and that all F&Os have been resolved. 

7 Therefore, the NRC staff concludes that the Level 2 PRA provides an acceptable basis for 

8 evaluating the benefits associated with various SAMAs. 

9 As indicated in the ER, the reactor core radionuclide inventory used in the consequence 

10 analysis corresponds to the end-of-cycle values for Seabrook operating at 3,659 MWt. This 

11 bounds the current Seabrook rated power of 3,648 MWt. The core radionuclide inventory is 

12 provided in Table F.3.4.3-1 of Appendix F of the ER (NextEra 2010). In response to an NRC 

13 staff RAI, NextEra clarified that a Seabrook-specific core inventory was calculated using 

14 ORIGEN2.1 except for Cobalt-58 and Cobalt-60 (NextEra 2011a). NextEra noted that the 

15 ORIGEN calculations did not provide isotopic inventories for Cobalt-58 and Cobalt-60. 

16 Therefore, these isotope inventories were estimated using the MACCS2 sample problem 

17 inventory corrected by the ratio of Seabrook’s power level to the MACCS2 sample problem A 

18 power level (i.e., 3,659 MWt/3,412 MWt). Based on this clarification, the NRC staff concludes 

19 that the reactor core radionuclide inventory assumptions for estimating consequences are 

20 reasonable and acceptable for purposes of the SAMA evaluation. 

21 The NRC staff reviewed the process used by NextEra to extend the containment performance 

22 (Level 2) portion of the PRA to an assessment of offsite consequences (essentially a Level 3 

23 PRA). This included consideration of the source terms used to characterize fission product 

24 releases for the applicable containment release categories and the major input assumptions 

25 used in the offsite consequence analyses. Version 1.13.1 of the MACCS2 code was used to 

26 estimate offsite consequences (NRC 1998) based on the results of the SSPSS-2011 PRA 

27 model (NextEra 2012a). Plant-specific input to the code includes the source terms for each 

28 release category and the reactor core radionuclide inventory (both discussed above), 

29 site-specific meteorological data, projected population distribution within an 80-km (50-mi) 

30 radius for the year 2050, emergency evacuation planning, and economic parameters including 

31 agricultural production. This information is provided in Section F3.4 of Attachment F to the ER 

32 (NextEra 2010) and was unchanged by the 2012 SAMA supplement (NextEra, 2012a). 

33 All releases were modeled as occurring at the top height of the containment building. In the 

34 ER, sensitivity cases were run assuming ground level release, as well as releases at 

35 25 percent, 50 percent, and 75 percent of the containment building height. In response to an 

36 NRC staff RAI, NextEra reported that decreasing the release height from the top of the reactor 

37 building to ground level decreased the population dose risk and offsite economic cost risk by up 

38 to 3 percent and 4 percent, respectively (NextEra 2011a). The thermal content of each of the 

39 releases was assumed to be the same as ambient (that is a non-buoyant plume). A sensitivity 

40 analysis was performed in the ER assuming a 1 MW and 10 MW heat release plume. In 

41 response to an NRC staff RAI, NextEra reported that increasing the release heat decreased the 

42 population dose risk by 2 percent and 12 percent, and the offsite economic cost risk decreased 

43 by 1 percent and 9 percent for the 1 MW and 10 MW heat release, respectively 

44 (NextEra 2011a). Wake effects for the containment building were included in the model. A 

45 sensitivity analysis was performed in the ER assuming the wake size was one-half and double 

46 the baseline wake size. In response to an NRC staff RAI, NextEra reported that decreasing the 

47 wake size by one-half decreased the population dose risk by 1 percent and did not change the 
Appendix F 

 F-22 

1 offsite economic cost risk, while doubling the wake size increased both the population dose risk 

2 and offsite economic cost risk by 1 percent (NextEra 2011a). While these sensitivity 

3 analyses were not re-performed for the 2012 SAMA supplement, NextEra concluded that 

4 the results in the ER would be representative of the updated SAMA evaluation 

5 (NextEra 2012a). The NRC staff notes that these results are consistent with previous SAMA 

6 analyses that have shown only minor sensitivities to release height, buoyancy, and building 

7 wake effects. Based on the information provided, the staff concludes that the release 

8 parameters used are acceptable for the purposes of the SAMA evaluation. 

9 NextEra used site-specific meteorological data for the year 2005 as input to the MACCS2 code. 

10 The development of the meteorological data is discussed in Section F.3.4.5 of the ER 

11 (NextEra 2010). Data from 2004 through 2008 were also considered, but the 2005 data were 

12 chosen because the results of a MACCS2 sensitivity analysis indicated that the 2005 data 

13 produced more conservative results (i.e., the 2005 data set was found to result in the largest 

14 population dose risk and offsite economic cost risk). In response to an NRC staff RAI, NextEra 

15 reported that the results of the meteorological data sensitivity analysis, which was performed for 

16 each of the years 2004 through 2008, showed a decrease in population dose risk in the range of 

17 5 to 13 percent and a range of 3 to 12 percent decrease in offsite economic cost risk 

18 (NextEra 2011a). NextEra repeated this sensitivity study for the 2012 SAMA supplement 

19 (NextEra 2012a), and the 2005 data set was again found to result in the largest population 

20 dose risk and offsite economic cost risk. Missing data were estimated using data 

21 substitution methods. These methods include substitution of missing data with corresponding 

22 data from another level on the meteorological tower, interpolation between data from the same 

23 level, or data from the same hour and a nearby day of a previous year. Hourly stability was 

24 classified according to the system used by the NRC (NRC 1983). The baseline analysis 

25 assumes perpetual rainfall in the 40 to 50 mi segment surrounding the site. A sensitivity 

26 analysis was performed for the 2012 SAMA supplement assuming measured rainfall rather 

27 than perpetual rainfall in the 40 to 50 mi spatial segment (NextEra 2012a). This resulted in a 

28 decrease in population dose risk of 14 percent and a decrease in offsite economic cost risk of 

29 1517 percent. The NRC staff notes that these results are consistent with previous SAMA 

30 analyses that have shown little sensitivity to year-to-year differences in meteorological data. 

31 Based on the information provided, the NRC staff concludes that the use of the 2005 

32 meteorological data in the SAMA analysis is reasonable. 

33 The population distribution the licensee used as input to the MACCS2 analysis was estimated 

34 for the year 2050 using year 2000 census data as accessed by SECPOP2000 (NRC 2003). 

35 The baseline population was determined for each of 160 sectors, consisting of the 16 directions 

36 for each of 10 concentric distance rings with outer radii at 1, 2, 3, 4, 5, 10, 20, 30, 40, and 50 mi 

37 surrounding the site. County population growth estimates were applied to year 2000 census 

38 data to develop year 2050 population distribution. The distribution of the population is given for 

39 the 10-mi radius from Seabrook and for the 50-mi radius from Seabrook in the ER 

40 (NextEra 2010). In response to an NRC staff RAI, NextEra clarified that the year 2000 

41 population was exponentially extrapolated to year 2050 (NextEra 2011a). The NRC staff noted 

42 that the total population of 4,157,215, identified in Section 2.6.1 of the ER, was different than the 

43 4,232,394 reported in ER Table F.3.4.1 (NRC 2010a). In response to the NRC staff RAI, this 

44 difference was attributed to the following factors (NextEra 2011a): 

45  the choice of distribution centroids between the two references, 

46  the inclusion of transient population in the population extrapolation for ER 

47 Table F.3.4.1-1 but not in ER Section 2.6.1, and 
 Appendix F 

 F-23 

1  the assumption that the population fraction is equal to the land area fraction where the 

2 50-mi radius bisects the census block groups. 

3 The NRC staff also requested clarification of why some sectors showed zero or (small) negative 

4 population growth (NRC 2010a). NextEra clarified that this was attributed to the geographic 

5 information system (GIS) land layers not being detailed enough to account for the existence of 

6 some small islands, and the GIS water sectors were projected as zero populations 

7 (NRC 2011a). Also, the direction distribution used in the 2050 projection was slightly offset from 

8 the existing population, resulting in some sectors being considered all water and, thus, zero 

9 population. In fact, a portion of those sectors include the coastline; therefore, they have a 

10 population. The population projections were refined to account for the above and to include the 

11 most recent county population growth rates (the sensitivity case above). A sensitivity analysis 

12 was performed using the refined population projections and the population distribution centroid 

13 for ER Table F.3.4.1-1 (NextEra 2010). This resulted in an overall population decrease of about 

14 4 percent, resulting in a corresponding decrease in population dose risk and economic cost risk 

15 of 5 percent and 6 percent, respectively. The NRC staff considers the methods and 

16 assumptions for estimating population reasonable and acceptable for purposes of the SAMA 

17 evaluation. 

18 The emergency evacuation model was modeled as a single evacuation zone extending out 

19 16 km (10 mi) from the plant. NextEra assumed that 95 percent of the population would 

20 evacuate. This assumption is conservative relative to the NUREG-1150 study (NRC 1990), 

21 which assumed evacuation of 99.5 percent of the population within the emergency planning 

22 zone (EPZ). The evacuated population was assumed to move at an average speed of 

23 approximately 0.4 mps (0.9 mph) with a delayed start time of 120 minutes after declaration of a 

24 general emergency. The evacuation speed was derived from the projected time to evacuate the 

25 entire EPZ under adverse weather conditions during the year 2000 (NextEra 2010) and then 

26 adjusted by the ratio of the year 2000 EPZ population to the projected year 2050 EPZ 

27 population. In the ER, NextEra performed sensitivity analyses in which the evacuation speed, 

28 the delayed start time or preparation time for evacuation of the EPZ, and the emergency 

29 declaration time were each individually decreased by 50 percent and doubled relative to the 

30 base case. In response to an NRC staff RAI, NextEra reported that the decrease in evacuation 

31 speed increased the population dose risk by 3 percent, and the increase in evacuation speed 

32 decreased the population dose risk by 4 percent. Additionally, the decrease in delay time 

33 decreased the population dose risk by 9 percent, the increase in delay time decreased the 

34 population dose risk by 2 percent, the decrease in emergency declaration time decreased the 

35 population dose risk by 6 percent, and the increase in emergency declaration time decreased 

36 the population dose risk by 3 percent (NextEra 2011a). For all three parameters, both the 

37 increase and decrease in the base values resulted in no change to the offsite economic cost 

38 risk. In the ER, NextEra explained that an increase in delay time or emergency declaration time 

39 could decrease population dose risk if the evacuation and plume release are simultaneous. 

40 NextEra also performed a sensitivity analysis in the 2012 SAMA supplement (NextEra 2012a)

41 assuming that the population does not evacuate for a severe accident resulting in a small, early 

42 containment penetration failure with no source term scrubbing, representative of a seismically 

43 induced severe accident event. This resulted in an increase in population dose risk of less 

44 than 1 percent and no change in offsite economic cost risk. The NRC staff concludes that the 

45 evacuation assumptions and analysis are reasonable and acceptable for the purposes of the 

46 SAMA evaluation. 

47 In an NRC staff RAI, NextEra clarified that sea-breeze circulation was included in the SAMA 

48 evaluation only to the extent that this is included in the onsite meteorological data 
Appendix F 

 F-24 

1 (NextEra 2011a). NextEra further explained that there are two major mechanisms associated 

2 with sea-breezes, a mixing front and thermal internal boundary layer (TIBL). A mixing front 

3 results in increased plume mixing and dispersion, resulting in a potential decrease in population 

4 dose. This was conservatively ignored in the SAMA evaluation. However, TIBL could decrease 

5 dispersion and increase population dose. Given this, NextEra performed a sensitivity study 

6 assuming 25 percent of the year with TIBL formation (data for year 2005 identified a TIBL was 

7 present 7 percent of the year). The increase in TIBL formation increased the population dose 

8 risk and offsite economic cost risk by 4 percent and 7 percent, respectively. NextEra re9 performed this sensitivity study in the 2012 SAMA supplement (NextEra 2012a). The 

10 results of the evaluation indicate that the population dose and offsite economic cost 

11 risks increase by less than 1 percent each. NextEra clarified that the previous results 

12 were calculated in MACCS2 using the Monte Carlo random bin sampling technique. The 

13 revised evaluation summarized above used the MACCS2 sequential hour analysis 

14 technique, which provides a more accurate result compared to the Monte Carlo bin 

15 sampling technique. Thus, the latest results are shown to be less than previous results 

16 despite the increase in release category source terms. In both the original RAI response 

17 and the 2012 SAMA supplement, NextEra performed a sensitivity study of the TIBL lid 

18 height by changing the lid height from 110 m to 100 m. The decrease in TIBL lid height, 

19 in both sensitivity studies, resulted in an increase in population dose risk and offsite 

20 economic cost of less than 1 percent each. The NRC staff concludes that sea-breeze affects 

21 have a minor impact on the SAMA analysis results. 

22 Much of the site-specific economic and agricultural data were provided from SECPOP2000 

23 (NRC 2003) by specifying the data for each of the 13 counties surrounding Seabrook, to a 

24 distance of 80 km (50 mi). SECPOP2000 uses county economic and agriculture data from the 

25 2000 National Census of Agriculture. This included the fraction of land devoted to farming, 

26 annual farm sales, the fraction of farm sales resulting from dairy production, and the value of 

27 non-farmland. In response to an NRC staff RAI, NextEra identified that the recent, three known 

28 errors in SECPOP2000 were corrected for the SAMA evaluation (NextEra 2011a). 

29 NRC staff asked NextEra to explain its assertion in the 2012 SAMA supplement 

30 (NextEra 2012a) that sensitivities to variation in other Level 3 parameters (not explicitly 

31 re-evaluated in the 2012 SAMA supplement) are expected to be consistent with the ER 

32 sensitivity analysis results. NextEra explained (NextEra 2012b) that except for the 

33 difference in source term release, the Level 3 parameters used in the SAMA analysis 

34 supplement did not change. In addition, NextEra further noted (a) that greater 

35 meteorology specification (imposed as 40 to 50 mi (approximately 64 to 80 km) rather 

36 than following the site boundary) produces 15 percent more conservative dose and cost 

37 risks, (b) that the re-evaluated sea-breeze effect for the 2012 SAMA supplement 

38 (NextEra 2012a) showed only small change in dose and cost risk, and (c) that non39 evacuation rather than delayed evacuation for extreme seismic events (release 

40 category LE4) results in only a small increase in total LE4 dose consequences.

41 The NRC staff concludes that the methodology used by NextEra to estimate the offsite 

42 consequences for Seabrook provides an acceptable basis from which to proceed with an 

43 assessment of risk reduction potential for candidate SAMAs. Accordingly, the NRC staff based 

44 its assessment of offsite risk on the CDF and offsite doses reported by NextEra. 
 Appendix F 

 F-25 

1 F.3 Potential Plant Improvements 

2 The process for identifying potential plant improvements, an evaluation of that process, and the 

3 improvements evaluated in detail by NextEra are discussed in this section. 

4 F.3.1 Process for Identifying Potential Plant Improvements 

5 NextEra’s process for identifying potential plant improvements (SAMAs) consisted of the 

6 following elements: 

7  review of the most significant basic events from the plant-specific PRA used in the 2012

8 SAMA supplement (NextEra 2012a), 

9  review of potential plant improvements identified in the Seabrook IPE and IPEEE, 

10  review of other industry documentation discussing potential plant improvements, and 

11  insights from Seabrook personnel. 

12 Based on this process, an initial set of 191 candidate SAMAs was identified in the ER 

13 (NextEra 2010), and 4 additional SAMA candidates were identified in the 2012 SAMA 

14 supplement. A total of 195 candidate SAMAs, which are referred to as Phase I SAMAs, was 

15 identified. In Phase I of the evaluation, NextEra performed a qualitative screening of the initial 

16 list of SAMAs and eliminated SAMAs from further consideration. The screening was 

17 performed using the following criteria: 

18  The SAMA is not applicable to Seabrook due to design differences (19 SAMAs 

19 screened). 

20  The SAMA has already been implemented at Seabrook or Seabrook meets the intent of 

21 the SAMA (87 SAMAs screened). 

22  The SAMA is similar to another SAMA under consideration (11 SAMAs screened). 

23  The SAMA has estimated implementation costs that would exceed the dollar value 

24 associated with eliminating all severe accident risk at Seabrook (no SAMA screened). 

25  The SAMA was determined to provide very low benefit (no SAMA screened). 

26 In response to an NRC staff RAI (NRC 2012a), NextEra clarified that Phase I SAMAs 

27 screened on the basis of the first three criteria were not re-reviewed in the 2012 SAMA 

28 supplement since this supplement was based on modeling changes that did not change 

29 the conclusions of earlier qualitative screening of Phase 1 SAMAs (NextEra 2012b). 

30 Based on this screening, 117 SAMAs were eliminated, leaving 7874 for reevaluation, 

31 including the 4 new SAMAs identified in the 2012 SAMA supplement (NextEra 2012a). 

32 These SAMAs are referred to as Phase II SAMAs and are listed in Table 1 of the 2012 SAMA 

33 supplement (NextEra 2012a). As part of Phase II, a detailed evaluation was performed for 

34 each of these 78 SAMA candidates, as discussed in Sections F.4 and F.6 below. The 

35 estimated benefits for these SAMAs include the risk reduction from both internal and external 

36 events. 

37 As previously discussed, NextEra accounted for the potential risk reduction benefits associated 

38 with each SAMA by quantifying the benefits using the integrated internal and external events 

39 PRA model. In response to NRC staff RAIs, NextEra performed a sensitivity analysis to account 

40 for the potential additional risk reduction benefits associated with the additional risk from seismic 
Appendix F 

 F-26 

1 events (NextEra 2011a), which was also performed in the 2012 SAMA supplement 

2 (NextEra 2012a), NextEra multiplied the estimated benefits for internal and external events by a 

3 factor of 2.16 for those Phase II SAMAs that were qualitatively screened on high implementation 

4 costs and by a factor of 2.1 for all other Phase II SAMAs for which a detailed evaluation was 

5 performed (NextEra 2012a). 

6 F.3.2 Review of NextEra’s Process 

7 NextEra’s efforts to identify potential SAMAs focused primarily on areas associated with internal 

8 initiating events but also included explicit consideration of potential SAMAs for fire and seismic 

9 events. The initial list of SAMAs generally addressed the accident sequences considered to be 

10 important to CDF from functional, initiating event, and risk reduction worth (RRW) perspectives 

11 at Seabrook. 

12 NextEra’s SAMA identification process began with a review of the list of potential PWR 

13 enhancements in Table 14 of NEI 05-01 (NEI 2005). As a result of this review, 153 SAMAs 

14 were identified. In response to NRC staff RAIs, NextEra clarified that 25 SAMAs were 

15 identified from previous reviews of internal and external events from the Seabrook plant16 specific PRA and an additional 13 SAMAs were identified as a result of a general solicitation 

17 of Seabrook staff for possible SAMA candidates by an expert panel. As mentioned 

18 previously, four additional SAMAs were identified in the 2012 SAMA supplement, of which 

19 three SAMAs were suggested by plant personnel and one SAMA was identified in 

20 response to an NRC staff RAI (NextEra 2012a). 

21 In the ER and subsequent RAI responses, NextEra provided tabular listings of both the 

22 Level 1 and LERF PRA internal, fire, and seismic basic events sorted according to their 

23 RRW (NextEra 2010), listings of the Level 2 non-LERF basic events that contribute 

24 90 percent of the population dose risk, and a review all of these basic events for potential 

25 SAMAs. 

26 These importance analyses were subsequently updated in the 2012 SAMA supplement 

27 (NextEra 2012a) based on the SSPSS-2011 PRA model. In this supplement, NextEra 

28 provided a tabular listing of the top 15 initiating events contributing to each of CDF and 

29 LERF, the top 15 basic events contributing to each of CDF and LERF, and the basic 

30 events for the Level 2 release categories that cumulatively contribute to approximately 

31 90 percent of the total public risk (i.e., dose and economic cost risk). As a result, 

32 existing SAMAs or new SAMAs were identified for a total of 29 initiating events (one 

33 initiating event contributes to both CDF and LERF) and 43 basic events (some basic 

34 events contribute to multiple release categories). In response to an NRC staff RAI on the 

35 supplement to provide importance analysis down to a level that all potentially cost36 beneficial SAMAs could be identified, NextEra provided listings of basic event 

37 contributors to non-LERF release categories LL-5 (large late containment basemat 

38 failure), SE-3 (small early containment penetration failure to isolate ), and SELL (small 

39 early RCS release with large late containment failure), down to RRW values of 1.005, 

40 1.003, and 1.003, respectively (NextEra 2012b). For release categories SE-3 and SELL, all 

41 of the basic events were already identified and evaluated in the 2012 SAMA supplement. 

42 For release category LL-5, 28 new basic events were identified, and a SAMA (either 

43 already existing or new) was correlated to each of these basic events. NextEra explained 

44 that differences in basic events and corresponding RRW values to those presented in the 

45 ER (NextEra 2010) and associated RAI responses (NextEra 2011a) were in general due to 

46 an accumulation of small changes including an updated HRA performed in 2009. In 
 Appendix F 

 F-27 

1 response to a separate RAI (NextEra 2012b), NextEra also provided a listing of all CDF 

2 and LERF initiating events contributing greater than 1 percent of the total CDF and 

3 0.3 percent of the total LERF. All of the LERF initiating events were already identified 

4 and evaluated in the 2012 SAMA supplement, while 11 new CDF initiating events and a 

5 SAMA (either already existing or new) was correlated to each of these initiating events. 

6 The newly identified SAMAs, and the results of their evaluation, are discussed further in 

7 Section F.6.2. 

8 NextEra states in the ER that no SAMAs were identified to address the operator actions in the 

9 Level 1 and LERF basic events importance lists because the current plant procedures and 

10 training meet current industry standards, and no plant-specific procedure improvements were 

11 identified that would affect the results of the HEP calculations. The NRC staff asked NextEra to 

12 consider the feasibility of non-procedural and training SAMAs for the human error basic events 

13 (NRC 2011a). In response to RAIs, NextEra identified and evaluated three operator actions 

14 included in the top 15 Level 1 basic events and to automate or install additional alarm indication 

15 for the operator action having the highest LERF-related RRW (NextEra 2011a). Subsequently 

16 in the 2012 SAMA supplement (NextEra 2012a), NextEra included an evaluation of SAMAs 

17 for 15 different operator failures covered by the importance analyses. 

18 The NRC staff estimated that a risk reduction of 3.3 1 percent, corresponding to the least 

19 bounding cut-off of the different importance analysis listings (i.e., CDF initiating event 

20 listing) produced by NextEra, equates to a maximum baseline benefit of approximately 

21 $30,000, or approximately $64,000 after the benefits have been multiplied by a factor of 2.1 to 

22 account for the additional risk from seismic events, which is less than the minimum 

23 implementation cost of $100,000 associated with a hardware change.

24 Based on this, and NextEra’s statement discussed previously that procedure and training 

25 improvements have been considered but that no improvements were identified that would 

26 reduce plant risk, the NRC staff concludes that it is unlikely that additional cost-beneficial 

27 SAMAs would be found from a further review of initiating events having lower contribution to 

28 CDF. 

29 In response to an NRC staff RAI, NextEra reviewed the cost-beneficial SAMAs from prior SAMA 

30 analyses for five Westinghouse four-loop PWR sites (NextEra 2011a). NextEra’s review 

31 determined that all but two of these cost-beneficial SAMAs were already represented by a 

32 SAMA, have intent that was already met at Seabrook, have low potential for risk reduction at 

33 Seabrook (e.g., do not address risk-important basic events), or were not applicable to Seabrook. 

34 Two SAMAs were identified and evaluated further as a result of this review and are further 

35 discussed in Section F.6.2. The two SAMAs are “procedure change to ensure that the reactor 

36 coolant system (RCS) cold leg water seals are not cleared” and “installation of redundant 

37 parallel service water valves to the emergency diesel generators (EDGs).” 

38 The NRC staff noted that both SAMA 173, identified from the IPEEE review, and SAMA 185 are 

39 described as “improve procedural guidance for directing depressurization of RCS,” and it asked 

40 NextEra to clarify the difference between these two SAMAs (NRC 2010a). In response to the 

41 RAI, NextEra clarified that SAMA 173 was to improve procedural guidance directing operators 

42 to depressurize the RCS before core damage, while SAMA 185 was to improve procedural 

43 guidance directing operators to depressurize the RCS after core damage. The NRC staff 

44 considers NextEra’s clarification reasonable and the screening of those Phase I SAMAs 

45 acceptable. 
Appendix F 

 F-28 

1 Although the IPE did not identify any fundamental vulnerabilities or weaknesses related to 

2 internal events, 14 potential plant improvements were identified. NextEra reviewed these 

3 potential improvements for consideration as plant-specific candidate SAMAs. In response to an 

4 NRC staff RAI, NextEra clarified that the following 13 SAMAs were identified from the review of 

5 the potential plant improvements identified in the IPE (NextEra 2011a): 

6  Phase II SAMA 167, “install independent seal injection pump (low volume pump) with 

7 automatic start,” 

8  Phase II SAMA 168, “install independent seal injection pump (low volume pump) with 

9 manual start,” 

10  Phase II SAMA 169, “install independent charging pump (low volume pump) with manual 

11 start,” 

12  Phase I SAMA 155, “install alternate emergency AC power source (e.g., swing diesel),” 

13  Phase II SAMA 156, “install alternate offsite power source that bypasses switchyard, for 

14 example, use campus power source to energize Bus E5 or E6,” 

15  Phase II SAMA 174, “provide alternate scram button to remove power from motor 

16 generator (MG) sets to control rod (CR) drives,” 

17  Phase II SAMA 157, “provide independent AC source for battery chargers, for example, 

18 provide portable generator to charge station battery,” 

19  Phase I SAMA 158, “provide enhanced procedural direction for cross-tie of batteries 

20 within each train,” 

21  Phase II SAMA 159, “install additional batteries,” 

22  Phase II SAMA 184, “control/reduce time that the containment purge valves are in open 

23 position,” 

24  Phase I SAMA 185, “improve procedural guidance to directing depressurization of RCS,” 

25  Phase II SAMA 186, “install containment leakage monitoring system,” and 

26  Phase II SAMA 187, “install RHR isolation valve leakage monitoring system.” 

27 In addition, the improvement identified in the IPE for “alternate, independent EFW pump 

28 (e.g., diesel firewater pump hard piped to discharge of startup feed pump),” is already 

29 addressed by Phase I SAMA 29, “provide capability for alternate injection via diesel-driven fire 

30 pump,” and Phase II SAMA 163, “install third EFW pump (steam-driven).” Phase I SAMA 29 

31 and Phase II SAMA 163 were previously identified from the review of the list of potential PWR 

32 enhancements in Table 14 of NEI 05-01 (NEI 2005). Phase I SAMAs 29, 155, 158, and 185 

33 were screened in the Phase I evaluation as having already been implemented. 

34 Based on this information, the NRC staff concludes that the set of SAMAs evaluated in the ER

35 and 2012 SAMA supplement (NextEra 2012a), together with those identified in response to 

36 NRC staff RAIs, addresses the major contributors to internal event CDF. 

37 As described previously, NextEra’s importance analysis considered both fire and seismic basic 

38 events from the internal and external event integrated Level 1 and Level 2 PRA model. The 

39 NRC staff noted that since the importance analyses did not separately consider the importance 

40 of internal, fire, and seismic events, SAMAs identified to address the important basic events 

41 may not address the more important initiator (e.g., fire), and it asked NextEra to explain how the 
 Appendix F 

 F-29 

1 identified SAMAs address this issue (NRC 2010a). In response to the RAI, NextEra explained 

2 that the importance analysis considers the contribution from all hazards, and the contribution 

3 from the individual hazards will be a subset of the total risk contribution (NextEra 2011a). 

4 Additionally, based on evaluations provided in response to the NRC staff RAIs discussed above, 

5 in which SAMAs were identified to address each of the important Level 1 and 2 basic events, 

6 hardware changes to address the individual hazard contributors would not, in NextEra’s 

7 judgement, be cost beneficial based on a conservative minimum cost for a hardware change of 

8 $100,000 (NextEra 2011a). Based on the NRC staff conclusions above regarding NextEra’s 

9 systematic process for identifying SAMAs for each important Level 1 and 2 basic event and 

10 NextEra’s statement that procedure/training improvements have been considered but that no 

11 improvements were identified that would reduce plant risk, the NRC staff agrees that it is 

12 unlikely that additional cost-beneficial SAMAs would be found from a further review of basic 

13 events. 

14 Although the IPEEE did not identify any fundamental vulnerabilities or weaknesses related to 

15 external events, two potential plant improvements were identified to improve seismic CDF, and 

16 five potential plant improvements were identified to improve fire CDF. Additionally, five potential 

17 plant improvements were identified that were being evaluated to improve internal event risk but 

18 which may also reduce external event risk because they address functional failures. In 

19 response to an NRC staff RAI, NextEra clarified that the following 12 SAMAs were identified 

20 from the review of the potential plant improvements identified in the IPEEE (NextEra 2011a): 

21  SAMAs to improve seismic CDF: 

22 – Phase II SAMA 181, “improve relay chatter fragility,” and 

23 – Phase II SAMA 182, “improve seismic capacity of EDGs and steam-driven EFW 

24 pump.” 

25  SAMAs to improve fire CDF: 

26 – Phase II SAMA 175, “install fire detection in turbine building relay room,” 

27 – Phase I SAMA 176, “install additional suppression at west wall of turbine 

28 building,” 

29 – Phase I SAMA 177, “improve fire response procedure to indicate that PCCW can 

30 be impacted by PAB fire event,” 

31 – Phase I SAMA 178, “improve the response procedure to indicate important fire 

32 areas including control room, PCCW pump area, and cable spreading room,” and 

33 – Phase I SAMA 180, “modify SW pump house roof to allow scuppers to function 

34 properly.” 

35  Other SAMAs identified from the IPEEE review: 

36 – Phase I SAMA 160, “enhancements to address loss of SF6-type sequences,” 

37 – Phase I SAMA 171, “install high temperature O-rings in RCPs,” 

38 – Phase I SAMA 173, “improve procedural guidance for directing depressurization 

39 of RCS,” 

40 – Phase II SAMA 179, “fire-induced LOCA response procedure from Alternate 

41 Shutdown Panel,” and 

42 – Phase I SAMA 183, “Turbine Building internal flooding improvements.” 
Appendix F 

 F-30 

1 Phase I SAMAs 160, 171, 173, 176, 177, 178, 180, and 183 were screened in the Phase I 

2 evaluation as having already been implemented. 

3 The NRC staff questioned whether SAMA 162, “increase the capacity margin of the CST” 

4 addressed basic event COTK25.RT, “CST CO-TK-25 ruptures/excessive leakage” 

5 (NRC 2010a). In response to the RAI, NextEra explained that the CST has a median seismic 

6 fragility of 1.65 g and a HCLPF of 0.65, without crediting the concrete shield structure 

7 surrounding the CST (NextEra 2011a). Therefore, NextEra identified and evaluated a SAMA to 

8 make “seismic upgrades to the CST.” This is discussed further in Section F.6.2. 

9 The NRC staff asked NextEra to clarify how additional fire barriers for fire areas were 

10 considered since SAMA 143, “upgrade fire compartment barriers,” was screened in the Phase I 

11 evaluation based on the Seabrook plant design including 3-hour rated fire barriers 

12 (NRC 2010a). NextEra responded with a review of the fire risk by plant location and explained 

13 that it is not physically possible to install additional fire barriers in the control room, which 

14 contribute 52 percent of the fire CDF. Additionally, NextEra stated that additional fire barriers in 

15 the essential SWGR rooms, which contribute 41 percent of the fire CDF, would have no impact 

16 on the fire risk since these rooms are already separated (NextEra 2011a). Other lower risk fire 

17 areas were also similarly evaluated with similar conclusions. In a response to a followup NRC 

18 staff RAI, NextEra further clarified that additional fire barriers were not considered for the 

19 essential SWGR rooms because a review of fire scenarios in these rooms did not identify 

20 impacts to any redundant safety train cables (NextEra 2011b). The NRC staff concludes that 

21 the applicant’s rationale for eliminating fire barrier enhancements from further consideration is 

22 reasonable. 

23 Based on the licensee’s IPEEE, the review of the results of the Seabrook PRA, which includes 

24 seismic and fire events, and the expected cost associated with further risk analysis and potential 

25 plant modifications, the NRC staff concludes that the opportunity for seismic and fire-related 

26 SAMAs has been adequately explored, and it is unlikely that there are any additional 

27 cost-beneficial seismic or fire-related SAMA candidates. 

28 As stated earlier, other external hazards (i.e., high winds, external floods, transportation and 

29 nearby facility accidents, and chemical releases) are below the IPEEE threshold screening 

30 frequency, or met the 1975 SRP design criteria, and are not expected to represent opportunities 

31 for cost-beneficial SAMA candidates. Nevertheless, NextEra reviewed the IPEEE results and 

32 identified no additional Phase I SAMAs to reduce HFO risk (NextEra 2010). 

33 For many of the Phase II SAMAs listed in the ER, the information provided did not sufficiently 

34 describe the proposed modification. Therefore, the NRC staff asked the applicant to provide 

35 more detailed descriptions of the modifications for several of the Phase II SAMA candidates 

36 (NRC 2010a). In response to the RAI, NextEra provided the requested information on the 

37 modifications for SAMAs 44, 59, 94, 112, 114, 163, 186, and 187 (NextEra 2011a). 

38 The NRC staff questioned NextEra about lower cost alternatives to some of the SAMAs 

39 evaluated (NRC 2010a) to include using a portable generator to extend the coping time in loss 

40 of AC power events (to power selected instrumentation and DC power to the turbine-driven 

41 auxiliary feedwater (TDAFW) pump provide alternate DC feeds (using a portable generator) to 

42 panels supplied only by DC bus and purchasing or manufacturing a “gagging device” that could 

43 be used to close a stuck-open SG safety valve for a SGTR event prior to core damage. 

44 In response to the RAIs, NextEra clarified that the first alternative to use a portable 

45 generator was already represented by SAMA 157, “provide independent AC power 
 Appendix F 

 F-31 

1 source for battery chargers; for example, provide portable generator to charge station 

2 battery” (NextEra 2011a). The second alternative was addressed in the 2012 SAMA 

3 supplement (NextEra 2012a) as SAMA 194, “purchase or manufacture of a “gagging 

4 device” that could be used to close a stuck-open steam generator safety valve.” Both of 

5 these SAMAs were assessed in the Phase II cost-benefit evaluation. The NRC staff 

6 concludes that these alternatives have been adequately addressed. 

7 The NRC staff requested NextEra to clarify the Phase I screening criteria, which was described 

8 in the ER as including two criteria that appear to not have been used—(1) excessive 

9 implementation cost, and (2) very low benefit (NRC 2010a). NextEra responded that these 

10 criteria, while they could have been used in the Phase I evaluation, were not used in the Phase I 

11 screening evaluation in order to force evaluation of more SAMA candidates into the Phase II 

12 evaluation so that the merit of each could be judged based on associated costs and benefits 

13 (NextEra 2011a). 

14 The NRC staff asked NextEra to provide justification for the screening of SAMA 29, “provide 

15 capability for alternate injection via diesel-driven fire pump,” in the Phase I evaluation on the 

16 basis that it has already been implemented through an existing alternate mitigation strategy 

17 (NRC 2010a). In response to the RAI, NextEra responded that Seabrook has the capability to 

18 use its diesel-driven fire pump to provide injection to the SGs through implementation of existing 

19 SAMGs (NextEra 2011a). NextEra also stated that two portable diesel-driven pumps are also 

20 available to provide injection using suction from the fire protection system, the cooling tower 

21 basin, and the Browns River. Based on this clarification, the NRC staff considers NextEra’s 

22 basis for screening SAMA 29 reasonable. 

23 The NRC staff noted that SAMA 64, “implement procedure and hardware modification for a 

24 CCW header cross-tie,” was screened in the Phase I evaluation because a cross-tie already 

25 exists to support a maintenance activity. The staff asked NextEra to clarify if the cross-tie 

26 between divisions A and B of the PCCW system is already provided for in existing plant 

27 procedures (NRC 2010a). In response to the RAI, NextEra clarified that the Seabrook operating 

28 procedures do provide explicit instructions for alignment of the PCCW division A and B 

29 cross-tie. Additionally, while the cross-tie is primarily used during maintenance activities, it 

30 could be used during an off-normal event involving a failure of heat sink in one division with 

31 failure of frontline components in the opposite division, provided that adequate time is available 

32 (NextEra 2011a). Based on this clarification, the NRC staff considers NextEra’s basis for 

33 screening SAMA 64 reasonable.

34 The NRC staff questioned why SAMA 79, “install bigger pilot operated relief valve so only one is 

35 required,” was screened in the Phase I evaluation based on the intent of the SAMA having 

36 already been implemented when the success criterion is two of two PORVs needed for 

37 intermediate head SI (NRC 2010a). NextEra responded that the context of SAMA 79 was to 

38 increase the capacity of the pressurizer PORVs such that opening of only one PORV would 

39 satisfy the feed and bleed success criteria for all loss of feedwater-type sequences, which is all 

40 that is needed at Seabrook if feed and bleed is provided by one of two high head charging 

41 pumps (NextEra 2010). However, since opening of two PORVs is needed if feed is provided by 

42 one of two SI pumps, NextEra provided a Phase II evaluation of this SAMA, the results of which 

43 are further discussed in Section F.6.2. 

44 The NRC staff asked NextEra to provide justification for the screening of SAMA 82, “stage 

45 backup fans in switchgear rooms,” and SAMA 84, “switch for emergency feedwater room fan 

46 power supply to station batteries,” in the Phase I evaluation on the basis that they are not 
Appendix F 

 F-32 

1 applicable to Seabrook (NRC 2010a). In response to the RAI, NextEra explained that the 

2 context of SAMA 82 was to enhance the availability and reliability of ventilation to the essential 

3 SWGR rooms in the event of a loss of SWGR room ventilation. Additionally, this SAMA is more 

4 accurately screened as its intent having been already implemented at Seabrook since 

5 procedures already exist for maintaining acceptable SWGR room temperatures when ventilation 

6 becomes unavailable, which includes opening doors and setting up portable fans 

7 (NextEra 2011a). The NRC staff considers NextEra’s basis for screening SAMA 82 

8 reasonable. 

9 Regarding SAMA 84, NextEra explained that the context of this SAMA was to enhance the 

10 availability and reliability of ventilation to the EFW pump house, in the event of a loss of pump 

11 house ventilation, by switching the pump house ventilation fan(s) power supply to station 

12 batteries. NextEra further stated that the initial screening of “not applicable” is incorrect 

13 (NextEra 2011a). NextEra explained that since procedures already exist for maintaining 

14 acceptable EFW pump house room temperatures when ventilation becomes unavailable, failure 

15 of the already reliable ventilation system is not a significant contributor to CDF. Nevertheless, 

16 NextEra provided a Phase II evaluation of this SAMA, the results of which are further discussed 

17 in Section F.6.2. 

18 The NRC staff noted that SAMA 92, “use a fire water system as a backup source for the 

19 containment spray system,” was screened in the Phase I evaluation because the containment 

20 spray function is not important early, yet basic events RCPCV456A.FC and RCPCV456B.FC, 

21 “spray valves fail to open on demand,” appear on the LERF importance list (NRC 2010a). In 

22 response to the RAI, NextEra explained that these two basic events refer to modeling of the 

23 PORVs and not the containment spray valves, that descriptions of these two events in the ER 

24 inadvertently referred to the PORVs as PORV spray valves, that the PORV function is unrelated 

25 to the containment spray function, and that, therefore, no SAMA is necessary. The NRC staff 

26 considers NextEra’s basis for screening SAMA 92 reasonable. 

27 The NRC staff also asked NextEra to provide justification for the screening of SAMA 105, “delay 

28 containment spray actuation after a large LOCA,” and SAMA 191, “remove the 135 °F 

29 temperature trip of the PCCW pumps,” in the Phase I evaluation on the basis that they would 

30 violate the CLB for Seabrook (NRC 2010a). In response to the RAI, NextEra provided a 

31 Phase II evaluation of these SAMAs, the results of which are further discussed in Section F.6.2 

32 (NextEra 2011a). 

33 The NRC staff requested that NextEra clarify the basis for screening SAMA 127, “revise 

34 emergency operating procedures (EOPs) to direct isolation of a faulted steam generator,” in the 

35 Phase I evaluation on the basis that it is already implemented (NRC 2010a). NextEra 

36 responded that the context of SAMA 127 was to have specific EOPs for isolation of the SG for 

37 the purpose of reducing the consequences of a SGTR, and existing EOPs direct specific 

38 operator actions to diagnose a SGTR and to perform its isolation. Additionally, existing plant 

39 EOPs also specifically provide actions for the identification and isolation of a faulted SG 

40 (NextEra 2011a). The NRC staff considers NextEra’s basis for screening SAMA 127

41 reasonable. 

42 The NRC staff asked NextEra to clarify the screening of SAMA 188, “containment flooding—

43 modify the containment integrated leak rate test (ILRT) 10-in. test flange to include a 5-in. 

44 adapter with isolation valve” based on the statement that “flange and procedures exist” 

45 (NRC 2010a). NextEra responded that the 10-in. flange with fire hose adapter has been 

46 pre-fabricated, is stored in a designated and controlled area, and is available for attaching to the 
 Appendix F 

 F-33 

1 10-in. ILRT flange to provide containment flooding via Severe Accident Guideline instructions 

2 (NextEra 2011a). NextEra further explained that pre-installation of the flange adapter will 

3 provide no significant time savings in light of the containment flooding scenario evolution via the 

4 fire hose connection which takes several days. The NRC staff considers NextEra’s basis for 

5 screening SAMA 188 reasonable. 

6 The NRC staff notes that the set of SAMAs submitted is not all-inclusive since additional, 

7 possibly even less expensive, design alternatives can always be postulated. However, the NRC 

8 staff concludes that the benefits of any additional modifications are unlikely to exceed the 

9 benefits of the modifications evaluated and that the alternative improvements would be unlikely 

10 to cost less than the least expensive alternatives evaluated, when the subsidiary costs 

11 associated with maintenance, procedures, and training are considered. 

12 The NRC staff concludes that NextEra used a systematic and comprehensive process for 

13 identifying potential plant improvements for Seabrook, and the set of SAMAs evaluated in the 

14 ER and 2012 SAMA supplement (NextEra 2012a), together with those evaluated in response 

15 to NRC staff inquiries, is reasonably comprehensive and, therefore, acceptable. This search 

16 included reviewing insights from the plant-specific risk studies and reviewing plant 

17 improvements considered in previous SAMA analyses. 

18 F.4 Risk Reduction Potential of Plant Improvements 

19 NextEra evaluated the risk-reduction potential of the 78 SAMAs retained for the Phase II 

20 evaluation in the ER and the 2012 SAMA supplement (NextEra 2012a). NextEra also 

21 evaluated the risk-reduction potential of the additional SAMAs discussed in Section F.3 

22 that were identified in the 2012 SAMA supplement (NextEra 2012a) and in response to 

23 NRC staff RAIs (NextEra 2012b). The majority of the SAMA evaluations were performed in a 

24 bounding fashion in that the SAMA was assumed to eliminate the risk associated with the 

25 proposed enhancement. On balance, such calculations overestimate the benefit and are 

26 conservative. 

27 NextEra used model re-quantification to determine the potential benefits. The CDF, population 

28 dose, and offsite economic cost reductions were estimated using the SSPSS-2011 PRA model 

with a truncation level of 110-14 29 per year. The changes made to the model to quantify the 

30 impact of SAMAs are detailed in Tables 1 and 2 of the 2012 SAMA supplement 

31 (NextEra 2012a) and in Tables 3-2, 3-3 and 4-1 of the response to NRC staff RAIs on the 

32 2012 SAMA supplement (NextEra 2012b). Tables F-6 and F-7 list the assumptions 

33 considered to estimate the risk reduction for each of the evaluated SAMA analysis cases, the 

34 estimated risk reduction in terms of percent reduction in CDF and population dose, the 

35 estimated total benefit (present value) of the averted risk, and the Phase II SAMAs evaluated for 

36 each analysis case. The estimated benefits reported in Tables F-6 and F-7 reflect the combined 

37 benefit in both internal and external events. The Phase II SAMAs included in Table F-4 are the 

38 78 Phase II SAMAs identified from industry sources, plant experts, or the IPE or IPEEE. 

39 The Phase II SAMAs included in Table F-5 are from plant-specific importance analyses. 

40 The determination of the benefits for the various SAMAs is further discussed in Section F.6. 

41 The NRC staff questioned the assumptions used in evaluating the benefits or risk reduction 

42 estimates of certain SAMAs (NRC 2012a). For example, Table 1 of the 2012 SAMA 

43 supplement (NextEra 2012a) presents SAMA case CONTX1, which eliminates AC, DC, and 

44 PCCW support for one division of CBS. The NRC staff asked how eliminating these 

45 support system failures bounds the hardware improvement SAMAs represented by this 
Appendix F 

 F-34 

1 case (i.e., SAMA 91-Install Passive Containment Spray System, SAMA 94-Install Filtered 

2 Containment Vent System, SAMA 99-Strengthen Containment, SAMA 102-Construct 

3 Containment Ventilation System, and SAMA 107-Install Redundant Containment Spray 

4 System). In response to the RAI (NextEra 2012b), NextEra provided a revised evaluation 

5 of these SAMAs using more differentiated SAMA analysis cases (i.e., CBSP, FVENT, 

6 CONST, and CBSR). Descriptions of these SAMA analysis cases and revised results for 

7 the corresponding SAMAs are provided in Table F-6. The NRC staff also asked NextEra 

8 to explain the basis for using SAMA analysis case NOATWS to evaluate the risk 

9 reduction of potential modifications addressing initiating events (IE) #23, #24, #25, #26, 

10 #27, and #28. Initiating events #23 through IE #27 are seismic initiators of different 

11 seismic acceleration levels (0.7 g, 1.0 g, 1.4 g, 1.8 g, and 2.5 g) which lead to ATWS while 

12 IE #28 is loss of main feedwater (MFW) that also leads to ATWS. In response to the RAI, 

13 NextEra clarified (NextEra 2012b) that SAMA analysis case NOATWS assumes all ATWS 

14 initiating events (both seismic and non-seismic initiators) are eliminated; therefore, it is a 

15 conservative evaluation for all of these initiating events. NextEra further clarified that the 

16 description of IE #28 is incorrect and should be ATWS with loss of MFW initially 

17 available, which provides further support for the assessment that the use of the SAMA 

18 analysis case NOATWS for this initiating event is conservative. The NRC staff considers 

19 NextEra’s explanations reasonable. 

20 The NRC staff has reviewed NextEra’s bases for calculating the risk reduction for the various 

21 plant improvements and concludes that the rationale and assumptions for estimating risk 

22 reduction are reasonable and generally conservative (i.e., the estimated risk reduction is higher 

23 than what would actually be realized). Accordingly, the NRC staff based its estimates of averted 

24 risk for the various SAMAs on NextEra’s risk reduction estimates. 

Table F-46. SAMA cost and benefit screening analysis for Seabrook(a) 25 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

NOSBO1 

2—Replace lead-acid 

batteries with fuel cells 

Eliminate failure of 

the EDGs 

22 27 6 12 220K

(470K) 160K

(330K2

525K 

(1.1M) 300K

(620K

>1.75M(w)

>1M

14(m)—Install a gas 

turbine generator 

 >2M(w)

1M

16(m)—Improve 

uninterruptable power 

supplies 

 >2M(w)

1M

20—Add a new backup 

source of diesel cooling 

 >2M(w)

1M
 Appendix F 

 F-35 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

161—Modify EDG jacket 

heat exchanger SW 

supply & return to allow 

timely alignment of 

alternate cooling water 

source (supply & drain) 

from firewater, reactor 

makeup water, 

dewatering, etc. 

 >2M(w)

1M

190—Add 

synchronization on 

capability to SEPS diesel 

 >1M6.4M(w)

NOLOSP 

13—Install an additional 

buried offsite power 

source 

Eliminate LOOP 

events 

18 42 1736 530K

(1.2M) 340K

(700K

1.2M 

(2.7M)640K

(1.3M)

>3(w) 2.4M(l

24—Bury offsite 

powerlines 

 >3M(l)

156—Install alternate 

offsite power source that 

bypasses the switchyard; 

for example, use campus 

power source to energize 

Bus E5 or E6 

 >7M(l)

BREAKER 

21—Develop procedures 

to repair or replace failed 

4 kV breakers 

Eliminate failure of 

the 4 KV bus 

infeed breakers 

1 <1 8K 

(17K) 

15K 

(32K) 

Screened(n)

CSBX LOCA02

25—Install an 

independent active or 

passive HPI system 

Eliminate failure of 

the HPI system 

2268 3452 1.1M

(2.3M) 470K

(980K

2.5M 

(5.3M) 890K

(1.9M

8.8M(w)

>5M(l

26—Provide an 

additional HPI pump with 

independent diesel 

 8.8M(lw)

>5M(l

39—Replace two of the 

four electric SI pumps 

with diesel-powered 

pumps

>5M(l)

LOCA03 

28—Add a diverse 

low-pressure injection 

system 

Eliminate failure of 

the low- pressure 

injection system 

2 11 2 29 68K

(140K) 160K

(340K

160K 

(340K) 300K

(640K

>1M 
Appendix F 

 F-36 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

LOCA04 

35—Throttle lowpressure injection pumps 

either in medium or 

large-break LOCAs to 

maintain RWST inventory 

Eliminate RWST 

running out of 

water 

13 28 10 12 310K

(655K) 160K

(330K

730K 

(1.5M) 300K

(630K)

>3M(w)

>1M(l

106—Install automatic 

containment spray pump 

header throttle valves 

 >3M(w)

1M(l

DSIPP 

39—Replace two of the 

four electric SI pumps 

with diesel-powered 

pumps 

Eliminate 

dependency of 

the existing 

intermediate head 

SI pump trains on 

AC power 

<1 0 <1K

(<1K) 

<1K

(<1K) 

>5M(l)

LOCA01 

41—Create a reactor 

coolant depressurization 

system 

Eliminate all small 

LOCA events 

2 7 1 2 27K

(57K) 33K

(70K

64K

63K (130K) 

>1M 

SW01 

43—Add redundant DC 

control power for SW 

pumps 

Eliminate the 

dependency of the 

SW pumps on DC 

power 

<2 1 0 1 11K

(24K) 10K

(21K

26K 

(55K) 19K

(40K

>100K 

CCW01 

44—Replace ECCS 

pump motors with aircooled motors 

Eliminate failure of 

the component 

cooling water 

(CCW) pumps 

14 25 31 23 920K

(1.9M) 180K

(380K

2.15M 

(4.6M) 350K

(730K

>6M(w)4M(l

PCCABCD 

59—Install a digital feed 

water upgrade 

Eliminates CCW 

pump failure 

when AC & DC 

power support is 

available

4 11 335K

(700K)

785K 

(1.7M)

>6.1M(lw)

CSBX

55—Install an 

independent RCP seal 

injection system with 

dedicated diesel 

Eliminate failures 

of support 

systems (e.g., AC 

& DC power, 

cooling) for 

division B of 

high- pressure 

injection

28 11 34 12 1.0M

(2.2M) 92K

(170K

2.45M 

(5.2M) 180K

(370K

>6.4M(w)

>1M

56(b)—Install an 

independent RCP seal 

injection system without 

dedicated diesel 

 >6.4M(w)

3M
 Appendix F 

 F-37 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

167—Install independent 

seal injection pump (low 

volume pump) with 

automatic start 

 >6.4M(w)

1M

168—Install independent 

seal injection pump (low 

volume pump) with 

manual start 

 >6.4M(w)

1M

169—Install independent 

charging pump (high 

volume pump) with 

manual start 

 >6.4M(w)

500K

170—Replace the 

positive displacement 

pump (PDP) with a 3rd 

centrifugal pump; 

consider low volume & 

cooling water 

independence 

 >6.4M(w)

500K

MAB(r)

65—Install digital feed 

water upgrade 

Eliminate all plant 

risk 

100 100 3.05M

(6.4M) 

7.15M 

(15M) >30M 

77—Provide a passive, 

secondary-side heatrejection loop 

consisting of a 

condenser & heat sink

 >15M(w)

1M

PORV FW01

79(d)—Install bigger pilot 

operated relief valve so 

only one is required 

Eliminate all PORV 

failures 

<1 12 0 7 1.7K

(4K) 73K

(150K

4.1K 

(9K) 140K

(290K

>2.7M(w)

1M(l

HVAC2 

80—Provide a redundant 

train or means of 

ventilation 

Eliminate the 

dependency of the 

CS, SI, RHR, & 

CBS pumps on 

HVAC 

3 8 5 1 150K

(320K) 32K

(67K

360K 

(750K) 61K

(130K

>1M(w)

500K

OEFWVS 

84(e)—Switch for EFW 

room fan power supply to 

station batteries 

Eliminate loss of 

EFW ventilation 

<1 0 <1 <1K 

(<1K2K) 

<2K

(<4K)<1K

(<2K)

>250K 
Appendix F 

 F-38 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

CBSP CONT01

91(b)(g)—Install a passive 

containment spray 

system 

Eliminate CBS 

power, signal, 

and& cooling 

support system 

failures, and& 

common cause 

failure among 

similar 

components for 

one division of 

CBS 

0 58 36 1.7M

(3.5M) 160K

(340K

4.0M 

(8.3M) 310K

(650K

>10M(w)

>3–6M

102(b)(g)(v)—Construct a 

building to be 

connected to primary & 

secondary containment 

& maintained at a 

vacuum

 >56.7M 3M

FVENT 

94(g)—Install a filtered 

containment vent to 

remove decay heat; 

Option 1: Gravel Bed 

Filter; Option 2: Multiple 

Venturi Scrubber 

Eliminate release 

category LL3 

(containment 

vent) and& 

prevents 80 

percent of release 

category LL5 

(basemat meltthrough)

0 69 2.0M

(4.1M)

4.6M 

(9.7M)

>20M(w)

5M(l

CONST 

99(b)—)(g)—Strengthen 

primary & secondary 

containment (e.g., add 

ribbing to containment 

shell) 

Reduce by a 

factor of 10 the 

non-recovery of 

off-site power 

before late 

containment 

pressure failure 

occurs

0 4 120K

(245K)

270K 

(570K)

11.5M(w)

>10M

CBSR 

107(b)(g)—Install a 

redundant containment 

spray system

Add redundant 

train of CBS

0 1 29K

(62K)

69K 

(140K)

>10M(w)

XOVNTS 

93(b)—Install a 

redundantan unfiltered 

hardened containment 

vent

Eliminate failure 

of the human 

action to vent 

containment(u)

0 1 39K

(82K)

92K 

(190K)

>3M 3–4M

H2Burn 

96—Provide postaccident containment 

inerting capability 

Eliminate all 

hydrogen ignition &

burns 

0 1 0(g) 18K

(39K) <1K

(<1K

43K 

(90K) <1K

(<1K >100K 
 Appendix F 

 F-39 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

108—Install an 

independent power 

supply to the hydrogen 

control system using 

either new batteries, a 

nonsafety grade portable 

generator, existing 

station batteries, or 

existing AC/DC 

independent power 

supplies, such as the 

security system diesel 

 >100K 

109—Install a passive 

hydrogen control system 

 >100K 

OLRP(t)

105(f)—Delay 

containment spray 

actuation after a large 

LOCA 

Eliminate the 

human failure to 

complete & ensure 

the RHR & 

low-head safety 

injection (LHSI) 

transfer to long-tterm recirculation 

during large LOCA 

events 

3 2 0 <1 12K

(25K) 7.2K

(15K

27K 

(58K) 14K

(29K

>100K 

HPME 

110—Erect a barrier 

that would provide 

enhanced protection of 

the containment walls 

(shell) from ejected 

core debris following a 

core melt scenario at 

high pressure 

Eliminate highpressure core 

ejection 

occurrences 

0 0 <1K

(<1K) 

1K 

(2K) 

>10M

CONT02(p)

112—Add redundant & 

diverse limit switches to 

each CIV 

Eliminate CIV 

failures

0 6 19 115K

(240K) 100K

(220K

270K 

(570K) 200K

(420K

>1M(w)

>500K

114—Install 

self-actuating CIVs 

 >2M(w)

500K

LOCA06(q)

113—Increase leak 

testing of valves in 

ISLOCA paths 

Eliminate ISLOCA 

contribution

<1 3 48K

(100K) 14K

(30K

110K 

(240K) 27K

(60K

>1M(w)

>100K

115—Locate RHR inside 

containment 

2 7 28K

(60K)

53K

(110K)

>1M 

187—Install RHR 

isolation valve leakage 

monitoring system 

 >500K(w)

190K
Appendix F 

 F-40 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

NOSGTR 

119—Institute a 

maintenance practice to 

perform a 100% 

inspection of SG tubes 

during each refueling 

outage 

Eliminate all SGTR 

events 

5 3 2 17 67K

(140K) 86K

(180K

160K 

(330K) 345K >500K 

121—Increase the 

pressure capacity of the 

secondary side so that a 

SGTR would not cause 

the relief valves to lift 

 >500K 

125—Route the 

discharge from the main 

steam safety valves 

(MSSVs) through a 

structure where a water 

spray would condense 

the steam & remove 

most of the fission 

products 

 >500K 

126—Install a highly 

reliable (closed loop) SG 

shell-side heat removal 

system that relies on 

natural circulation & 

stored water sources 

 >15M(w)

500K

129—Vent MSSVs in 

containment 

 >500K 

NOATWS 

130—Add an 

independent boron 

injection system 

Eliminate all ATWS 

events 

4 3 2 11 60K

(130K) 70K

(150K

140K 

(290K) >500K 

131—Add a system of 

relief valves to prevent 

equipment damage from 

pressure spikes during 

an ATWS 

 >500K 

133—Install an ATWS 

sized filtered containment 

vent to remove decay 

heat 

 >500K 

174—Provide alternate 

scram button to remove 

power from MG sets to 

CR drives 

 >500K 
 Appendix F 

 F-41 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

LOCA05 

147—Install digital large 

break LOCA protection 

system 

Eliminate all piping 

failure LOCAs 

9 10 2 12 77K

(160K) 100K

(220K

180K 

(380K) 200K

(410K

>500K 

NOSLB 

153—Install secondary 

side guard pipes up to 

the main steam isolation 

valves 

Eliminate all steam 

line break events 

<1 0 0 <1 5K

(11K) 3K

(7K

11K 

(24K) 6K

(13K

>500K 

OSEPALL 

154(k)—Modify SEPS 

design to accommodate 

automatic bus loading & 

automatic bus alignment 

Eliminate failure of 

all operator actions 

to align & load the 

SEPS DGs 

8 Not 

Provided

2 Not 

Provided

64K

(135K) 33K

(68K

150K 

(320K) 62K

(130K

>750K 

Case INDEPAC 

157—Provide 

independent AC power 

source for battery 

chargers; for example, 

provide portable 

generator to charge 

station battery 

Eliminate failure 

of operator action 

to shed DC loads 

to extend 

batteries to 12 

hours. Also, 

eliminate failure 

to recover offsite 

power for plantrelated, gridrelated, & 

weather-related 

LOOP events.(h)

<2 4 1 2 34K

(72K) 23K

(48K

80K 

(170K) 45K

(95K 30K 

159—Install additional 

batteries 

 >1M 

CST01 

162—Increase the 

capacity margin of the 

CST 

Eliminate CST 

running out of 

water 

<2 1 1 35K

(73K) 9K

(18K

81K 

(170K) 16K

(34K

>2.5M(w)

100K

164—Modify 10" 

condensate filter flange 

to have a 21⁄2" female 

fire hose adapter with 

isolation valve 

 >40K

TDAFW 

163—Install third EFW 

pump (steam-driven) 

Eliminate failure of 

the TDAFW train

 

5 19 12 9 360K

(750K) 100K

(210K

835K 

(1.8M) 190K

(400K

>2M(l)
Appendix F 

 F-42 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

NORMW 

165—RWST fill from 

firewater during 

containment injection—

modify 6" RWST flush 

flange to have a 21⁄2"

female fire hose 

adapter with isolation 

valve 

Guaranteed 

success of RWST 

makeup for longterm sequences 

where 

recirculation is 

not available 

5 10 2 8 57K

(120K) 75K

(160K

130K 

(280K) 

120K

(300K

50K

RCPL 

172—Evaluate 

installation of a 

“shutdown seal” in the 

RCPs being developed 

by Westinghouse 

Eliminate loss of 

RCP seal cooling 

initiating event & 

RCP seal failures 

subsequent to a 

plant transient 

34 49 1.5M

(3.2M) 

2.5M 

(7.4M) 

>2M(l)

FIRE2 

175—Improve fire 

detection in turbine 

building relay room 

This SAMA has been implemented (NextEra, 2011b). 

FIRE1A

179—Fire-induced LOCA 

response procedure from 

alternate shutdown panel 

Eliminate operator 

failure to close 

PORV block valve 

during a control 

room fire 

0 1 0 <1 <1K

(<1K) 4K

(8K

<1K

(<2K) 7K

(15K

>20K(l)

SEISMIC01 

181—Improve relay 

chatter fragility 

Eliminate all 

seismic relay 

chatter failures 

12 9 3 12 87K

(180K) 100K

(210K

204K 

(470K) 200K

(410K

>600K(l)

SEISMIC02 

182—Improve seismic 

capacity of EDGs &

steam-driven EFW pump 

Eliminate all 

seismic failures of 

EDGs or turbinedriven emergency 

feedwater 

(TDEFW) 

<1 0 0 2.4K

(6K) <1K

(<1K

5.6K 

(12K) <1K

(<1K

>500K 

COP

184—Control & reduce 

time that the containment 

purge valves are in open 

position 

Eliminate 

possibility of 

containment purge 

valves being open 

at the time of an 

event 

0 ≈0 <1K 

(<1K) 

<1K 

(<2K) 

>20K 

CISPRE 

186(o)—Install 

containment leakage 

monitoring system 

Eliminate all CDF 

contribution from 

pre-existing 

containment 

leakage 

0 Not 

Provided

0 Not 

Provided

4.4K

(12K) 11K

(23K

10K 

(27K) 20K

(43K

>500K 
 Appendix F 

 F-43 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

SEPS

189—Modify or analyze 

SEPS capability; one of 

two SEPS for LOOP nonSI loads, two of two for 

LOOP SI loads 

Modify fault tree so 

that one of two 

SEPS DGs are 

required rather 

than both SEPS 

DGs being required

6 7 2 1 63K

(130K) 30K

(60K

150K 

(310K) 60K

(120K

>2M(w)

300K

PCTES 

191(f)—Remove the 

135 °F temperature trip 

of the PCCW pumps 

Eliminate 

inadvertent failure 

of the redundant 

TE/logic of the 

associated PCC 

division for both 

loss of PCCW 

initiating events & 

loss of PCCW 

mitigative function 

<1 0 <1 <1K 

(<1K) 

<1K 

(<2K 1K) 

>100K 

NOCBFLD 

192(i)—Install a globe 

valve or flow limiting 

orifice upstream in the 

fire protection system 

Eliminate control 

building fire 

protection 

flooding initiators 

24 25 11 6 470K

(990K) 

160K

(340K

1.1M 

(2.3M) 310K

(640K

370K(w)

200K

CSV167

193(c)—Hardware 

change to eliminate 

MOV AC power 

dependency 

Eliminate 

operator failure to 

close CIV CS-V167 

locallyEliminate 

MOV AC power 

dependency by 

replacing the 

MOV with a failclosed AOV

0 5 35 86K

(180K) 

190K

(400K

200K 

(420K) 

365K

(770K

300K

MSSVRS 

194—Purchase or 

manufacture a 

“gagging device” that 

could be used to close 

a stuck-open SG safety 

valve 

Eliminate failure 

of MSSVs to 

reseat 

0 0 <1K

(<1K) 

<1K

(<2K) 

>30K

CCTE1 

195(s)—Make 

improvements to 

PCCW temperature 

control reliability 

Eliminate failure 

of temperature 

control & 

modulation for 

PCC Trains A & B 

that could fail 

PCCW 

3 5 140K

(300K) 

340K 

(710K) 

300K

(a) SAMAs in bold are potentially cost beneficial. This table summarizes the results of the revised SAMA analysis 

provided in the 2012 SAMA supplement (NextEra 2012a), which revised all results reported for “% Risk reduction” and 

“Total benefit ($),” and included changes to “Analysis case & applicable SAMAs,” “Modeling assumptions,” and “Cost 

($).” 
Appendix F 

 F-44 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(j)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

(b) This is retained as a quantitatively evaluated Phase II SAMA in response to NRC staff RAI 3.g (NextEra 2011a). 

(c) This is a new SAMA identified in response to NRC staff RAI 2.f (NextEra 2011a) and conference call clarification #7 

(NRC 2011a). 

(d) Evaluation of this SAMA is provided in response to NRC staff RAIs 5.g (NextEra 2011a) and conference call clarification #14 

(NRC 2011a), and it was subsequently updated in the 2012 SAMA supplement (NextEra 2012a). 

(e) Evaluation of this SAMA is provided in response to NRC staff RAI 5.j (NextEra 2011a) and was subsequently updated in the 

2012 SAMA supplement (NextEra 2012a). 

(f) Evaluation of these SAMAs is provided in response to NRC staff RAI 5.n (NextEra 2011a) and conference call clarification #15 

(NRC 2011a), and it was subsequently updated in the 2012 SAMA supplement (NextEra 2012a). 

(g) In response to an NRC staff RAI, NextEra subdivided previous SAMA analysis case, CONTX1, into separate SAMA 

analysis cases CBSP (SAMA s 91 and 102), FVENT (SAMA 94), CONST (SAMA 99), and CBSR (SAMA 107) given the 

potentially high benefits (NextEra 2012b). NextEra refers to these as sensitivity cases. 

(h) Information is provided for SAMA157 in response to NRC staff RAI 6.h (NextEra 2011a), and it subsequently updated in the 

2012 SAMA supplement (NextEra 2012a). 

(i) This is a new SAMA (#192) identified and evaluated in response to NRC staff RAI 1.a (NextEra 2011a) and conference call 

clarification #1 (NRC 2011a) and subsequently updated in the 2012 SAMA supplement (NextEra 2012a). 

(j) Values in parenthesis are the results of the sensitivity analysis applying a multiplier of 2.1 to account for the additional risk of 

seismic events (NextEra 2011b). 

(k) The analysis case for SAMA 154 changed from NOSBO to OSEPALL in response to followup NRC staff RAI 4 (NextEra 2011b). 

(l) Cost updated in supplement to response to followup NRC staff RAI 4 (NextEra 2011c). 

(m) The analysis case for SAMAs 14 and 16 changed from NOLOSP to NOSBO in response to followup NRC staff RAI 4 

(NextEra 2011b). 

(n) In response to followup NRC staff RAI 4, NextEra determined that detailed procedures already exist for inspection and repair of 

the Seabrook 4 kV breakers, and this SAMA was, therefore, screened from further consideration (NextEra 2011b). 

(o) The analysis case for SAMA 186 changed from CONT01 to CISPRE in response to followup NRC staff RAI 4 (NextEra 2011b). 

(p) NextEra notes (NextEra 2010) that although calculated as eliminating all CIV failures, the limit switches actually 

contribute no more than 50 percent to the containment isolation function; thus, the upper bound benefit is more 

accurately $566*0.5 = $283K (NextEra 2012a). 

(q) NextEra notes (NextEra 2010) that although calculated as eliminating all ISLOCAs pressure isolation valve testing could 

be assumed to reduce ISLOCA by half, thus the upper bound benefit is more accurately $240K * 0.5 = $120K 

(NextEra 2012a). 

(r) In response to NRC staff RAI 4, NextEra clarified that the analysis case for SAMAs designated MAB are evaluated using 

the MACR (NextEra 2012b). 

(s) In response to an NRC staff, NextEra clarified that SAMA analysis case CCTE1 addresses both the reliability of PCCW 

and loss of CCW as an initiator (NextEra 2012b). 

(t) Although the name of this SAMA analysis case was changed from “OLPRS” in the 2012 SAMA supplement to ”OLPR” 

in the ER, the modeling assumptions are unchanged (NextEra 2012a). 

(u) Description of analysis case provided in response to NRC staff RAI 2f (NextEra , 2011b).

(v) The analysis case CBSR was used to represent this SAMA because CBSP would prevent containment overpressure 

(NextEra 2012b). 

(w) Cost updated in 2012 SAMA supplement (NextEra 2012a).

1 F.5 Cost Impacts of Candidate Plant Improvements 

2 NextEra developed plant-specific costs of implementing the 78 Phase II candidate SAMAs 

3 evaluated in the ER and the 2012 SAMA supplement (NextEra 2012a). This SAMA group 

4 consisted of SAMAs identified from industry, by plant experts, by identifying important 
 Appendix F 

 F-45 

1 failures, and by plant improvements identified in the Seabrook IPE and IPEEE. NextEra 

2 also developed implementation cost for the additional SAMAs discussed in Section F.3 

3 that were identified in the 2012 SAMA supplement (NextEra 2012a) and in response to 

4 NRC staff RAIs (NextEra 2012b). An expert panel—composed of senior plant staff from the 

5 PRA group, the design group, operations, and license renewal—developed the cost estimates 

6 based on their experience with developing and implementing modifications at Seabrook. The 

7 NRC staff requested that NextEra describe the level of detail used to develop the cost estimates 

8 (NRC 2010a). In response to the RAI, NextEra explained that the cost estimates were based on 

9 the experience and judgment of the plant staff serving on the expert panel and that, in most 

10 cases, detailed cost estimates were not developed because of the large margin between the 

11 estimated SAMA benefits and the estimated implementation costs (NextEra 2011a). The cost 

12 estimates conservatively did not specifically account for inflation, contingencies, implementation 

13 obstacles, or replacement power costs (RPC). 

14 The NRC staff reviewed the bases for the applicant’s cost estimates provided in the ER 

15 (presented in Section F.7.2 and Table F.7-1 of Attachment F to the ER). For certain 

16 improvements, the NRC staff also compared the cost estimates to estimates developed 

17 elsewhere for similar improvements, including estimates developed as part of other applicants’ 

18 analyses of SAMAs for operating reactors and advanced light-water reactors. In response to an 

19 RAI requesting a more detailed description of the changes associated with Phase II SAMAs 44, 

20 59, 94, 112, 114, 163, 186, and 187, NextEra provided additional information detailing the 

21 analysis and plant modifications included in the cost estimate of each improvement 

22 (NextEra 2011a). The staff reviewed the costs and found them to be reasonable and generally 

23 consistent with estimates provided in support of other plants’ analyses. In many cases, the 

24 cost estimates and their descriptions were superseded by the estimates performed for 

25 the 2012 SAMA supplement (NextEra 2012b), and they were generally higher than the 

26 cost estimates provided in the ER and associated RAI responses. Based on its review of 

27 this supplement, the NRC staff requested more detailed justification of the cost estimates 

28 for Phase II SAMAs 162 and 189 (NRC 2012a). In response to the RAI, NextEra provided 

29 additional justification as to why the cost estimates increased for these SAMAs 

30 (NextEra 2012b). For SAMA 162, NextEra explained that the original cost estimate of 

31 greater than $100,000 was made to represent a non-complex hardware change because a 

32 detailed estimate was not needed due to the low benefit estimated for the SAMA, but that 

33 the higher benefit estimated in the 2012 SAMA supplement necessitated reassessing the 

34 implementation cost to reflect the expected scope of the modification. Similarly, for 

35 SAMA 189, NextEra explained that the original cost estimate of greater than $300,000 was 

36 a conservative minimum estimate made based on the assumption that the SAMA would 

37 primarily be an analytical task, while the higher benefit estimate in the 2012 SAMA 

38 supplement for this SAMA necessitated the development of a more detailed cost 

39 estimate of the expected scope of the modification, which includes engineering analysis, 

40 hardware modifications, and testing.

41 The NRC staff also asked NextEra to provide the basis for the implementation cost 

42 estimates for the plant modifications to address IE #23, #24, #25, #26, #27, and #28. 

43 Initiating events #23 through IE #27 are seismic initiators of different seismic 

44 acceleration levels (0.7 g, 1.0 g, 1.4 g, 1.8 g, and 2.5 g), which lead to ATWS while IE #28 

45 is loss of MFW that also leads to ATWS. In response to the RAI, NextEra clarified 

46 (NextEra 2012b) that modifications to reduce risk from IE #23 through IE #27 all include 

47 structural upgrades to the reactor internals to increase seismic capacity, which would be 

48 expected to significantly exceed the $500,000 cost estimate for this SAMA case. 

49 Additionally, NextEra clarified that IE #28 is dominated by failure of control rods to insert 
Appendix F 

 F-46 

1 and failure to initiate emergency boration of RCS and that a hardware modification to 

2 upgrade reactor internals and emergency boration system are expected to significantly 

3 exceed $500,000. The NRC staff considers NextEra’s clarification reasonable. 

4 The NRC staff noted that Phase I SAMA 65, “install a digital feed water upgrade,” has an 

5 estimated implementation cost of $30 million, which is much larger than the estimated 

6 implementation cost of more than $500,000 for Phase II SAMA 147, “install digital large break 

7 LOCA protection system.” The NRC staff asked NextEra to explain the reason for this 

8 difference between what appear to be similar modifications (NRC 2010a). NextEra responded 

9 that the estimated implementation cost of $30 million for Phase I SAMA 65 was based on a 

10 detailed assessment of the costs associated with the Seabrook long-range plan for a digital 

11 upgrade of the feedwater control system, while the estimated cost of more than $500,000 for 

12 SAMA 147 was based on the judgment of the expert panel (NextEra 2011a). NextEra also 

13 noted that since the conservatively estimated benefit for SAMA 147 was much less than the 

14 estimated implementation cost, developing a more detailed cost estimate for this SAMA was not 

15 necessary. The NRC staff considers NextEra’s clarification reasonable. 

16 The NRC staff also requested additional clarification on the estimated cost of $30,000 for 

17 implementation of Phase II SAMA 157, “provide independent AC power source for battery 

18 chargers,” which seems low for what is described as a hardware change (NRC 2010a). In 

19 response to the RAI, NextEra explained that the cost estimate is based on expert panel 

20 judgment and includes procurement of a small portable, nonsafety-related 480 V generator and 

21 associated connection cables, operation guideline development, and storage onsite in a 

22 convenient location for ease in moving into position/connected if ever needed during an 

23 extended SBO event (NextEra 2011a). The NRC staff considers NextEra’s clarification 

24 reasonable. 

25 As discussed in Section F.2.2, NextEra provided the results of a sensitivity analysis that applied 

26 a multiplier of 2.1 to account for the additional risk reduction from seismic events 

27 (NextEra 2011b, 2012a). In these analyses, NextEra revised the implementation costs for 

28 several SAMAs in which the estimated costs were determined to be overly conservative. The 

29 revised implementation costs are reflected in Tables F-6 and F-7. The staff reviewed the basis 

30 for each of the revised costs and found them to be reasonable and, generally, consistent with 

31 estimates provided in support of other plants’ analyses. 

32 The NRC staff concludes that the cost estimates provided by NextEra are sufficient and 

33 appropriate for use in the SAMA evaluation. 

34 F.6 Cost-Benefit Comparison 

35 NextEra’s cost-benefit analysis and the NRC staff’s review are described in the following 

36 sections. 

37 F.6.1 NextEra’s Evaluation 

38 The methodology used by NextEra was based primarily on NRC’s guidance for performing 

39 cost-benefit analysis (i.e., NUREG/BR-0184, Regulatory Analysis Technical Evaluation 

40 Handbook (NRC 1997a)). The guidance involves determining the net value for each SAMA 

41 according to the following formula: 

42 Net Value = (APE + AOC + AOE + AOSC) – COE where, 
 Appendix F 

 F-47 

1 APE = present value of averted public exposure ($) 

2 AOC = present value of averted offsite property damage costs ($) 

3 AOE = present value of averted occupational exposure costs ($) 

4 AOSC = present value of averted onsite costs ($) 

5 COE = cost of enhancement ($) 

6 If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 

7 benefit associated with the SAMA, and it is not considered cost beneficial. NextEra’s derivation 

8 of each of the associated costs is summarized below, which reflects updated values 

9 provided in the 2012 SAMA supplement (NextEra 2012a).

10 NUREG/BR-0058 has recently been revised to reflect the NRC’s policy on discount rates. 

11 Revision 4 of NUREG/BR-0058 states that two sets of estimates should be developed, one at 

12 3 percent and one at 7 percent (NRC 2004). NextEra provided a base set of results using the 

13 7 percent discount rate and a sensitivity study using the 3 percent discount rate 

14 (NextEra 2012a). 

15 Averted Public Exposure (APE) Costs 

16 The APE costs were calculated using the following formula: 

17 APE = Annual reduction in public exposure (Δperson-rem/year) 

18 x monetary equivalent of unit dose ($2,000 per person-rem) 

19 x present value conversion factor (10.76 based on a 20-year period with a 

20 7 percent discount rate) 

21 As stated in NUREG/BR-0184 (NRC 1997a), the monetary value of the public health risk after 

22 discounting does not represent the expected reduction in public health risk due to a single 

23 accident. Rather, it is the present value of a stream of potential losses extending over the 

24 remaining lifetime (in this case, the renewal period) of the facility. Thus, it reflects the expected 

25 annual loss due to a single accident, the possibility that such an accident could occur at any 

26 time over the renewal period, and the effect of discounting these potential future losses to 

27 present value. For the purposes of initial screening, which assumes elimination of all severe 

28 accidents caused by internal and external events, NextEra calculated an APE of approximately 

29 $815,100 230,400 for the 20-year license renewal period (NextEra 2012b). 

30 Averted Offsite Property Damage Costs (AOC) 

31 The AOCs were calculated using the following formula: 

32 AOC = Annual CDF reduction 

33 x offsite economic costs associated with a severe accident (on a per34 event basis) 

35 x present value conversion factor 

36 This term represents the sum of the frequency-weighted offsite economic costs for each release 

37 category, as obtained for the Level 3 risk analysis. For the purposes of initial screening, which 

38 assumes elimination of all severe accidents caused by internal events, NextEra calculated an 
Appendix F 

 F-48 

1 annual offsite economic cost of about $23,500 based on the Level 3 risk analysis 

2 (NextEra 2011a). This results in a 7 percent-discounted value of approximately $1,950,600

3 253,300 for the 20-year license renewal period (NextEra 2012b).

4 Averted Occupational Exposure (AOE) Costs 

5 The AOE costs were calculated using the following formula: 

6 AOE = Annual CDF reduction 

7 x occupational exposure per core damage event 

8 x monetary equivalent of unit dose 

9 x present value conversion factor 

10 NextEra derived the values for AOE from information provided in Section 5.7.3 of the Regulatory 

11 Analysis Technical Evaluation Handbook (NRC 1997a). Best estimate values provided for 

12 immediate occupational dose (3,300 person-rem) and long-term occupational dose 

13 (20,000 person-rem over a 10-year cleanup period) were used. The present value of these 

14 doses was calculated using the equations provided in the handbook in conjunction with a 

15 monetary equivalent of unit dose of $2,000 per person-rem, a real discount rate of 7 percent, 

16 and a time period of 20 years to represent the license renewal period. For the purposes of initial 

17 screening, which assumes elimination of all severe accidents caused by internal events, 

18 NextEra calculated an AOE of approximately $4,600 5,500 for the 20-year license renewal 

19 period (NextEra 2012b). 

20 Averted Onsite Costs (AOSC) 

21 AOSC include averted cleanup and decontamination costs (ACC) and averted power 

22 replacement costs. Repair and refurbishment costs are considered for recoverable accidents 

23 only and not for severe accidents. NextEra derived the values for AOSC based on information 

24 provided in Section 5.7.6 of NUREG/BR-0184, the Regulatory Analysis Technical Evaluation 

25 Handbook (NRC 1997a). 

26 NextEra divided this cost element into two parts—the onsite cleanup and decontamination cost, 

27 also commonly referred to as ACC, and the RPC. 

28 ACC were calculated using the following formula: 

29 ACC = Annual CDF reduction 

30 x present value of cleanup costs per core damage event 

31 x present value conversion factor 

32 The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 

NUREG/BR-0184 to be $1.5x109 33 (undiscounted). This value was converted to present costs 

34 over a 10-year cleanup period and integrated over the term of the proposed license extension. 

35 For the purposes of initial screening, which assumes elimination of all severe accidents caused 

36 by internal events, NextEra calculated an ACC of approximately $141,700 167,200 for the 

37 20-year license renewal period. 

38 Long-term RPC were calculated using the following formula: 
 Appendix F 

 F-49 

1 RPC = Annual CDF reduction 

2 x present value of replacement power for a single event 

3 x factor to account for remaining service years for which replacement 

4 power is required 

5 x reactor power scaling factor 

6 NextEra based its calculations on the rated Seabrook gross electric output of 1,290 MWe and 

7 scaled up from the 910 MWe reference plant in NUREG/BR-0184 (NRC 1997a). Therefore, 

8 NextEra applied a power scaling factor of 1,290/910 to determine the RPC. For the purposes of 

9 initial screening, which assumes elimination of all severe accidents caused by internal events, 

10 NextEra calculated an RPC of approximately $136,500 and an AOSC (AOSC = ACC + RPC) of 

11 approximately $278,200 and RPC of $162,300) for the 20-year license renewal period

12 (NextEra 2012b).

13 Using the above equations, NextEra estimated the total present dollar value equivalent 

14 associated with eliminating severe accidents from internal and external events at Seabrook to 

15 be about $3,048,500. Use of a multiplier of 2.1 to account for the additional risk from seismic 

16 events in the sensitivity analysis increases the value, as estimated by the NRC staff, to 

17 $6.4 million. This represents the dollar value associated with completely eliminating all 

18 internal and external event severe accident risk at Seabrook, and it is also referred to as 

19 the maximum averted cost risk (MACR). NextEra explained (NRC 2012b) that the value of 

20 $3,048,500, reported in a response to an RAI (NextEra 2012b), was slightly updated from 

21 the value of $3,051,800 reported in the 2012 SAMA supplement (NextEra 2012a). The 

22 value was updated because of refinements in the calculation that were made related to 

23 time used to declare a general emergency. The small reduction had negligible impact on 

24 the SAMA cost benefit analysis. The NRC staff agrees that this change would have 

25 negligible impact on the SAMA cost benefit analysis. 

26 NextEra’s Results 

27 If the implementation costs for a candidate SAMA exceeded the calculated benefit, the SAMA 

28 was considered not to be cost beneficial. In the baseline analysis contained in the 2012 SAMA 

29 supplement (NextEra 2012a), using a 7 percent discount rate, NextEra identified threeone

30 potentially cost-beneficial SAMAs (SAMAs 157, 165, and 192). Based on the consideration of 

31 analysis uncertainties, NextEra identified three additional potentially cost-beneficial SAMAs 

32 (SAMAs 164, 172, and 195). In addition, as a result of the sensitivity analysis using a 

33 multiplier of 2.1 to account for the additional risk from seismic events, NextEra identified 

34 one additional cost-beneficial SAMA (SAMA 193). The potentially cost-beneficial SAMAs for 

35 Seabrook are listed below: 

36  SAMA 157—provide independent AC power source for battery chargers, 

37  SAMA 164—modify condensate filter flange to incorporate a 2.5-in female hose 

38 adapter and isolation valve, 

39  SAMA 165—RWST fill from firewater during containment injection—modify 6-in. RWST 

40 flush flange to have a 21⁄2-in. female fire hose adapter with isolation valve, 

41  SAMA 172—evaluate installation of a RCP “shutdown seal” being developed by 

42 Westinghouse, 
Appendix F 

 F-50 

1  SAMA 192—install a globe valve or flow limiting orifice upstream in the fire protection 

2 system, 

3  SAMA 193—hardware change to eliminate MOV AC power dependency, and 

4  SAMA 195—make improvement to PCCW temperature control. 

5 The potentially cost-beneficial SAMAs, and NextEra’s plans for further evaluation of these 

6 SAMAs, are discussed in more detail in Section F.6.2. 

7 F.6.2 Review of NextEra’s Cost-Benefit Evaluation 

8 The cost-benefit analysis performed by NextEra was based primarily on NUREG/BR-0184 

9 (NRC 1997a) and discount rate guidelines in NUREG/BR-0058 (NRC 2004), and it was 

10 executed consistently with this guidance. Three SAMAs were determined to be cost beneficial 

11 in NextEra’s baseline analysis in the 2012 SAMA supplement (SAMAs 157, 165, and 192, as 

12 described above). NextEra stated that these SAMAs would be entered into the Seabrook long13 range plan development process for further implementation consideration (NextEra 2012a). 

14 NextEra considered the impact that possible increases in benefits from analysis uncertainties 

15 would have on the results of the SAMA assessment. In the 2012 SAMA supplement 

16 (NextEra 2012a), NextEra presents an uncertainty multiplier of 2.35 based on the ratio of the 

CDF mean value of 1.23x10-5 per year to the 95th percentile value of 2.86x10-5 17 per year. 

18 Since none of the Phase I SAMAs were screened based on excessive cost or very low benefit, 

19 a reexamination of the Phase I SAMAs based on the 95th percent upper bound benefits was 

20 not necessary. NextEra examined the Phase II SAMAs to determine if any would be potentially 

21 cost beneficial if the baseline benefits were increased by a factor of 2.35. As a result, three 

22 SAMAs became cost beneficial (SAMAs 164, 172, and 195, as described above). Although not 

23 cost beneficial in the baseline analysis, NextEra stated that these SAMAs would be entered 

24 into the Seabrook long-range plan development process for further implementation 

25 consideration (NextEra 2012a). 

26 The NRC staff asked NextEra to describe how the uncertainty distribution was developed to 

27 derive the 95th percentile CDF value and how the distribution is different for internal, fire, and 

28 seismic CDF (NRC 2010a). In response to the RAI, NextEra explained that the uncertainty 

29 distribution was developed using a Monte Carlo sample size of 10,000 and a sequence bin 

cutoff of 110-9 30 , that the distribution included the integrated contribution from both internal and 

31 external events, and that individual contributions for internal, fire, and seismic events were not 

32 developed (NextEra 2011a). In response to a followup RAI, NextEra further clarified that the 

33 uncertainty analysis included uncertainty distributions for fire-initiating events, seismic-initiating 

34 events, component seismic fragilities, operator actions, and component random failures 

35 (NRC 2011b). NextEra also noted that, while uncertainty distributions were not specifically 

36 considered for hot short probabilities and non-suppression probabilities, numerous sensitivity 

37 studies were performed to support the fire events and seismic events models to ensure the 

38 reasonableness of key input parameters. The results of these sensitivity studies indicate that 

39 the baseline fire and seismic results are relatively insensitive to reasonable variations in key 

40 input parameters. Based on the results of these studies and the level of uncertainty applied in 

41 the fire and seismic events analyses, NextEra concluded that the uncertainty distribution used 

42 for the SAMA evaluation adequately reflects the uncertainty for both internal and external 

43 events. 
 Appendix F 

 F-51 

1 NextEra provided the results of additional sensitivity analyses in the ER, including the use of 

2 3 percent and 8.5 percent discount rates, variations in MACCS2 input parameters (as discussed 

3 in Section F.2.2), and a 41-year analysis period representing the remaining operating life of the 

4 plant accounting for the expected 20-year period of extended operation. Cost benefits are 

5 determined using the 3 percent discount rate, as clarified in an RAI response, and the 

6 41-year extended period are bounded by the cost benefits determined using 95 percent 

7 upper bound MACR. These analyses did not identify any additional potentially cost-beneficial 

8 SAMAs. 

9 SAMAs identified primarily on the basis of the internal events analysis could provide benefits in 

10 certain external events, in addition to their benefits in internal events. Since the SSPSS-2011

11 PRA model is an integrated internal and external events model, NextEra’s evaluation accounted 

12 for the potential risk reduction benefits associated with both internal and external events. The 

13 NRC staff asked NextEra to assess the impact of updated 2008 seismic hazard curves by the 

14 USGS on the Seabrook SAMA analysis (NRC 2010a). As indicated in Section F.2.2, NextEra 

15 responded with a sensitivity analysis in which a 2.1 multiplier is applied to the estimated benefits 

16 for internal and external events to account for the higher seismic CDF developed from the 

17 2008 USGS seismic hazard curves (NextEra 2011a). This same multiplier was subsequently 

18 used in the 2012 SAMA supplement (NextEra 2012a). Since no SAMAs were screened in 

19 the Phase I analysis on very low benefit or excessive implementation cost, NextEra did not 

20 reexamine the Phase I SAMAs. 

21 However, NextEra did provide a sensitivity analysis that reexamined the Phase II SAMAs to 

22 determine if any would be potentially cost beneficial if the baseline (7 percent real discount 

23 rate), uncertainty benefits (95th uncertainty percentile), and a 2.1 seismic multiplier were 

24 considered together (NextEra 2012a). As a result of this sensitivity analysis, one 

25 additional SAMA (SAMA 193) became cost beneficial. Although not cost beneficial in the 

26 baseline analysis, NextEra stated that this SAMA would be entered into the Seabrook 

27 long-range plan development process for further implementation consideration 

28 (NextEra 2012a).

29 As indicated in Section F.3.2, in response to NRC staff RAIs and followup RAIs related to the 

30 ER (NextEra 2010) and 2012 SAMA supplement (NextEra 2012a), NextEra performed cost31 benefit analyses on risk-significant Level 1 and Level 2 basic events, including human error 

32 basic events and risk-significant initiating events. The additional SAMAs and NextEra’s 

33 evaluation of each is summarized in Table F-7 (NextEra 2012a, 2012b). This table also 

34 provides the results of the sensitivity analysis applying the multiplier of 2.1 to account for the 

35 additional risk of seismic events (NextEra 2012a, 2012b). While these analyses did not 

36 identify any additional potentially cost-beneficial SAMAs, two of the SAMAs were 

37 determined to be cost beneficial but were already identified as such in the baseline SAMA 

38 analyses after accounting for uncertainties (SAMA 195) and after accounting for the 

39 seismic multiplier of 2.1 (SAMA 193). 
Appendix F 

 F-52 

1 Table F-57. SAMAs identified and evaluated for risk-significant basic events and 

initiating events(a) 2 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

OALTO 

Provide automatic 

alignment of alternate 

cooling based on 

applicable signals 

Eliminate failure 

of operator to 

align alternate 

cooling 

4 11 340K

(710K) 

800K 

(1.7M) 

>2.4M

PCCABCD 

Install a diverse & 

independent CCW 

pump, reduce to reduce 

potential for common 

mode failure 

Eliminate CCW 

pump failure if AC 

& DC power are 

available 

4 11 335K

(700K) 

785K 

(1.65M) 

>6M

SWG11AB 

Improve Bus 11A/B 

reliability to reduce 

common mode failure 

Eliminate bus 

failures that could 

fail associated 

division during 

mission 

3 10 290K

(610K) 

680K 

(1.4M) 

>1.8M

XOINEO 

Implement hardware 

change to improve 

reliability of 

containment injection 

for sequences where 

containment pressure 

is low 

Eliminate all 

failures of 

operators to 

perform early 

injection during 

AC power 

scenarios 

<1 10 290K

(610K) 

680K 

(1.4M) 

>1.5M

Implement hardware 

change in support of 

automatic initiation of 

containment injection 

gravity drain 

>1.5M

OHSBO 

Implement hardware 

change to improve 

ability to maintain 

stable primary & 

secondary conditions 

with plant in hot 

standby 

Eliminate all 

operator failures 

related to 

maintaining 

stable hot 

standby 

conditions for 

extended cooling 

using the SG 

4 5 140K

(300K) 

335K 

(705K) 

>1.5M(c)

ZZSY12 

Provide power system 

upgrades that would 

significantly reduce or 

prevent consequential 

LOOP events 

Eliminate LOOP 

events that occur 

subsequent to a 

plant trip 

7 5 140K

(300K) 

340K 

(710K) 

>2M
 Appendix F 

 F-53 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

CCTE1 

Install hardware to 

improve the reliability 

of the CCW to reduce 

the potential for loss of 

CCW initiators 

(SAMA 195)(f)

Eliminate PCCW 

temperature 

element failures 

towards the 

temperature 

control function 

3 5 140K

(300K) 

340K 

(710K) 

>300K

CCE17 

Improve Primary 

Closed Cooling (PCC) 

heat exchanger 

reliability related to 

tube leakage 

The Intent of this SAMA has already been implemented (NextEra 2012a)

ORHP10 

Improve reliability or 

capability of the 

operator to restore RCS 

makeup after support 

systems are made 

available 

Eliminate failure 

of all actions to 

restore high 

pressure for long 

term 

2 4 110K

(230K) 

260K 

(550K) 

>5M

SWAFN 

Improve reliability of 

SW Cooling Tower 

SWGR Room 

Ventilation fans 

Eliminate failures 

related to 

ventilation fan 

FN-64 & 

associated 

damper & 

temperature 

switch when 

support systems 

are available 

1 3 91K

(190K) 

210K 

(445K) 

>480K

Eliminate failures 

related to 

ventilation fan 

FN-51A & 

associated 

damper & 

temperature 

switch 

1 2 74K

(160K) 

170K 

(340K) 

>1M

Eliminate failures 

related to 

ventilation fan 

FN-64 & 

associated 

damper & 

temperature 

switch when 

support systems 

are available 

1 2 91K

(190K) 

210K 

(445K) 

>480K
Appendix F 

 F-54 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

XOSMPO 

Implement hardware 

modification for 

automatic control of 

containment sump 

recirculation after core 

melt 

Eliminate 

operator failure to 

align containment 

sump 

recirculation after 

core melt given 

recovery of CBS 

<1 3 61K

(130K) 

140K 

(230K) 

>1.5M

CISPRE 

Install containment 

leakage monitoring 

system 

Eliminate all preexisting small & 

large containment 

leakage events 

0 <1 4K

(12K) 

10K 

(27K) 

50K to 

100K 

NOSBO1 

Install additional DG to 

improve overall 

reliability of onsite 

emergency power 

Elimination of all 

SBO events 

22 6 220K

(470K) 

525K 

(1.1M) 

>2M

OSEPS 

Implement hardware 

change in support of 

auto closure of 

supplemental electrical 

power system (SEPS) 

breaker to replace 

operator action 

Eliminate 

operator failures 

associated with 

align & load the 

SEPS DGs 

8 2 64K

(135K) 

151K 

(320K) 

>750K

SEPS 

Install or modify a 

SEPS DG to 

substantially improve 

reliability of DG start & 

run failures 

Eliminate SEPS 

DG hardware 

failures 

6 2 63K

(130K) 

148K 

(310K) 

>2M

OC12 

Implement hardware 

modification 

(additional signals or 

remote capability) to 

allow closure of MOV 

CS-V-167 

This SAMA is address by SAMA 193 and SAMA analysis case CSV167 

(NextEra 2012a) 

CSV167 

Implement hardware 

change to eliminate 

MOV AC power 

dependencies (SAMA 

193) 

Eliminate 

operator failure to 

close CIV CS-V167 locally. 

0 5 86K

(180K) 

200K 

(420K) 

>300K
 Appendix F 

 F-55 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

TDAFW 

Install additional steam 

driven EFW pump 

Eliminates all 

failures of the 

motor-driven EFW 

independent of 

AC power 

5.3 12 360K

(750K) 

835K 

(1.75M) 

>2M

OTS10 

Implement hardware 

change to improve 

reliability of SGTR 

control to eliminate or 

reduce operator failure 

to terminate safety 

injection (SI) 

Eliminate 

operator failure to 

terminate SI 

3 1 26K

(55K) 

61K 

(130K) 

>300K

OLPR 

Implement hardware 

change to improve 

reliability of ECCS 

transfer to long-term 

recirculation 

Eliminate 

operator failure to 

complete transfer 

of RHR/LHSI to 

long-term 

recirculation 

following a LOCA 

3 0 12K

(25K) 

27K 

(58K) 

>100K

OHSB670 

Implement hardware 

change to improve 

ability to maintain 

stable & secondary 

conditions with SG 

cooling with plant in 

hot standby during CR 

fire events 

Eliminate 

operator failures 

related to 

evacuation & 

control at the 

remote safe 

shutdown panel 

after fire-induced 

transients & 

LOCAs 

3 1 29K

(61K) 

68K 

(140K) 

>420K

OSGLC0 

Implement hardware 

change to improve 

operator reliability or 

provide automatic 

feature to control SG 

levels using the EFW 

discharge pathway 

Eliminate 

operator failures 

related to 

controlling SG 

level via a EFW 

SUFP and EFW 

with the EFW 

discharge & SUFP 

with the MFW 

discharge 

2 1 29K

(62K) 

68K 

(140K) 

>500K

SWGE561 

Improve 4 KV 

emergency Bus E6 

reliability to eliminate 

potential for bus fault 

Eliminate Bus 5 

and 6 random 

failures in the 

initiating event 

model or 

eliminate 

associated power 

division failure or 

both (d)

6 3 100K

(220K) 

240K 

(510K) 

>1.2M
Appendix F 

 F-56 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

XOEFW 

Implement hardware 

change to improve 

operator reliability to 

feed a failed SG during 

a SGTR 

Eliminate 

operator failures 

related to feeding 

the SG to back 

pressure the leak 

0 1 21K

(44K) 

50K 

(100K) 

>500K

ORWMZ 

Implement hardware 

change to improve 

operator reliability or 

provide automatic 

feature to throttle ECCS 

RCS to minimize leak 

for small break LOCA 

(SLOCA) and ISLOCA 

sequences 

Eliminate 

operator failure to 

throttle ECCS 

flow for scenarios 

where the 

containment 

sump Is not 

available during 

SLOCA or 

ISLOCA 

2 0 15K

(32K) 

35K 

(74K) 

>500K

ORWCD1 

Implement hardware 

change to improve 

operator reliability or 

provide automatic 

features to cool & 

depressurize the RCS 

to minimize leak for 

SLOCA and ISLOCA 

sequences 

Eliminate 

operator failure 

control RCS 

cooldown & 

depressurization 

in scenarios 

where the 

containment 

sump is not 

available during 

SLOCA & ISLOCA 

<1 0 5.3K

(11K) 

12K 

(26K) 

>500K

ORWLT1 

Implement hardware 

change to improve 

operator reliability or 

provide automatic 

features to maintain 

stable plant conditions 

for extended SG 

cooling after a LOCA or 

SGTR 

Eliminate 

operator failure to 

maintain stable 

primary & 

secondary 

conditions to 

extend SG 

cooling following 

SLOCA, ISLOCA, 

or ISLOCA(e)

<1 0 5.3K

(11K) 

11K 

(24K) 

>500K

ORWIN 

Implement hardware 

change to improve 

operator reliability or 

provide automatic 

feature to initiate RWST 

makeup 

Eliminate 

operator failure to 

initiate makeup to 

the RWST to 

extend ECCS 

injection during 

SLOCA & ISLOCA 

with recirculation 

failed 

<1 0 4K

(8.4K) 

9.3K 

(20K) 

>500K
 Appendix F 

 F-57 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

PS40XA

Implement hardware 

change to improve 

reliability of the 

low-pressure 

permissive signal need 

to align RHR suction 

Eliminate failure 

of Train A & B 

low-pressure 

permissive 

signals 

2 0 9K

(20K) 

21K 

(44K) 

>500K

RCVR 

Implement hardware 

change to improve RHR 

Train A suction relief 

valve opening on 

demand 

Eliminate failures 

of both RHR 

Train A relief 

valves to open & 

reclose 

<1 2 24K

(50K) 

55K 

(120K) 

>500K

CST01 

Implement hardware & 

procedural changes to 

improve reliability of 

makeup to CST for 

long-term SG cooling 

Eliminate failures 

of condensate 

storage tank 

(CST) source for 

EFW 

1 1 35K

(73K) 

81K 

(170K) 

>500K

SWOC6 

Implement hardware & 

procedural changes to 

improve reliability of 

transferring SW from 

the ocean to the 

cooling tower 

Eliminate failure 

to transfer SW 

from the ocean to 

the cooling tower 

<1 1 28K

(59K) 

66K 

(140K) 

>1.5M

SWA6 

Implement hardware 

changes to improve 

reliability of the SW 

cooling tower SWGR 

ventilation 

Eliminate failure 

to transfer SW 

from the ocean to 

the cooling tower 

<1 1 22K

(46K) 

52K 

(110K) 

>240K

OFCR0 

Implement hardware 

and procedural 

changes to improve 

operator capacity to 

restore PCCW at the 

remote shutdown 

panel 

Eliminate failure 

to restore PCCW 

at the remote 

shutdown panel 

<1 1 27K

(56K) 

62K 

(130K) 

>200K

SW64 

Implement hardware 

changes to reduce the 

probability of spurious 

SW intake return valve 

opening 

Reduces to a low 

probability that 

SW intake return 

valve spuriously 

opens 

<1 1 25K

(52K) 

58K 

(120K) 

>300K
Appendix F 

 F-58 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

SW7071C 

Implement hardware 

changes to improve 

reliability of SW cooling 

tower pump or SWGR 

room ventilation fans 

to reduce potential for 

common mode failure 

Eliminate failure 

of CW cooling 

tower pump or 

SWGR room 

ventilation fans 

when support 

systems are 

available 

1 3 84K

(180K) 

200K 

(410K) 

>480K

EA180C 

Implement hardware 

changes to improve 

reliability of the 

emergency air handing 

ventilation fans by 

eliminating potential for 

common mode failure 

Eliminate failure 

of emergency air 

handing 

ventilation fans 

when support 

systems are 

available 

1 2 58K

(120K) 

140K 

(285K) 

>480K

SW51C 

Implement hardware 

changes to improve 

reliability of SW cooling 

tower fans to reduce 

potential for common 

mode failure 

Eliminate failure 

of SW cooling 

tower fans when 

support systems 

are available 

1 3 87K

(180K) 

205K 

(430K) 

>1M

E7T 

Implement hardware 

changes to reduce or 

eliminate impact of 

0.7 g seismic events 

Eliminate the 

0.7 g seismic 

initiator 

8 2 77K

(160K) 

180K 

(380K) 

>500K

NOLOSP 

Implement hardware 

changes to reduce the 

risk of weather-related 

loss of system 

pressure (LOSP) 

Eliminate the 

LOSP initiator 

18 17 530K

(1.2M) 

1.2M 

(2.7M) 

>3M

F4TREL 

Provide analysis & 

hardware changes to 

protect relay room 

structure from 

postulated turbine bay 

flooding due to an 

HELB 

Eliminate the 

HELB flooding 

initiator in the 

turbine bay 

5 1 46K

(97K) 

110K 

(225K) 

>300K
 Appendix F 

 F-59 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

NOSGTR 

Install upgrades that 

would reduce or 

eliminate SGTR 

Eliminate the 

SGTR initiator in 

addition to 

pressure and 

thermo-induced 

tube rupture 

5 2 67K

(140K) 

160K 

(330K) 

>500K

RXT1 

Improve overall 

Seabrook reliability by 

installing digital control 

systems to reduce 

plant trip initiating 

frequency 

Eliminate the 

plant trip initiator 

4 7 205K

(430K) 

480K 

(1.0M) 

>19M

LOCA05 

Implement hardware 

changes to reduce or 

eliminate pipe break 

LOCA events 

Eliminate all 

small, medium, & 

large pipe break 

LOCA events 

9 2 77K

(160K) 

180K 

(380K) 

>500K

F1SWCY 

Implement hardware 

changes to reduce the 

risk of SW common 

return line rupture 

event 

Eliminate the SW 

common return 

line rupture event 

3 9 260K

(550K) 

620K 

(1.3M) 

>5M

FIRE1 

Implement hardware 

change to reduce 

potential for PORV 

LOCA caused by fire in 

the control room 

Eliminate 

spurious or 

fire-induced 

actuation of the 

PORV 

3 0 14K

(31K) 

34K 

(71K) 

>100K

FSGBE6 

Implement hardware 

change to reduce 

potential for loss of 

electrical Bus E6 

caused by fire in 

SWGR room B 

Eliminate fire 

initiating events 

in SWGR room B 

that result in loss 

of electrical Bus 

E6 

3 1 28K

(58K) 

65K 

(140K) 

>500K

Implement hardware 

change to reduce 

potential for loss of 

electrical Bus E6 

caused by fire in SWGR 

room A 
Appendix F 

 F-60 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

LACPA

Improve Bus E5 

reliability & eliminate or 

reduce bus faults 

contributing 

Eliminate the loss 

of the Train A 

essential 4 KV 

power (Bus 5E) 

initiator 

3 1 44K

(92K) 

100K 

(220K) 

>3M

LOCA06 

Implement hardware 

changes to reduce or 

eliminate ISLOCA risk 

in the RHR injection 

path 

Eliminate ISLOCA 

events 

<1 3 48K

(101K) 

110K 

(240K) 

>500K

LOCA05 

Implement hardware 

changes to reduce or 

eliminate impact of 

2.5 g seismically 

induced LOCA (by 

installing digital large 

break LOCA protection 

system) 

Eliminates pipe 

break LOCAs 

9 2 77K

(160K) 

180K 

(380K) 

>500K

E18T 

Implement hardware 

changes to reduce or 

eliminate impact of 

1.8 g seismic transient 

event 

Eliminate the 

1.8 g seismic 

transient initiator 

<1 3 48K

(100K) 

110K 

(240K) 

>500K

NOATWS 

Implement seismic 

upgrades to the ATWS 

system to withstand up 

to a 2.5 g seismic event 

Eliminate the 

ATWS initiator 

4 2 60K

(130K) 

140K 

(290K) 

>500K(g)

Implement hardware 

upgrades to ATWS to 

reduce potential for 

ATWS with loss of 

MFW 

>500K

NOSLB 

Install secondary side 

guard pipes to up to 

the main steam 

isolation valves 

Eliminate steam 

line breaks 

<1 0 5K

(11K) 

11K 

(24K) 

>500K

MSSVO 

Install “gagging 

device” to close a 

stuck open MSSV 

Eliminate stuck 

open MSSV 

initiator 

<1 0 1K

(2K) 

2K 

(4.5K) 

>500K
 Appendix F 

 F-61 

Analysis case & 

applicable SAMAs 

Modeling 

assumptions 

 % Risk reduction Total benefit ($)(b)

Cost ($) 

CDF Population 

dose 

Baseline 

(internal + 

external) 

Baseline 

with 

uncertainty 

LOSPP 

Implement hardware 

upgrades to reduce 

LOSP 

Eliminate all plant 

centered LOSP 

events 

2 2 80K

(170K) 

190K 

(395K) 

>7M

F4TFPB 

Implement hardware 

changes to provide 

flood and spray 

protection of nonsafety bus duct in 

turbine bay 

Eliminate all 

flooding 

scenarios due to 

rupture of fire 

protection piping 

in the turbine bay 

impacting offsite 

power 

1 0 14K

(30K) 

33K 

(70K) 

>100K(h)

FCRAC 

Implement hardware 

changes to provide fire 

protection features to 

eliminate or reduce the 

potential for fire on the 

Main Control Room 

panel 

Eliminate all 

scenarios where 

fire in the Main 

Control Room 

leads to AC 

power loss 

1 0 15K

(31K) 

35K 

(70K) 

>100K(h)

LOC1LG 

Implement hardware 

changes to eliminate or 

reduce the potential for 

large LOCA events 

Eliminate all large 

LOCAs 

1 0 15K

(31K) 

35K 

(70K) 

>100K(h)

(a) SAMAs in bold are potentially cost beneficial. This table summarizes the results of the revised SAMA analysis 

provided in the 2012 SAMA supplement (NextEra 2012a). 

(b) Values in parenthesis are the results of the sensitivity analysis applying a multiplier of 2.1 to account for the additional 

risk of seismic events (NextEra 2011a). 

(c) In response to an NRC staff RAI, NextEra clarified that the cost reported in the “Expected Cost” column of the 2012 

SAMA supplement (NextEra 2012a) was incorrect, but it was reported correctly (i.e., $1.5M) in the “Evaluation” column 

(NextEra 2012b). 

(d) In response to an NRC staff RAI, NextEra clarified that PRA case SWGE61 eliminated both the initiating and basic 

events associated with 4 kV essential buses E5 and E6 (NextEra 2012b). 

(e) In response to an NRC staff RAI, NextEra clarified that PRA case ORWLT1 applied to small LOCA, interfacing LOCA, 

and SGTR (NextEra 2012b). 

(f) In response to an NRC staff RAI, NextEra clarified that PRA case CCTE1 addresses both the reliability of PCCW and 

loss of CCW as an initiator (NextEra 2012b). 

(g) In response to an NRC staff RAI, NextEra clarified that the cost of PRA case NOATWS reflects structural upgrades to 

reactor internals to reduce seismic capacity as well as non-seismically related reactor internals and emergency boration 

system upgrades (NextEra 2012b). 

(h) NextEra explained in a telephone clarification meeting (NRC 2012b) that $100K is a nominal value used because of the 

very low calculated benefit. This value reflects the minimum cost of a hardware change. 

1 As indicated in Section F.3.2, in response to an NRC staff RAI, NextEra identified and evaluated 

2 a SAMA to make “seismic upgrades to the CST” (NextEra 2011a). This SAMA was estimated to 

3 have an implementation cost of more than $100,000. NextEra performed a bounding analysis 

4 of the benefit of this SAMA by assuming that it eliminated structural failures of the CST during 
Appendix F 

 F-62 

1 all seismic-initiating events. The total baseline benefit (using a 7 percent real discount rate) was 

2 estimated to be $1,000 and, after accounting for uncertainties, to be $2,000. Based on this 

3 result, NextEra concluded that this SAMA was not cost beneficial in either the baseline or the 

4 uncertainty analysis. This SAMA was not re-evaluated in the 2012 SAMA supplement 

5 (NextEra 2012a). However, based on the very low potential benefit for this SAMA, the

6 NRC staff concludes that this SAMA would not be cost beneficial even after accounting for 

7 the higher MACR in the 2012 SAMA supplement, which is about a factor 3.7 increase over 

8 the MACR presented in the ER, and after applying the multiplier of 2.1 to account for the 

9 additional risk from seismic events. 

10 Also, in response to an NRC staff RAI, NextEra provided a Phase II evaluation of the following 

11 SAMAs, which were originally screened in the Phase I evaluation (NextEra 2011a, 2011b): 

12  SAMA 79—install bigger pilot operated relief valve so only one is required, 

13  SAMA 84—switch for EFW room fan power supply to station batteries, 

14  SAMA 105—delay containment spray actuation after a large LOCA, and 

15  SAMA 191—remove the 135 °F temperature trip of the PCCW pumps. 

16 The 2012 SAMA supplement (NextEra 2012a) evaluated these SAMAs (in Table F-6), and

17 determined them to not be cost beneficial in either the baseline or uncertainty analysis or in the 

18 sensitivity analysis applying the seismic multiplier of 2.1. 

19 As indicated in Section F.3.2, in response to an NRC staff RAI, NextEra provided an evaluation 

20 of the following two SAMAs identified as a result of its review of the cost-beneficial SAMAs from 

21 prior SAMA analyses for five Westinghouse four-loop PWR sites (NextEra 2011a): 

22  SAMA “procedure change to ensure that the RCS cold leg water seals are not cleared” 

23 has an estimated implementation cost of $15,000 to $20,000. NextEra performed a 

24 bounding analysis of the benefit of this SAMA by assuming that it eliminated all thermally 

25 induced SGTR events (Analysis Case XSGTIS). The total baseline benefit (using a 

26 7 percent real discount rate) was estimated to be less than $1,000 and, after accounting 

27 for uncertainties, to be less than $1,000. Based on this result, NextEra concluded that 

28 this SAMA was not cost beneficial in either the baseline or the uncertainty analysis. 

29 NextEra also concluded that this SAMA would not be cost beneficial after applying the 

30 multiplier of 2.1 to account for the additional risk from seismic events (NextEra 2011b). 

31 This SAMA was not re-evaluated in the 2012 SAMA supplement (NextEra 2012a). 

32 However, based on the very low potential benefit for this SAMA, the NRC staff 

33 concludes that this SAMA would not be cost beneficial even after accounting for 

34 the higher MACR in the 2012 SAMA supplement, which is about a factor 3.7 

35 increase over the MACR presented in the ER. 

36  SAMA “installation of redundant parallel service water valves to the EDGs” was

37 estimated to have an implementation cost similar to SAMA 161 (NextEra 2011b), or 

38 $2 million (NextEra 2012a). In response to RAIs on the ER, NextEra performed a 

39 bounding analysis of the benefit of this SAMA by assuming that it eliminated all SBO 

40 events (SAMA analysis case NOSBO1). It concluded that this SAMA was not cost 

41 beneficial either in the baseline (using a 7 percent real discount rate) nor after 

42 accounting for uncertainties and the seismic risk multiplier of 2.1 

43 (NextEra 2011a, 2011b). This SAMA was not re-evaluated in the 2012 SAMA 

44 supplement (NextEra 2012a). However, using the benefit results for SAMA 

45 analysis case NOSBO1 provided in Table F-6, the NRC staff estimates total baseline 

46 benefit (using a 7 percent real discount rate and the seismic multiplier of 2.1) to be 
 Appendix F 

 F-63 

1 $470,000 and, after accounting for uncertainties, to be $1.1 million. The NRC staff 

2 concludes that this SAMA is not cost beneficial. 

3 Based on review of the ER (NextEra 2010), the NRC staff noted that the evaluation of 

4 SAMA 80, “provide a redundant train or means of ventilation,” assumes removal of HVAC 

5 dependence for CS, SI, RHR, and CBS pumps. The NRC staff asked NextEra to provide an 

6 evaluation of a SAMA to remove the HVAC dependency for just the highest risk system 

7 (NRC 2010a). In response to the RAI, NextEra explained that the estimated implementation 

8 cost to install a redundant HVAC train to either a single ECCS pump/system or multiple

9 ECCS pumps and systems was estimated to be greater than $500,000. NextEra further 

10 noted that this cost estimate is significantly greater than the estimated benefit, after 

11 accounting for uncertainties and the seismic multiplier of 2.1, and which conservatively 

12 assumes elimination of 100 percent of the ECCS dependency on HVAC during long-term 

13 recirculation sequences. The analysis of this SAMA was updated in the 2012 SAMA 

14 supplement (NextEra 2012a), which shows a maximum benefit of $750,000, after 

15 accounting for uncertainties and the seismic multiplier of 2.1) and an updated cost 

16 estimate of greater than $1 million. NextEra points out (NextEra 2012a) that this cost is 

17 judged to be comparable to other plants that do not have this redundancy. The NRC staff 

18 concludes that this SAMA has been adequately addressed. 

19 The NRC staff notes that all of the potentially cost-beneficial SAMAs (SAMAs 157, 164, 165, 

20 172, 192, 193, and 195) identified in the 2012 SAMA supplement (NextEra 2012a) are 

21 included within the set of SAMAs that NextEra plans to enter into the Seabrook long-range plan 

22 development process for further implementation consideration. The NRC staff concludes that, 

23 with the exception of the potentially cost-beneficial SAMAs discussed above, the costs of the 

24 other SAMAs evaluated would be higher than the associated benefits. 

25 F.7 Conclusions 

26 NextEra compiled a list of 191 SAMAs in the ER (NextEra 2010) and 4 additional SAMAs in 

27 the 2012 SAMA supplement (NextEra 2012a) based on a review of the most significant basic 

28 events from the plant-specific PRA, insights from the plant-specific IPE and IPEEE, review of 

29 other industry documentation, and insights from Seabrook personnel. A qualitative screening 

30 removed SAMA candidates that had modified features not applicable to Seabrook due to design 

31 differences, that were determined to have already been implemented at Seabrook or Seabrook 

32 meets the intent of the SAMA, or that could be combined with another similar SAMA under 

33 consideration. Based on this screening, 117 SAMAs were eliminated, leaving 78 74 candidate 

34 SAMAs for evaluation. 

35 For the remaining SAMA candidates, more detailed design and cost estimates were developed, 

36 as shown in Table F-4. The cost-benefit analyses showed that twothree of the SAMA 

37 candidates were potentially cost beneficial in the baseline analysis (SAMAs 157, 165, and 192). 

38 NextEra performed additional analyses to evaluate the impact of parameter choices and 

39 uncertainties on the results of the SAMA assessment. As a result, nothree additional SAMAs 

40 were identified as potentially cost beneficial in the 2012 SAMA supplement (SAMAs 164, 172, 

41 and 195). In addition, NextEra performed a sensitivity analysis accounting for the

42 additional risk of seismic events and identified one additional SAMA (SAMA 193) as being 

43 potentially cost beneficial. NextEra has indicated that all fourseven potentially cost-beneficial 

44 SAMAs would be entered into the Seabrook long-range plan development process for further 

45 implementation consideration. 
Appendix F 

 F-64 

1 The NRC staff reviewed the NextEra analysis and concludes that the methods used and their 

2 implementation were sound. In reviewing insights from plant-specific risk studies, the 

3 SAMA evaluation included explicit consideration of external as well as internal hazards. 

4 The treatment of SAMA benefits and costs support the general conclusion that the SAMA 

5 evaluations performed by NextEra are reasonable and sufficient for the license renewal 

6 submittal. Although the treatment of SAMAs for external events was somewhat limited, the 

7 likelihood of there being cost beneficial enhancements in this area was minimized by 

8 improvements that have been realized as a result of the IPEEE process and inclusion of a 

9 multiplier to account for the additional risk of seismic events. 

10 The NRC staff agrees with NextEra’s identification of areas in which risk can be further 

11 reduced in a cost-beneficial manner through the implementation of the identified, 

12 potentially cost-beneficial SAMAs. Given the potential for cost beneficial risk reduction, the 

13 NRC staff agrees that further evaluation of these SAMAs by NextEra is warranted. However,

14 the applicant stated that the sevenfour potentially cost-beneficial SAMAs are not aging-related

15 in that they do not involve aging management of passive, long-lived systems, structures, and 

16 components during the period of extended operation. Therefore, the NRC staff concludes 

17 that the potential cost beneficial SAMAs are not aging related and they need not be 

18 implemented as part of license renewal pursuant to 10 CFR Part 54. 

19 F.8 References 

20 American Society of Mechanical Engineers (ASME), 2003, “Addenda to ASME RA-S-2002, 

21 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications,” 

22 ASME RA-Sa-2003, December 5, 2003. 

23 ASME, 2009, “Addenda to ASME RA-S-2008, Standard for Level 1/Large Early Release 

24 Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications,” ASME 

25 RA-Sa-2009, February 2, 2009. 

26 Electric Power Research Institute (EPRI), 1988, “A Methodology for Assessment of Nuclear 

27 Power Plant Seismic Margin,” EPRI NP-6041, Revision 0, Palo Alto, CA, August 1988. 

28 EPRI, 1992, “Fire-Induced Vulnerability Evaluation (FIVE),” EPRI TR-100370, Revision 0, Palo 

29 Alto, CA, April 1992. 

30 New Hampshire Yankee (NHY), 1991, “Individual Plant Examination Report for Seabrook 

31 Station,” March 1, 1991. 

32 NextEra Energy Seabrook, LLC. (NextEra), 2010, “Seabrook Station—License Renewal 

33 Application, Applicant’s Environmental Report, Operating License Renewal Stage,” 

34 May 25, 2010, ADAMS Accession Nos. ML101590092 and ML101590089. 

35 NextEra, 2011a, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control Desk. 

36 Subject: “Seabrook Station, Response to Request for Additional Information, NextEra Energy 

37 Seabrook License Renewal Application,” Seabrook, NH, January 13, 2011, ADAMS Accession 

38 No. ML110140810. 

39 NextEra, 2011b, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control Desk. 

40 Subject: “Seabrook Station, Response to Request for Additional Information, NextEra Energy 

41 Seabrook License Renewal Application,” Seabrook, NH, April 18, 2011, ADAMS Accession 

42 No. ML11122A075. 
 Appendix F 

 F-65 

1 NextEra, 2011c, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control Desk. 

2 Subject: “Seabrook Station, Supplement to Response to Request for Additional Information, 

3 NextEra Energy Seabrook License Renewal Application,” Seabrook, NH, June 10, 2011, 

4 ADAMS Accession No. ML11166A255. 

5 NextEra, 2012a, Letter from Paul O. Freeman, NextEra, to U.S. NRC Document Control 

6 Desk. Subject: “Seabrook Station, Supplement 2 to Severe Accident Mitigation 

7 Alternatives Analysis, NextEra Energy Seabrook License Renewal Application,” 

8 Seabrook, NH, March 19, 2012, ADAMS Accession No. ML12080A137. 

9 NextEra, 2012b, Letter from Kevin T. Walsh, NextEra, to U.S. NRC Document Control 

10 Desk. Subject: “Seabrook Station, Supplement 3 to Severe Accident Mitigation 

11 Alternatives Analysis, Response to RAI Request dated July 16, 2012, NextEra Energy 

12 Seabrook License Renewal Application,” Seabrook, NH, September 13, 2012, ADAMS 

13 Accession No. ML12262A513. 

14 North Atlantic Energy Service Corp. (NAESC), 1992, “Individual Plant Examination External 

15 Events Report for Seabrook Station,” October 2, 1992, ADAMS Accession No. ML080100029. 

16 Nuclear Energy Institute (NEI), 2005, “Severe Accident Mitigation Alternative (SAMA) Analysis 

17 Guidance Document,” NEI 05-01 (Revision A), Washington, D.C., November 2005. 

18 Pickard, Lowe, and Garrick, Inc. (PLG), 1983, “Seabrook Station Probabilistic Safety 

19 Assessment,” prepared for the Public Service Company of New Hampshire and Yankee Atomic 

20 Electric Company, PLG-0300, December 1982. 

21 U.S. Geologic Survey (USGS), 2008, “2008 NSHM Gridded Data, Peak Ground Acceleration,” 

22 Available URL: http://earthquake.usgs.gov/hazards/products/conterminous/2008/data/. 

23 U.S. Nuclear Regulatory Commission (NRC), 1975, “Standard Review Plan for the Review of 

24 Safety Analysis Report for Nuclear Power Plants,” NUREG-0800, Washington, D.C., 

25 November 1975. 

26 NRC, 1983, PRA Procedure Guide, NUREG/CR-2300, Washington, D.C., January 1983. 

27 NRC, 1988, GL 88-20, “Individual Plant Examination for Severe Accident Vulnerabilities,” 

28 November 23, 1988. 

29 NRC, 1990, “Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants,” 

30 NUREG-1150, Washington, D.C., December 1990. 

31 NRC, 1991, GL No. 88-20, “Individual Plant Examination of External Events for Severe Accident 

32 Vulnerabilities,” NUREG-1407, Washington, D.C., Supplement 4, June 28, 1991. 

33 NRC, 1992, Letter from Gordon E. Edison, U.S. NRC, to Ted C. Feigenbaum, NHY, Subject: 

34 “Staff Evaluation of Seabrook Individual Plant Examination (IPE)—Internal Events, GL 88-20 

35 (TAC No. M74466),” Washington, D.C., February 28, 1992. 

36 NRC, 1997a, Regulatory Analysis Technical Evaluation Handbook, NUREG/BR-0184, 

37 Washington, D.C., January 1997. 

38 NRC, 1997b, “Individual Plant Examination Program: Perspectives on Reactor Safety and Plant 

39 Performance,” NUREG-1560, Washington, D.C., December 1997. 
Appendix F 

 F-66 

1 NRC, 1998, Code Manual for MACCS2: Volume 1, User’s Guide, NUREG/CR-6613, 

2 Washington, D.C., May 1998. 

3 NRC, 2001, Letter from Victor Nerses, U.S. NRC, to Ted C. Feigenbaum, NAESC. Subject: 

4 “Seabrook Station, Unit No. 1—Individual Plant Examination of External Events (IPEEE) (TAC 

5 No. M83673),” Washington, D.C., May 2, 2001, ADAMS Accession No. ML010320252. 

6 NRC, 2003, “Sector Population, Land Fraction, and Economic Estimation Program,” SECPOP: 

7 NUREG/CR-6525, Washington D.C., April 2003 

8 NRC, 2004, “Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission,” 

9 NUREG/BR-0058, Washington, D.C., Revision 4, September 2004. 

10 NRC, 2010a, Letter from Michael Wentzel, U.S. NRC, to Paul Freeman, NextEra. Subject: 

11 “Request for Additional Information for the Review of the Seabrook Station License Renewal 

12 Application-SAMA Review (TAC No. ME3959),” Washington, D.C., November 16, 2010, 

13 ADAMS Accession No. ML103090215. 

14 NRC, 2010b, NRC Information Notice 2010-18: GI-199, “Implications of Updated Probabilistic 

15 Seismic Hazard Estimates in Central and Eastern United States on Existing Plants,” 

16 Washington, D.C., September 2, 2010, ADAMS Accession No. ML101970221. 

17 NRC, 2011a, Memorandum to NextEra from Michael J. Wentzel, U.S. NRC. Subject: “Summary 

18 of Telephone Conference Calls held on February 15, 2011, between the U.S. Nuclear 

19 Regulatory Commission and NextEra Energy Seabrook, LLC, to Clarify the Responses to the 

20 Requests for Additional Information Pertaining to the Severe Accident Mitigation Alternatives 

21 Review of the Seabrook Station License Renewal Application (TAC No. ME3959),” 

22 Washington, D.C., February 28, 2011, ADAMS Accession No. ML110490165. 

23 NRC, 2011b, Letter from Bo Pham, U.S. NRC, to Paul Freeman, NextEra. Subject: “Schedule 

24 Revision and Request for Additional Information for the Review of the Seabrook Station License 

25 Renewal Application Environmental Review (TAC Number ME3959),” Washington, D.C., 

26 March 4, 2011, ADAMS Accession No. ML110590638.

27 NRC, 2012a, Letter from Micheal Wentzel, U.S. NRC, to Kevin Walsh, NextEra. Subject: 

28 “Request for Additional Information for the Review of the Seabrook Station License 

29 Renewal Application Environmental Review—SAMA Review (TAC Number ME3959),” 

30 Washington, D.C., July 16, 2012, ADAMS Accession No. ML12180A355. 

31 NRC, 2012b, Memorandum to File. Subject: “Summary of Telephone Conference Call 

32 held on October 3, 2012, between the U.S. Nuclear Regulatory Commission and NextEra 

33 Energy Seabrook, LLC, Clarifying Responses to Requests for Additional Information 

34 Pertaining to the Seabrook Station License Renewal Application Environmental Review 

35 (TAC. No. ME3959),” dated November 1, 2012, ADAMS Accession No. ML12278A25

36 



UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

--------------------

OFFICIAL BUSINESS
NUREG-1437

Second 

Supplement 46

Draft

Generic Environmental Impact Statement for License Renewal of Nuclear Plants 

Regarding Seabrook Station