Regulatory Analysis for Mitigation of Beyon-Design-basis Events Proposed Rule

MBDBE regulatory analysis.pdf

10 CFR Part 50, Domestic Licensing of Production and Utilization Facilities

Regulatory Analysis for Mitigation of Beyon-Design-basis Events Proposed Rule

OMB: 3150-0011

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Regulatory Analysis
Proposed Rulemaking to Address
Mitigation of Beyond-Design-Basis Events

U.S. Nuclear Regulatory Commission
October 2015

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page i

Table of Contents
Executive Summary ...................................................................................................................................... 1
Abbreviations ................................................................................................................................................ 3
1.

Introduction ........................................................................................................................................... 5
1.1

Background ...................................................................................................................................... 5

1.2

Statement of the Problem and Nuclear Regulatory Commission Objectives for the Rulemaking ... 8

Identification and Preliminary Analysis of Alternative Approaches ....................................................... 9
2.1

Option 1: Take No Action (Considered-Not Selected) .................................................................... 9

2.2 Option 2: Undertake Rulemaking to Require SAMGs and Make Order EA-12-049, Order EA-12051, and Industry Initiatives Generically Applicable (Considered-Not Selected) .................................... 10
2.3 Option 3: Undertake Rulemaking to Make Order EA-12-049, Order EA-12-051, and Industry
Initiatives Generically Applicable (NRC Selected) .................................................................................. 11
2.4
3.

Non-rulemaking Alternatives .......................................................................................................... 11

Estimation and Evaluation of Benefits and Costs: Presentation of Results ...................................... 11
3.1

Methodology and Assumptions ...................................................................................................... 12

Affected Universe................................................................................................................................. 12
Cost Estimation .................................................................................................................................... 16
Time Period of Analysis ....................................................................................................................... 18
Present Value Calculations .................................................................................................................. 18
3.2

Summary of Costs and Benefits of the Regulatory Options .......................................................... 19

3.3

Costs of the Proposed Rule ........................................................................................................... 22

3.3.1. Industry Implementation ........................................................................................................... 25
3.3.2 Industry Operation ..................................................................................................................... 30
3.3.3 NRC Implementation ................................................................................................................. 38
3.3.4 NRC Operation .......................................................................................................................... 41
3.4. Benefits of the Proposed Rule ....................................................................................................... 43
3.4.1 Benefits Associated with Public Health (Accident), Occupational Health (Accident), Offsite
Property, Onsite Property, and Environmental Considerations ........................................................... 43
3.4.2 Benefits Associated with Regulatory Efficiency ......................................................................... 47
3.5. Disaggregation ............................................................................................................................... 48
3.6. Sensitivity Analysis......................................................................................................................... 48
4.

Decision Rationale for Selection of Proposed Action ......................................................................... 48
4.1

Safety Goal Evaluation................................................................................................................... 49

4.2

Committee to Review Generic Requirements (CRGR).................................................................. 49

References .................................................................................................................................................. 51

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page ii

List of Exhibits
Exhibit 3-1. List of Operating PWR and BWR Sites ................................................................................... 14
Exhibit 3-2. Operating Site Counts by SAMGs and Reactor Type............................................................. 15
Exhibit 3-3. COL Applications that Reference Reactor Designs ................................................................ 15
Exhibit 3-4. Number of COL Applications that Reference New Reactor Designs...................................... 16
Exhibit 3-5. Wage Rate Estimates by Labor Category .............................................................................. 17
Exhibit 3-6. Summary of Incremental Costs and Benefits for Option 1: No Action Baseline ..................... 19
Exhibit 3-7. Summary of Total Costs for Option 2: Undertake Rulemaking to Require SAMGs and Make
the Orders and Industry Initiatives Generically Applicable ................................................................. 20
Exhibit 3-8. Summary of Incremental Costs and Benefits for Option 2 ..................................................... 20
Exhibit 3-9. Summary of Total Costs for Option 3: Undertake Rulemaking to Make the Orders and
Industry Initiatives Generically Applicable .......................................................................................... 21
Exhibit 3-10. Summary of Incremental Costs and Benefits for Option 3 ................................................... 21
Exhibit 3-11. Summary of Industry and NRC Total Costs for Option 2 ...................................................... 24
Exhibit 3-12. Summary of Industry and NRC Total Costs for Option 3 ...................................................... 25
Exhibit 3-13. Present Value of Industry’s Implementation Cost for Option 2 ............................................. 26
Exhibit 3-14. Industry Implementation Cost: SAMGs ................................................................................. 27
Exhibit 3-15. Industry Implementation Cost: Integration of Emergency Procedures with SAMGs ............ 27
Exhibit 3-16. Industry Implementation: SAMGs Command and Control .................................................... 28
Exhibit 3-17. Industry Implementation Cost: SAMGs Training................................................................... 28
Exhibit 3-18. Industry Implementation Cost: SAMGs Drills and Exercises ................................................ 29
Exhibit 3-19. Industry Implementation Cost: SAMGs Change Control ...................................................... 30
Exhibit 3-20. Present Value of Industry’s Implementation Cost for Option 3 ............................................. 30
Exhibit 3-21. Present Value of Industry’s Operations Cost for Option 2 .................................................... 31
Exhibit 3-22. Industry Operations Cost: SAMGs (During the Operating Term) ......................................... 32
Exhibit 3-23. Industry Operations Cost: SAMGs (During the First 2 Years of Decommissioning) ............ 32
Exhibit 3-24. Industry Operations: SAMGs Training (During the Operating License Term) ...................... 34
Exhibit 3-25. Industry Operations: SAMGs Training (During the First 2 Years of Decommissioning) ....... 35
Exhibit 3-26. Industry Operations Cost: SAMGs Drills and Exercises ....................................................... 36
Exhibit 3-27. Industry Operations Cost: SAMGs Change Control (During Operating License Term) ...... 37
Exhibit 3-28. Industry Operations Cost: SAMGs Change Control (During the First 2 Years of
Decommissioning) .............................................................................................................................. 38
Exhibit 3-29. Present Value of NRC Implementation Cost ........................................................................ 39
Exhibit 3-30. NRC Implementation Cost: Developing and Issuing the Final Rule ..................................... 39
Exhibit 3-31. NRC Implementation Cost: SAMGs ...................................................................................... 40
Exhibit 3-32. NRC Implementation Cost: SAMGs Drills and Exercises ..................................................... 40
Exhibit 3-33. NRC Implementation Cost: SAMGs Change Control ........................................................... 40
Exhibit 3-34. Present Value of NRC’s Operations Cost ............................................................................. 41
Exhibit 3-35. NRC Operations Cost: SAMGs ............................................................................................. 42

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page iii

Exhibit 3-36. NRC Operations Cost: SAMGs Drills and Exercises ............................................................ 42
Exhibit 3-37. NRC Operations Cost: SAMGs Change Control .................................................................. 43
Exhibit 3-38. NRC’s QHO and Risk Evaluation Results of CPPR Rulemaking Alternatives ..................... 45
Exhibit 4-1. Specific CRGR Regulatory Analysis Information Requirements ............................................ 50
Exhibit B-1. Site Counts by Number of Units and Reactor Types.............................................................. 70
Exhibit B-2. List of BWR Reactor Sites Included in the Analysis by Number of Units ............................... 70
Exhibit B-3. List of PWR Reactor Sites Included in the Historical Cost Analysis by Number of Units....... 71
Exhibit B-4. List of AP1000 Reactor Sites Included in the Historical Cost Analysis by Number of Units .. 72
Exhibit B-5. Labor Rates Used in the Historical Cost Analysis .................................................................. 72
Exhibit B-6. Assumptions for Equipment Needs at 2- and 3-Unit Sites ..................................................... 73
Exhibit B-7. Sites Used to Develop the Lists of Compliance Activities and Quantities of Equipment Used
............................................................................................................................................................ 76
Exhibit B-8. Number of Sites Purchasing and Installing SFP Instruments ................................................ 81
Exhibit B-9. Summary of Industry and NRC Costs: Historical Cost Analysis ............................................ 82
Exhibit B-10. Summary of Costs for Order EA-12-049: Historical Cost Analysis ...................................... 83
Exhibit B-11. Present Value of Industry’s Implementation Cost ................................................................ 84
Exhibit B-12. BWR Implementation Cost: Initial Response ....................................................................... 85
Exhibit B-13. BWR Implementation Cost: Onsite Portable Equipment ...................................................... 85
Exhibit B-14. BWR Implementation Cost: Offsite Portable Equipment ...................................................... 87
Exhibit B-15. BWR Implementation Cost: Supporting Function ................................................................. 87
Exhibit B-16. BWR Implementation Cost: External Event Considerations ................................................ 88
Exhibit B-17. BWR Implementation Cost: Programmatic Controls ............................................................ 89
Exhibit B-18. PWR Implementation Cost: Initial Response ....................................................................... 90
Exhibit B-19. PWR Implementation Cost: Onsite Portable Equipment ...................................................... 91
Exhibit B-20. PWR Implementation Cost: Offsite Portable Equipment ...................................................... 92
Exhibit B-21. PWR Implementation Cost: Supporting Function ................................................................. 92
Exhibit B-22. PWR Implementation Cost: External Event Considerations ................................................ 93
Exhibit B-23. PWR Implementation Cost: Programmatic Controls ............................................................ 94
Exhibit B-24. AP1000 Implementation Cost: Programmatic Controls ........................................................ 95
Exhibit B-25. Cost of Offsite Equipment at RRCs ...................................................................................... 96
Exhibit B-26. Cost of Staffing, Training, Outfitting, and Moving at RRCs .................................................. 98
Exhibit B-27. Present Value of Industry’s Operations Cost ....................................................................... 98
Exhibit B-28. BWR Operations Cost: Programmatic Controls ................................................................... 99
Exhibit B-29. PWR Operations Cost: Programmatic Controls ................................................................. 100
Exhibit B-30. AP1000 Operations Cost: Programmatic Controls ............................................................. 100
Exhibit B-31. Quantity and Cost of Ongoing RRC Activities .................................................................... 101
Exhibit B-32. Present Value of NRC Implementation Cost ...................................................................... 101
Exhibit B-33. Present Value of NRC Operations Cost ............................................................................. 102
Exhibit B-34. Summary of Costs for Order EA-12-051 ............................................................................ 102

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page iv

Exhibit B-35. Present Value of Industry’s Implementation Cost .............................................................. 103
Exhibit B-36. Industry Implementation Cost: SFP Instrumentation .......................................................... 104
Exhibit B-37. Present Value of Industry’s Operations Cost ..................................................................... 104
Exhibit B-38. Industry Operations Cost: SFP Instrumentation during the Operating Period ................... 105
Exhibit B-39. Industry Operations Cost: SFP Instrumentation during the First 2 Years of
Decommissioning) ............................................................................................................................ 106
Exhibit B-40. Present Value of NRC’s Implementation Cost ................................................................... 106
Exhibit B-41. NRC Implementation Cost: SFP Instrumentation ............................................................... 106
Exhibit B-42. Present Value of NRC Operations Cost ............................................................................. 107
Exhibit B-43. NRC Operations Cost: SFP Instrumentation ...................................................................... 107
Exhibit B-44. Summary of Costs for Industry Initiatives ........................................................................... 108
Exhibit B-45. Present Value of Industry’s Implementation Cost for Industry Initiatives ........................... 109
Exhibit B-46. Industry Implementation Cost for Industry Initiatives: Exemption Analysis ........................ 109
Exhibit B-47. Industry Implementation Cost for Industry Initiatives: SAMGs Guidance........................... 110
Exhibit B-48. Industry Implementation Cost for Industry Initiatives: Phase 1 Staffing ............................. 110
Exhibit B-49. Industry Implementation Cost for Industry Initiatives: Multiple Source Term Dose
Assessment....................................................................................................................................... 111
Exhibit B-50. Present Value of Industry’s Operations Cost for Industry Initiatives .................................. 112
Exhibit B-51. Industry Operations Cost for Industry Initiatives: Multiple Source Term Dose Assessment
(During the Operating Period) ........................................................................................................... 112
Exhibit B-52. Industry Operations Cost for Industry Initiatives: Multiple Source Term Dose Assessment
(During the First 2 Years of Decommissioning) ................................................................................ 113
Exhibit B-53. Present Value of NRC Implementation Cost for Industry Initiatives ................................... 113
Exhibit B-54. NRC Implementation Cost for Industry Initiatives: Exemption Analysis ............................. 114
Exhibit B-55. NRC Implementation Cost for Industry Initiatives: Phase 1 Staffing .................................. 114
Exhibit B-56. NRC Implementation Cost for Industry Initiatives: Multiple Source Term Dose Assessment
.......................................................................................................................................................... 115
Exhibit B-57. Present Value of NRC’s Operations Cost .......................................................................... 115
Exhibit B-58. NRC Implementation Cost for Industry Initiatives: Multiple Source Term Dose Assessment
.......................................................................................................................................................... 115

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Appendices
Appendix A: Backfitting and Issue Finality
Appendix B: Historical Cost Analysis
Appendix C: Detailed Cost Build-up for the Operating License Term
Appendix D: Detailed Cost Build-up for the Decommissioning Term
Appendix E: Order EA-12-049 Costs – BWR 1-Unit Site
Appendix F: Order EA-12-049 Costs – BWR 2-Unit Site
Appendix G: Order EA-12-049 Costs – BWR 3-Unit Site
Appendix H: Order EA-12-049 Costs – PWR 1-Unit Site
Appendix I: Order EA-12-049 Costs – PWR 2-Unit Site
Appendix J: Order EA-12-049 Costs – PWR 3-Unit Site
Appendix K: Order EA-12-049 Costs – AP1000 2-Unit Site
Appendix L: Order EA-12-049 – NRC Costs
Appendix M: Order EA-12-049 – Equipment and Supplies Unit Cost References

Page v

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page vi

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page 1

Executive Summary
The U.S. Nuclear Regulatory Commission (NRC) is proposing to amend Title 10 of the Code of
Federal Regulations (10 CFR) to accomplish four objectives: (1) make the requirements in
Order EA-12-049, Order Modifying Licenses with Regard to Requirements for Mitigation
Strategies for Beyond-Design-Basis External Events, and Order EA-12-051, Order Modifying
Licenses with Regard to Reliable Spent Fuel Pool Instrumentation, generically applicable;
(2) establish requirements for an integrated response capability; (3) incorporate other
Fukushima-related actions intended to enhance the onsite emergency response capabilities for
multi-unit events into the regulations; and (4) address a number of petitions for rulemaking
(PRMs) submitted to the NRC following the March 2011 Fukushima Dai-ichi event (Refs. 1 and
2). To achieve these objectives, the proposed rulemaking would amend 10 CFR Parts 50 and
52 to require additional mitigation strategies for responding to beyond-design-basis events
(BDBEs) (Ref. 3).
The analysis presented in this document examines the benefits and costs of the proposed
Mitigation of Beyond-Design-Basis Events rule requirements relative to the baseline case
(i.e., the no action alternative). In addition, the NRC estimated the historical costs incurred as a
result of Order EA-12-049, Order EA-12-051, and related industry initiatives. See Appendix B
for the complete historical cost analysis.
The key findings are as follows:
•

Proposed Rule Analysis – Results. The proposed rule encompasses provisions that are
currently being implemented via Order EA-12-049 and Order EA-12-051 and related
industry initiatives. Because the NRC uses a no action baseline to estimate incremental
costs, the total cost of the proposed rule largely results from licensee’s review of the rule
to confirm compliance with the requirements (i.e., a comparison of the rule requirements
with the Orders and related industry initiatives and updates to procedures, programs, or
plans) because the proposed requirements are expected to be implemented prior to the
effective date of the rule. However, this regulatory analysis does not estimate the
impacts that may occur as a result of licensees needing to make changes to mitigation
strategies including potential plant modifications as a result of the need to address the
seismic and flooding reevaluated hazards for reasonable protection of the FLEX
equipment. As part of the proposed rule, the NRC is seeking external stakeholder
feedback to enable these impacts to be estimated.
As a result of the proposed rule, the NRC estimates that the industry as a whole would
incur a total one-time cost of $7.2 million to review the rule requirements as documented
in this regulatory analysis. The total present value of these costs is $7.2 million (using
either a 7 percent or 3 percent discount rate) over a 63-year period.
The average site would incur a one-time cost of approximately $110,000.
The proposed rule would result in incremental costs to the NRC of $940,000 (using a 7
percent discount rate) or $910,000 (using a 3 percent discount rate). These costs result
from the NRC’s activities to complete the rulemaking (i.e., complete the proposed rule,
analyze public comments, hold public meeting(s), and develop the final rule and
regulatory guidance).

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page 2

According to Executive Order 12866, Regulatory Planning and Overview, (58 FR 190),
an economically significant regulatory action is one that would have an annual effect on
the economy of $100 million or more (Ref. 4). This proposed rulemaking does not reach
this threshold because the annualized cost of the proposed rule would be $580,000
using a 7 percent discount rate and $290,000 using a 3 percent discount rate.
•

Benefits. The proposed rule requirements (i.e., making Order requirements and industry
initiatives generically applicable) are drawn from stakeholder feedback and lessons
learned from the implementation of Order EA-12-049 and Order EA-12-051, including
any challenges or unintended consequences associated with the implementation. These
regulatory requirements would result in enhanced regulatory efficiency by providing a
predictable and stable set of regulations for future designs and applications, so as to
avoid the need for issuance of Orders or license conditions and introduce regulatory
stability.

•

Historical Cost Analysis – Results. For informational purposes, the NRC also estimated
the costs that have been incurred (or will be incurred) as a result of Order EA-12-049,
Order EA-12-051, and related industry initiatives (see Appendix B). The NRC estimates
that these actions result in a total present value cost of $1.9 billion (using a 7 percent
discount rate) and $2.3 billion (using a 3 percent discount rate).
The average site incurred an upfront cost of approximately $29 million, followed by
annual costs of approximately $170,000.

•

Decision Rationale. Relative to the no action baseline, the NRC concludes that the
costs of this proposed rule are justified.

•

Backfit Analysis. The NRC determined that the provisions in the proposed rule that
would make the requirements in Order EA-12-049, Order EA-12-051, and industry
initiatives (as applied to existing licensees and construction permit (CP) holders to whom
Order EA-12-049 and Order EA-12-051 was directed) generically applicable would not
constitute a new instance of backfitting under 10 CFR 50.109 (with one exception as
noted below), or an additional inconsistency with the issue finality provisions applicable
to holders of COLs in 10 CFR 52.98. Any backfitting and issue finality issues for this
portion of the proposed rulemaking were addressed as part of the issuance of Order EA12-049 and Order EA-12-051. The proposed requirements limited to mitigation
measures in Order EA-12-049, Order EA-12-051, and industry initiatives, would
introduce no new backfitting and issue finality matters apart from those addressed in the
underlying Orders. Therefore, the staff’s position is that the NRC’s consideration of
backfitting and issue finality matters for the Orders also serves as the NRC’s
consideration of the same backfitting and issue finality matters for the proposed rule with
respect to mitigation measures and SFP level instrumentation.
The proposed rule requirements that would require multiple source term dose
assessment constitute backfits, but are justified under backfitting requirements.
Appendix A details the NRC’s conclusions for these requirements.

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Abbreviations
ABWR
ac
ADAMS
AFW
AP1000
ASI
BDBE
BDBEE
BLS
BWR
BWROG
CFR
COL
CP
CPRR
CRGR
CST
CVCS
CWRT
DC
dc
DG
EDG
EDMGs
EFW
ELAP
EOPs
EPGs
EPRI
ERDS
ERO
ESBWR
ESW
EWST
FENOC
FLEX
FSGs
GDC
GL
gpm
HPCI
HPCS
ILCF
INSAG
IPE
ISAP
ISG
JLD
L&T
LOE
LOOP
LUHS
MCC
ML

Advanced boiling-water-reactor
Alternating current
Agencywide Documents Access and Management System
Auxiliary feedwater
Advanced pressurized 1000 reactor
Alternate seal injection
Beyond-design-basis event
Beyond-design-basis external event
Bureau of Labor Statistics
Boiling-water-reactor
BWR owners group
Title 10 of the Code of Federal Regulations
Combined license
Construction permit
Containment protection and release reduction
Committee to Review Generic Requirements
Condensate storage tank
Chemical and volume control system
Clean water receiver tank
Design certification
Direct current
Diesel generator
Emergency diesel generator
Extensive damage mitigation guidelines
Emergency feedwater
Extended loss of ac power
Emergency operating procedures
Emergency procedure guidelines
Electric Power Research Institute
Emergency Response Data System
Emergency Response Organization
Economic simplified boiling-water-reactor
Essential service water
Emergency water storage tank
FirstEnergy Nuclear Operating Company
Diverse and flexible coping strategies
FLEX Support Guidelines
General Design Criteria
Generic letter
Gallons per minute
High-pressure coolant injection
High-pressure core spray
Individual latent cancer fatality
International Safety Advisory Group
Individual plant examination
Integrated Safety Assessment Program
Interim Staff Guidance
Japan Lessons-Learned Project Directorate
Logistics and transportation
Level of effort
Loss of offsite power
Loss of normal access to the ultimate heat sink
Motor control center
Manufacturing license

Page 3

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events
NEI
NLO
NPP
NRC
NSRC
NSSS
NTTF
OIP
PRM
PRA
PWR
PWROG
QHO
RCIC
RCP
RCS
RHR
RMWST
RPV
SA
SAFER
SAG
SAMG
SAMGs
SAT
SBO
SBOMS
SCC
SDA
SFP
SG
SRM
SSC
SW
TBR
TI
UDM

Nuclear Energy Institute
Non-licensed operator
Nuclear power plant
Nuclear Regulatory Commission
National SAFER response center
Nuclear steam supply system
Near-Term Task Force
Overall Integrated Plan
Petition for rulemaking
Probabilistic risk assessment
Pressurized-water-reactor
PWR owners group
Quantitative health objective
Reactor core isolation cooling
Reactor coolant pump
Reactor coolant system
Residual heat removal
Reactor makeup water storage tank
Reactor pressure vessel
Staging area
Strategic Alliance for FLEX Emergency Response
Severe accident guidelines
Severe accident management guideline
Severe accident management guidelines
Systems approach to training
Station blackout
Station blackout mitigation strategies
SAFER control center
Standard design approval
Spent fuel pool
Steam generator
Staff requirements memoranda
Structure, system, and component
Service water
Technical Basis Report
Temporary Instruction
Ultimate decision maker

Page 4

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page 5

Introduction

This document presents the draft regulatory analysis of the proposed Mitigation of BeyondDesign-Basis Events rulemaking. This introduction is divided into two sections: Section 1.1
provides background information on the rulemaking; and Section 1.2 states the problem and the
objectives for the proposed rulemaking.

1.1

Background

The events of March 11, 2011, at the Fukushima Dai-ichi Nuclear Power Plant (NPP) site
highlighted the possibility that extreme natural phenomena could challenge the prevention,
mitigation, and emergency preparedness defense-in-depth layers that are currently in place
under the U.S. Nuclear Regulatory Commission’s (NRC) regulatory framework. The
magnitude 9.0 earthquake and resulting tsunami inundated the Fukushima Dai-ichi site and
resulted in a loss of alternating current (ac) electrical power, creating a station blackout (SBO).
The SBO caused operators to lose the ability to cool the fuel in three of the six reactors and
resulted in damage to the nuclear fuel shortly after the loss of cooling capabilities.
Following the Fukushima Dai-ichi event, the NRC Chairman at the time, Gregory Jaczko,
directed the NRC, through tasking memorandum COMGBJ-11-0002, NRC Actions Following the
Events in Japan, to conduct a review of the NRC’s processes and regulations to determine if
any changes needed to be made and to make recommendations based on their findings (Ref.
5). The Near-Term Task Force (NTTF) was created in response to the tasking memorandum.
The NTTF’s Recommendations for Enhancing Reactor Safety in the 21st Century (SECY-110093) called for the NRC to: (1) strengthen SBO mitigation capability at all operating and new
reactors for design-basis events and beyond-design-basis events (BDBEs); (2) enhance spent
fuel pool (SFP) makeup capability and instrumentation for the SFP; (3) strengthen and integrate
onsite emergency response capabilities such as emergency operating procedures (EOPs),
severe accident management guidelines (SAMGs), and extensive damage mitigation guidelines
(EDMGs); (4) require facility emergency plans to address prolonged SBO and multi-unit events;
(5) pursue additional emergency protection topics related to multi-unit events and prolonged
SBO; and (6) pursue emergency management topics related to decision making, radiation
monitoring, and public education (Ref. 6).
Following the issuance of the NTTF report, the NRC developed recommendations for the
Commission’s consideration. In response, in Staff Requirements Memorandum (SRM)-SECY11-0124, Recommended Actions to be Taken Without Delay From the Near-Term Task Force
Report and SRM-SECY-11-0137, Prioritization of Recommended Actions to be Taken in
Response to Fukushima Lessons Learned, the Commission directed the staff to initiate a highpriority rulemaking for SBO regulatory actions and Onsite Emergency Response Capabilities
regulatory actions (Refs. 7 and 8).
On February 17, 2012, the NRC provided SECY-12-0025, Proposed Orders and Requests for
Information in Response to Lessons Learned from Japan’s March 11, 2011, Great Tohoku
Earthquake and Tsunami, to the Commission, including the proposed Order to implement
enhanced mitigation strategies (Ref. 9). As directed by SRM-SECY-12-0025, on
March 12, 2012, the NRC issued Order EA-12-049 and Order EA-12-051. Order EA-12-049
imposed new requirements to implement mitigation strategies to provide additional capability to
respond to beyond-design-basis external events (BDBEEs) that lead to an extended loss of
ac power (ELAP) and loss of normal access to the ultimate heat sink (LUHS) (e.g., events
arising from severe natural phenomena). The Commission concluded that the new

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page 6

requirements were necessary to continue to have reasonable assurance of adequate protection
of public health and safety. Order EA-12-051 required power reactor licensees to have a
reliable means of remotely monitoring wide-range SFP levels to support effective prioritization of
event mitigation and recovery actions in the event of a BDBEE. The Commission concluded
that the new requirements provided a greater capability, consistent with the overall
defense-in-depth philosophy, and therefore greater assurance of protection of public health and
safety from the challenges posed by BDBEEs to power reactors.
Following the imposition of the Orders, the NRC began work on two proposed rulemakings as
directed by the Commission: the Station Blackout Mitigation Strategies (SBOMS) proposed
rulemaking and Onsite Emergency Response Capabilities proposed rulemaking. During
development of the proposed rulemakings, the NRC identified that the Onsite Emergency
Response Capabilities rulemaking could not be issued before the SBOMS proposed rulemaking
because it would need to reference the proposed SBOMS requirements. The NRC also
identified several areas of overlap between the two proposed rules. The direct links between
these post-Fukushima proposed rulemakings caused the NRC to conclude that they should be
combined into a single proposed rulemaking package.
In response to a request from the NRC in SECY-14-0046, Proposal to Consolidate
Post-Fukushima Rulemaking Activities, enclosure 6, the Commission agreed, in SRM dated
July 9, 2014, to consolidate the SBOMS and Onsite Emergency Response Capabilities
rulemakings (Ref. 10). The combined scope of this proposed rulemaking, described in terms of
the relationship to various NTTF recommendations that provided the regulatory impetus for the
proposed rulemaking, would include:
1. All the requirements that were within the scope of the SBOMS rulemaking, directed by
COMSECY-13-0002, Consolidation of Japan Lessons Learned Near-Term Task Force
Recommendations 4 and 7 Regulatory Activities (Ref. 11). This portion of the proposed
rulemaking stems from NTTF Recommendations 4 and 7, and is intended, in part, to
make the requirements of Order EA-12-049 and Order EA-12-051 (and equivalent
license conditions) generically applicable.
2. All the requirements that were within the scope of the Onsite Emergency Response
Capabilities rulemaking. This portion of the proposed rulemaking stems from NTTF
Recommendation 8, and was directed by SRM-SECY-11-0137 (Ref. 8). This includes
command and control issues, and as such, addresses NTTF Recommendation 10.2
concerning command and control and the qualifications of decision makers. Command
and control is being addressed in supporting draft regulatory guidance for this proposed
rulemaking including Nuclear Energy Institute (NEI) 14-01, Emergency Response
Procedures and Guidelines for Extreme Events and Severe Accidents, Rev. 0 (Ref. 12).
3. Numerous emergency preparedness actions are addressed within this proposed
rulemaking. These emergency preparedness actions are currently being implemented in
conjunction with the implementation of Order EA-12-049, and through the development
of guidance supporting this proposed rulemaking. Specifically those regulatory actions
and the associated NTTF Recommendations from which they stem, are:
a. Staffing and communications issues in this proposed rulemaking stem from
NTTF Recommendation 9.3, and are also discussed in NTTF
Recommendations 9.1 and 9.2. These regulatory issues are currently being
addressed through Order EA-12-049 implementation guidance; specifically

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

Page 7

NEI 12-01 which is referenced in NEI 12-06, Rev 0, Diverse and Flexible Coping
Strategies (FLEX) Implementation Guide, currently endorsed by the NRC in
Japan Lessons-Learned Project Directorate-Interim Staff Guidance (JLD-ISG)12-01, Compliance with Order EA-12-049, Order Modifying Licenses with Regard
to Requirements for Mitigation Strategies for Beyond-Design-Basis External
Events (Refs. 13 and 14). The draft supporting guidance for this proposed
rulemaking includes this guidance.
b. Facilities and equipment issues addressed in this proposed rulemaking stem
from NTTF Recommendation 9.3, and are also discussed in NTTF
Recommendations 9.1 and 9.2. These regulatory issues are currently being
addressed through Order EA-12-049 implementation guidance. These issues
are addressed by draft guidance for this proposed rulemaking which includes
NEI 13-06, Enhancements to Emergency Response Capabilities for Beyond
Design Basis Accidents and Events, Rev. 0 (Ref. 15).
c. Multiple Source Term Dose Assessments addressed in this proposed rulemaking
stem from NTTF Recommendation 9.3, and are also discussed in NTTF
Recommendation 9.1. This regulatory issue is being voluntarily implemented by
industry, and is also addressed by draft guidance for this proposed rulemaking
which includes NEI 13-06, Rev 0.
d. Training and drills or exercise issues addressed in this proposed rulemaking
stem from NTTF Recommendation 9.3, and are also discussed in NTTF
Recommendations 9.1 and 9.2. These regulatory issues are currently being
addressed through Order EA-12-049 implementation guidance. These issues
are addressed by draft guidance for this proposed rulemaking which includes
NEI 13-06, Rev 0.
e. Onsite emergency resources to support multi-unit events with SBO, including the
need to deliver equipment to the site with offsite infrastructure degraded, stem
from NTTF Recommendation 11.1. This is a regulatory issue currently being
addressed by Order EA-12-049 implementation. This issue is addressed by draft
guidance for this proposed rulemaking.
Accordingly, this proposed rulemaking addresses, either in requirements or through
implementation guidance, all of the recommendations in NTTF Recommendations 4, 7, 8, 9.1,
9.2, 9.3 with one exception (maintenance of emergency response data system (ERDS)
capability throughout the accident), 10.2, and 11.1.1

The proposed rulemaking also addresses NTTF Recommendation 9.4 to modernize ERDS. This action differs
from the above list of regulatory actions because ERDS is not an essential component of a licensee’s capability
to mitigate a BDBE. However, ERDS is important for communication purposes between the licensee and the
NRC, and in some situations, other external stakeholders. The modernization has been voluntarily completed by
industry, and the NRC concluded it could readily be incorporated into this proposed rulemaking to amend the
technology-specific references in 10 CFR Part 50, Appendix E, Section VI, “Emergency Response Data System.”

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Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events

1.2

Page 8

Statement of the Problem and Nuclear Regulatory Commission
Objectives for the Rulemaking

The NRC has developed this proposed rulemaking, in large measure, to make generically
applicable the regulatory actions taken following the Fukushima event. With regard to FLEX
support guidelines (FSGs), current NRC regulations do not incorporate requirements to
implement mitigation strategies to provide additional capability to respond to events that could
lead to an ELAP (e.g., events arising from severe natural phenomena).2 A proposed rulemaking
would make generically applicable requirements similar to those imposed by Order EA-12-049,
Order EA-12-051, and other post-Fukushima industry initiatives. The regulatory objectives of
the proposed rulemaking are as follows:
•

Make the requirements in Order EA-12-049 and Order EA-12-051 generically applicable.
The rulemaking is intended to place the requirements in Order EA-12-049 and Order EA12-051 into the NRC’s regulations to provide regulatory clarity to operating reactors and
to ensure that they apply to all future power reactor applicants. Operating reactor
licensees and one combined license (COL) holder currently are subject to the Order
requirements. In addition, two COL holders were issued license conditions to implement
these requirements. In the absence of a rule, these requirements would need to be
implemented for new reactor sites through additional Orders or license conditions (as
was done for the Enrico Fermi Nuclear Plant Unit 3 [Fermi], Virgil C. Summer Nuclear
Station [V.C. Summer] Units 2 and 3, and Vogtle Electric Generating Plant [Vogtle] Units
3 and 4 COLs).
As part of the rulemaking process to make Order EA-12-049 and Order EA-12-051
generically applicable, the NRC considered stakeholder feedback and lessons learned
from the implementation of the Orders. As a result, the NRC considered unintended
consequences or challenges associated with implementation of the mitigation strategies
(consistent with Commission direction in an August 2012 SRM). These are captured in
the updated guidance for mitigation strategies. Pursuing rulemaking allows the NRC to
make the Order requirements generically applicable with adjustments to account for any
lessons learned. These adjustments would result in more effective regulation, but would
not extend beyond the footprint of the existing scope of the Orders. Once the resulting
proposed rule is implemented, the NRC may choose to withdraw Order EA-12-049 and
Order EA-12-051.

•

Establish requirements for an integrated response. An objective of the proposed
rulemaking is to establish requirements for an integrated response capability for BDBEs
that would integrate existing strategies and guidelines (implemented through guideline
sets) with the existing EOPs. This would include guideline sets that implement the
requirements of current § 50.54(hh)(2) and Order EA-12-049.

•

Incorporate enhanced onsite emergency response capabilities into the regulations.
Numerous enhanced onsite emergency response actions are being addressed as part of
this proposed rulemaking. These enhancements are being implemented in conjunction
with the implementation of Order EA-12-049, and through the development of guidance
supporting the onsite emergency response portion of this proposed rulemaking. These

In the context of the proposed Mitigation of Beyond-Design-Basis Events rulemaking, the term FSGs has
replaced the term SBOMS.

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Page 9

new requirements would address emergency response-related actions such as staffing
and communications (NTTF Recommendation 9.3, also addressed in NTTF
Recommendations 9.1 and 9.2), facilities and equipment (NTTF Recommendation 9.3,
also addressed in NTTF Recommendations 9.1 and 9.2), training and exercises (NTTF
Recommendation 9.3, also addressed in NTTF Recommendations 9.1 and 9.2),
command and control structure and decision-making qualifications (NTTF
Recommendation 10.2), and multiple source term dose assessment (NTTF
Recommendation 9.3, also addressed in NTTF Recommendation 9.1). Requiring
current and future licensees to meet these requirements would ensure robust
emergency response capabilities for BDBEs impacting multiple units.
To achieve these objectives, the proposed rulemaking would amend 10 CFR Part 50 and
Part 52 to require additional mitigation strategies for responding to BDBEs that is intended to
result in an integrated response capability that includes FSGs, EDMGs, and EOPs.

Identification and Preliminary Analysis of Alternative
Approaches

For historical purposes, in addition to the proposed rule (identified as Option 3), the NRC has
identified two alternatives for consideration.
•

Option 1: Take no action.

•

Option 2: Undertake rulemaking to require SAMGs and make Order EA-12-049,
Order EA-12-051, and industry initiatives generically applicable.

•

Option 3: Undertake rulemaking to make Order EA-12-049, Order EA-12-051, and
industry initiatives generically applicable.

The following sections provide a preliminary analysis of these options.

2.1

Option 1: Take No Action (Considered-Not Selected)

This alternative entails continuing the implementation of the mitigation strategies requirements
in Order EA-12-049, Order EA-12-051, and other related industry initiatives. No further
regulatory action would be taken to make the Order requirements generically applicable or to
consider stakeholder feedback and lessons learned from the implementation of these Orders.
This alternative is equivalent to the status quo and serves as a baseline to measure against the
other identified alternatives.
This option would avoid certain costs that the proposed rule would impose, while benefits
associated with voluntary initiatives would remain. However, under this option, the NRC would
need to address mitigation strategies requirements for new reactor sites on a case-by-case
basis (either through additional Orders or license conditions). As a result, this option would not
achieve the NRC’s objectives.

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Page 10

Option 2: Undertake Rulemaking to Require SAMGs and Make
Order EA-12-049, Order EA-12-051, and Industry Initiatives
Generically Applicable (Considered-Not Selected)

This option would address the NRC’s objective to make the requirements in Order EA-12-049,
Order EA 12-051, and industry initiatives generically applicable, while also requiring SAMGs.
Option 2 would make Order EA-12-049 and Order EA-12-051 generically applicable, and
incorporate industry initiatives into 10 CFR. The NRC regulations do not currently contain
requirements for the mitigation of BDBEEs as addressed by Order EA-12-049, or for SFP widerange level as addressed by Order EA-12-051. The strategies required by the Orders (which
sites are currently implementing in conjunction with numerous onsite emergency response
initiatives) are intended to add multiple ways to maintain or restore core cooling, containment,
and SFP cooling capabilities in order to improve the defense-in-depth of licensed nuclear power
reactors. The Commission directed the staff to pursue rulemaking that would incorporate the
Order requirements into NRC regulations to ensure that future NPP designs and licensing
applications are subject to the same requirements as current operating sites and COL holders.
SAMGs are currently voluntary industry initiatives, which are implemented when an accident
leads to fuel damage. Industry updated the generic SAMG technical work to reflect lessons
learned from the Fukushima event. This option would require licensees to update their sitespecific SAMGs and maintain the SAMGs within the plant configuration management program.
The proposed SAMGs would be supported with requirements that include command and
control, change control, drills and exercises, and training. The SAMGs would be one of the
three guideline sets that would be integrated with the existing EOPs to provide for an integrated
response capability.
Under this option, the proposed rule would impose costs on industry and the NRC. Licensees
would be required to develop, implement, and maintain site-specific SAMGs, for which the NRC
would have to develop oversight materials. Supporting provisions of the proposed rule would
impose costs associated with integrating site-specific emergency procedures, updating
organizational structures for command and control, and developing change control procedures.
During the proposed rule development process, the NRC made several adjustments to Option 2
in order to minimize costs to licensees, without sacrificing benefits. This effort stems in part
from the NRC making use of the risk insights obtained from its backfitting analysis to structure a
proposed framework for SAMGs requirements that minimized the resultant regulatory impact on
licensees. For example, the NRC originally intended to propose more intensive requirements
for SAMGs trainings that would result in a required effort similar to that of existing
EOP trainings. However, after hearing stakeholder feedback during a public meeting, the NRC
revised the proposed SAMGs training requirement to be consistent with the systems approach
to training (SAT) process instead. The SAT process is well-established and meets the NRC’s
regulatory objectives while reflecting lessons learned through engagement with stakeholders.
In addition, the NRC considered requiring the integration of additional procedures (e.g., firefighting procedures, alarm response procedures, abnormal operating procedures) with the
strategies and guidelines in the proposed rule. However, the NRC determined that the existing
regulations governing these procedures are adequate, and there is no demonstrated need for
mandatory integration. A more comprehensive procedure integration requirement would have
increased costs while providing little to no benefits.

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2.3

Page 11

Option 3: Undertake Rulemaking to Make Order EA-12-049,
Order EA-12-051, and Industry Initiatives Generically Applicable
(NRC Selected)

Because the provisions associated with SAMGs and SAMGs-related activities would impose
additional costs on industry and the NRC, and the available risk insights indicated that the
backfit requirements of 10 CFR 50.109 may not be satisfied for Option 2, the NRC considered
and subsequently selected a rulemaking option omitting all the SAMGs-related requirements.
Option 3 (i.e., the proposed rule) would address the NRC’s objective to make the requirements
in Order EA-12-049, Order EA-12-051, and industry initiatives generically applicable. The
proposed rule would ensure that future NPP licensing applications are subject to the same
requirements as current operating sites and COL holders without the need for additional Orders
or license conditions. Option 3 also would allow the NRC to consider stakeholder feedback and
lessons learned from the implementation of these Orders and would provide regulatory clarity to
operating reactors.
Option 3 would be less costly relative to Option 2, and because Option 2 (with inclusion of the
SAMGs as part of the integrated response capability) was judged not to satisfy the backfitting
requirements of 10 CFR 50.109(a)(3) as discussed later in this regulatory analysis and in detail
in Appendix A, Option 3 was chosen.
Section 3 presents the results of the NRC’s detailed cost-benefit analysis of all three options.

2.4

Non-rulemaking Alternatives

The NRC did not consider non-rulemaking approaches, such as voluntary initiatives, NRC
guidance, and generic communications (e.g., Information Notices, Regulatory Information
Summaries, Generic Letters) in the regulatory basis (and by extension in this regulatory
analysis) for two reasons. First, in SRM-SECY-11-0124 and SRM-SECY-11-0137, the
Commission directed the staff to initiate a rulemaking for SBO regulatory actions and onsite
emergency response capabilities and designated the rulemakings as “high-priority.” Further, a
non-rulemaking approach would not achieve the NRC’s objective to make Order EA-12-049,
Order EA-12-051, and industry initiatives generically applicable and, at the same time,
incorporate stakeholder feedback and lessons learned from implementation, including any
challenges or unintended consequences. Non-rulemaking approaches would not achieve the
broad applicability of a rulemaking, and therefore would not be appropriate to address the
NRC’s objectives.

Estimation and Evaluation of Benefits and Costs:
Presentation of Results

This section describes the NRC’s approach to estimating costs and benefits, and presents the
results of the analysis:
•
•
•

Section 3.1 details the methodology, assumptions, and baseline used to evaluate the
costs and benefits associated with the options considered in the regulatory analysis.
Section 3.2 summarizes the costs and benefits associated with the options.
Section 3.3 presents the details of the costs associated with Option 2 (not selected) and
Option 3 (the proposed rule).

Regulatory Analysis:
Proposed Rulemaking to Address Mitigation of Beyond-Design-Basis Events
•
•
•

3.1

Page 12

Section 3.4 discusses the benefits of Option 2 (not selected) and Option 3 (the proposed
rule).
Section 3.5 provides a discussion of the disaggregated results.
Section 3.6 discusses the sensitivity analysis.

Methodology and Assumptions

This section explains the process used to evaluate the costs and benefits associated with the
rulemaking options, consistent with the guidance provided in NUREG/BR-0058, Regulatory
Analysis Guidelines of the U.S. Nuclear Regulatory Commission (Ref. 16). The benefits include
any desirable changes in affected attributes (e.g., monetary savings, improved safety, improved
security), while the costs include any undesirable changes in affected attributes (e.g., monetary
costs, increased exposures).
The NRC analyzes costs and benefits according to a “no action” baseline. The no action
baseline includes the historical costs incurred by industry and the NRC to implement Order EA12-049, Order EA-12-051, and industry initiatives. The NRC estimates all of the incremental
costs and benefits resulting from the proposed rule requirements that would be incurred
beginning in 2017, the year the proposed rule is assumed to become effective.
In addition, the NRC estimated the historical costs associated with Order EA-12-049, Order EA12-051, and industry initiatives. Appendix B discusses the methodology and results of the
historical cost analysis.

Affected Universe
The regulatory options under consideration would affect all NPP licensees at the site-level.
However, the costs affecting individual sites differ depending on various characteristics
(e.g., type of reactor, design, and nuclear steam supply system (NSSS)). The differences in
cost are discussed in more detail in Section 3.3.
The NRC estimates the costs incurred by 60 operating sites and 5 decommissioning sites (i.e.,
Crystal River, Kewaunee, Oyster Creek,3 San Onofre, and Vermont Yankee). Incremental costs
to the five decommissioning sites are not considered in the regulatory analysis under Option 2
(not selected). Proposed 10 CFR 50.155(a)(3) would enable decommissioning licensees to
discontinue compliance with portions of the proposed rule, with the exception of proposed
10 CFR 50.155(b)(2), EDMGs, which would not impose incremental costs because EDMGs are
existing requirements under the no action baseline. To satisfy proposed 10 CFR 50.155(a)(3),
the licensee would be required to prepare and retain an analysis demonstrating that the decay
heat of the fuel in the SFP is removed solely by heating and boiling of water within the SFP and
the boil-off period provides sufficient time for the licensee to obtain offsite resources (referred to
as an “exemption analysis” in the regulatory analysis). The NRC assumes that the five currently
decommissioning sites have submitted, or will soon submit, the exemption analysis and will
therefore not incur incremental costs. Appendix B details the historical costs that will be
incurred by current decommissioning sites prior to the effective date of the proposed rule.

Oyster Creek has announced intentions to decommission in 2019, which is likely to occur prior to the end of the
rule implementation period estimated to occur in 2019.

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Page 13

Of the 60 operating sites included in the analysis, 22 are boiling-water-reactor (BWR) sites and
38 are pressurized-water-reactor (PWR) sites. Exhibit 3-1 lists BWR and PWR operating and
new reactor sites that are included in the universe of affected entities under this analysis. The
AP1000 reactor units are under construction at two of the operating sites (i.e., V.C. Summer and
Vogtle). Because incremental costs are estimated at the site-level, the new units are accounted
for as part of the operating site on which they are located. However, the difference in reactor
types on the V.C. Summer and Vogtle sites does affect the costs incurred by the sites, and the
timeline over which costs are incurred. Section 3.3 provides additional detail regarding the cost
analysis for each type of site.
For Option 2 of this regulatory analysis where the option of requiring SAMGs was considered
and rejected by the Commission, for cost estimating purposes, each of these affected sites has
been identified as either a single-SAMGs site or a dual-SAMGs site. Costs for certain SAMGsrelated activities (i.e., developing, implementing, maintaining, and updating site-specific SAMGs;
developing and updating training materials; attending and documenting training; developing new
training and exercise scenarios; and conducting drills and exercises) differ depending on
whether an operating site has one or two sets of SAMGs. Single-SAMGs sites have one set of
guidelines for severe accident management, while dual-SAMGs sites have two sets of
guidelines for severe accident management. The NRC assumes that single-SAMGs sites are
single-unit sites, or multi-unit sites with one reactor, design, and NSSS types. Similarly, the
NRC assumes that dual-SAMGs sites are multi-unit sites with different reactor, design, or NSSS
types.4

The NRC considered vintage as another cost variation that could affect SAMGs-related costs. According to the
NRC’s assessment, one site (i.e., Beaver Valley) has units of different vintages. The NRC treats this site as
single-SAMGs sites, and not dual-SAMGs sites, because even with different vintages, the NRC believes costs
for these two sites would be more similar to single-SAMGs sites rather than dual-SAMGs sites.

Regulatory Analysis:
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Page 14

Exhibit 3-1. List of Operating PWR and BWR Sites
PWR Sites
Arkansas Nuclear One
Millstone
Virgil C. Summer
Vogtle
Beaver Valley
Braidwood
Byron
Callaway
Calvert Cliffs
Catawba
Comanche Peak
Davis-Besse
Diablo Canyon
Donald C. Cook
Fort Calhoun Station
H. B. Robinson
Indian Point
Joseph M. Farley
McGuire
North Anna
Oconee
Palisades
Palo Verde
Point Beach
Prairie Island
R.E. Ginna
Salem
Seabrook
Sequoyah
Shearon Harris
South Texas Project
St. Lucie
Surry
Three Mile Island
Turkey Point
Waterford
Watts Bar
Wolf Creek
38 Sites

BWR Sites
Nine Mile Point
Browns Ferry
Brunswick
Clinton
Columbia
Cooper
Dresden
Duane Arnold
Edwin I. Hatch
Fermi
Grand Gulf
Hope Creek
James A. FitzPatrick
LaSalle County
Limerick
Monticello
Peach Bottom
Perry
Pilgrim
Quad Cities
River Bend
Susquehanna

22 Sites

The NRC identified five operating sites as dual-SAMGs sites (i.e., Arkansas Nuclear One,
Millstone, Nine Mile Point, V.C. Summer, and Vogtle). Exhibit 3-2 provides the number of
single-SAMGs and dual-SAMGs sites by reactor type. These sites are mentioned for historical
purposes since Option 2 was not selected.

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Page 15

Exhibit 3-2. Operating Site Counts by SAMGs and Reactor Type
Number of SingleSAMGs Sites

Number of DualSAMGs Sites

Total Number of
Sites

BWR

PWR

55 Sites

5 Sites

60 Sites

Total Sites

Exhibit 3-3 provides information on the COL applications that the NRC has received to date.
The NRC assumes that no additional COL applications will be submitted over the next 10 years
that would be affected by the alternatives. The staff considered forecasts beyond 2025 as too
speculative for this analysis.
Exhibit 3-3. COL Applications that Reference Reactor Designs
Proposed New Reactor(s)

Design

Bell Bend Nuclear Power
Plant
Bellefonte Nuclear Station,
Units 3 and 4
Callaway Plant, Unit 2

U.S. EPR

Calvert Cliffs, Unit 3

U.S. EPR

Comanche Peak, Units 3
and 4
Fermi, Unit 3
Grand Gulf, Unit 3
Levy County, Units 1 and 2
Nine Mile Point, Unit 3

U.S. EPR
AP1000

US-APWR
ESBWR
ESBWR
AP1000
U.S. EPR

COL Applicant
PPL Bell Bend, LLC

Status
Under review

Tennessee Valley Authority

Suspended

AmerenUE
Calvert Cliffs 3 Nuclear Project, LLC and
UniStar Nuclear Operating Services, LLC
Luminant Generation Company, LLC
(Luminant)
Detroit Edison Company
Entergy Operations, Inc.
Progress Energy Florida, Inc. (PEF)
Nine Mile Point 3 Nuclear Project, LLC
and UniStar Nuclear Operating Services,
LLC (UniStar)
Dominion Virginia Power (Dominion)
Entergy Operations, Inc.

Suspended
Withdrawn
Suspended
Completed
Suspended
Under Review
Withdrawn

North Anna, Unit 3
ESBWR
Under Review
River Bend Station, Unit 3
ESBWR
Suspended
Shearon Harris, Units 2 and
AP1000
Progress Energy Carolinas, Inc.
Suspended
3
South Texas Project Nuclear Operating
South Texas Project, Units
Under Review
ABWR
Company (STPNOC)
3 and 4
Turkey Point, Units 6 and 7
AP1000
Florida Power and Light Company
Under Review
Victoria County Station,
ESBWR
Exelon Nuclear Texas Holdings, LLC
Withdrawn
Units 1 and 2
William States Lee III,
AP1000
Duke Energy
Under Review
Units 1 and 2
*Values from U.S. NRC webpage, “Combined License Applications for New Reactors,” updated as of
August 11, 2015, retrievable at http://www.nrc.gov/reactors/new-reactors/col.html.

The COL applications that reference reactor designs with issued design certifications (DCs;
i.e., AP1000, ESBWR, or ABWR) will have no incremental cost differences for submitting
information required in their application or for the NRC review of that information. Incremental
licensing costs for this proposed rule would only apply to applicants for new nuclear power

Regulatory Analysis:
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Page 16

designs. Exhibit 3-4 summarizes the review status of known COL applicants whose application
will reference a new reactor design.
Exhibit 3-4. Number of COL Applications that Reference New Reactor Designs
No. of COL Applications by Review Status a
New Reactor Design

Under Review

Suspended

Withdrawn
•

AREVA (U.S. EPR)

Bell Bend
–

•

Callaway
Plant Unit 2

•

Comanche
Peak Unit 3
Comanche
Peak Unit 4

•

Nine Mile
Point Unit 3
Calvert Cliffs
Unit 3 c

Mitsubishi Heavy
Industries (US-APWR)

–

KHNP (APR1400)

–

NuScale Power (NuScale)

–

a.
b.
c.

•

Future COLAs

•

–

The NRC assumes no additional COL applications for this regulatory analysis.
The safety portion of the COL application review was suspended in January 2014 at the request of
the applicant. For purposes of this analysis, this application is excluded from this analysis.
The COL application review was suspended in February 2015 (Agencywide Documents and Access
and Management System (ADAMS) Accession No. ML15062A050) at the request of the applicant
and is excluded from this analysis.

For the reasons cited, the affected universe in this regulatory analysis does not include any
incremental costs for current and future license applicants.5

Cost Estimation
All costs presented in this analysis are in 2013 dollars.
In order to estimate the costs associated with the proposed rule, the NRC used a work
breakdown approach to deconstruct the proposed rule requirements according to required
activities. For each required activity, the NRC further sub-divided the work across labor
categories (i.e., executive, manager, staff, clerical, licensing). The NRC estimated the required
level of effort (LOE) for each labor category for each required activity in order to develop a
bottoms-up cost estimate.
The NRC gathered data from several sources and consulted industry experts to develop LOE
and unit cost estimates. Mean hourly wage rates for various industry labor categories were
derived from 2013 Occupational Employment and Wages data. As per NUREG/CR-4627,
Generic Cost Estimates, direct wage rates are loaded using a multiplier of 2 to account for
licensee and contractor labor and overhead (i.e., fringe, benefits, general administration, and
profit) (Ref. 17). Exhibit 3-5 presents the wage rates used throughout this analysis.
5

Because current COL applicants (i.e., Bell Bend, Lee, and Levy) have not announced an intention to construct
and operate a new reactor, costs for these applicants to develop and maintain SAMGs or costs associated with
the integrated response capability, additional equipment, training requirements, drills and exercises, and the
emergency preparedness requirements are not quantified.

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Page 17

Exhibit 3-5. Wage Rate Estimates by Labor Category
Labor Category

Mean Wage Rate

Loaded Wage
Factor
B

Loaded Wage Rate

A
C=AxB
Industry Executives
$79.82
$159.63
Industry Managers
$52.11
$104.21
2
Industry Staff
$41.93
$83.85
Industry Clerical Staff
$26.34
$52.68
Industry Licensing Staff
$64.36
$128.71
NRC
$124.00
*The loaded wage rates for Industry Managers, Industry Staff, and Industry Licensing Staff are based on
those used in a related NRC regulatory analysis.
**The mean wage rate for Industry Executives was calculated as the average of the mean hourly wage (in
the Electric Power Generation, Transmission, and Distribution Industry) for Top Executives (SOC 11-1011)
and Chief Executives (SOC 11-0000) from the Bureau of Labor Statistics (BLS).
***The mean wage rate for Industry Clerical Staff was calculated as the average of the mean hourly wage
(in the Electric Power Generation, Transmission, and Distribution Industry) for Office and Administrative
Support Occupations (SOC 43-0000), Office Clerks, General (SOC 43-9061), and First-line Supervisors of
Office and Administrative Support Workers (SOC 43-1011) from BLS.
****The NRC staff labor rates are estimated to be $124 per hour and are calculated based on actual labor
and benefit costs from the prior fiscal year detailed by office and grade.

Cost Estimation Methods
The NRC applied several cost estimation methods in this analysis. Many costs were estimated
using expert opinion, which relies on the NRC’s professional knowledge and judgment. The
NRC consulted industry experts within and outside of the agency to develop most of the LOE
estimates used in the analysis. For example, the NRC referred to industry comments in
response to the Onsite Emergency Response Capabilities Advance Notice of Proposed
Rulemaking (77 FR 23161) to inform the LOE estimates used for developing site-specific
SAMGs.
Some cost activities were estimated using extrapolation, which relies on actual past or current
costs to estimate the future cost of similar activities. The NRC extrapolated LOE estimates from
existing NRC documentation and licensee submittals to estimate the LOE of the proposed rule’s
required activities. For example, the NRC reviewed exemption analyses already submitted by
licensees to extrapolate the cost of this activity under the proposed rule.
Some activities were estimated using the engineering build-up method of cost estimation, which
combines incremental costs of an activity from the bottom-up to estimate a total cost. For
instance, under Option 2 (not selected), the NRC built up the dual-SAMGs costs based on the
costs associated with single-SAMGs. In these cases, the NRC assumed that dual-SAMGs sites
would require roughly twice the effort of single-SAMGs sites to develop, implement, and
maintain SAMGs as well as to comply with SAMGs-related activities.
Finally, other costs were developed relying on the method of analogy, which compares similar
activities in order to estimate costs. Some examples of cost activities that were estimated using
the analogy method include the Option 2 effort required to develop new SAMGs training and the
cost to the NRC to observe drills and exercises. The NRC considered the costs associated with
existing training, drill, and exercise programs to derive the costs imposed by the narrower scope
of SAMGs-related training, drill, and exercise requirements.

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Page 18

Time Period of Analysis
To define the period of analysis covered by this regulatory analysis (i.e., the period over which
costs and benefits would be incurred), the NRC derived an average remaining license term for
operating licensees and COL licensees. These average remaining license terms were
calculated based on data from NUREG-1350, vol.26, NRC Information Digest (Ref. 18). In total,
the regulatory analysis covers a 63-year period.
To estimate the average remaining license term for operating reactors, the NRC assumed each
operating site applies for and receives one, 20-year license renewal beyond its original 40-year
license term. For the 60 operating sites in the analysis, the NRC estimated that the average
remaining license term is 24 years, as of the effective date of the proposed rule. At the end of
this 24-year period, the NRC assumes that these sites would enter the decommissioning phase,
and would in turn incur decommissioning site costs associated with the proposed rule for the
first 2 years of decommissioning. According to 10 CFR 50.155(a)(3)(i), if the licensee performs
and retains an analysis (hereafter referred to as the “exemption analysis”) demonstrating that
the decay heat of the fuel in the SFP is removed solely by heating and boiling of water within the
SFP and the boil-off period provides sufficient time for the licensee to obtain offsite resources to
sustain the SFP cooling function indefinitely, they must only comply with 10 CFR 50.155(b)(2) of
the proposed rule, which has no associated incremental costs. Therefore, the period of analysis
for operating reactors begins in 2017, the year the proposed rule is assumed to take effect, and
runs through 2040. From 2041 through 2042, the costs associated with these sites decrease to
reflect the change in operating status.6
There are two new reactor sites included in the analysis (i.e., V.C. Summer and Vogtle). The
NRC assumes that both sites will apply for and receive one 20-year license renewal in addition
to the original 40-year license. Based on these assumptions, the new reactor sites would incur
costs associated with the proposed rule from 2017 through 2077. In 2078, costs associated
with the new reactor sites would shift to those for decommissioning sites for 2 years, from 2078
through 2079, based on the NRC’s assumption that both sites would prepare and submit an
exemption analysis to the NRC, exempting them from all but 10 CFR 50.155(b)(2) of the
proposed rule requirements.7
There are three current COL applicants included in the analysis (i.e., Bell Bend, Lee, and Levy).
Because these applicants have not announced an intention to construct and operate a new
reactor, costs for these applicants only include incremental licensing costs for their applications
and the NRC review of that information.

Present Value Calculations
The NRC calculated the present value of the costs sites would incur over the average remaining
license term. The NRC assumes that the proposed rule would be finalized and become
effective in 2017. One-time implementation costs would be incurred in 2017, while annual
operations costs would begin in 2018 and end in 2079. The analysis uses a 3 percent and
7 percent discount rate to calculate present values. Costs that would be incurred before the
6

The cost associated with the exemption analysis is considered an historical cost (see Appendix B). Currently,
decommissioning sites are preparing these analyses to be granted an exemption from Orders EA-12-049 and
EA-12-051. Therefore, the NRC assumes that in the absence of the rule, operating and new reactor sites would
similarly prepare and submit the exemption analysis. As a result, the cost is reflected in the no action baseline.

Ibid.

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Page 19

effective date of the proposed rule (e.g., cost to the NRC to develop and issue the final rule) are
expressed in present value terms using the 3 percent and 7 percent discount rates, which
increase the costs due to the time value of money.

3.2

Summary of Costs and Benefits of the Regulatory Options

This section presents the costs and benefits of the proposed rule with respect to three options:
(1) take no action, (2) undertake a rulemaking to require SAMGs and make Order EA-12-049,
Order EA-12-051, and industry initiatives generically applicable, and (3) undertake a rulemaking
to make Order EA-12-049, Order EA-12-051, and industry initiatives generically applicable.
Where possible, the NRC monetizes impacts. Those impacts that cannot be monetized are
instead described, to the extent possible, quantitatively or qualitatively. This section presents a
summary of the total costs and benefits associated with each option. Sections 3.3 and 3.4
describe in greater detail the costs and benefits of the proposed requirements under Option 2
(not selected) and Option 3 (the proposed rule). Appendix B presents the historical costs of the
Orders and industry initiatives. Note that all costs presented in this analysis are rounded to two
significant figures. Refer to Appendices C and D for a more detailed presentation of the cost
data.
Option 1: Take No Action (Considered-Not Selected)
Under Option 1, the NRC assumes that the proposed rule would not be implemented; however,
existing programs and regulatory efforts would still be in effect. Therefore, the NRC assumes
that industry would continue with the implementation of all Orders (including Order EA-12-049
and Order EA-12-051) as well as industry initiatives undertaken following the Fukushima
accident (Ref. 19). There would be no incremental costs associated with this option, as shown
in Exhibit 3-6.
Exhibit 3-6. Summary of Incremental Costs and Benefits for Option 1: No Action
Baseline
Incremental Costs
Industry:
$0 using a 3% discount rate
$0 using a 7% discount rate
NRC:
$0 using a 3% discount rate
$0 using a 7% discount rate

Incremental Benefits

Regulatory Efficiency –The quantitative benefit of this
alternative related to regulatory efficiency is reflected in no
additional costs to the NRC and the industry.

Option 2: Undertake Rulemaking to Require SAMGs and Make the Orders and Industry
Initiatives Generically Applicable (Considered-Not Selected)
Under Option 2, the NRC would undertake the proposed rulemaking to require industry to
develop and implement SAMGs and conduct SAMGs-related activities. In addition, under this
option, the proposed rule would make Order EA-12-049 and Order EA-12-051 as well as
industry initiatives generically applicable. The NRC estimates the costs of Option 2 relative to a
no action baseline (i.e., Option 1). Option 2 would result in incremental costs of $61 million
(using a 7 percent discount rate) or $76 million (using a 3 percent discount rate). Exhibit 3-7
presents the total costs.

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Page 20

The total one-time cost amounts to approximately $31 million. The total annual cost is
approximately $2.6 million. The average one-time cost per site is estimated at $510,000 and
the average annual cost per site is approximately $42,000 (based on a universe of 60 affected
sites).
Exhibit 3-7. Summary of Total Costs for Option 2: Undertake Rulemaking to Require
SAMGs and Make the Orders and Industry Initiatives Generically Applicable
Average Cost Per Site
One-Time
Costs

Total Costs

Annual
Costs

One-Time
Costs

Annual
Costs

Undiscounted
Value

Present
Value
(7 percent)

Present
Value
(3 percent)

N/A

Develop and Issue Final Rule
Industry
N/A
N/A
NRC

N/A

$880,000

N/A

$880,000

$940,000

$910,000

Subtotal

N/A

$880,000

N/A

$880,000

$940,000

$910,000

$42,000

$30,000,000

$2,400,000

$94,000,000

$58,000,000

$72,000,000

N/A

$230,000

$170,000

$4,400,000

$2,100,000

$3,000,000

Subtotal

$510,000

$42,000

$30,000,000

$2,600,000

$98,000,000

$60,000,000

$75,000,000

Total
Industry

$510,000

$42,000

$30,000,000

$2,400,000

$94,000,000

$58,000,000

$72,000,000

SAMGs-Related Activities
Industry
$510,000
NRC

NRC

N/A

$1,100,000

$170,000

$5,300,000

$3,000,000

$3,900,000

Total

$510,000

$42,000

$31,000,000

$2,600,000

$99,000,000

$61,000,000

$76,000,000

*Results are rounded.

Exhibit 3-8 summarizes the incremental costs and benefits of the proposed rule under Option 2
(not selected).
Exhibit 3-8. Summary of Incremental Costs and Benefits for Option 2
Incremental Costs
Industry:
$72,000,000 using a 3% discount rate
$58,000,000 using a 7% discount rate

Incremental Benefits
Qualitative Benefits:
Enhances regulatory efficiency
Enhances defense-in-depth

NRC:
$3,900,000 using a 3% discount rate
$3,000,000 using a 7% discount rate

Enhances decision making for the mitigation of the
consequences of core damage
Supports effective use of emergency procedures by
ensuring that strategies and guidelines are useable and
cohesive
Ensures adequate command and control and
communication for multi-unit events
Allows for the effective use of mitigation strategies and
guidelines by enhancing knowledge and abilities of
personnel
Maintains the effectiveness of SAMGs over time

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Page 21

Option 3: Undertake Rulemaking to Make the Orders and Industry Initiatives Generically
Applicable (NRC Selected)
Under Option 3, the NRC would undertake the proposed rulemaking to make Order EA-12-049,
Order EA-12-051, and industry initiatives generically applicable, but would not require SAMGs
or SAMGs-related activities. As with Option 2, the NRC estimates the costs and benefits of
Option 3 relative to a no action baseline. Option 3 would result in incremental costs of $8.1
million (using either a 7 percent or 3 percent discount rate). These costs result from the NRC’s
rulemaking activities and industry’s review of the rule requirements. Exhibit 3-9 presents the
total costs associated with Option 3.
Exhibit 3-9. Summary of Total Costs for Option 3: Undertake Rulemaking to Make the
Orders and Industry Initiatives Generically Applicable
Average Cost Per
Site
One-Time
Annual
Costs
Costs
Develop and Issue Final Rule
Industry
N/A
N/A

Total Costs
One-Time
Costs

Annual
Costs

Undiscounted
Value

Present Value
(7 percent)

Present Value
(3 percent)

N/A

NRC

N/A

$880,000

N/A

$880,000

$940,000

$910,000

Subtotal

N/A

$880,000

N/A

$880,000

$940,000

$910,000

N/A

$7,200,000

N/A

$7,200,000

Review Rule Requirements
Industry
NRC

$110,000
N/A

N/A

Subtotal

$110,000

N/A

$7,200,000

N/A

$7,200,000

Total
Industry

$110,000

N/A

$7,200,000

N/A

$7,200,000

NRC

N/A

$880,000

N/A

$880,000

$940,000

$910,000

Total

$110,000

N/A

$8,100,000

N/A

$8,100,000

*Results are rounded.

Exhibit 3-10 summarizes the incremental costs and benefits of Option 3 (selected).
Exhibit 3-10. Summary of Incremental Costs and Benefits for Option 3
Incremental Costs
Industry:
$7,200,000 using a 3% discount rate
$7,200,000 using a 7% discount rate
NRC:
$910,000 using a 3% discount rate
$940,000 using a 7% discount rate

Incremental Benefits
Qualitative Benefits:
Enhances regulatory efficiency

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3.3

Page 22

Costs of the Proposed Rule

This section details the estimated costs of Options 2 and 3. Under Option 3, the proposed rule,
these costs include developing and issuing the final rule8 and reviewing the rule requirements in
the following portions of Section 50.155 numbered as follows:
•

Section 50.155(b)(3) would require integration of FSGs and EDMGs with the EOPs.

•

Section 50.155(b)(4) would require each applicant or licensee to develop, implement,
and maintain sufficient staffing to support implementation of FSGs and EDMGs in
conjunction with the EOPs during an event.

•

Section 50.155(b)(5) would require each applicant or licensee to develop, implement,
and maintain a supporting organizational structure with defined roles, responsibilities,
and authorities for directing and performing the FSGs and EDMGs.

•

Section 50.155(d) would require each licensee to provide training to personnel that
perform activities in accordance with FSGs and EDMGs.

•

Section 50.155(e)(1)-(4) would require drills or exercises demonstrating implementation
of FSGs and EDMGs.

•

Section 50.155(f)(1)-(3) would allow a licensee to make changes to FSGs and EDMGs
without prior NRC approval, provided that the licensee performs an evaluation
demonstrating that regulatory requirements continue to be met. Documentation of all
changes would need to be maintained.

Under Option 3, all of the above requirements are limited to FSGs and EDMGs, and as such
would be implemented by ongoing activities prior to the effective date of the rule, and are not
expected to result in additional costs.
Under Option 2 (not selected), in addition to the above requirements of paragraphs 50.155(b)(f), each applicant or licensee would have been required to (1) integrate SAMGs with the EOPs;
(2) develop, implement, and maintain SAMGs; (3) provide sufficient staffing to support
implementation of SAMGs in conjunction with the EOPs during an event; (4) provide a
supporting organizational structure for directing and performing SAMGs; (5) provide training to
personnel that perform activities in accordance with SAMGs; (6) establish a change control
program for SAMGs; and (7) perform drills or exercises demonstrating implementation of
SAMGs.
Additionally, under both Options 2 and 3, the proposed rule also would include the following
requirements, which are not analyzed in this regulatory analysis:
•

Section 50.155(a)(3) would allow licensees to prepare and retain an analysis to enable
decommissioning licensees to discontinue compliance with portions of the proposed
rule, with the exception of Section 50.155(b)(2). The costs associated with this rule
provision are considered historical (because currently decommissioning sites are

The regulatory analysis does not account for industry costs incurred prior to the effective date of the final rule
(i.e., any costs incurred during the development of the final rule).

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Page 23

preparing these analyses in the baseline to be exempted from Order EA-12-049 and
Order EA-12-051), and are estimated and discussed in Appendix B. These costs are a
savings since the proposed rule would save decommissioning licensees the expense of
sending in an exemption request and the NRC the expense of reviewing and acting on
the request (versus the current process).
•

Section 50.155(b)(1) would require strategies and guidelines to mitigate BDBEE from
natural phenomena that result in an ELAP concurrent with either a LUHS or a loss of
normal access to the normal heat sink. These strategies and guidelines are consistent
with the existing FSGs. The costs associated with this rule provision are being incurred
as a result of the requirements of Order EA-12-049, and are estimated and discussed in
Appendix B.

•

Section 50.155(c)(2) would require licensees to provide reasonable protection of the
equipment relied on for mitigation strategies, as previously required by Order EA-12-049.
The NRC did not estimate any additional costs associated with the industry confirmation
that equipment relied on for mitigation strategies are reasonably protected for the reevaluated protection levels as clarified by the Commission in SRM-COMSECY-14-0037.
To understand the effect of this clarification, the NRC is explicitly seeking stakeholder
feedback regarding this proposed requirement.

•

Section 50.155(c)(4) would require licensees to install SFP level instrumentation, as
required by Order EA-12-051. The costs associated with this rule provision are being
incurred as a result of the requirements of Order EA-12-051, and are estimated and
discussed in Appendix B.

•

Part 50, Appendix E, Section IV.B would require licensees to maintain the capability to
determine the magnitude of, and continually assess the impact of, the release of
radioactive materials, including from all reactor core and SFP sources. The costs
associated with this rule provision are being incurred as a result of existing industry
initiatives, and are estimated and discussed in Appendix B.

•

Part 50, Appendix E, Section VII would require each applicant or licensee to perform a
detailed analysis demonstrating that sufficient staff is available to implement the
guidelines and strategies to respond to a BDBEE. The costs associated with this rule
provision are being incurred as a result of existing industry initiatives, and are discussed
in Appendix B. This proposed provision also would require licensees to make and
describe adequate provisions for onsite and offsite communication. The costs
associated with this rule provision are being incurred as a result of the requirements of
Order EA-12-049, and are estimated and discussed in Appendix B.

Option 2 was not selected because it is the only option that is expected to have significant
additional costs on industry. Under Option 2, the proposed SAMGs-related requirements would
result in an estimated cost of $61 million (using a 7 percent discount rate) and $76 million (using
a 3 percent discount rate), as shown in Exhibit 3-11. These monetized costs are described in
more detail in the following sections.

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Page 24

Exhibit 3-11. Summary of Industry and NRC Total Costs for Option 2
Average Cost Per Site
One-Time
Cost

Annual
Cost

Total Cost
One-Time
Cost

Annual
Cost

Undiscounted
Value

Present
Value
(7 percent)

Present
Value
(3 percent)

Develop and Issue Final Rule
Industry
N/A

N/A

NRC

N/A

$880,000

N/A

$880,000

$940,000

$910,000

Subtotal

N/A

$880,000

N/A

$880,000

$940,000

$910,000

SAMGs-Related Activities
SAMGs
Industry
NRC
Subtotal

$220,000

$2,200

$13,000,000

$130,000

$17,000,000

$14,000,000

$15,000,000

N/A

$99,000

$30,000

$800,000

$440,000

$600,000

$220,000

$2,200

$13,000,000

$160,000

$18,000,000

$14,000,000

$16,000,000

Integration of Emergency Procedures with SAMGs
Industry
NRC
Subtotal

$20,000

N/A

$1,200,000

N/A

$1,200,000

N/A

$20,000

N/A

$1,200,000

N/A

$1,200,000

$170,000

SAMGs Command and Control
Industry
NRC
Subtotal

$2,800

N/A

$170,000

N/A

$170,000

N/A

$2,800

N/A

$170,000

N/A

$170,000

$55,000,000

$32,000,000

$41,000,000

SAMGs Training
Industry
NRC
Subtotal

$220,000

$27,000

$13,000,000

$1,600,000

N/A

$220,000

$27,000

$13,000,000

$1,600,000

$55,000,000

$32,000,000

$41,000,000

SAMGs Drills and Exercises
Industry
NRC
Subtotal

$32,000

$3,300

$1,900,000

$200,000

$6,400,000

$3,600,000

$4,800,000

N/A

$120,000

$8,900

$310,000

$190,000

$240,000

$32,000

$3,300

$2,000,000

$210,000

$6,700,000

$3,800,000

$5,000,000

SAMGs Change Control
Industry
NRC
Subtotal

$15,000

$9,000

$880,000

$510,000

$14,000,000

$6,800,000

$9,900,000

N/A

$12,000

$130,000

$3,300,000

$1,500,000

$2,200,000

$15,000

$9,000

$890,000

$640,000

$17,000,000

$8,300,000

$12,000,000

Total
Industry

$500,000

$42,000

$30,000,000

$2,400,000

$94,000,000

$58,000,000

$72,000,000

NRC

N/A

$1,100,000

$170,000

$5,000,000

$3,100,000

$4,000,000

Total

$500,000

$42,000

$31,000,000

$2,600,000

$99,000,000

$61,000,000

$76,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***The annual cost data represents the per year costs incurred by sites during their operating license term.
****Although costs vary according to site characteristics, the average cost per site represents an industry
average.

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Page 25

Instead, Option 3 was selected as the proposed rule. The proposed rule would result in an
estimated one-time cost of $8.1 million (using either a 7 percent or 3 percent discount rate), as
shown in Exhibit 3-12. These monetized costs are described in more detail in the following
sections.
Exhibit 3-12. Summary of Industry and NRC Total Costs for Option 3
Average Cost Per Site

Total Costs

Annual
Costs

One-Time
Costs

Annual
Costs

Undiscounted
Value

Present
Value
(7 percent)

Present
Value
(3 percent)

Develop and Issue Final Rule
Industry
N/A

N/A

NRC

N/A

$880,000

N/A

$880,000

$940,000

$910,000

Subtotal

N/A

$880,000

N/A

$880,000

$940,000

$910,000

$110,000

N/A

$7,200,000

N/A

$7,200,000

N/A

Subtotal

$110,000

N/A

$7,200,000

N/A

$7,200,000

Total
Industry

$110,000

N/A

$7,200,000

N/A

$7,200,000

NRC

N/A

$880,000

N/A

$880,000

$940,000

$910,000

Total

$110,000

N/A

$8,100,000

N/A

$8,100,000

One-Time
Costs

Review Rule Requirements
Industry
NRC

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

3.3.1. Industry Implementation
This section presents the industry implementation costs resulting from Option 2 and Option 3.
Option 2 (Considered-Not Selected)
Option 2 (not selected) includes SAMGs requirements, which would have resulted in significant
industry implementation costs. These incremental costs include procedural and administrative
activities (such as developing SAMGs, integrating emergency procedures, revising procedures
to document command and control, developing trainings on SAMGs, conducting SAMGs drills
or exercises, and developing SAMGs change control procedures, programs, and plans). Onetime industry implementation costs are assumed to begin in 2017 (the expected effective date of
the proposed rule under Option 2). As discussed in Section 3.1, decommissioning sites would
not incur implementation costs because proposed 10 CFR 50.155(a)(3) would exempt
decommissioning sites from SAMGs-related requirements once the NRC approves the site’s
exemption analysis. See Appendix B, the NRC’s historical cost analysis, for more information
regarding the costs incurred by decommissioning sites.
Exhibit 3-13 lists the industry’s implementation costs for Option 2 (not selected), which amount
to a total one-time cost of approximately $30 million. The average one-time cost per site is
estimated at $500,000 (based on 60 affected sites). The NRC believes that the revised
voluntary initiative that industry discussed in its May 11, 2015 letter (ADAMS Accession No.
ML15217A314) will probably have costs similar to those estimated below.

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Page 26

Exhibit 3-13. Present Value of Industry’s Implementation Cost for Option 2
Average Cost
per Site

Section

One-Time Cost
SAMGs
$220,000
Integration of Emergency
$20,000
Procedures with SAMGs
SAMGs Command and Control
$2,800
SAMGs Training
$220,000
SAMGs Drills and Exercises
$32,000
SAMGs Change Control
$15,000
Total
$500,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Total Cost

$13,000,000

Present Value
(7 percent)
$13,000,000

Present Value
(3 percent)
$13,000,000

$1,200,000

$170,000
$13,000,000
$1,900,000
$880,000
$30,000,000

$170,000
$13,000,000
$1,900,000
$900,000
$30,000,000

$170,000
$13,000,000
$1,900,000
$880,000
$30,000,000

One-Time Cost

The following sections detail the compliance activities for Option 2 required of affected sites
(i.e., related to SAMGs, Integration of Emergency Procedures with SAMGs, SAMGs Command
and Control, SAMGs Training, SAMGs Drills and Exercises, and SAMGs Change Control).
SAMGs
Exhibit 3-14 shows that the industry implementation cost associated with developing and
implementing SAMGs is $13 million. These one-time costs would be incurred in 2017.
The NRC assumes that each of the 60 operating sites (including the 2 AP1000 COL sites)
would develop and implement site-specific SAMGs.
The LOE to develop and implement site-specific SAMGs is dependent on a site’s reactor type
(e.g., BWR or PWR) and whether the site is a single-SAMGs or dual-SAMGs site (as defined in
Section 3.1).
Specifically, the NRC assumes:

•

Development of site-specific SAMGs for PWR sites would require more effort than for
BWR sites because the pressurized-water-reactor owners group’s (PWROG) generic
SAMG recently consolidated three generic SAMGs into one (i.e., Westinghouse,
Combustion Engineering, and Babcock and Wilcox).

•

The two AP1000 units are co-located with operating sites, so they are categorized as
dual-SAMGs sites.9

•

Development of site-specific SAMGs at a dual-SAMGs site would require twice the
amount of effort required by a single-SAMGs site.

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Page 27

Exhibit 3-14. Industry Implementation Cost: SAMGs
Activity

Average Cost per
Affected Site

Develop and implement site-specific SAMGs
$170,000
(single-SAMGs BWR sites)
Develop and implement site-specific SAMGs
$350,000
(dual-SAMGs BWR sites)
Develop and implement site-specific SAMGs
$210,000
(single-SAMGs PWR sites)
Develop and implement site-specific SAMGs
$420,000
(dual-SAMGs PWR sites)
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.1 for additional detail on these cost estimates.

Total Cost
$3,700,000
$350,000
$7,200,000
$1,700,000
$13,000,000

Integration of Emergency Procedures with SAMGs
The industry implementation cost associated with integrating emergency procedures with
SAMGs is $1.2 million, as shown in Exhibit 3-15. These one-time costs would be incurred in
2017.
The NRC assumes that each of the 60 operating sites would review the FSGs, EDMGs, and
SAMGs to confirm that the guidelines are integrated with the EOPs. The NRC assumes that the
LOE to review guidelines would not vary between single-SAMGs and dual-SAMGs sites. The
costs associated with revisions to site-specific SAMGs resulting from these reviews are
accounted for under SAMGs Change Control. In addition, the costs associated with integrating
the FSGs with the EOPs are included in the historical cost analysis found in Appendix B.
Exhibit 3-15. Industry Implementation Cost: Integration of Emergency Procedures with
SAMGs
Activity

Average Cost per
Affected Site

Review the FSGs, EDMGs, and
SAMGs to confirm integration with
$20,000
EOPs
Subtotal
*Results are rounded.
**All costs are presented in 2013 dollars
***See Appendix C.2 for additional detail on these cost estimates.

Total Cost
$1,200,000
$1,200,000

SAMGs Command and Control
Exhibit 3-16 shows that the industry implementation costs associated with the SAMGs
command and control requirements are estimated to be $170,000. The one-time costs would
be incurred in 2017. The NRC assumes that each of the 60 operating sites would revise its
procedures to verify the site’s supporting organizational structure and to define roles,
responsibilities, and authorities for directing and performing the activities called for in the

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SAMGs. The NRC assumes that effort required to implement SAMGs Command and Control
procedures would not vary between single-SAMGs and dual-SAMGs sites.
Exhibit 3-16. Industry Implementation: SAMGs Command and Control
Activity

Average Cost per
Affected Site

Revise procedures to document
$2,900
command and control
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.4 for additional detail on these cost estimates.

Total Cost
$170,000
$170,000

SAMGs Training
Exhibit 3-17 documents the industry implementation costs for compliance activities related to
SAMGs training. The one-time cost is estimated to be $13 million and would be incurred in
2017. This provision would affect the 60 operating sites (including the two AP1000 COL sites).
The NRC assumes that each site would develop new training materials to incorporate provisions
of the proposed rule into existing training materials.
The NRC assumes that the training materials would be developed by a third-party contractor.
The contractor cost would depend on whether the site is a single-SAMGs or dual-SAMGs site.
Specifically, the staff assumes the cost to develop training materials for a dual-SAMGs site
would be twice as expensive as the cost for a single-SAMGs site.
Exhibit 3-17. Industry Implementation Cost: SAMGs Training
Activity

Average Cost per
Affected Site

Total Cost

Develop new training materials (single$200,000
$11,000,000
SAMGs sites)
Develop new training materials (dual$400,000
$2,000,000
SAMGs sites)
$13,000,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***Contractor cost estimates are based on the NRC’s professional judgment.
****See Appendix C.6 for additional detail on these cost estimates.

SAMGs Drills and Exercises
Exhibit 3-18 presents the industry implementation costs associated with SAMGs Drills and
Exercises. The NRC estimates that the 60 operating sites would incur a one-time cost of
$1.9 million. The NRC believes that the revised voluntary initiative that industry discussed in its
May 11, 2015 letter will probably have similar costs in terms of drills the licensees perform for
SAMGs.
The NRC estimates the incremental cost of SAMGs drills and exercises because drills and
exercises for EDMGs are currently required (in the baseline), and FSGs drills and exercises are

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accounted for in the historical cost analysis, specifically related to Order EA-12-049, found in
Appendix B. The NRC assumes that each site would develop SAMGs drill and exercise
scenarios to incorporate into existing emergency preparedness drills and exercises. Each site
also would be required to conduct an initial drill or exercise within 4 years of the effective date of
the proposed rule. The NRC assumes each operating site would conduct an initial drill, rather
than an exercise. In addition, the NRC assumes:
•

The LOE to develop new drill and exercise scenarios for a dual-SAMGs site is twice the
LOE for a single-SAMGs site.

•

Initial drills (as opposed to exercises) would be performed by each of the 60 operating
sites within 4 years after the rule becomes effective (2017–2020). Initial drills by the
COL holders would occur in 2017.

•

Each initial SAMGs drill would require 4 hours per participant. One ultimate decision
maker (UDM) would participate in initial drills at each site. Ten non-licensed operators
(NLOs) would participate in initial drills at site. NLOs would include onshift NLOs,
maintenance workers, and security personnel assigned operational tasks under SAMGs.
Exhibit 3-18. Industry Implementation Cost: SAMGs Drills and Exercises
Activity

Average Cost per
Affected Site

Develop new drill and exercise
$22,000
scenarios (single-SAMGs sites)
Develop new drill and exercise
$44,000
scenarios (dual-SAMGs sites)
Conduct initial drills (operating license
$7,900
holders)
Conduct initial drills (COL holders)
$7,900
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.7 for additional detail on these cost estimates.

Total Cost
$1,200,000
$220,000
$470,000
$16,000
$1,900,000

SAMGs Change Control
Exhibit 3-19 summarizes the industry implementation costs related to carrying out SAMGs
change control requirements. The one-time cost would be $880,000. The NRC assumes that
each of the 60 operating sites would develop change control procedures, programs, and plans
and the costs incurred would be equivalent for single- and dual-SAMGs site.

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Exhibit 3-19. Industry Implementation Cost: SAMGs Change Control
Average Cost per
Affected Site

Activity

Total Cost

Develop change control procedures,
$15,000
programs, and plans (operating sites)
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.8 for additional detail on these cost estimates.

$880,000
$880,000

Option 3 (NRC Selected)
The proposed rule (i.e., Option 3) would result in industry implementation costs associated with
reviewing the rule requirements to confirm compliance with the final rule (i.e., a comparison of
the rule requirements with the Orders and related industry initiatives and updates to procedures,
programs, or plans). The NRC assumes that each of the 60 operating sites (including the 2
AP1000 COL sites) and the 5 decommissioning sites would review the final rule and make
limited updates to procedures, programs, or plans to reflect the rule requirements. One-time
industry implementation costs are assumed to begin in 2017 (the year the rule is expected to be
effective).
Exhibit 3-20 lists the industry’s implementation costs for the proposed rule, which amount to a
total one-time cost of approximately $7.2 million. The average one-time cost per site is
estimated at $110,000 (based on 65 affected sites).
Exhibit 3-20. Present Value of Industry’s Implementation Cost for Option 3

Section

Average Cost
per Site

Total Cost

One-Time Cost

Present Value
(7 percent)

Present Value
(3 percent)

$110,000

$7,200,000

Total
$110,000
$7,200,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.11 for additional detail on these cost estimates.

$7,200,000

Review Rule Requirements

3.3.2 Industry Operation
This section presents the industry operation costs resulting from Option 2 and Option 3.
Option 2 (Considered-Not Selected)
Option 2 (not selected) would impose operations costs on 60 operating sites, including the two
COL holders. These incremental costs include routine and recurring activities (such as SAMGs
maintenance, attending and documenting SAMGs training, conducting and documenting
SAMGs drills and exercises, and updating SAMGs-related documents). These annual costs are
assumed to begin in 2018, with the exception of the Strategic Alliance for FLEX Emergency
Response (SAFER) training which would begin in 2017, and accrue up to 61 years, depending
on the activity and reactor type.

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Exhibit 3-21 presents the industry’s operations costs. The NRC estimates that industry would
incur an annual cost of approximately $2.4 million. The present value of these costs is
approximately $29 million (using a 7 percent discount rate) and $42 million (using a 3 percent
discount rate). The average annual cost per site is approximately $42,000 (based on
60 affected sites).
Exhibit 3-21. Present Value of Industry’s Operations Cost for Option 2

Section

Average
Cost per Site
Annual Cost

Total Cost
Annual Cost

Present Value
(7 percent)

Present Value
(3 percent)

SAMGs
$2,200
$130,000
$1,500,000
$2,400,000
SAMGs Training
$27,000
$1,600,000
$19,000,000
$28,000,000
SAMGs Drills and Exercises
$3,300
$200,000
$2,000,000
$2,900,000
SAMGs Change Control
$9,000
$510,000
$6,000,000
$9,000,000
Total
$42,000
$2,400,000
$29,000,000
$42,000,000
*Results are rounded.
**The annual cost data represents the per year costs incurred by sites during their operating license term.
***All costs in this exhibit are presented in 2013 dollars.

The following sections detail the annual compliance activities required of affected sites for
Option 2 (i.e., related to SAMGs, SAMGs Training, SAMGs Drills and Exercises, and SAMGs
Change Control). As discussed in Section 3.1, at the end of the average operating license term,
the NRC assumes that sites would enter the decommissioning phase, and would in turn incur
decommissioning site costs associated with the proposed rule for the first 2 years of
decommissioning. The following sections discuss the operations costs during both the
operating license term and the first 2 years of decommissioning.
SAMGs
Exhibits 3-22 and 3-23 present the annual costs associated with maintaining SAMGs over time.
These costs are incurred during the operating license term (Exhibit 3-22) and the first 2 years of
decommissioning (Exhibit 3-23).
The NRC assumes that each of the 60 operating sites would update their site-specific SAMGs
on a triennial basis. These costs would be incurred throughout the operating license term. The
NRC assumes that 58 BWR and PWR sites would incur SAMGs maintenance costs for the
average remaining license term, beginning in 2018 and ending in 2040. The two AP1000 sites
would incur operations costs from 2018 through 2077 (the average remaining license term for
new reactors). Refer to Section 3.1 for more detail regarding how these average license terms
were calculated.
Each site also would incur costs associated with maintaining SAMGs during the first 2 years of
decommissioning. The NRC assumes that the 58 BWR and PWR sites would incur
decommissioning costs in 2041 and 2042, and the two AP1000 sites would incur
decommissioning costs in 2078 and 2079. After 2 years, the NRC assumes the licensees would
have prepared and submitted the exemption analysis to the NRC, exempting them from all but
proposed 10 CFR 50.155(b)(2) of the proposed rule.

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Assumptions Related to Costs Incurred During the Operating Period
The NRC assumes that operating sites would perform a high-level review of the site-specific
SAMGs on a triennial basis to determine if any updates are needed. The SAMGs review would
be added to the site’s existing procedure review processes, which would need only slight
modifications. Therefore, the NRC expects the incremental impact of this provision to be small.
The NRC assumes that a dual-SAMGs site would require twice the effort required by a singleSAMGs site to maintain its site-specific SAMGs. Any revisions resulting from these reviews
would impose incremental costs. However, these costs are accounted for in the operations
costs for SAMGs Change Control. The NRC estimates that industry would incur annual costs of
$130,000 to maintain site-specific SAMGs.
Exhibit 3-22. Industry Operations Cost: SAMGs
(During the Operating Term)

Activity

Average
Annual Cost
per Affected
Site

Annual Cost

Maintain site-specific SAMGs (single$5,900
$110,000
SAMGs operating sites)
Maintain site-specific SAMGs (dual$12,000
$24,000
SAMGs operating sites)
$130,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.1 for additional detail on these cost estimates.

Assumptions Related to Costs Incurred During the First 2 Years of Decommissioning
The NRC assumes that sites would incur costs related to maintaining SAMGs for the first 2
years of decommissioning. The NRC estimates that industry would incur $120,000 in annual
costs to maintain SAMGs during the first 2 years of decommissioning.
Exhibit 3-23. Industry Operations Cost: SAMGs
(During the First 2 Years of Decommissioning)
Activity

Average
Annual Cost
per Affected
Site

Annual Cost

Maintain site-specific SAMGs (BWR
$5,900
$110,000
and PWR decommissioning sites)
Maintain site-specific SAMGs (AP1000
$5,900
$5,900
decommissioning sites)
$120,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix D.2 for additional detail on these cost estimates.

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SAMGs Training
Exhibits 3-24 and 3-25 present the annual training costs incurred during the operating license
term and the first 2 years of decommissioning, respectively. This provision would affect the
60 operating sites (including the 2 AP1000 COL sites). During the operating license term, the
NRC assumes that 58 BWR and PWR sites would incur operations costs beginning in 2018 and
ending in 2040 (the average remaining industry-wide license term for currently licensed BWRs
and PWR sites). The two AP1000 sites would incur these operations costs from 2018 to 2077
(the average remaining industry-wide license term for currently licensed AP1000 sites). See
Section 3.1 for more detail on how these average license terms were derived.
In addition, each site would incur costs during the first 2 years of decommissioning. The NRC
assumes that for 2 years following the end of the operating license term (2041 and 2042), the
58 BWR and PWR sites would incur costs to conduct training on a narrowed scope of SAMGs
(limited to SFP SAMGs), while the 2 AP1000 sites would incur these costs in 2078 and 2079.
After 2 years, the NRC assumes the sites would have prepared and submitted the necessary
analysis to the NRC, exempting them from all but proposed 10 CFR 50.155(b)(2) of the
proposed rule.
Assumptions Related to Costs Incurred During the Operating Period
The NRC assumes that each of the 60 operating sites would provide SAMGs training to UDMs
and NLOs on a biennial basis.10 Specifically, the training would target personnel that perform
activities under the SAMGs.11 Sites also would be required to document training attendance
and update training materials on a biennial basis.
The LOE to perform these activities varies for single-SAMGs and dual-SAMGs sites.
Specifically, the NRC assumes that:
•

SAMGs training would require 8 hours per participant. Five UDMs would attend training
at each single-SAMGs and dual-SAMGs site. Thirty NLOs and sixty NLOs would attend
training at each single-SAMGs and dual-SAMGs site, respectively.

•

The costs to document attendance and update training materials incurred by dualSAMGs sites is twice that of single-SAMGs sites.

The NRC estimates that during the sites’ operating license term, industry would incur an annual
cost of $1.6 million to train staff on SAMGs.

NLOs would include on-shift NLOs, maintenance workers, and security personnel assigned operational tasks
under SAMGs.

The incremental costs of training licensed operators are not considered in the analysis because they would be
trained in the baseline.

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Exhibit 3-24. Industry Operations: SAMGs Training (During the Operating License Term)
Activity

Average Annual
Cost per Affected
Site

Annual Cost

Attend training for UDMs and NLOs (single$28,000
$790,000
SAMGs sites)
Attend training for UDMs and NLOs (dual$50,000
$150,000
SAMGs sites)
Document training and update materials
$20,000
$570,000
(single-SAMGs sites)
Document training and update materials (dual$41,000
$120,000
SAMGs sites)
$1,600,000
Subtotal
* Results are rounded.
**The activities in the exhibit occur on a biennial basis. The costs have been annualized to reflect
this.
***All costs in this exhibit are presented in 2013 dollars.
****See Appendix C.6 for additional detail on these cost estimates.

Assumptions Related to Costs Incurred During the First 2 Years of Decommissioning
The NRC assumes that each of the 60 sites would continue to provide SAMGs training to UDMs
and NLOs, document training attendance, and update training materials on a biennial basis
during the first 2 years of decommissioning.
The NRC makes the following assumptions:
•

UDMs and NLOs at decommissioning sites require less time in training, relative to
operating sites. SAMGs training would require 2 hours per participant. Five UDMs and
ten NLOs would attend training at each decommissioning site.

•

The LOE to document and update training materials for decommissioning sites is less
than that required at operating sites.

As shown in Exhibit 3-25, during the first 2 years of decommissioning, the NRC estimates that
industry would incur an annual cost of $250,000 to train staff on SAMGs.

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Exhibit 3-25. Industry Operations: SAMGs Training (During the First 2 Years of
Decommissioning)
Activity
Attend training for UDMs and NLOs (BWR
and PWR decommissioning sites)

Annual Cost per
Affected Site

Annual Cost

$4,100

$120,000

Attend training for UDMs and NLOs (AP1000
$4,100
$4,100
decommissioning sites)
Document training and update materials
$4,200
$120,000
(BWR and PWR decommissioning sites)
Document training and update materials
$4,200
$4,200
(AP1000 decommissioning sites)
$250,000
Subtotal
*Results are rounded.
**The activities in the exhibit occur on a biennial basis. The costs have been annualized to reflect
this.
***All costs in this exhibit are presented in 2013 dollars.
****See Appendix D.4 for additional detail on these cost estimates.

SAMGs Drills and Exercises
Exhibit 3-26 provides the annual costs associated with SAMGs Drills and Exercises, which is
estimated to be $200,000. The NRC assumes that 60 operating sites would conduct drills or
exercises and document the results. Although the proposed rule would allow sites to choose
between a drill and an exercise in succeeding 8-year intervals, the NRC assumes that each
year, one single-SAMGs site and one dual-SAMGs site would conduct and document the results
of a SAMGs exercise, which is approximately 6 times more costly than a drill. The remaining
sites would choose to perform drills instead. Therefore, on an annual basis, approximately six
single-SAMGs sites and one dual-SAMGs site would conduct a SAMGs drill and document the
results. Furthermore, the NRC assumes that representatives from SAFER would participate in
one drill per year.
In addition:
•

Each SAMGs drill would require 4 hours per participant. One UDM would participate in
drills at each site. Ten NLOs would participate in drills at each single-SAMGs site, while
twenty NLOs would participate at each dual-SAMGs site.

•

Each SAMGs exercise would require 10 hours per participant. Five UDMs per site
would participate in exercises. Forty NLOs would participate in exercises at each singleSAMGs site, while eighty NLOs would participate at each dual-SAMGs site.

•

SAFER participation in drills would include a SAFER Control Center (SCC) Lead, an
SCC Logistics and Transportation (L&T) Coordinator, an SCC Staging Area (SA)
Coordinator, and two National SAFER Response Center (NSRC) Leads.

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Exhibit 3-26. Industry Operations Cost: SAMGs Drills and Exercises

Activity

Average Annual
Cost per Affected
Site

Annual Cost

Conduct drills and document performance
$7,900
(single-SAMGs sites)
Conduct drills and document performance
$14,000
(dual-SAMGs sites)
Conduct an exercise and document
$47,000
performance (single-SAMGs sites)
Conduct an exercise and document
$86,000
performance (dual-SAMGs sites)
Participate in drills (SAFER)
N/A
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.7 for additional detail on these cost estimates.

$47,000
$14,000
$47,000
$86,000
$4,200
$200,000

SAMGs Change Control
Exhibits 3-27 and 3-28 present the annual SAMGs change control costs that would be incurred
during the operating license term and during the first 2 years of decommissioning, respectively.
The NRC assumes the boiling-water-reactor owners group (BWROG), PWROG, and each of
the 60 operating sites would incur costs associated with this provision. The 60 operating sites
would incur operating costs for the remainder of the operating license term. Therefore, 58 BWR
and PWR sites would incur these operating costs beginning in 2018 and ending in 2040 (the
average remaining industry-wide license term for currently licensed BWR and PWR sites), and
the 2 AP1000 sites would incur these operations costs from 2018 to 2077.
Each site also would incur costs for the first 2 years of decommissioning. The NRC assumes
that for 2 years following the end of the license term (i.e., 2040–2041 for BWR and PWR sites,
and 2078–2079 for AP1000 sites) sites would incur change control costs. After 2 years, the
NRC assumes that licensees would have prepared and submitted the appropriate exemption
analysis to the NRC, triggering the provision in proposed 10 CFR 50.155(a)(3), which exempts
decommissioning licensees from all but proposed 10 CFR 50.155(b)(2) of the proposed rule.
Assumptions Related to Costs Incurred During the Operating Period
The NRC assumes that the BWROG would update the generic severe accident guidelines
(SAG)12 and the PWROG would update the generic SAMG on a triennial basis. The two
AP1000 sites would refer to the generic PWROG SAMG when developing their site-specific
SAMGs. Therefore, the costs associated with the PWROG updates to the generic SAMG would
continue throughout the remaining operating license term for these two sites (i.e., from 2017
12

SAGs are specific to BWR sites and SAMGs are specific to PWR sites. Both provide strategies taken after the
onset of fuel damage. This analysis uses the term “SAMGs” to refer to these strategies unless referring
specifically to the BWR sites.

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through 2077). The BWROG would incur costs to update the generic SAG for the remainder of
the operating license term for BWR sites (i.e., 2017 through 2040).
In addition, each of the 60 operating sites would update their site-specific SAMGs on a triennial
basis. The NRC assumes that the LOE varies for single-SAMGs and dual-SAMGs sites, with
dual-SAMGs sites requiring twice the effort of single-SAMGs sites.
The NRC estimates that industry would incur annual operating costs of $510,000 to carry out
the SAMGs change control requirements.
Exhibit 3-27. Industry Operations Cost: SAMGs Change Control
(During Operating License Term)
Activity

Average Annual
Cost per Affected
Site

Update generic BWROG SAG
N/A
Update generic PWROG SAMG
N/A
Update site-specific SAMGs (single-SAMGs
$6,500
BWR sites)
Update site-specific SAMGs (dual-SAMGs BWR
$13,000
sites)
Update site-specific SAMGs (single-SAMGs
$8,400
PWR sites)
Update site-specific SAMGs (dual-SAMGs PWR
$17,000
sites)
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.8 for additional detail on these cost estimates.

Annual Cost
$4,700
$5,000
$140,000
$13,000
$290,000
$68,000
$510,000

Assumptions Related to Costs Incurred During the First 2 Years of Decommissioning
Exhibit 3-28 presents the annual cost of SAMGs change control during the first 2 years of
decommissioning. The NRC assumes that each of the 60 operating sites would incur costs to
update site-specific SAMGs for the first 2 years of decommissioning. Due to the narrowed
scope of the SAMGs during decommissioning, the NRC assumes that variations in reactor type
would not affect change control costs. The NRC estimates that industry would incur an annual
cost of $180,000 for the first 2 years of decommissioning.

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Exhibit 3-28. Industry Operations Cost: SAMGs Change Control
(During the First 2 Years of Decommissioning)
Activity

Average Annual
Cost per
Affected Site

Update site-specific SAMGs (BWR and PWR
$3,000
decommissioning sites)
Update site-specific SAMGs (AP1000
$3,000
decommissioning sites)
Subtotal
*Results are rounded
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix D.5 for additional detail on these cost estimates.

Annual Cost

$170,000
$6,000
$180,000

Option 3 (NRC Selected)
The NRC estimates that the proposed rule (Option 3) would not impose additional operations
costs on licensees because the operations costs associated with the proposed rule
requirements are accounted for in the baseline of the analysis.

3.3.3 NRC Implementation
This section presents the NRC implementation costs resulting from Option 2 and Option 3.
Option 2 (Considered-Not Selected)
For Option 2 (not selected), the implementation costs on the NRC would include procedural and
administrative activities (such as developing and issuing the final rule, becoming familiar with
the owners groups’ SAMGs, developing SAMG oversight materials, reviewing new scenarios
and observing initial drills, as well as revising existing inspection procedures). These one-time
costs are assumed to be incurred in 2017 with the exception of developing and issuing the final
rule, which would occur in 2016.
Exhibit 3-29 presents the NRC’s total implementation costs for Option 2 which amount to a onetime cost of approximately $1.1 million. The total present value of these costs is approximately
$1.2 million (using a 7 percent discount rate) and $1.1 million (using a 3 percent discount rate).

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Exhibit 3-29. Present Value of NRC Implementation Cost
Total Cost
Section
One-Time Cost
Develop and Issue Final Rule
$880,000
SAMGs
$99,000
SAMGs Drills and Exercises
$120,000
SAMGs Change Control
$12,000
Total
$1,100,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Present Value
(7 percent)

Present Value
(3 percent)

$940,000
$99,000
$120,000
$12,000
$1,200,000

$910,000
$99,000
$120,000
$12,000
$1,100,000

The following sections describe the NRC’s one-time costs (i.e., related to developing and
issuing the final rule, SAMGs, SAMGs Drills and Exercises, and SAMGs Change Control).
Developing and Issuing the Final Rule
Exhibit 3-30 summarizes the one-time costs for developing and issuing the final rule. The NRC
assumes these costs would be occurred in 2016, in advance of the issuance of the final rule in
2017. The NRC estimates that the cost to complete the rulemaking would be $880,000.
Exhibit 3-30. NRC Implementation Cost: Developing and Issuing the Final Rule
Activity
Develop and issue MBDBE final rule

Total Cost
$880,000
$880,000

Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.10 for additional detail on these cost estimates.

SAMGs
Exhibit 3-31 summarizes the one-time costs of SAMGs compliance activities for Option 2 (not
selected). The NRC would incur costs to become familiar with the owners groups’ generic
SAMGs. Because all sites are assumed to adopt the owners groups’ generic SAMGs, the NRC
would not review any site-specific SAMGs. In addition, the NRC would develop SAMG
oversight materials such as inspection procedures. The NRC estimates that the NRC would
incur one-time costs of $99,000 in response to the new SAMGs requirements.

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Exhibit 3-31. NRC Implementation Cost: SAMGs
Activity

Total Cost

Become familiar with the owners groups' generic
$50,000
SAMGs
Develop SAMG oversight materials (e.g., inspection
$50,000
procedures)
$99,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.1 for additional detail on these cost estimates.

SAMGs Drills and Exercises
Exhibit 3-32 contains the one-time costs of compliance activities related to SAMGs drills and
exercises for Option 2 (not selected). The NRC would review the new drill and exercise
scenarios developed by the 60 operating sites. In addition, the NRC would observe the initial
drills conducted by the operating licensees and the COL holders in the first 4 years following the
effective date of the proposed rule (2017–2020). The NRC would incur one-time costs of
$120,000 as a result of the new SAMGs Drills and Exercises requirements.
Exhibit 3-32. NRC Implementation Cost: SAMGs Drills and Exercises
Activity
Review new scenarios
Observe initial drills (operating licenses)
Observe initial drills (COL holders)

Total Cost
$60,000
$60,000
$2,000
$120,000

Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.7 for additional information on these cost estimates.

SAMGs Change Control
Exhibit 3-33 reports the one-time cost to the NRC for SAMGs change control compliance
activities for Option 2 (not selected). The NRC would revise existing inspection procedures to
include oversight of SAMGs change control procedures. Because these changes would be
made to existing inspection procedures, ongoing updates to inspection procedures are assumed
to be included in the baseline. The NRC would incur one-time costs of $12,000.
Exhibit 3-33. NRC Implementation Cost: SAMGs Change Control
Activity

Total Cost

Revise existing inspection procedures
$12,000
$12,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.8 for additional detail on these cost estimates.

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Option 3 (NRC Selected)
The proposed rule (Option 3) would impose implementation costs to develop and issue the final
rule, equivalent to those presented in Exhibits 3-29 and 3-30.

3.3.4 NRC Operation
This section presents the NRC operation costs resulting from Option 2 and Option 3.
Option 2 (Considered-Not Selected)
For Option 2 (not selected), the NRC also would incur ongoing, operations costs (specifically,
overseeing site-specific SAMGs, observing drills and exercises, as well as overseeing sites’
SAMGs change control processes). These annual costs are assumed to begin in 2018 and
accrue over the following 58 years. The NRC would incur costs associated with the 58 BWR
and PWR sites through 2040, while costs associated with the 2 AP1000 sites will continue
through 2077.
Exhibit 3-34 provides the NRC’s total operations cost which amounts to an annual cost of
approximately $170,000. The total present value of these costs is approximately $1.9 million
(using a 7 percent discount rate) and $2.8 million (using a 3 percent discount rate).
Exhibit 3-34. Present Value of NRC’s Operations Cost
Total Cost
Section
Annual Cost

Present Value
(7 percent)
$340,000
$78,000
$1,500,000
$1,900,000

SAMGs
$30,000
SAMGs Drills and Exercises
$8,900
SAMGs Change Control
$130,000
Total
$170,000
*Results are rounded.
**The annual cost varies based on the number of operating reactor sites.
***All costs in this exhibit are presented in 2013 dollars.

Present Value
(3 percent)
$500,000
$120,000
$2,200,000
$2,800,000

The following sections detail the annual costs incurred by the NRC (i.e., related to SAMGs,
SAMGs Drills and Exercises, and SAMGs Change Control) for Option 2 (not selected).
SAMGs
Exhibit 3-35 contains the annual costs incurred by the NRC associated with maintaining SAMGs
over time. The NRC would oversee licensee implementation of site-specific SAMGs. The costs
associated with SAMGs oversight of the 58 BWR and PWR sites would be incurred by the NRC
beginning in 2018 and ending in 2040. Oversight of the AP1000 sites would begin in 2018 and
end in 2077. To oversee site-specific SAMGs, the NRC would incur annual costs of $30,000.

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Exhibit 3-35. NRC Operations Cost: SAMGs
Activity

Annual Cost

Oversee site-specific SAMGs
$30,000
$30,000
Subtotal
*Results are rounded.
**The annual cost varies based on the number of operating reactor sites.
***See Appendix C.1 for additional detail on these cost estimates.

SAMGs Drills and Exercises
Exhibit 3-36 presents the annual costs incurred by the NRC associated with SAMGs Drills and
Exercises. The NRC would observe SAMGs drills and exercises performed in 8-year intervals
by each of the 60 operating sites. The proposed rule would not impose incremental costs on
State and local offsite response organizations because the NRC assumes SAMGs drills and
exercises would occur concurrently with other emergency preparedness drills and exercises that
occur in the baseline. The NRC would oversee drills and exercises conducted by the 58 BWR
and PWR sites until 2040, and would oversee drills and exercises performed by the AP1000
sites until 2077. The NRC would incur annual costs of $8,900 to oversee the SAMGs drills and
exercises.
Exhibit 3-36. NRC Operations Cost: SAMGs Drills and Exercises
Activity

Annual Cost

Observe drills or exercises
$8,900
$8,900
Subtotal
*Results are rounded.
**The annual cost varies based on the number of operating reactor sites.
***See Appendix C.7 for additional detail on these cost estimates.

SAMGs Change Control
Exhibit 3-37 displays the annual costs incurred by the NRC to oversee licensees’ SAMGs
change control programs. Oversight would entail some incremental inspection activity on the
NRC’s behalf. The NRC would require twice the amount of effort to oversee the implementation
of change control procedures for site-specific SAMGs for dual-SAMGs sites than it would for
single-SAMGs sites. The NRC would provide oversight of the change control process until 2040
for the 58 BWR and PWR sites and until 2077 for the 2 AP1000 sites. The NRC would incur
annual costs of $130,000 to oversee SAMGs change control.

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Exhibit 3-37. NRC Operations Cost: SAMGs Change Control
Activity

Annual Cost

Oversee SAMG change control process for single$110,000
SAMGs sites
Oversee SAMG change control process for dual$20,000
SAMGs sites
$130,000
Subtotal
*Results are rounded.
**The annual cost varies based on the number of operating reactor sites.
***See Appendix C.8 for additional detail on these cost estimates.

Option 3 (NRC Selected)
The NRC estimates that the proposed rule (Option 3) would not impose additional operations
costs on NRC because the operations costs associated with the proposed rule requirements are
accounted for in the baseline of the analysis.

3.4. Benefits of the Proposed Rule
For historical purposes, all three options considered are shown below. Relative to the no action
baseline which includes the benefits derived from Order EA-12-049, Order EA-12-051, and
related industry initiatives, the incremental benefits from the options under consideration are as
follows:
•

Option 1 (not selected): No action alternative. This option would not result in any
incremental benefits above those resulting from the Orders and related industry
initiatives.

•

Option 2 (not selected): Undertake rulemaking to require SAMGs and make Order EA12-049, Order EA-12-051, and industry initiatives generically applicable. This option
would result in improvements (discussed more below) in the following attributes: Public
Health (Accident), Occupational Health (Accident), Offsite Property, Onsite Property,
Regulatory Efficiency, and Environmental Considerations.

•

Option 3 (selected): Undertake rulemaking to make Order EA-12-049, Order EA-12-051,
and industry initiatives generically applicable. This option, (i.e., the proposed rule) which
consists of a subset of the requirements in Option 2, would result in improvements
(discussed more below) in Regulatory Efficiency.

3.4.1 Benefits Associated with Public Health (Accident), Occupational
Health (Accident), Offsite Property, Onsite Property, and
Environmental Considerations
Option 2 (Considered-Not Selected)
Under Option 2 (not selected), the NRC proposed that the SAMGs-related requirements would
result in benefits to public and occupational health (accident), offsite and onsite property, and
environmental considerations. These benefits are discussed in terms of recent quantitative risk
analysis and qualitative factors. Note that the discussion that follows was not sufficient to cause

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the NRC to conclude that SAMGs requirements should be imposed as a substantial additional
protection backfit and satisfy the criteria under 10 CFR 50.109(a)(3). Instead the NRC
concluded that although SAMGs are beneficial to safety, making voluntary SAMGs a
requirement would not result in qualitative safety benefits that would sufficiently supplement
what the NRC concludes is a small quantitative risk benefit such that a substantial additional
protection of public health and safety would be achieved.
Recent Risk Analysis Results
The NRC decided in 1985 that the severe accident risk did not represent an undue risk to public
health and safety. (See Appendix A, Backfit and Issue Finality Analysis.)
Subsequent and recent work performed by the NRC indicates that quantifiable risk information
is not sufficient to justify the imposition of SAMGs requirements. Specifically, the NRC looked at
its recent technical analysis work performed in support of the Containment Protection and
Release Reduction (CPRR) rulemaking regulatory basis. This analysis estimated the potential
benefits of strategies used after the onset of core damage (i.e., these post-core-damage
strategies would be implemented by the SAMGs and as such are indicative of relative safety
benefit that might be obtained by SAMGs requirements). The NRC also considered other postFukushima regulatory efforts (e.g., the safety benefits that occur due to implementation of Order
EA-12-049 mitigation strategies, which result in a reduction in core damage frequency) within
this technical analysis. The NRC acknowledges that the work to support the CPRR rulemaking
was not intended to, and does not provide, a complete quantitative measure of the possible
safety benefits of SAMGs requirements, particularly with regard to how SAMGs might benefit
maintenance of containment integrity or support more informed protective action
recommendations by the emergency response organization (ERO) following core damage.
However, this technical analysis work does provide valuable risk insights that the NRC
concluded were important to fully inform the decision on this matter, and that additionally
influenced the NRC’s development of the proposed SAMG framework.
The CPRR technical analyses show that under a bounding set of assumptions, the maximum
benefits that could be obtained through the post-core-damage strategies at power reactors that
have a Mark I or Mark II containment would be a full order of magnitude below the quantitative
health objective (QHO; i.e., a level of risk that equates to 1/10 of 1 percent of the individual
latent cancer fatality (ILCF) risk). More refined risk estimates, from the same work, push this
benefit significantly lower. This result, as expected, demonstrates the benefits of the NRC’s
regulations to both effectively keep the frequency of core damage very low, and to ensure
through emergency preparedness requirements that the surrounding population is adequately
protected.
The estimated benefit to safety showed no benefit for acute fatalities and small benefits for
latent cancer fatalities (an estimated reduction of 10-9 or 10-10 for latent cancer fatalities).
Exhibit 3-38 presents the results of the risk evaluation. The QHO provides a risk criterion for
regulatory decision making, and in this case the results are 1,000 to 10,000 times below this
QHO. Even the high-level conservative estimate (i.e., this can be considered a bounding level
that equates to a maximum possible safety benefit) is well below the QHO. This quantitative
result indicates that the use of SAMGs would result in minimal benefits to public health and
safety.

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Exhibit 3-38. NRC’s QHO and Risk Evaluation Results of CPPR Rulemaking Alternatives

Source: NRC. 2014 Advisory Committee on Reactor Safeguards (ACRS) Meeting Schedule and Related
Documents. Retrieved from: http://pbadupws.nrc.gov/docs/ML1433/ML14337A651.pdf.

The NRC understands that this work was not intended to address SAMGs, and NRC notes that
it has not performed a comprehensive quantitative analysis of the potential safety benefits of
SAMGs requirements. However, the general risk insights obtained from the CPRR work also
align with the results of NUREG-1935, “State-of-the-Art Reactor Consequence Analyses
(SOARCA) Report,” (November 2012). Both point to the likely outcome that a comprehensive
quantitative analysis would not demonstrate a substantial safety benefit from imposing SAMGs
requirements when compared against the current regulatory state where SAMGs are voluntary
industry initiatives.
Qualitative Considerations Considered as part of Option 2
These minimal quantitative benefits were not developed with the intent of measuring possible
SAMG safety benefits, and as such are not a complete measure of SAMG safety benefits. The
referenced work was performed to address whether strategies taken after core damage for
power reactors having Mark I and Mark II containment designs could be justified for new
requirements. As such it is an indication of the benefits that can be achieved for SAMGs, since
such strategies are implemented using SAMGs, but it is not a complete assessment of such
benefits). SAMGs lead to indirect benefits by maintaining containment integrity (i.e., this
contributes to the mitigation of releases which manifest as reduced doses) and by supporting
the ERO with regard to making more informed protective action recommendations (i.e., this can
support efforts to protect onsite personnel, and possibly to move people out of the path of
effluents and therefore could result in reduced doses). Following the onset of core damage,
SAMGs are valuable at providing important information to decision makers that support more
informed decisions and actions on the use of resources in a severe accident. Typically, the

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SAMGs support decision makers as they work to minimize, reduce, and delay the releases of
fission products. Furthermore, there are some accident sequences for which SAMGs actions
may be successful in halting the progression of the accident (i.e., providing a much larger
benefit for those sequences). Recognizing the substantially increased mitigation capabilities
stemming from the implementation of Order EA-12-049 requirements and additionally noting the
flexible and adaptable nature of the strategies to include the potential for offsite resources to
assist with mitigation, it is more likely that the opportunities for halting a core melt progression
have increased.
Therefore, although available quantitative risk information does not indicate that SAMGs would
have a safety benefit, qualitatively SAMGs would support better use of resources thereby
reducing risk and benefiting public health and safety.
Specifically, updated SAMGs would enable about 20 years of additional insights to be
considered, including Fukushima insights. This results in an improved SAMGs decision making,
and leads to better post-core damage decisions and actions. Requiring SAMGs (i.e., requiring
licensees to develop, implement, and maintain site-specific SAMGs that reflect the recent
generic efforts and the site-specific features, including a nominal level of training and drills)
would specifically result in more informed decisions and actions (when compared to a presumed
state of voluntary SAMGs that are not up to date and may not reflect the current plant
configuration) involving:
•
•
•
•
•

Containment;
Minimization and delay of radiological releases;
Use of all equipment including the mitigation equipment of Order EA-12-049;
Use of Order EA-13-109 emergency procedure guidelines (EPGs)/SAGs for Mark I and
II designs;
Decisions made by the ERO following core damage.

SAMGs directly support two key, defense-in-depth foundational elements of the NRC’s
regulatory framework: Containment and Emergency Preparedness. These features and
requirements have their greatest importance to safety after the onset of core damage (i.e., when
fission products are present), at which time the site transitions to SAMGs, which then serve as
the operative guideline set for decisions and actions concerning the use of containment (to
minimize and delay of fission product releases) and support to emergency response (to inform
the ERO regarding fission product barrier integrity).
Additionally, SAMGs requirements could facilitate a more complete treatment of external event
uncertainties as well as events that have yet to be anticipated. The Fukushima Dai-ichi event
resulted in a greater appreciation for the uncertainties surrounding external events. Having
updated SAMGs to reflect the availability and use of equipment would facilitate the
implementation of mitigation strategies following core damage.
Finally, the SAMGs are an essential part of the regulatory framework for the mitigation of the
consequences of accidents and it is critical that the SAMGs and thereby the knowledge base
related to SAMGs is maintained. Prior to this proposed rule, all licensees developed SAMGs as
a voluntary industry initiative in the 1990s. However, Temporary Instruction (TI) 2515/184,
Availability and Readiness Inspection of Severe Accident Mitigation Guidelines, found that there

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was not a consistent approach to conducting periodic reviews (Ref. 20).13 Imposing SAMGs
requirements would ensure that SAMGs are maintained as effective guidelines set through time,
allowing licensees to better engage in knowledge management through the incorporation of
industry-wide lessons learned and operating experience.
While the above qualitative benefits are associated with SAMGs, the Commission did not select
Option 2 of this regulatory analysis since it concluded that these benefits largely accrue due to
the voluntary initiative, and more importantly, since it concluded that these qualitative benefits
(of a requirement versus a voluntary initiative) are not sufficient to supplement the small
estimated quantitative risk benefits associated with SAMGs such that a substantial additional
protection of public health and safety would be achieved. Accordingly, the Commission
concluded that this option does not satisfy 10 CFR 50.109(a)(3), and it was not selected.
Option 3 (NRC Selected)
The NRC estimates that the proposed rule (Option 3) would not result in incremental benefits to
Public Health (Accident), Occupational Health (Accident), Offsite Property, Onsite Property, and
Environmental Considerations because the benefits associated with the proposed rule
requirements are accounted for in the baseline of the analysis.

3.4.2 Benefits Associated with Regulatory Efficiency
Option 2 (Considered-Not Selected)
Under Option 2, the NRC anticipates that the Order-related requirements would result in
regulatory efficiency benefits. By placing the requirements in Order EA-12-049 and Order EA12-051 into the NRC’s regulations, they would enhance regulatory efficiency by applying the
requirements to all current and future power reactor applicants, and provide regulatory clarity to
operating reactors. Operating reactor licensees and three COL holder reactor sites currently
are subject to the Order requirements. Any future licensees would not be covered by the Order
requirements. In making the requirements of Order EA-12-049 generically applicable, this
option would also consider the reevaluated hazard information from the March 12, 2012, NRC
letter issued under 10 CFR 50.54(f) as part of providing reasonable protection for mitigation
strategies equipment for external flooding or seismic hazards.
In the absence of the proposed rule under Option 2, these requirements would need to be
implemented for new reactor sites through additional Orders or license conditions (as was done
for the Fermi, V.C. Summer, and Vogtle COLs), which would impose additional costs on the
NRC. The proposed rulemaking under Options 2 also would enhance regulatory efficiency by
reflecting stakeholder feedback and lessons learned from the implementation of the Orders,
including any challenges or unintended consequences associated with implementation.

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Option 3 (NRC Selected)
The proposed rule (Option 3) would result in the equivalent incremental benefits related to
regulatory efficiency as described under Option 2 above.

3.5. Disaggregation
The proposed rule (Option 3) does not impose significant additional costs on industry, and
accordingly, there is not a need to disaggregate provisions that impose incremental costs to
industry to ensure that such rule does not contain provisions that are not necessary components
are not cost-beneficial.

3.6. Sensitivity Analysis
For the option chosen (Option 3), the NRC does not estimate significant additional costs to be
imposed on industry, and as such, there was not a need to perform a sensitivity study to
examine changes in costs due to uncertainties associated with analytical assumptions and input
data.

Decision Rationale for Selection of Proposed Action

The NRC rejects Option 1, the no action alternative, because it would not achieve the NRC’s
objectives as stated in Section 1.2. The NRC did not select Option 2, which is described in
Section 2.2, and instead selected Option 3, which is discussed in Section 2.3. This decision
rationale focuses on Option 2 and Option 3. Option 2 is to undertake rulemaking to require
SAMGs and make Order EA-12-049, Order EA-12-051, including the associated regulatory
actions implemented in conjunction with the Orders, generically applicable. Option 3 is the
same as Option 2 but removes the SAMGs-related requirements from the rulemaking.
Because the regulatory scope of Option 3 includes the scope set forth in Order EA-12-049 and
Order EA-12-051 and related industry initiatives, the total incremental cost of Option 3 includes
limited implementation costs for industry to review the regulatory requirements in order to
confirm ongoing compliance (i.e., a comparison of the rule requirements with the Orders and
related industry initiatives and updates to procedures, programs, or plans). Option 2, however,
includes the regulatory scope of Option 3, but adds requirements for SAMGs. Relative to the no
action baseline, the estimated costs of Option 2 largely represents the costs associated with the
new regulatory requirements for licensees to develop, implement, and maintain SAMGs, as well
as the NRC’s rulemaking-related costs.
Recent work by the NRC indicates that the use of SAMGs would result in minimal benefits to
public health and safety (see Section 3.4). Because the available quantitative risk information is
not a complete measure of the SAMG safety benefits, the NRC relied on quantitative and
qualitative reasons to determine whether the SAMGs requirements would result in a substantial
additional protection for public health and safety, as discussed in Appendix A to the regulatory
analysis. Specifically, quantitative risk information indicates that SAMGs have a small safety
benefit. In addition, SAMGs directly support maintenance of containment integrity following
severe accidents, and indirectly support the protective action recommendations made by the
ERO in such circumstances, and as such, the SAMGs have a very important link to two
foundational parts of the NRC’s defense-in-depth framework: Containment and Emergency
Preparedness. The SAMGs requirements would ensure that operators and decision makers
have an updated set of guidelines to use following the onset of core damage. The availability of

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updated SAMGs would provide pre-planned guidelines for the best use of all available
resources to mitigate an accident.
The NRC concluded that although SAMGs are beneficial to safety, making voluntary SAMGs a
requirement would not result in qualitative safety benefits that were large enough to supplement
the small quantitative risk benefit such that a substantial additional protection of public health
and safety would be achieved. Accordingly, the NRC concluded that Option 2 did not satisfy
10 CFR 50.109(a)(3) and chose Option 3 for the proposed rule.

4.1

Safety Goal Evaluation

Safety goal evaluations apply only to regulatory initiatives considered to be generic safety
enhancement backfits subject to the substantial additional protection standard at
10 CFR 50.109(a)(3). The SAMGs-related provisions included as Option 2 in the regulatory
analysis qualify as backfits. The NRC did not select Option 2.
A safety goal evaluation is intended to eliminate proposed regulatory requirements in cases
where the residual risk is already acceptably low. As discussed earlier, NRC found that the
quantitative benefit of SAMGs to public health and safety likely would not approach thresholds
that would justify the costs of the proposed rule (because the low risk of events leading to
severe accidents).
While the NRC recognizes that available quantitative risk information indicates that SAMGs
have a small safety benefit, this information is not a complete measure of SAMG safety benefits.
The NRC looked at whether the SAMGs requirements would result in a substantial additional
protection for public health and safety based on the qualitative reasons as discussed in
Appendix A to this regulatory analysis. Specifically, SAMGs directly support maintenance of
containment integrity following severe accidents, and indirectly support the protective action
recommendations made by the ERO in such circumstances, and as such, the SAMGs have a
very important link to two foundational parts of the NRC’s defense-in-depth framework:
Containment and Emergency Preparedness. While the NRC concluded that SAMGs are
beneficial to safety, making voluntary SAMGs a requirement would not result in qualitative
safety benefits that were large enough to supplement the small quantitative risk benefit such
that a substantial additional protection of public health and safety would be achieved. As a
result, Option 2 was judged to not be a substantial additional protection of public health and
safety (i.e., does not meet the requirements of 10 CFR 50.109(a)(3)).
Instead, the Commission limited the scope of the proposed rulemaking to encompass provisions
that are currently being implemented via Order EA-12-049, Order EA-12-051, and related
industry initiatives. Based on the NRC assessment of the costs and benefits of Option 3 (the
proposed rule), the agency has concluded that the proposed requirements are justified.
Therefore, a safety goal evaluation is not appropriate for the proposed rule. Refer to the
discussion in Appendix A (Backfitting and Issue Finality).

4.2

Committee to Review Generic Requirements (CRGR)

This section addresses regulatory analysis information requirements for rulemaking actions or
staff positions subject to review by the Committee to Review Generic Requirements (CRGR).
All information called for by the CRGR charter is presented in this regulatory analysis, or in the
Federal Register notice for the proposed rule. As a reference aid, Exhibit 4-1 provides a cross-

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reference between the relevant information and its location in this document or the Federal
Register notice.
Exhibit 4-1. Specific CRGR Regulatory Analysis Information Requirements
CRGR
Charter
Citation
(Ref. 27)

Information Item to be Included in a Regulatory
Analysis Prepared for
CRGR Review

Where Item is
Discussed

Appendix C, (i)

Proposed generic requirement or staff position as it is
proposed to be sent out to licensees.

Proposed rule text in
Federal Register notice.

Appendix C, (ii)

Draft papers or other documents supporting the
requirements or staff positions.

Federal Register notice
for the proposed rule.

Appendix C, (iii)

The sponsoring office's position on each proposed
requirement or staff position as to whether the
proposal would modify requirements or staff
positions, implement existing requirements or staff
positions, or relax or reduce existing requirements or
staff positions.

Regulatory Analysis,
Section 3.2 and Backfit
Analysis, Appendix A.

Appendix C, (iv)

The proposed method of implementation.

Federal Register notice
for the proposed rule.

Appendix C, (vi)

Identification of the category of power reactors, new
reactors, or nuclear materials facilities or activities to
which the proposed generic requirement or staff
position is applicable.

Regulatory Analysis,
Section 3.1.

Appendix C (vii)
- (viii)

The proposed action involves a power reactor backfit
and the exception at 10 CFR 50.109(a)(4)(ii) is
applicable for imposition of multiple source term dose
assessment requirements. For the proposed and
rejected backfits for Option 2 of this regulatory
analysis, the items required at 10 CFR 50.109(c) and
the required rationale at 10 CFR 50.109(a)(3) are to
be included and are discussed. (Ref. 4).

Backfit Analysis,
Appendix A.

III.

For proposed generic relaxations or decreases in
current requirements or staff positions, provide a
determination along with the rationale that (a) the
public health and safety and the common defense
and security would be adequately protected if the
proposed relaxations were implemented and (b) the
cost savings attributed to each action would be
significant enough to justify the action.

Federal Register notice
for the proposed rule.

Appendix C (xi)

Preparation of an assessment of how the proposed
Regulatory Analysis,
action relates to the Commission’s Safety Goal Policy Section 4.1.
Statement (Ref. 21).
Source: U.S. Nuclear Regulatory Commission, “Charter: Committee to Review Generic Requirements,”
Revision 8, March 2011, ADAMS Accession No. ML110620618 (Ref. 21).

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19. U.S. Nuclear Regulatory Commission, “Issuance of Order to Modify Licenses with Regard to Reliable
Hardened Containment Vents Capable of Operation Under Severe Accident Conditions,”
Order EA-13-109, June 6, 2013, ADAMS Accession No. ML12054A736.
20. U.S. Nuclear Regulatory Commission, “NRC Inspection Manual – Temporary Instructions
2515/184-Availability and Readiness Inspection of Severe Accident Management Guidelines
(SAMGs),” April 29, 2011, ADAMS Accession No. ML11115A053.
21. U.S. Nuclear Regulatory Commission, “Charter, Committee to Review Generic Requirements,”
Revision 8, March 2011, ADAMS Accession No. ML110620618.

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Appendix A: Backfitting and Issue Finality
This appendix presents the NRC’s analysis of backfitting and issue finality under Option 2 (not
selected) and Option 3 (the proposed rule) of the regulatory analysis. Section A.1 presents the
backfitting and issue finality analysis of the requirements that make Order EA-12-049 and Order
EA-12-051 generically applicable. These provisions do not constitute backfits and are
consistent with issue finality.14 Section A.2 provides the NRC’s analysis of backfitting and issue
finality for the remaining requirements associated with codifying voluntary industry initiatives and
SAMGs. These provisions constitute backfitting but are consistent with issue finality.

A.1

Rule Provisions that Do Not Constitute Backfits

The requirements in Option 2 (not selected) and Option 3 (the proposed rule) that make Order
EA-12-049 and Order EA-12-051 generically applicable do not qualify as backfitting as defined
in 10 CFR 50.109. Appendix B to the regulatory analysis evaluates the costs of these
provisions (i.e., the historical cost analysis). This section discusses why these regulatory
requirements do not constitute backfits. Because of differences in the application of the backfit
rule to licensees, entities with existing DCs, and future applicants for COLs, DCs, manufacturing
licenses (MLs), and standard design approvals (SDAs), the NRC addresses each class
separately.
Both Options include requirements for conducting staffing analyses and communications system
assessments. These proposed requirements are based on the NRC’s information requests
pursuant to 10 CFR 50.54(f). These regulatory issues are currently being addressed through
Order EA-12-049 implementation guidance (i.e., NRC-endorsed guidance in NEI 12-06, Diverse
and Flexible Coping Strategies (FLEX) Implementation Guide, and NEI 12-01, Guideline for
Assessing beyond Design Basis Accident Response Staffing and Communications Capabilities).
Although these proposed requirements for staffing and communications stemmed from separate
regulatory action, they were necessary for a proper and complete implementation of Order EA12-049. As discussed in COMSECY-13-0010 “Schedule and Plans for Tier 2 Order on
Emergency Preparedness for Japan Lessons Learned,” dated March 27, 2013 (ADAMS
Accession No. ML12339A262), the NRC and licensees determined that a complete
implementation of a response to a site-wide, beyond-design-basis external event would require
sufficient staffing and communications capabilities for both onsite and to offsite that can occur
without ac power and recognizing infrastructure damage. As such they are considered to be
part of the Order EA-12-049-imposed requirements.
Existing Licensees
The NRC’s backfit provisions for holders of operating licenses and construction permits (CPs)
are found in the regulations at 10 CFR 50.109, which defines backfitting as:

In 10 CFR Part 50, Appendix E, Section VI., the proposed rule removes references to the use of modems in
order to make the ERDS requirements technology-neutral. The NRC considers this revision a minor
administrative change to make the NRC’s regulatory requirements consistent with a technological initiative that
has already been implemented by industry. Also, by making the requirement technology-neutral, the NRC is
relaxing this requirement. Because this proposal is an administrative change to the ERDS regulations and a
relaxation that provides flexibility to licensees, it is not subject to the backfit rule.

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[T]he modification of or addition to systems, structures, components, or design of
a facility; or the design approval or manufacturing license for a facility; or the
procedures or organization required to design, construct or operate a facility; any
of which may result from a new or amended provision in the Commission’s
regulations or the imposition of a regulatory staff position interpreting the
Commission’s regulations that is either new or different from a previously
applicable staff position […].
The NRC determined the requirements in the proposed rule that would make generically
applicable the requirements in Order EA-12-049 and Order EA-12-051 as applied to existing
licensees and CP holders to whom Order EA-12-049 and Order EA-12-051 were directed,
would not constitute a new instance of backfitting under 10 CFR 50.109, or an additional
inconsistency with the issue finality provisions applicable to holders of COLs in 10 CFR 52.98.
Any backfitting and issue finality issues for this rulemaking based on the Orders were addressed
as part of the issuance of Order EA-12-049 and Order EA-12-051. The proposed requirements
limited to mitigation measures in Order EA-12-049 and SFP level instrumentation requirements
in Order EA-12-051 would introduce no new backfitting and issue finality matters apart from
those addressed in the underlying Orders. Therefore, the NRC’s consideration of backfitting
and issue finality matters for the Orders also serves as the NRC’s consideration of the same
backfitting and issue finality matters for the proposed rule with respect to mitigation measures
and SFP level instrumentation.
Existing Design Certifications
The issues that may be resolved in a DC and accorded issue finality may not include
operational matters, such as the elements of the proposed rule. Therefore, the proposed rule is
consistent with the issue finality provision in 10 CFR 52.63.
Current and Future Applicants
Applicants and potential applicants (of licenses, permits and regulatory approvals, such as DCs)
are not, with certain exceptions, protected by either the backfit rule or any issue finality
provisions under Part 52. Neither the backfit rule nor the issue finality provisions under
Part 52—with certain exclusions not applicable here—were intended to apply to every NRC
action that substantially changes the expectations of current and future applicants.

A.2

Backfit Analysis of Rule Provisions that Constitute Backfits

The following requirements qualify as backfits. Section 3 of the regulatory analysis
quantitatively estimates the incremental costs and benefits of these provisions.
•

Option 2 and Option 3 of the regulatory analysis: Multiple source term dose
assessment. A key component of the NRC’s existing emergency preparedness regime
is that licensees must assess and monitor actual or potential offsite consequences of a
radiological emergency condition. This planning standard, found in 10 CFR 50.47(b)(9),
is essential to developing protective action recommendations and must be satisfied
before the NRC can make a finding that there is reasonable assurance that adequate
protective measures can and will be taken in the event of a radiological emergency at a
power reactor. Further details of this requirement are set forth in Appendix E to Part 50.
The proposed requirement to monitor and assess multiple source terms is a lesson

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learned from the Fukushima event, and would result in upgrading the existing capability
to reflect the response required for a multi-unit event where there is potential damage to
multiple power reactor units, including SFPs, or for a single-unit event where there is
potential damage to both the reactor and the SFP. Updating this requirement to address
the potential for multiple source terms to be damaged from BDBEs that impact an entire
reactor site makes this proposed requirement an upgrade to the basic capability required
to meet the current emergency preparedness regulatory objectives. This regulatory
action is being voluntarily implemented by industry and is expected to be complete by
the rule’s effective date (i.e., without a formal regulatory action). This proposed
requirement is considered to be part of the essential emergency preparedness
regulatory infrastructure that is required to meet current emergency preparedness
regulatory objectives, and as such, is considered part of the set of emergency
preparedness requirements to provide reasonable assurance of adequate protection of
public health and safety, consistent with the regulatory basis for emergency
preparedness that has existed for more than three decades.
•

Option 2 (of the regulatory analysis): SAMGs and supporting requirements (e.g., SAMGrelated training, drills and exercises, command and control, and change control). The
remainder of this section discusses the backfitting issues related to SAMGs and their
supporting requirements that were considered under Option 2 in the regulatory analysis.
Because the NRC concluded that SAMGs requirements could not be imposed under
10 CFR 50.109, there was not a need to consider the application of the backfit rule to
entities with existing DCs, and future applicants for COLs, DCs, MLs, and SDAs.

Note that the proposed multiple source term dose assessment requirement, considered
necessary for adequate protection as part of emergency preparedness, is currently being
implemented and should be complete by the effective date of the rule. Accordingly, it is
accounted for as an historical cost in Appendix D. The remainder of this backfit analysis
focuses on the requirements under Option 2 of the regulatory analysis that relate to SAMGs.
Consideration for Imposing SAMGs Requirements (per Option 2 of the regulatory analysis) on
Existing Licensees
The NRC previously considered the need to require SAMGs. This effort is relevant to the
backfit analysis because the NRC determined that severe accident risk was not at a level that
would warrant regulatory action for adequate protection of public health and safety. The
following section provides background on these deliberations. Following the background, the
NRC provides the basis for reconsidering the need to impose SAMGs requirements.
Background: Previous Commission Deliberations Related to this Backfitting Consideration
The Severe Accident Policy Statement was issued in 1985 (50 FR 32138) and it describes the
Commission’s policy to resolve safety issues for events more severe than design basis
accidents. While the main focus is on the criteria and procedures the Commission uses to
certify new reactor designs, the policy also provided guidance on decision and analytical
procedures for the resolution of severe accident issues for existing plants.
In this policy statement, the Commission states with regard to existing plants:
On the basis of currently available information, the Commission concludes that existing plants
pose no undue risk to public health and safety and sees no present basis for immediate action

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on generic rulemaking or other regulatory changes for these plants because of severe accident
risk.
Later the policy states:
Should significant new safety information become available from whatever source to question
the conclusion of “no undue risk” then the technical issues thus identified would be resolved by
the NRC under its backfit policy and other existing procedures, including the possibility of
generic rulemaking where this is justified.
In Section C, “Policy for Existing Plants,” the Commission provides more detailed guidance:
In light of the above principles and conclusions, the Commission's policy for operating reactors
includes the following guidance:
Operating nuclear power plants require no further regulatory action to deal with severe accident
issues unless significant new safety information arises to question whether there is adequate
assurance of no undue risk to public health and safety.
In the latter event, a careful assessment shall be made of the severe accident vulnerability
posed by the issue and whether this vulnerability is plant or site specific or of generic
importance.
The most cost-effective options for reducing this vulnerability shall be identified and a decision
shall be reached consistent with the cost effectiveness criteria of the Commission's backfit
policy as to which option or set of options (if any) are justifiable and required to be implemented.
In those instances where the technical issue goes beyond current regulatory requirements,
generic rulemaking will be the preferred solution. In other cases, the issue should be disposed
of through the conventional practice of issuing bulletins and Orders or generic letters where
modifications are justified through backfit policy, or through site-specific decision making along
the lines of the Integrated Safety Assessment Program (ISAP) conception.
Recognizing that plant-specific PRAs have yielded valuable insight to unique plant
vulnerabilities to severe accidents leading to low-cost modifications, licensees of each operating
reactor will be expected to perform a limited-scope, accident safety analysis designed to
discover instances (i.e., outliers) of particular vulnerability to core melt or to unusually poor
containment performance, given core melt accidents. These plant-specific studies will serve to
verify that conclusions developed from intensive severe accident safety analyses of reference or
surrogate plants can be applied to each of the individual operating plants. During the next two
years, the Commission will formulate a systematic approach, including the development of
guidelines and procedural criteria, with an expectation that such an approach will be
implemented by licensees of the remaining operating reactors not yet systematically analyzed in
an equivalent or superior manner.
In 1986, the Safety Goal Policy was issued and has several relevant statements concerning
impositions of SAMGs as requirements:
Severe core damage accidents can lead to more serious accidents with the potential for lifethreatening offsite release of radiation, for evacuation of members of the public, and for
contamination of public property. Apart from their health and safety consequences, severe core

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damage accidents can erode public confidence in the safety of nuclear power and can lead to
further instability and unpredictability for the industry. In order to avoid these adverse
consequences, the Commission intends to continue to pursue a regulatory program that has as
its objective providing reasonable assurance, while giving appropriate consideration to the
uncertainties involved, that a severe core damage accident will not occur at a U.S. nuclear
power plant.
The Commission recognizes the importance of mitigating the consequences of a core-melt
accident and continues to emphasize features such as containment, siting in less populated
areas, and emergency planning as integral parts of the defense-in-depth concept associated
with its accident prevention and mitigation philosophy.
An “Integration Plan” for closure of severe accident issues (SECY-88-147, dated May 25, 1988)
was developed to integrate and close severe accident issues. This plan included a program to
ensure that licensees develop and implement severe accident management programs at their
plants. In SECY-89-12, “Staff Plans for Accident Management Regulatory and Research
Programs,” the NRC described the goals, framework, and elements of NRC’s accident
management program, which evolved into SAMGs. In SECY-89-12, the staff describes accident
management as follows:
Accident Management encompasses those actions taken during the course of an accident by
the plant operation and technical staff to: (1) prevent core damage, (2) terminate the progress
of core damage if it begins and retain the core within the reactor vessel, (3) maintain
containment integrity as long as possible, and (4) minimize offsite releases. Accident
management, in effect extends the defense-in-depth principle to plant operating staff by
extending the operating procedures well beyond the plant design basis into severe fuel damage
regimes, with the goal of taking advantage of existing plant equipment and operator skills and
creativity to find ways to terminate accidents beyond the design basis or to limit offsite releases.
Regarding the importance of accident management to safety, SECY-89-12 states:
The NRC has concluded, based upon PRAs and severe accident analyses, that the risk
associated with severe core damage accidents can be further reduced through effective
accident management. In this context, effective accident management would ensure that
optimal and maximum safety benefits are derived from available, existing systems and plant
operating staff through pre-planned strategies. Furthermore, the International Nuclear Safety
Advisory Group (INSAG) in its report on Basic Safety Principles for Nuclear Power Plants
concluded that accident management and mitigation measures can significantly reduce risk.
Accordingly, accident management is considered to be an essential element of the severe
accident closure process described in the Integration Plan for Closure of Severe Accident
Issues (SECY-88-147) and the Generic Letter on the Individual Plant Examination (Generic
Letter 88-20).
GL 88-20 supplement 2 was issued on April 4, 1990, and in the summary it states:
Over the past several years, the NRC has performed and reviewed numerous probabilistic risk
assessments (PRAs) and severe accident studies. From this experience, it has become evident
that it is possible to implement certain actions, or accident management strategies, that have
significant potential for recovering from a wide variety of accident scenarios. These accident
management strategies typically involve the use of equipment that already exists at plants. The
NRC has compiled a list of such accident management strategies. The purpose of this letter is

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to forward these strategies to industry so that licensees can evaluate these or similar strategies
for applicability and effectiveness at each of their plants as part of conducting the Individual
Plant Examination (IPE) called for in Generic Letter 88-20: "Individual Plant Examination for
Severe Accident Vulnerabilities." This generic letter supplement also transmits for information
the enclosed NUREG/CR-5474, which contains a technical assessment of these accident
management strategies.
This generic letter supplement does not establish any requirements for licensees to take the
specific accident management strategies into account as part of the IPE or to implement any of
the strategies. Adoption on the part of a licensee of any accident management strategies in
response to this supplement is voluntary. (emphasis added)
The SAMGs were strictly voluntary. Between 1989 and 1998, following the issuance of this
generic letter, there were yearly progress reports to the Commission on the status of
implementation of the Integration Plan. SAMGs implementation at licensee facilities was
completed at the end of 1998.
Conclusions Drawn from Previous Commission Deliberations on SAMGs
1. Severe accident risk was not viewed by the Commission to be at a level that would
warrant regulatory action for adequate protection of public health and safety
(1985 Severe Accident Policy Statement).
a. SAMGs, which are the guideline set used by licensee personnel to mitigate the
consequences of events and accidents after the onset of core damage, as a
direct result, also would not be considered necessary for adequate protection of
public health and safety to mitigate severe accident risk (i.e., if that were the
case, then new SAMGs requirements would have been immediately imposed).
Accordingly, SAMGs were not imposed as requirements on licensees. This
remains the position today (prior to the current rulemaking).
2. Industry, through a voluntary initiative, involving the Electric Power Research Institute
(EPRI), owners groups, NUMARC (now NEI), and the licensees implemented SAMGs by
the end of 1998, with full cognizance and agreement of the Commission.
3. SAMGs were viewed as being significant in terms of enhancing safety but the NRC
never quantified this benefit or conducted a backfit analysis to reach a conclusion as to
whether SAMGs could be imposed as requirements. It is reasonable to attribute this in
part, to the voluntary efforts of the industry, which were extensive, and the fact that in the
late 1990s, NRC policy was to credit industry voluntary initiatives (i.e., such that if there
was a substantial benefit to SAMGs, crediting the industry initiative would remove that
benefit and the backfit criteria would be very unlikely to be satisfied).
With this background, the following discussion represents the NRC’s backfit analysis for
reconsidering the need to impose SAMGs requirements in the aftermath of the Fukushima Daiichi accident.
(1)

Statement of the specific objectives that the backfit is designed to achieve

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Basis for Reconsidering the Need to Impose SAMGs15 Requirements
There are two principal factors that cause the NRC to reconsider its view of imposing SAMGs
requirements:
•

A greater appreciation of external event uncertainty and the consequences that can
occur as a result of an inadequate facility design basis for external events (i.e., this
recognizes that the current regulatory effort stems from the Fukushima event and the
recommendations of the NTTF).

•

The SAMGs voluntary initiative was not entirely successful, in that it did not result in
licensees consistently maintaining SAMGs across the industry (although all licensees
have SAMGs). The voluntary initiative did not compel all licensees to update and
maintain SAMGs.

Greater Appreciation for External Event Uncertainty
After the Fukushima event, there is a greater appreciation that some external events have
significant uncertainty in terms of the known return frequency and associated event conditions.
In fact, this greater appreciation for external event uncertainty was the fundamental basis for the
Commission’s issuance of Order EA-12-049 requirements to have increased defense-in-depth
mitigation measures for BDBEEs.
After Fukushima, the NRC mindset changed. Today, the NRC would more likely conclude that
the deterministic external event design bases (which are dated) are not always robust. Further,
the staff notes that these phenomena are better understood today than in the 1960s when the
majority of the current operating plants were being sited. So while General Design Criteria
(GDC)-2 of 10 CFR Part 50 and its predecessor GDC recognized the need for understanding
the regional history concerning external events, including the need to have margin in the design
of power reactor facilities for such events, the GDC did not account for the potential that better
knowledge would be acquired in the future concerning external events. Of course this
eventuality is accounted for under the NRC’s backfit rule, hence the current analysis. In terms
of some external events such as floods, it can be difficult to obtain historical information
regarding recurrence frequency and event magnitude that support making a determination for
the need for regulatory action (because the risk remains much less well-known). As such there
is more uncertainty for these sites, which places greater importance on mitigation strategies and
SAMGs.
In terms of SAMGs requirements, the Fukushima event demonstrates that BDBEEs can occur
and lead to core damage with the subsequent need to implement SAMGs. Further, when
external events exceed the facility protection level, extensive damage to the facility can result
and complicate mitigation efforts, placing greater importance on mitigation approaches that are
flexible and adaptable, and include pre-planned strategies.
Voluntary Industry Initiative
15

SAMGs requirements for the purposes of this backfit discussion include a requirement for the SAMGs itself, and
supporting requirements to ensure that licensees integrate the guideline set with other procedures and guideline
sets as applicable, maintain the SAMGs within the configuration management program of the facility, control
changes to the SAMGs, conduct drills and/or exercises to provide a sufficient level of assurance that the SAMGs
can be implemented, and train key personnel that make decisions and direct the implementation of the SAMGs.

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The second significant new piece of information is that that the industry’s voluntary initiative was
not entirely successful in ensuring that all licensees adopted SAMGs, maintained the capability
to implement SAMGs effectively, and updated SAMGs. While SAMGs were in place at all sites,
they were not always reflective of the most up-to-date owners groups’ SAMG versions. This
leads to the conclusion that absent requirements for SAMGs, the NRC cannot have a sufficient
level of regulatory assurance that SAMGs will be updated and maintained over time and that
licensees will maintain their capability to effectively implement SAMGs.
(2)

General description of the activity that would be required by the licensee or
applicant in order to complete the backfit

Option 2 under the regulatory analysis would have required licensees to:
•
•
•
•
•
•

Develop, implement, and maintain site-specific SAMGs.
Verify that SAMGs are integrated with existing emergency procedures.
Verify their supporting organizational structure is adequate to perform the activities
called for in the SAMGs.
Ensure adequate training of personnel that perform SAMGs by developing new training
materials and delivering training to the appropriate individuals onsite.
Conduct drills or exercises to demonstrate the capability to implement SAMGs.
Develop change control procedures, programs, or plans for site-specific SAMGs.
(3)

Potential change in the risk to the public from the accidental offsite release of
radioactive material

The following discussion provides a better understanding of the safety importance of SAMGs
and considers whether the current regulatory state for SAMGs (i.e., voluntary SAMGs not
updated and maintained in all cases by all licensees) impacts safety and therefore warrants
imposition of SAMGs requirements.
How important are SAMGs for public health and safety (i.e., assuming that no SAMGs existed)?
Without SAMGs, it is likely that informed decisions would not be made for the best use of
human and equipment resources following core damage. Decisions regarding containment, and
specifically maintaining containment integrity under human control, minimization of radiological
releases (including action that might halt the core damage progression) would be more ad hoc
and less effective than if the proposed SAMGs requirements were implemented. The SAMGs,
by providing information (e.g., potential impending loss of a fission product barrier) that informs
decisions made by the ERO, help to support more informed protective action recommendations.
It is not reasonable to assume that the site staff could create SAMGs strategies and give proper
consideration to the effects of core damage during an event due to the complexity of core
damage events and the associated phenomena that occur. The SAMGs document more than
20 years of research and analysis. They are a guideline set that supports informed decision
making.
A more important question is whether there is sufficient severe accident risk that SAMGs would
then substantially reduce, such that this proposed imposition can be supported. There are
sound reasons to conclude that the current risk of severe accidents is much less than existed in
1985, when the Commission concluded that severe accident risk did not warrant immediate

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regulatory action. There are 30 additional years of regulations now in place, and those
additional regulations have collectively and substantially lowered the risk (i.e., the regulations
issued as either adequate protection requirements or substantial additional protection
requirements should have individually and collectively reduced risk). One important and
relevant example is the SBO rule (10 CFR 50.63). This rule was a cost-justified substantial
safety enhancement that reduced risk through the removal of approximately 75 percent of the
existing core damage frequency stemming from blackouts. At the time the SBO rule went into
effect (1988), SBO was a dominant contributor to risk for many plants (e.g., refer to NUREG1776, “Regulatory Effectiveness of the Station Blackout Rule,” dated August 2003
Section 3.2.1). The recent post-Fukushima requirements imposed by Order EA-12-049 have as
an important benefit the virtual elimination of the remaining SBO risk (i.e., residual risk
stemming from a loss of offsite power (LOOPs) with coincident onsite emergency ac power
source failure) by providing power reactors with “indefinite” SBO coping capability. For the
events that 10 CFR 50.63 addressed (i.e., those not stemming from BDBEEs), the Order EA-12049 mitigation strategies that would be made generically applicable by this proposed rule, are
very likely to be successful. The result of just these two regulatory actions alone has
substantially reduced risk to well below the levels that existed in 1985.
The NRC sought to make use of any applicable quantified risk information that might provide
risk insights to inform this justification. In this regard, the NRC looked at its recent technical
analysis work performed in support of the Containment Protection and Release Reduction
(CPRR) rulemaking regulatory basis.16 This analysis estimated the potential benefits of
strategies used after the onset of core damage. This analysis work was considered relevant
because it examined regulatory alternatives that would be implemented after core damage to
determine whether any of the contemplated approaches can be justified under the NRC’s
backfitting provisions, and in this respect, the risk insights stemming from this work might have
relevance to NRC’s consideration of SAMGs requirements where the safety benefits would
occur after core damage. The NRC also considered other post-Fukushima regulatory efforts
(e.g., the safety benefits that occur due to implementation of Order EA-12-049 mitigation
strategies, which result in a reduction in core damage frequency) within this technical analysis.
The NRC acknowledges that the work to support the CPRR rulemaking was not intended to,
and does not provide, a complete quantitative measure of the possible safety benefits of
SAMGs requirements, particularly with regard to how SAMGs might benefit maintenance of
containment integrity or support more informed protective action recommendations by the ERO
following core damage. However, this technical analysis work does provide valuable risk
insights that the NRC concluded were important to fully inform the decision on this matter, and
that additionally influenced the NRC’s development of the proposed SAMG framework under
Option 2 of the regulatory analysis.
The CPRR technical analysis includes a screening analysis for estimating a conservative high
estimate of frequency-weighted ILCF risk. This screening analysis combined the highest ELAP
frequency among all Mark I and II BWRs, a success probability in the FLEX equipment of
0.6 per demand following core melt, the highest conditional ILCF risk among all Mark I and II
BWRs, and a worst case re-habitability assumption. This yields a conservative high estimate of
frequency-weighted ILCF risk of approximately 7x10-8 per reactor year. This combination of
assumptions does not exist at any Mark I or Mark II power reactor. This conservative estimate
of the risk can be viewed as the maximum possible risk that could be removed or reduced
16

Refer to the draft regulatory basis for Containment Protection and Release Reduction in ADAMS Accession
No. ML15022A214 for further details.

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through regulatory action (i.e., the CPRR technical analysis examines a range of post-core
damage regulatory actions for BWRs with Mark I and Mark II to identify whether any of these
proposals might result in a safety benefit large enough to be justified under the Commission’s
backfitting requirements). This estimate is compared against the QHO, which is a quantitative
measure that equates to 1/10 of 1 percent of the ILCF risk and relates to the Commission’s
Safety Goal Policy. This quantitative metric for the ILCF risk is approximately 2x10-6 per reactor
year. This technical work shows that the risk is well below a level that equates to 1/10 of 1
percent of the surrounding population’s latent cancer fatality risk. This result also means that,
from a quantitative standpoint, achieving risk reductions that might satisfy backfitting
requirements is unlikely. More refined risk estimates from the same work (i.e., which remove
the worst case assumptions and instead use assumptions specific to each power reactor), push
this potential risk benefit significantly lower, by approximately two orders of magnitude. This
result demonstrates the benefits of the NRC’s regulations to both effectively keep the frequency
of core damage very low at Mark I and II designs, and to ensure through emergency
preparedness requirements that the surrounding population is adequately protected. Those
general attributes of the NRC’s regulations that result in this risk insight (i.e., requirements that
resulted in reduced core damage frequencies and effective emergency preparedness
requirements) apply to all power reactor designs. The NRC has not performed a
comprehensive quantitative analysis of the potential safety benefits of SAMGs requirements for
all types of reactors. However, the general risk insights obtained from the CPRR work align well
with NUREG-1935, “State-of-the-Art Reactor Consequence Analyses (SOARCA) Report,”
(November 2012), which shows very low levels of risk (individual early fatality risk essentially
zero and ILCF risk thousands of times lower than the NRC Safety Goal and millions of times
lower than the general cancer fatality risk in the United States from all causes). As such, the
available risk insights point to the likely outcome that a comprehensive quantitative analysis,
where the proposed regulatory action is intended to provide its safety benefit in the post-core
damage environment (as is the case for use of SAMGs) would not demonstrate a substantial
safety benefit. In addition, for the specific case of proposed SAMGs requirements, the
proposed regulatory action’s benefit must also recognize that imposing SAMGs requirements
must be compared with the current regulatory state in which SAMGs are already in existence as
a voluntary industry initiative.
Following the onset of core damage, SAMGs are valuable at providing important information to
decision makers that support more informed decisions and actions on the use of resources in a
severe accident. Typically, the SAMGs support decision makers as they work to minimize,
reduce, and delay the releases of fission products. Furthermore, there are some accident
sequences for which SAMGs actions may be successful in halting the progression of the
accident (i.e., providing a much larger benefit for those sequences). Recognizing the
substantially increased mitigation capabilities stemming from the implementation of Order EA12-049 requirements and additionally noting the flexible and adaptable nature of the strategies
to include the potential for offsite resources to assist with mitigation, it is more likely that the
opportunities for halting a core melt progression have increased.
The available risk information indicates that SAMGs would have a small safety benefit. The
NRC took a broader view of the SAMGs and considered whether the qualitative benefits of
SAMGs in addition to the small quantitative benefits could result in a substantial increase in
protection to public health and safety.
How important to safety are updated SAMGs subject to NRC oversight relative to the current
voluntary approach?

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Updating the SAMGs enables about 20 years of additional insights to be considered including
Fukushima insights. This enhances the candidate high level actions (five new candidate high
level actions are added to reflect lessons learned from Fukushima), results in an improved
SAMGs decision making process, and leads to better post-core damage decisions and actions.
Requiring SAMGs (i.e., requiring licensees to develop, implement, and maintain site-specific
SAMGs that would reflect the recent generic efforts and the plant-specific features, including a
nominal level of training and drills) would specifically result in more informed decisions and
actions (when compared to a presumed state of voluntary SAMGs that are not up to date and
may not reflect the current plant configuration) involving:
•
•
•
•
•

Containment;
Minimization and delay of radiological releases;
Use of all equipment including the mitigation equipment of Order EA-12-049;
Use of Order EA-13-109 EPGs/SAGs for Mark I and II designs;
Decisions made by the ERO following core damage.

SAMGs directly support maintenance of containment integrity following severe accidents, and
indirectly support the protective action recommendations made by the ERO and as such are
considered to support two key, defense-in-depth foundational elements of the NRC’s regulatory
framework: Containment and Emergency Preparedness. These features and requirements
have their greatest importance to safety after the onset of core damage (i.e., when fission
products are present), at which time the plant transitions to SAMGs, which then serve as the
operative guideline set for decisions and actions concerning the use of containment (to minimize
and delay of fission product releases) and support to emergency response (to inform the ERO
regarding fission product barrier integrity).
Updated, site-specific SAMGs would:
1. Provide a more complete and improved set of actions (e.g., new candidate high level
actions as reflected in the updated SAMGs) for consideration following core damage;
2. Provide a more complete set of equipment and strategies for use in mitigating the effects
of core damage (i.e., the mitigation strategies equipment imposed by Order EA-12-049);
3. Reflect the current plant configuration to facilitate the use and consideration of new
candidate high level actions reflected in the updated SAMGs (per number 1 above) and
mitigation equipment (per number 2 above).
If it is assumed that the current worst case situation is voluntary SAMGs that are outdated, not
updated to reflect the industry efforts and not maintained so as to reflect the plant’s current
configuration, imposition of SAMGs requirements (versus a continuing voluntary initiative) would
not likely reduce severe accident (known) risk in a substantial manner. In this worst case
assumed condition, the SAMGs would still provide benefit to decision makers should an event
occur and lead to core damage. More importantly, the practical reality is that in a real event, if
there is time and communications capability, then experts would be assisting the plant staff in
making post-core damage decisions (i.e., similar to the recent experience for the Fukushima
Dai-ichi event). In fact, the plant personnel, given their experience with mitigation strategies
would likely be able to implement strategies (even with outdated SAMGs because of the recent
efforts to implement Order EA-12-049) that would be effective. As such, imposing SAMGs,
while beneficial, would result in well maintained and updated SAMGs, but is not likely to result in
measureable reductions in risk.

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What are the qualitative benefits of imposing SAMGs requirements?
The NRC’s regulatory framework reflects a philosophy of defense-in-depth. One important
element of defense-in-depth is to maintain a balance that includes prevention of core damage,
prevention of containment failure or bypass, and mitigation of the consequences of accidents.
As discussed above, SAMGs have their safety benefit after the onset of core damage and as
such contribute to the prevention of containment failure and provide information that optimizes
the decision process for the mitigation of accident consequences. There is a sound basis for
concluding that the risk of severe accidents is very low (which in turn reduces the benefits of
SAMGs). However, when SAMGs are viewed from the larger perspective of defense-in-depth
and the need to maintain a balance that includes prevention of containment failure and the
mitigation of accident consequences, then SAMGs become a very important part of defense-indepth. After core damage, SAMGs are the guidelines employed to make the key decisions to
mitigate the consequences of the accident. From this perspective, SAMGs are, after core
damage, the equivalent of the EOPs, prior to core damage. All of the decisions and associated
mitigation actions following the onset of core damage are informed by, or stem directly out of,
the SAMGs. SAMGs support actions and decisions to:
1. Halt the progression of the accident (if possible);
2. Minimize or delay the release of fission products (including making best use of the
containment);
3. Cope with the radiological conditions, make decisions regarding onsite mitigation, make
notifications to offsite organizations, and make recommendations regarding offsite
protective actions.
For example, decisions regarding containment (i.e., to open, close, or cool containment, in order
to reduce the chance of the loss of containment integrity due to a structural failure) after core
damage occurs when containment serves its principle function as a fission product barrier, are
made using the SAMGs. For this reason alone, the SAMGs are very important from a defensein-depth standpoint. In addition, the SAMGs inform the actions of the ERO (i.e., providing
information to that organization regarding the status of fission product barriers which in turn can
influence both onsite and offsite protective action recommendations). This link between SAMGs
and emergency preparedness actions provides another defense-in-depth layer and as such
supports another fundamental part of the NRC’s regulatory infrastructure: Emergency
Preparedness.
Finally, SAMGs requirements could have an additional benefit for facilitating a more complete
treatment of external event uncertainties. As previously discussed, an important new piece of
information that informs the current perspective on SAMGs requirements is the greater
appreciation for external event uncertainties that stems from the Fukushima event. The
Commission recognized the need to address this uncertainty and imposed mitigation strategies
on power reactor licensees to provide an additional capability for the mitigation of BDBEEs.
Complete implementation of Order EA-12-049 could be viewed as involving the updating of
SAMGs to reflect the availability and use of this equipment to implement similar strategies in the
post-core damage environment. While licensees may in fact make these kinds of changes to
their current SAMGs without SAMGs being requirements, these updates would definitely occur if
SAMGs were imposed as requirements.
(4)

Potential impact on radiological exposure of facility employees

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The discussion under Item 3 also applies to the potential impact on radiological exposure of
facility employees.
(5)

Installation and continuing costs associated with the backfit, including the
cost of facility downtime or the cost of construction delay

The industry through EPRI and the BWROG and PWROG have spent considerable effort and
resources updating the SAMGs and producing an updated version that is a significant
improvement over the original SAMGs developed during the 1990s. Licensees would still incur
a cost to take the new owners groups’ SAMGs and adapt them to their sites to reflect sitespecific features and current site configuration. This cost is estimated in the supporting
regulatory analysis to this proposed rulemaking.
This estimated impact is considered to be most significant for PWR licensees, which due to the
effort to produce a single SAMG for all three vendors means that some licensees will have a
larger task to produce the site-specific version (i.e., the new generic PWR SAMG may deviate
significantly from the version that the licensee voluntarily implemented at the end of 1998).
The estimated one-time industry cost associated with the backfits would be approximately
$30 million, and the annually recurring cost would be approximately $2.4 million. Combining
these initial and annual costs, this analysis estimates that the backfits associated with Option 2
of the regulatory analysis would cost industry approximately $58 million (present value,
assuming a 7 percent discount rate) to $72 million (present value, assuming a 3 percent
discount rate).
This estimate also reflects the NRC’s effort to develop the proposed SAMG regulatory
framework in a manner that is informed by these risk insights as follows:
1. The proposed requirements for inclusion of SAMGs requirements under Option 2 of the
regulatory analysis would be limited to requiring the SAMG guideline sets, and not
extended to require NRC review and approval of SAMG strategies, use of the equipment
within the SAMGs, or for NRC to require that licensees re-assess the work that industry
has completed over 20 plus years to develop the SAMGs, including the recent effort to
update and revise the SAMGs to reflect the Fukushima lessons learned.
2. The proposed requirements for inclusion of SAMGs requirements under Option 2 of the
regulatory analysis would be intended to address the problem identified with the SAMG
voluntary initiative after Fukushima, and to require that SAMGs be updated and
maintained. Specifically, this would mean that the plant-specific SAMGs would be
maintained within the plant configuration management system and be updated to reflect
generic industry improvements at a reasonable frequency.
3. The proposed requirements and supporting endorsed guidance for inclusion of SAMGs
requirements under Option 2 of the regulatory analysis would be intended to result in an
integration of the SAMGs with the other guideline sets and the symptom-based EOPs,
consistent with proposed 10 CFR 50.155(b). The NRC’s intent would be to verify that
this integration is in place through inspection.
(6)

The potential safety impact of changes in plant or operational complexity,
including the relationship to proposed and existing regulatory requirements

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The discussion under Item 3 also applies to the potential safety impact of the proposed
requirements for inclusion of SAMGs requirements under Option 2 of the regulatory analysis.
(7)

The estimated resource burden on the NRC associated with the backfit and
the availability of such resources

The NRC would oversee licensee implementation of site-specific SAMGs, drills and exercises,
and the change control process. In addition, the NRC would develop the final rule package.
The estimated one-time cost to the NRC associated with the backfits would be approximately
$1.1 million, and the annually recurring cost would be approximately $170,000. Combining
these initial and annual costs, this analysis estimates that the backfits associated with the
proposed rule would cost the NRC approximately $3.1 million (present value, assuming a 7
percent discount rate) to $4 million (present value, assuming a 3 percent discount rate).
As discussed above, the proposed SAMG regulatory framework for inclusion of SAMGs
requirements under Option 2 of the regulatory analysis does not include NRC review and
approval of either the generic or plant-specific SAMGs.
(8)

The potential impact of differences in facility type, design, or age on the
relevancy and practicality of the backfit

The costs attributable to Option 2 of the regulatory analysis would vary for a variety of sitespecific reasons, including the nuclear power reactor’s facility type, design, or age. These
variations are reflected in the estimates provided in Section 3 of the regulatory analysis.
However, the additional protection for defense-in-depth that results from the SAMGs
requirements in the proposed rule is expected to be consistent across industry, and would not
directly relate to the facility type, design, or age.
(9)

Whether the backfit is interim or final and, if interim, the justification for
imposing the backfit on an interim basis

The backfit for inclusion of SAMGs requirements under Option 2 of the regulatory analysis was
not justified.
Conclusion
If this backfit decision were based solely on known (quantified) risk, then the NRC’s recent
regulatory efforts associated with the CPRR regulatory basis would cause the NRC to conclude
that imposition of SAMGs requirements would not result in a substantial safety benefit to public
health and safety. As such, SAMGs requirements would not satisfy the standard of
10 CFR 50.109(a)(3).
The NRC took a broader view of the SAMGs and considered the qualitative benefits in addition
to the small quantitative benefits. Important actions concerning minimization of fission product
releases, delay of fission product release, and the use of containment in this regard, are
supported with SAMGs. The SAMGs can potentially support more informed recommendations
made by the ERO in terms of protective actions for both onsite and offsite personnel. The
SAMGs provide a set of information and considerations for mitigation in a post-core damage

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environment that directly support these key defense-in-depth elements of the NRC’s regulatory
framework.
Notwithstanding these qualitative considerations and recognizing that SAMGs are beneficial to
safety, the NRC concluded that making voluntary SAMGs a requirement would not result in a
qualitative safety benefit large enough to supplement the small quantitative risk benefit such that
a substantial additional protection of public health and safety would be achieved. Accordingly,
the agency concludes that imposition of SAMGs requirements per Option 2 of the regulatory
analysis is not supportable under the provisions of 10 CFR 50.109.

References
NRC Policy Statement, “Severe Reactor Accidents Regarding Future Designs and Existing
Plants” (Volume 50, page 32138, of the Federal Register, 50 FR 32138, August 8, 1985.
NRC Policy Statement, “Safety Goals for the Operations of Nuclear Power Plants,”
51 FR 28044, August 4, 1986.
SECY-88-147, “Integration Plan for Closure of Severe Accident Issues,” May 25, 1988.
SECY-89-012, “Staff Plans for Accident Management Regulatory and Research Programs,”
January 18, 1989.
Generic Letter 88-20 Supplement 2 “Accident Management Strategies for Consideration in the
Individual Plant Examination Process (Generic Letter 88-20 Supplement No. 2),” April 4, 1990.
EPRI Report TR-101869 “Severe Accident Management Guidance Technical Basis Report,”
dated December 1992.
NEI 91-04 revision 1 (formerly NUMARC 91-04), “Severe Accident Issue Closure Guidelines,”
December 1994.
NRC Letter dated June 20, 1994 to William Rasin (NEI) accepting NEI 91-04 as meeting the
objectives of SECY-89-012.
There were numerous progress SECYs (every year) – reporting on implementation of SAMGs
including: SECY-89-308, SECY-90-180, SECY-90-384, SECY-94-166, SECY-95-004,
SECY-96-088, SECY-97-132, and SECY-98-131.
NRC Policy Statement, “The Use of Probabilistic Risk Assessment Methods in Nuclear
Regulatory Activities,” 60 FR 42622, August 16, 1995.
Staff Requirements (SRM)–SECY-12-0025 – Proposed Orders and Requests for Information in
Response to Lessons Learned from Japan’s March 11, 2011, Great Tohoku Earthquake and
Tsunami, March 9, 2012.
New Reactor Related:

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10 CFR Part 52, “Early Site Permits; Standard Design Certification; and Combined Licenses for
Nuclear Power Plants.”
SECY-90-016, “Evolutionary Light-Water Reactor (LWR) Certification Issues and Their
Relationship to Current Regulatory Requirements,” issued January 12, 1990, and the
corresponding SRM, issued June 26, 1990.
SECY-93-087, “Policy, Technical, and Licensing Issues Pertaining to Evolutionary and
Advanced Light-Water Reactor Designs,” issued April 2, 1993, and the corresponding SRM,
issued July 21, 1993.
SECY-96-128, “Policy and Key Technical Issues Pertaining to the Westinghouse AP600
Standardized Passive Reactor Design,” issued June 12, 1996, and the corresponding SRM,
issued January 15, 1997.
SECY-97-044, “Policy and Key Technical Issues Pertaining to the Westinghouse AP600
Standardized Passive Reactor Design,” issued February 18, 1997 and the corresponding SRM
issued June 30, 1997.

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Appendix B. Historical Cost Analysis
In this appendix, the NRC estimates the costs associated with Order EA-12-049, Order
Modifying Licenses with Regard to Requirements for Mitigation Strategies for Beyond-DesignBasis External Events, Order EA-12-051, Order Modifying Licenses with Regard to Reliable
Spent Fuel Pool Instrumentation, and related activities undertaken by industry following
Fukushima (Refs. 1 and 2). The NRC analyzed these historical costs for informational
purposes—to inform both the Commission and the public regarding some of the activities that
have been undertaken since the Fukushima accident. These costs are attributable to Order EA12-049, Order EA-12-051, and related activities, rather than the proposed rule. However, the
proposed rule includes provisions that require the activities described in the following section.

B.1

Methodology and Assumptions

As mentioned above, the historical cost analysis estimates the costs resulting from Order EA12-049, Order EA-12-051, and industry initiatives. This analysis does not account for all of the
costs incurred by industry and the NRC post-Fukushima. The following sections describe the
methodology used to estimate the costs associated with Order EA-12-049, Order EA-12-051,
and related industry initiatives, which have been or will be incurred prior to the proposed rule’s
effective date.

B.1.1 Methodology for Estimating the Costs of Order EA-12-049
Order EA-12-049 requires licensees and COL holders to develop guidance and strategies to be
implemented in response to BDBEEs. The NRC discusses the historical costs of Order EA-12049 according to activities required by the Order.
Affected Universe
Order EA-12-049 affects both current and new NPP licensees. There are some differences in
how licensees are affected depending on the operational state of their reactors (e.g., operating,
under construction, and new designs). This section describes how the estimates and
evaluations of costs differ between these categories.
The NRC estimates costs on a per-site basis. The cost analysis includes three reactor types:
BWR, PWR, and AP1000. Due to reactor differences, activities undertaken to come into
compliance with the requirements set forth by Order EA-12-049 differed among these reactor
types. Therefore, the NRC evaluates the costs separately for each reactor type (see the Cost
Estimation section below for the NRC’s cost estimating approach). In all, the NRC estimates
the costs for 62 sites (60 operating reactor sites plus 2 AP1000 sites) to separately account for
the costs associated with the AP1000 reactors which will differ from the costs incurred by the
co-located PWRs (i.e., V.C. Summer and Vogtle).17 Costs also differ depending on how many
reactor units are located on each site. Therefore, the NRC further differentiates the affected
universe by the number of units on each BWR, PWR, and AP1000 site. Exhibit B-1 shows the
total number of sites accounted for costs in the historical cost analysis due to Order EA-12-049
by reactor type and number of units.

Because the costs related to Order EA-12-049 are significantly lower for sites with AP1000 reactors, the NRC
modelled these two sites as four sites, two of which will incur costs only for the PWRs and two of which will incur
costs only for the AP1000 reactors.

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Exhibit B-1. Site Counts by Number of Units and Reactor Types
BWRs

PWRs

AP1000s

Total Sites

One Unit

Two Units

Three Units

24 Sites

38 Sites

2 Sites

64 Sites

Total Sites

The cost analysis of Order EA-12-049 accounts for 24 BWR sites. There are fourteen 1-unit,
nine 2-unit, and one 3-unit BWR sites. Two of the 1-unit BWR sites are decommissioning sites
(i.e., Oyster Creek and Vermont Yankee). Exhibit B-2 lists each BWR site included in the
historical cost analysis related to Order EA-12-049 by its number of units.
Exhibit B-2. List of BWR Reactor Sites Included in the Analysis by Number of Units
1-Unit BWR Sites

2-Unit BWR Sites

3-Unit BWR Sites

Clinton

Brunswick

Browns Ferry

Columbia

Dresden

Cooper

Edwin I. Hatch

Duane Arnold

LaSalle County

Fermi

Limerick

Grand Gulf

Nine Mile Point

Hope Creek

Peach Bottom

James A. FitzPatrick

Quad Cities

Monticello

Susquehanna

Perry
Pilgrim
River Bend
Oyster Creek
Vermont Yankee
14 Sites

9 Sites

1 Sites

The analysis of Order EA-12-049 also accounts for 38 PWR sites. There are twelve 1-unit,
twenty-four 2-unit, and two 3-unit PWR sites. Exhibit B-3 lists each affected PWR site by its
number of units. Because the NRC rescinded the Order requirements for four decommissioning
sites (i.e., Crystal River, Kewaunee, San Onofre, and Vermont Yankee), these sites are no
longer required to comply with the Order requirements and are not included in the cost analysis
of Order EA-12-049.

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Exhibit B-3. List of PWR Reactor Sites Included in the Historical Cost Analysis by
Number of Units
1-Unit PWR Sites

2-Unit PWR Sites

3-Unit PWR Sites

Callaway

Arkansas Nuclear One

Oconee

Davis-Besse

Beaver Valley

Palo Verde

Fort Calhoun

Braidwood

H.B. Robinson

Byron

Palisades

Calvert Cliffs

R. E. Ginna

Catawba

Seabrook

Comanche Peak

Shearon Harris

Donald C. Cook

Three Mile Island

Diablo Canyon

Virgil C. Summer

Indian Point

Waterford

Joseph M. Farley

Wolf Creek

McGuire
Millstone
North Anna
Point Beach
Prairie Island
St. Lucie Plant
Salem
Sequoyah
South Texas Project
Surry
Turkey Point
Vogtle
Watts Bar

12 Sites

24 Sites

2 Sites

The analysis of Order EA-12-049 includes two AP1000 sites. Both are 2-unit sites and are
listed in Exhibit B-4. The AP1000 sites are still under construction. However, the NRC imposed
requirements on these construction sites via Order EA-12-049 (Vogtle Units 3 and 4) and
license condition (March 30, 2012, Memorandum and Order, CLI-12-09 (Ref. 3), V.C. Summer
Units 2 and 3). The analysis of Order EA-12-049, therefore, estimates the costs associated with
the Order requirements for both AP1000 sites.
The AP1000 reactors possess several safety design features and onsite equipment that allow
the reactors to cope longer during an SBO event than BWRs and PWRs. Because of its design
features, the impact of the Order requirements on the AP1000 sites is smaller than that on the
BWR and PWR sites (see Section B.2.1 for additional discussion of these costs).

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Exhibit B-4. List of AP1000 Reactor Sites Included in the Historical Cost Analysis by
Number of Units
1-Unit AP1000 Sites

2-Unit AP1000 Sites

3-Unit AP1000 Sites

Virgil C. Summer
Vogtle
0 Sites

2 Sites

0 Sites

Cost Estimation
The NRC used information from sites’ Overall Integrated Plans (OIPs) to estimate the costs of
the Order. These plans laid out how compliance with the Order will be achieved.
Data Sources for Inputs
The NRC gathered equipment cost data from multiple sources. The staff gathered unit cost
data from suppliers and industry sources. In addition, the NRC used the RSMeans cost
reference books, Building Construction Cost Data and Facilities Construction Cost Data, for
certain compliance activities (Refs. 4 and 5). An EPRI study, Costs of Utility Distributed
Generators, 1-10 MW: Twenty-Four Case Studies also provided costs for generators,
switchgears, and transformers (Ref. 6). In addition, the NRC consulted with industry experts to
estimate certain cost data.
The NRC estimated loaded labor costs according to data provided by the BLS and wage rates
used in related NRC regulatory analysis. The NRC used the 2013 Occupational Employment
and Wages data. Note that all costs presented in this analysis are in 2013 dollars. As per
NUREG/CR-4627, Generic Cost Estimates, direct wage rates are loaded using a multiplier of
two to account for licensee and contractor labor and overhead (i.e., fringe, benefits, general
administration, and profit) (Ref. 7). A loading factor of two is considered conservative.
Exhibit B-5 presents the labor rates used throughout this analysis.
Exhibit B-5. Labor Rates Used in the Historical Cost Analysis
Labor Category

Mean Wage Rate

Loaded Wage
Factor
B

Loaded Wage Rate

A
C=AxB
Mechanical Engineers
$41.31
$82.62
Electricians
$25.75
$51.50
Plumbers, Pipefitters, and
$25.88
$51.76
Steamfitters
Control and Valve Installers
2
and Repairers, Except
$25.95
$51.90
Mechanical Door
Electrical and Electronic
$15.07
$30.14
Equipment Assemblers
Industry Staff
$41.93
$83.85
*The loaded wage rate for Industry Staff was based on recent NRC regulatory analysis.
**The mean wage rate for Mechanical Engineers (SOCI 17-2141); Electricians (SOC 47-2111); Plumber,
Pipefitters, and Steamfitters (SOC 47-2152); Control Valve Installers and Repairers, Except Mechanical
Door (49-9012); and Electrical and Electronic Equipment Assemblers (SOC 51-2022) were provided by
BLS.

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Estimating Quantity of Equipment Needed
Working from a sampling of the 1-unit reactor sites’ OIPs, the NRC estimated how many pieces
of equipment and supplies were required. The NRC referenced these BWR and PWR OIPs to
estimate the quantities needed at a “typical” 1-unit site. The NRC estimated the quantity of
equipment needed for 2- and 3-unit sites from the 1-unit site data (the assumptions used to
estimate quantities are described in more detail in the following section, Description of
Assumptions Used in the Analysis).
The NRC also used sources outside of the OIPs in cases where the OIPs did not provide
sufficient detail to estimate quantities. For example, communications gear is required
equipment under the Order, but the OIPs do not specify the number or type of communication
equipment that needed to be procured. Instead, the NRC referred to a document prepared by
FirstEnergy Nuclear Operating Company (FENOC) in response to an NRC request for
information pursuant to 10 CFR 50.54(f) in which the licensee identified the number and types of
communication equipment shared by three FENOC sites (Ref. 8). The NRC used these data to
approximate the quantity of additional communication equipment needed to comply with the
Order.
Appendices E through M provide a list of assumptions and data sources used in the regulatory
analysis.
Description of Assumptions Used in the Analysis
The NRC applied the following assumptions in this analysis.
Compliance Activities and Equipment Needs
The NRC developed a “model” reference site for each reactor type (i.e., BWR, PWR, and
AP1000). The models include a list of compliance activities that must be performed to comply
with the Order. The NRC used these models, which are based on the contents of a sampling of
OIPs (see Exhibit B-7 for a list of the sampled sites) to approximate the cost of the Order.
The NRC reviewed OIPs from a sampling of 1-unit sites to identify the quantities of equipment
needed at a “typical” 1-unit site. For 2- and 3-unit sites, the NRC derived quantities of
equipment by adjusting the 1-unit site estimates. Required quantities of some of the FSGs
equipment depends on the number of reactors onsite (i.e., “N”). As stated in NEI 12-06, Rev. 0,
Diverse and Flexible Coping Strategies (FLEX) Implementation Guide, an N + 1 equipment
capability applies to portable FLEX equipment (i.e., that equipment that directly supports
maintenance of the key safety functions) (Ref. 9). Any other support equipment only requires
an N capability. Exhibit B-6 shows how the NRC adjusted equipment needs according to the
number of reactors onsite.
Exhibit B-6. Assumptions for Equipment Needs at 2- and 3-Unit Sites
1-Unit Site
2-Unit Site
(N + 1 = 2)
(N + 1 = 3)
Sets of portable, onsite FLEX equipment
2X
3X
Sets of other equipment
X
2X
*N is the number of units and X is the number of sets of equipment needed.

3-Unit Site
(N + 1 = 4)
4X
3X

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Time Period of Analysis
The NRC assumes that operating BWR and PWR licensees and newly constructed AP1000
licensees will incur savings and costs over a 24-, 26-, and 63-year period, respectively.
Decommissioning BWR sites will incur costs and benefits over a 3-year period. These
timeframes represent the average operating license term life plus a 2-year period during which
fuel will be removed from the SFP during decommissioning of the 64 sites included in the
analysis. The time period during which each site will operate depends on the term of the
operating license and how long the licensee chooses to operate within the term. The NRC
assumed that each licensee of an operating or newly constructed reactor will apply for and
receive a 20-year license extension beyond the original 40-year license term. The NRC
assumed that each site will incur costs to comply with the Order over the first 2 years following
the end of the license extension (to cover compliance with Order EA-12-049 during
decommissioning).
Present Value Calculation
The NRC calculated the present value of the costs a licensee would incur beginning in 2012 and
extending over its average remaining operating license term.
Categorization of Costs
The NRC mapped the activities described in the OIPs to overarching categories that best
described their function.18 Each overarching category is described below:
1. Initial response: The initial response category captures activities needed to support the
initial coping phase during an SBO event. This initial coping phase requires use of only
installed onsite equipment. These activities typically consist of modifying installed
equipment to gain additional time to install portable equipment during an event.
Examples of initial response activities include hardening and protecting water sources
and piping, as well as installing low-leakage reactor coolant pump (RCP) seals.
2. Onsite portable equipment: The onsite portable equipment category includes procuring
SBO mitigation equipment that is stored onsite and deployed prior to the availability of
offsite assistance. Portable equipment includes generators, fans, communications gear,
fuel containers, pumps, and food and water commodities, among others. Activities
associated with this category involve modifying existing connections to allow for the use
of portable equipment, as well as procuring the portable equipment.
3. Offsite portable equipment: The offsite portable equipment category reflects the
activities needed to prepare the NSRCs. This includes one-time costs to stock critical
equipment and to staff and train the organization running the NSRCs. Under the
implementation of Order EA-12-049, the industry established two NSRCs located near
Memphis, Tennessee, and Phoenix, Arizona. The NSRCs would be capable of
delivering supplemental emergency equipment to any U.S. nuclear energy facility within
24 hours. The equipment and materials provided by the NSRCs supplement the
additional portable equipment purchased at each U.S. nuclear energy facility.

The NRC used the OIPs submitted by licensees in the February 2013 timeframe.

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4. Supporting functions: The supporting functions category captures activities that support
the first three categories listed. For example, upgrading emergency lighting, as well as
analyzing fuel storage needs and consumption rates, fall within the supporting functions
category.
5. External event considerations: The external event considerations category includes
activities related to the storage and staging of onsite and offsite portable equipment in a
manner that protects the equipment from site-specific external events and allows for
deployment of the portable equipment under extreme onsite conditions.
6. Programmatic controls: The programmatic controls category involves activities related
to maintenance and testing of portable equipment, FSGs change control, and the
periodic training of personnel. For example, this category includes developing an OIP,
conducting staffing analyses, and modifying plant procedures. The category also
includes the ongoing costs related to operating the NSRCs (e.g., staffing, rent, testing
and maintenance, and transportation capabilities). These costs are shared across
industry.
Other Cost Variations Considered
Analysis of the OIPs revealed that some activities vary depending on the site’s characteristics.
For the cost analysis of Order EA-12-049, the NRC focused on variations that posed significant
cost implications for the analysis. The NRC identified two variations that affected cost most
significantly: reactor type (i.e., BWR, PWR, and AP1000) and number of units (i.e., one, two, or
three). With regard to reactor type, the differences between BWR, PWR, and AP1000 facilities
in terms of the structures, systems, and components (SSCs) required to mitigate an SBO event
are significant enough to warrant this distinction. (Subdividing the BWRs and PWRs to
acknowledge the differences in plant vintage and mitigation strategies was considered;
however, the number and significance of such variations was not sufficient to warrant additional
analysis.) With regard to number of units per site, the NRC accounted for cost differences
between 1-, 2-, and 3-unit sites because, for example, “N + 1” sets of some SBOMS equipment,
where N is the number of reactor units onsite, must be available onsite (which can have a
significant impact on costs).
The NRC identified representative compliance activities from the OIPs submitted by several
BWR and PWR plants, as identified in Exhibit B-7.19 The OIPs described site-specific activities
(e.g., relating to specific buses, switchgear, and locations). For this analysis, the NRC
extrapolated from these site-specific activities to identify generic actions and equipment needed.
The NRC’s selection of OIPs covered a variety of site characteristics including NSSS type,
containment type, operator, and applicable hazards. Because the approach uses selected
examples of specific activities from a sampling of sites to estimate industry-wide costs, it could
skew cost estimates. However, the NRC believes the number of activities analyzed is
sufficiently high so that any potential for bias averages out in the final cost estimate.

The NRC considered including sites with Mark II containments, but determined that the activities described in
those OIPs would not serve as suitable models from which to generalize costs industry-wide.

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Exhibit B-7. Sites Used to Develop the Lists of Compliance Activities and Quantities of
Equipment Used
BWR Model
Brunswick
Grand Gulf
Duane Arnold
Edwin I. Hatch
Dresden*
Monticello*
Vermont Yankee*20

PWR Model
AP1000 Model
Davis-Besse
Virgil C. Summer
Donald C. Cook
Vogtle
Joseph M. Farley
Shearon Harris
Braidwood*
Calvert Cliffs*
McGuire*
Millstone*
R. E. Ginna*
Sequoyah*
*These sites were used for estimating equipment quantity—not for developing the list of compliance
activities—because of the level of detail in the OIPs regarding equipment types and quantity.

Cost Variations Not Accounted for in the Analysis
The analysis presents the estimated cost of imposing the Order EA-12-049 requirements for two
significant variations: design type (BWR, PWR, and AP 1000) and number of units per site. In
addition to these variations, the staff considered whether there were other design or operational
differences that could cause the cost to vary for individual sites. The NRC assessed whether
differences could arise due to variations in NSSS vendor, architectural-engineering firm, plant
vintage, individual plant modifications, or core power. Although there are design and
operational differences among these categories, there is similarity in ac power systems. The
staff used their professional judgment to identify eight additional variations (other than reactor
type and number of units) that could affect the costs incurred related to Order EA-12-049.
The following discussion explains the NRC’s consideration of these additional sources of
variation relative to their impact on the total costs of Order EA-12-049.
1. Initial response mitigation strategy differs from NEI-12-06 guidance.
Source of the variation: In their OIPs, some sites departed from NEI 12-06 by either
(1) crediting existing onsite ac power sources for the initial response (this includes crediting
hardened, dedicated shutdown systems for ELAP mitigation) or (2) defining what constitutes a
“robust” structure with respect to seismic events differently than NEI 12-06.
Impact on implementation or operational activities resulting from the variation: Crediting existing
ac power sources at the site would reduce a site’s need to procure some onsite portable
equipment that would provide a similar function. Further, this strategy may allow the licensee to
credit motor-driven seismic Category I pumps and piping that exist at the plant to help with the
initial response. Sites using this approach would incur relatively lower costs as a result of the
Order. With regard to the definition of “robust” structure, a less stringent set of codes or criteria
for determining what constitutes an adequate design to withstand an extreme seismic event
would result in significant cost savings for sites.
20

The OIP issued by Vermont Yankee was issued prior to the announcement of its shutdown. The NRC believes
its OIP is a relevant model.

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Significance of cost impact on implementation or operational activities: The NRC concluded
that variations found in OIPs related to the initial response could result in some savings for sites
choosing to depart from NEI 12-06. The NRC does not estimate the cost savings of these
alternative approaches, however, because the impact on the overall cost of the Order is
expected to be insignificant.
2. Design limitations affect ability to cope during initial response.
Source of the variation: Some design aspects may be inadequate when challenged by an
ELAP event (most likely seismic or high winds events).
Impact on implementation or operational activities resulting from the variation: The design
inadequacies with respect to an ELAP event would need to be remedied. Such inadequacies
could result in activities such as constructing a seismically qualified or tornado missile-proof
tank(s) to provide water inventory. Alternatively, if a site has inadequately qualified equipment
to transfer the water inventory via pumps (e.g., backup instrumentation, piping, and valves),
then these systems would need to be upgraded to appropriately qualify and protect them.
Significance of impact on implementation or operational activities: The costs involved with
addressing design limitations could range from insignificant to substantial. For example, the
construction of seismically qualified or tornado missile-proof tanks with adequate capacity to
meet the needs of an ELAP event could result in significant costs. The design, labor, and
materials costs would be substantial. In addition, sites would need to engage a highly skilled
workforce to connect the new tanks to the existing auxiliary feedwater/emergency
feedwater/reactor core isolation cooling (AFW/EFW/RCIC) system and procure highly qualified
components, such as N-stamp valves. However, the NRC believes that very few sites face
design limitations to the degree that would require substantial, costly modifications. The NRC,
therefore, estimated the costs associated with addressing design limitations that are most
typical among the current fleet.
3. Limited battery capacity
Source of the variation: Some sites have only 2 hours of battery capacity to carry necessary
electrical loads following an SBO event, while other sites have up to 8 hours of battery capacity.
Impact on implementation or operational activities resulting from the variation: Even when
taking into account extended load shedding, limited-capacity batteries are unlikely to provide
adequate voltage for much longer than 4 hours. Sites with limited-capacity batteries would need
to transition from the initial response phase to the use of onsite portable equipment in a shorter
period of time than sites with greater battery capacity. To achieve a quicker transition, sites
would need additional response staff to move and install onsite portable equipment.
Significance of impact on implementation or operational activities: The need for additional
response staff would result in additional costs. Alternatively, sites with limited battery capacity
could procure additional batteries (and potentially battery chargers). Additional batteries would
require additional testing and evaluations of capacity, seismic capacity, room ventilation needs,
and instrumentation, for example. The costs involved with addressing limited battery capacity
could range from insignificant to substantial. The NRC accounted for some battery capacityrelated costs, but could not account for all potential variation in costs across the industry

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because the sampled OIPs do not provide sufficient information on the extent of variation across
the industry.
4. Dewatering pumps for flooded areas that require access
Source of the variation: Due to the potential for internal and external flooding, some sites
require additional equipment (e.g., diesel-driven pumps, hoses, and screens) to dewater flooded
areas in the plant that should be accessible following an ELAP event or where flooding could
disable equipment important to ELAP mitigation.
Impact on implementation or operational activities resulting from the variation: To dewater
areas of the site, licensees would need to procure additional equipment, such as diesel-driven
pump(s). In addition, licensees would need to write associated procedures, perform additional
testing, and train personnel. Some plants may need large dewatering pumps due to the higher
potential leak rate and the larger size of the leaking water source.
Significance of impact on implementation or operational activities: Sites that require dewatering
pumps may be able to use commercial pumps regularly used in agriculture or mining to provide
dewatering needs. Costs for commercial pumps are expected to be somewhat less than the
cost of a FLEX pump that provides flow to a depressurized steam generator (SG) or the reactor
coolant system (RCS). This historical analysis accounts for some dewatering-related costs, but
cannot account for all potential variation in costs across the industry because the sampled OIPs
do not provide sufficient information on the extent of variation across the industry.
5. Westinghouse RCP low-leakage seals
Source of the variation: Recent testing of Westinghouse RCP low-leakage seals at an operating
reactor led NRC to issue a Part 21 Notice that questioned the capability of the new seal design
to significantly lower the leak rate when cooling is lost.
Impact on implementation or operational activities resulting from the variation: There are
multiple vendors attempting to develop RCP low-leakage seals and to seek affirmation from the
NRC as to the efficacy of the seals. In some PWR OIPs, licensees relied on a low (assumed)
rate of RCP seal leakage (i.e., approximately 1 gallon per minute (gpm) per pump). This rate
affected the timing of both RCS depressurization and boron injection. In addition, this rate could
possibly affect the size of portable pumps procured by the licensee. If the RCP seals leak at a
significantly higher rate than assumed in the OIPs, licensees may need to depressurize the
RCS and replenish the RCS inventory earlier in the course of an ELAP event. Licensees also
may need additional staff to meet the additional mitigation demands. Alternatively, a licensee
may need newly designed and tested RCP seals to provide a seal leakage rate similar to that
assumed in the OIPs. These seals could be purchased and installed by the licensee.
Significance of impact on implementation or operational activities: If the rate of the RCP seal
leakage determined by testing is found to be significantly higher than assumed in a site’s OIP,
then the licensee may need to re-work the mitigation strategies described in the OIP. The
timing of events and mitigation strategies would need to be recalculated, which could lead to the
need for additional staff and equipment (e.g., larger pumps may be needed to keep the core
covered due to RCS inventory loss and shrinkage during RCS cool down). Or, a licensee may
choose to replace the RCP seal to provide a low leakage rate when the seal cooling is lost. The
costs involved with addressing RCP low-leakage seals could range from insignificant to
substantial. The NRC accounted for some RCP seal leakage-related costs, but cannot account

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for all potential variation in costs across the industry because the sampled OIPs do not provide
sufficient information on the extent of variation across the industry. Third generation
Westinghouse low-leakage RCP shutdown seals are currently installed at a PWR site and are
planned to be removed and tested in October 2015. The NRC is reviewing a topical report PRA
Model for Generation III Westinghouse Shutdown Seal, July 2014, PWROG-14001-P/NP,
Rev. 1, which supports the Generation III seals (Ref. 10). In addition, other vendors are
developing low-leakage seal designs and Flowserve has submitted a white paper on its seal
design that is under review by the NRC.
6. Provide backup power to igniters (PWR ice condenser/BWR Mark III containments)
Source of the variation: Igniters are required in ice condensers and Mark III BWRs because
these containments rely on steam condensation to control containment pressure and therefore
experience rapid development of flammable hydrogen concentrations. Mark I and Mark II
containments also rely on steam condensation, but they control the hydrogen threat by inerting
the wetwell atmosphere. To prevent containment failure, igniters are installed in strategic
locations in ice condenser and Mark III containment designs to burn off the hydrogen gas before
it can reach a concentration resulting in an explosion that could cause containment failure.
Many igniters are electrically powered.
Impact on implementation or operational activities resulting from the variation: Igniters may lose
power during an ELAP event. To assure that containment integrity is maintained, the power
source for these igniters may need to be rewired to provide an alternative electrical source, such
as portable batteries, small diesel and gas generators, or larger FLEX generators. Licensees
may need to make use of new or unused containment penetrations to meet wiring needs.
Alternatively, igniters that do not require electrical power could be installed inside containment
at appropriate locations. Some PWR ice condenser or BWR Mark III plants already may have
addressed these concerns during implementation of the 10 CFR 50.54(hh)(2) requirements,
although 10 CFR 50.54(hh)(2) does not require the licensee to protect against extreme external
events.
Significance of impact on implementation or operational activities: Significant costs could result
from the need for a new containment penetration (and all the attendant evaluations and
qualifications), as well as new igniters that do not require electric power. The installation of new
igniters would involve containment entry and possible dose accumulation. Some sites may
have igniters that can be manually ignited with portable batteries at the electrical penetration
location(s) following an ELAP event. This historical analysis accounts for some igniter-related
costs, but cannot account for all potential variation in costs across the industry because the
sampled OIPs do not provide sufficient information on the extent of variation across the industry.
7. Diversity of water sources (location and type)
Source of the variation: Some plants have limited water sources, in terms of diversity and
redundancy, for core cooling, SFP cooling, and makeup to the RCS and SFP.
Impact on implementation or operational activities resulting from the variation: Plants with
limited diversity of water sources (e.g., the plant’s only water sources are a condensate storage
tank (CST) and a river) are more vulnerable. These plants may have to provide additional,
protected water sources, such as a hardened tank. At present, these sites rely on having
redundant or diverse paths from the water source (i.e., river, lake, ocean, or pond) to pumps,
rather than providing redundant water sources.

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Significance of impact on implementation or operational activities: Large hardened tanks are
costly. The most costly tanks would be those that need to be protected against seismic, tornado
missile, and hurricane events. The NRC accounted for some costs associated with upgrading
water sources, but could not account for all potential variation in costs across the industry
because the OIPs do not provide sufficient information on the extent of variation across the
industry.
8. Revised seismic or flood hazard (per response to 10 CFR 50.54(f) letter)
Source of the variation: Licensees currently are re-evaluating seismic and flooding hazards
using the most up-to-date seismic and external flood methods and information. This action,
which was prompted by NRC’s 10 CFR 50.54(f) letters, may lead to the discovery of seismic
hazards (e.g., ground motion) or flood hazards (e.g., potential height of an extreme flood) that
significantly exceed design basis.
Impact on implementation or operational activities resulting from the variation: If revised
hazards are significantly higher than the design basis, the Commission may require plants to
mitigate the risks associated with these hazards. For example, if the revised maximum height of
an external flood at a site is significantly higher than the design basis flood height, licensees
may need to upgrade existing plant equipment, tanks, and structures to comply with the revised
flood heights.
Significance of impact on implementation or operational activities in terms of cost: To date, the
integrated assessments submitted to the NRC under JLD-ISG-12-05, Draft Interim Staff
Guidance on Performance of an Integrated Assessment for Flooding have not reflected a
significant impact on the FSGs developed in response to Order EA-12-049 (Ref. 11). Any costs
resulting from the re-evaluations performed under NTTF Recommendation 2.1 are not
attributable to the Order.

B.1.2 Methodology for Estimating the Costs of Order EA-12-051
Order EA-12-051 required licensees and COL holders to install equipment to reliably monitor
the water level in SFPs in order to ensure it is adequate to support SFP cooling, to provide
radiation shielding for an operator on the SFP operating deck, and to cover the spent fuel.
The methods and assumptions applied to the analysis of Order EA-12-051 largely align with
those used in the regulatory analysis, except as discussed below.
Affected Universe
The NRC estimates the costs incurred by 60 operating sites that installed SFP instrumentation
as a result of Order EA-12-051, as shown in Exhibit B-8. The NRC exempted four
decommissioning sites (i.e., Crystal River, Kewaunee, San Onofre, and Vermont Yankee) from
the requirements set forth by Order EA-12-051. Oyster Creek has announced intentions to
decommission in 2019. The NRC assumes in this analysis that Oyster Creek will submit a
rescission letter that the NRC will approve.21 Therefore, the analysis does not include any costs
21

See SECY 14-0114 for more information regarding the exemption of decommissioning sites from compliance
with Order EA-12-051.

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for these five sites. Based on data assembled by the NRC, Exhibit B-8 also shows the NRC’s
estimate for the number of sites that would purchase two, four, or six SFP instruments.
Exhibit B-8. Number of Sites Purchasing and Installing SFP Instruments
Number of Sites
Two instruments

Three instruments

Four instruments

Six instruments

Total

60 Sites

B.1.3 Methodology for Estimating the Cost of Related Industry Initiatives
The NRC estimates the costs of related industry initiatives initiated following Fukushima using
the methods and assumptions applied to the regulatory analysis, except as discussed below.
Time Period of Analysis
Industry initiatives include costs to affected entities that have been or will be incurred prior to
2017. Specifically, costs associated with voluntary industry initiatives began as early as 2012.

B.2

Analysis of the Cost of Order EA-12-049, Order EA-12-051, and
Related Industry Initiatives

This section describes the costs incurred by industry and the NRC as a result of Order EA-12049, Order EA-12-051, and related industry initiatives. Note that all costs presented in this
analysis are rounded to two significant figures. Appendices C through K provide the detailed
calculations used to estimate these costs.
Exhibit B-9 summarizes the monetized costs of Order EA-12-049, Order EA-12-051, and related
industry initiatives.

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Exhibit B-9. Summary of Industry and NRC Costs: Historical Cost Analysis
Average Cost Per Site

Total Costs

One-Time
Costs

Annual
Costs

One-Time
Costs

Annual Costs

Undiscounted
Value

Present Value
(7 percent)

Present Value
(3 percent)

$24,000,000

$150,000

$1,600,000,000

$9,900,000

$2,200,000,000

$1,700,000,000

$2,000,000,000

N/A

$530,000

$2,100,000

$1,800,000

$2,000,000

$24,000,000

$150,000

$1,600,000,000

$10,000,000

$2,200,000,000

$1,700,000,000

$2,000,000,000

$3,800,000

$15,000

$250,000,000

$1,000,000

$250,000,000

$210,000,000

$230,000,000

N/A

$390,000

$150,000

$840,000

$730,000

$790,000

$3,800,000

$15,000

$250,000,000

$1,200,000

$250,000,000

$210,000,000

$230,000,000

$730,000

$8,500

$47,000,000

$550,000

$63,000,000

$25,000,000

$37,000,000

N/A

$8,500,000

$15,000

$9,500,000

$2,500,000

$4,900,000

$730,000

$8,500

$56,000,000

$570,000

$73,000,000

$28,000,000

$42,000,000

EA-12-049
Industry
NRC
Subtotal
EA-12-051
Industry
NRC
Subtotal

Other Industry Initiatives
Industry
NRC
Subtotal
Total
Industry

$29,000,000

$170,000

$1,900,000,000

$11,000,000

$2,500,000,000

$1,900,000,000

$2,300,000,000

NRC

N/A

$9,400,000

$700,000

$12,000,000

$5,000,000

$7,700,000

Total

$29,000,000

$170,000

$1,900,000,000

$12,000,000

$2,500,000,000

$1,900,000,000

$2,300,000,000

*Results are rounded.

B.2.1 Costs of Order EA-12-049
Exhibit B-10 summarizes the monetized costs related to Order EA-12-049, which resulted in a
cost between $1.7 billion and $2 billion (using a 7 percent and 3 percent discount rate,
respectively). These monetized costs are described in more detail in the following sections.

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Exhibit B-10. Summary of Costs for Order EA-12-049: Historical Cost Analysis
Cost Per Site

Total Costs

One-Time
Costs

Annual
Costs

One-Time
Costs

Annual Costs

Undiscounted
Value

Present Value
(7 percent)

Present Value
(3 percent)

$4,200,000

N/A

$270,000,000

N/A

$270,000,000

$250,000,000

$260,000,000

$6,900,000

N/A

$450,000,000

N/A

$450,000,000

$420,000,000

$440,000,000

$2,000,000

N/A

$130,000,000

N/A

$130,000,000

$120,000,000

$2,300,000

N/A

$150,000,000

N/A

$150,000,000

$140,000,000

$150,000,000

$6,800,000

N/A

$440,000,000

N/A

$440,000,000

$420,000,000

$430,000,000

$2,000,000

N/A

$130,000,000

N/A

$130,000,000

$120,000,000

$130,000,000

N/A

$150,000

N/A

$9,900,000

$650,000,000

$270,000,000

$420,000,000

$24,000,000

$150,000

$1,600,000,000

$9,900,000

$2,200,000,000

$1,700,000,000

$2,000,000,000

N/A

$530,000

N/A

$530,000

$490,000

$510,000

N/A

$530,000

$1,600,000

$1,300,000

$1,500,000

N/A

$530,000

$500,000

$2,100,000

$1,800,000

$2,000,000

$24,000,000

$150,000

$1,600,000,000

$9,900,000

$2,200,000,000

$1,700,000,000

$2,000,000,000

N/A

$530,000

$2,100,000

$1,800,000

$2,000,000

$24,000,000

$150,000

$1,600,000,000

$10,000,000

$2,200,000,000

$1,700,000,000

$2,000,000,000

Industry
Initial Response
Onsite Portable
Equipment
Offsite Portable
Equipment
Supporting
Functions
External Event
Considerations
Programmatic
Controls (Onetime)
Programmatic
Controls
(Annual)
Subtotal
NRC
Licensing
activities
Inspection
activities
Subtotal
TOTAL
Industry
NRC
Total

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

B.2.1.1 Industry Implementation
Exhibit B-11 lists the upfront costs to industry to implement Order EA-12-049, which amount to a
total one-time cost of approximately $1.6 billion. The total present value of these costs is
approximately $1.5 billion (using a 7 percent or 3 percent discount rate). The average cost per
site is estimated at $24 million (based on 65 affected sites).22

Although Order EA-12-049 only imposed costs on 62 sites, the NRC used 65 sites as the basis to calculate the
average one-time costs per site so that the cost estimate is comparable to the one-time costs per site in the
remainder of the historical analysis.

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Exhibit B-11. Present Value of Industry’s Implementation Cost

Section

Cost per
Site
One-Time
Cost

Total Cost
One-Time Cost

Initial Response
$4,200,000
$270,000,000
Onsite Portable
$6,900,000
$450,000,000
Equipment
Offsite Portable
$2,000,000
$130,000,000
Equipment
Supporting
$2,300,000
$150,000,000
Functions
External Event
$6,800,000
$440,000,000
Considerations
Programmatic
$2,000,000
$130,000,000
Controls (One-time)
Total
$24,000,000 $1,600,000,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Present Value
(7 percent)

Present Value
(3 percent)

$250,000,000

$260,000,000

$420,000,000

$440,000,000

$120,000,000

$140,000,000

$150,000,000

$420,000,000

$430,000,000

$120,000,000

$130,000,000

$1,500,000,000

The costs in Exhibit B-11 are derived from the combined costs of the Order EA-12-049
compliance activities applicable to each reactor type (i.e., BWR, PWR, and AP1000s). Because
the compliance activities differ between reactor types, the following sections provide the
implementation costs for each individual reactor type.
BWRs
The following sections detail the initial compliance activities required of a BWR site (i.e., initial
response, onsite equipment, offsite equipment, supporting functions, external event
considerations, and programmatic controls). These exhibits also provide the compliance activity
cost estimates for affected 1-unit, 2-unit, and 3-unit BWR sites.
Exhibit B-12 contains the upfront costs that resulted from the initial response compliance
activities. The initial response compliance activities include constructing, installing, and
modifying equipment for coping strategies to maintain SFP cooling. The NRC estimates that the
undiscounted total cost associated with initial response compliance activities for BWRs is $59
million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $1.7 million, $3.4 million, and
$5.2 million, respectively.

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Exhibit B-12. BWR Implementation Cost: Initial Response
Initial Response Compliance
Activity

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

Construct a seismic missileprotected emergency water
$390,000
$770,000
$1,200,000
$13,000,000
storage tank (EWST).
Build clean water tank with
availability to supply RCIC/ highpressure coolant injection (HPCI)
$390,000
$770,000
$1,200,000
$13,000,000
with water for RCIC/HPCI injection
into reactor pressure vessel
(RPV).
Install quick-disconnect
connection point downstream of
$94,000
$190,000
$280,000
$3,300,000
the CST isolation valve.
Install cross connect between the
$240,000
$470,000
$710,000
$8,200,000
RCIC/HPCI suction supply lines.
Modify high-pressure core spray
(HPCS) service water (SW),
HPCS SW return line, and
$590,000
$1,200,000
$1,800,000
$21,000,000
residual heat removal (RHR) C
injection piping.
$1,700,000
$3,400,000
$5,200,000
$59,000,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

Exhibit B-13 reports on the upfront costs of onsite portable equipment compliance activities for
BWRs. The onsite portable equipment compliance activities involve purchasing portable FLEX
equipment and other supplies as well as installing and modifying equipment for coping
strategies to maintain SFP cooling. The NRC estimates that the undiscounted total cost
associated with the onsite portable equipment compliance activities is approximately
$290 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $8.2 million, $16 million,
and $24 million, respectively.
Exhibit B-13. BWR Implementation Cost: Onsite Portable Equipment
Onsite Portable Equipment
Compliance Activity
Procure portable FLEX equipment
(N+1).
Install quick-disconnect connection point
on Auxiliary Steam Supply and an
Auxiliary Steam Supply line to RCIC
piping interconnection.
Design and pre-stage modified flange
adapter for connection of FLEX pump
discharge hose.
Modify HPCS SW to install connection
points.

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$1,300,000

$2,000,000

$2,600,000

$38,000,000

$1,100,000

$2,200,000

$3,300,000

$39,000,000

$27,000

$53,000

$80,000

$930,000

$990,000

$2,000,000

$3,000,000

$35,000,000

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Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

Add connection points and cabling at
control building wall to connect to
Buses. Add connection points and
transfer switches.

$3,000,000

$6,100,000

$9,100,000

$110,000,000

Procure and install electrical cabling.

$1,600

$3,200

$4,900

$57,000

$2,100

$4,100

$6,200

$72,000

$1,200

$2,500

$3,700

$43,000

$3,200

$6,400

$9,600

$110,000

$750,000

$1,500,000

$2,300,000

$26,000,000

$100,000

$200,000

$300,000

$3,500,000

$2,100

$4,100

$6,200

$72,000

$750,000

$1,500,000

$2,300,000

$26,000,000

$170,000

$340,000

$520,000

$6,000,000

$29,000

$57,000

$76,000

$990,000

$8,200,000

$16,000,000

$24,000,000

$290,000,000

Onsite Portable Equipment
Compliance Activity

Modify or refurbish spare breaker on
Class 1 E LC 15BA6/16BB6 to make
connections from 480 V FLEX DG.
Install power cables from outside
connection point to alternate decay heat
removal power supply.
Modify power supply to battery chargers
to install welding type receptacles,
termination box, disconnects, and cable
for quick connection to battery chargers
and battery exhaust fan.
Modify power supply to Division I
SPMU valves by installing a connection
point and new permanent cable or
conduit to receive backup power from
480 V FLEX DG.
Provide cable and raceway (that is
seismically supported) from 480 V FLEX
DG to battery chargers and battery room
exhaust fan.
Modify or refurbish spare breaker to
motor control center (MCC) 16B31 to
provide sufficient capacity to power train
B RHR support loads from 480 V FLEX
DG.
Modify connection of 4160 Vac NSRC
FLEX DG to the Class1E 16AB
4160 Vac.
Modify the SFP line by installing
2 connections for 2 separate lines
leading to the SFP area for a SFP FLEX
hose connection and a SFP FLEX spray
connection.
Install hard pipe with dual isolation valve
to new SFP FLEX connection.
Subtotal

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

Exhibit B-14 shows the upfront costs of offsite portable equipment compliance activities for
BWRs. Offsite portable equipment compliance activities include procuring offsite equipment
and installing equipment for coping strategies to maintain SFP cooling. Note, this cost estimate
does not include the licensee’s share of NSRC costs, which is discussed separately and in
greater detail in the NSRC costs section. The NRC estimates that the undiscounted total cost
associated with the offsite portable equipment compliance activities is $1.8 million. The cost per
an affected 1-unit, 2-unit, and 3-unit site is $52,000, $100,000, and $150,000, respectively.

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Exhibit B-14. BWR Implementation Cost: Offsite Portable Equipment
Offsite Portable Equipment
Compliance Activity
Procure offsite Phase 3 equipment.*
Install transfer panel (disconnect
switch) in Turbine Building.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$48,000

$96,000

$140,000

$1,700,000

$3,600

$7,200

$11,000

$130,000

$52,000

$100,000

$150,000

$1,800,000

*This does not include procuring equipment stored at the NSRCs.
**Results are rounded.
***All costs in this exhibit are presented in 2013 dollars.
****There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

Exhibit B-15 documents the costs of supporting function compliance activities to BWRs. The
supporting function compliance activities involve changing the lighting to conserve battery life
and conducting an analysis to determine site-specific fuel consumption rates and available
supplies. The NRC estimates that the undiscounted total cost associated with the supporting
function compliance activities is $460,000. The cost per an affected 1-unit, 2-unit, and 3-unit
site is $13,000, $27,000, and $40,000, respectively.
Exhibit B-15. BWR Implementation Cost: Supporting Function
Onsite Portable Equipment
Compliance Activity
Change emergency control room
lighting to LED bulbs to reduce load on
batteries.
An analysis will be performed to
determine site-specific fuel
consumption rates and available
supplies.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$3,300

$6,500

$9,800

$110,000

$10,000

$20,000

$30,000

$350,000

$13,000

$27,000

$40,000

$460,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

Exhibit B-16 presents the costs of external event considerations compliance activities to BWRs.
The external event considerations compliance activities involve establishing a flood staging area
and building onsite FLEX storage buildings to protect equipment. The NRC estimates that the
undiscounted total cost associated with the external event considerations compliance activities
is approximately $200 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $5.3
million, $8.3 million, and $11 million, respectively.

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Exhibit B-16. BWR Implementation Cost: External Event Considerations
External Event Considerations
Compliance Activity
Establish a flood staging area for
portable equipment.
Design or build onsite FLEX storage
buildings (protect from storms and high
winds).
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$600,000

$1,200,000

$1,800,000

$21,000,000

$4,700,000

$7,100,000

$9,400,000

$140,000,000

$5,300,000

$8,300,000

$11,000,000

$200,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

Exhibit B-17 summarizes the initial costs of programmatic controls compliance activities to
BWRs. The programmatic controls compliance activities include procedural and administrative
activities such as developing an OIP as well as procedures for site configuration control,
maintenance and testing, and setpoint calculations. Sites ensured that their FSGs were
integrated with their EOPs, EDMGs, and SAMGs and established a strategies playbook with the
respective NSRC. Additionally, sites developed training modules and programs. Furthermore,
sites conducted analyses to determine if staffing and commodities were adequate. The NRC
estimates that the undiscounted total cost associated with the programmatic controls activities is
$46 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $1.8 million, $2.2 million,
and $2.6 million, respectively.

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Exhibit B-17. BWR Implementation Cost: Programmatic Controls
Programmatic Controls
Compliance Activity
Develop the OIP.
Develop strategies (playbook) with
NSRC.
Develop and conduct staffing
analysis.
Issue FSGs.

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$340,000

$420,000

$500,000

$9,000,000

$27,000

$34,000

$40,000

$720,000

$40,000

$970,000

$340,000

$500,000

$670,000

$9,900,000

Modify plant procedures to take into
account FSGs. Procedures to be
considered include EOP, EDMG, and
SAMGs strategies.

$67,000

$100,000

$130,000

$2,000,000

Modify existing plant configuration
control procedures to ensure that
changes to the plant design physical
layout, roads, buildings, and
miscellaneous structures will not
adversely affect the approved FLEX
strategies.

$34,000

$800,000

$84,000

$100,000

$120,000

$2,200,000

$250,000

$6,000,000

$250,000

$300,000

$350,000

$6,600,000

$170,000

$200,000

$230,000

$4,400,000

$6,700

$160,000

$63,000

$66,000

$69,000

$1,500,000

$84,000

$100,000

$130,000

$2,200,000

$1,800,000

$2,200,000

$2,600,000

$46,000,000

Create maintenance and testing
procedures.
Develop training programs for
operation of FLEX equipment.
Develop training modules for
personnel that will be responsible for
implementing the FLEX strategies.
Develop design requirements and
supporting analysis for portable FLEX
equipment.
An analysis will be performed to
determine commodity requirements.
Involvement with industry group
activities.
Procedure setpoint calculations
(procedure entry, exit, and decision
criteria) and other engineering
support.
Subtotal

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

The NRC provides more detail on the costs presented for these BWR compliance activities (i.e.,
equipment and labor costs, quantities needed, wage rates) in Appendices E, F, and G.
PWRs
The following sections detail the initial compliance activities required of a PWR site (i.e., initial
response, onsite equipment, offsite equipment, supporting functions, external event
considerations, and programmatic controls). These exhibits also provide the compliance activity
cost estimates for affected 1-unit, 2-unit, and 3-unit PWR sites.

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Exhibit B-18 presents the upfront costs of initial response compliance activities to PWRs. The
initial response compliance activities include constructing, installing, upgrading, and modifying
equipment for coping strategies to maintain SFP cooling. The NRC estimates that the
undiscounted total cost associated with initial response compliance activities for PWRs is
approximately $210 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is
$3.1 million, $6.4 million, and $9.6 million, respectively.
Exhibit B-18. PWR Implementation Cost: Initial Response
Initial Response Compliance Activity
Harden and protect the dedicated
shutdown diesel generator (DG).
Install a robust, shielded connection on
each reactor makeup water storage tank
(RMWST).
Upgrade non-seismic condensate
transfer pump suction nozzle to seismic
qualification.
Construct a seismic, missile-protected
EWST.
Construct a seismic, missile-protected
tank to provide a protected water source
for core cooling and heat removal
strategies.
Install clean water receiver tank (CWRT)
(high wind/missile protected and contains
borated water).
Modify power controls for SG PORVs
from a direct current-powered (dc)
instrument bus.
Install permanent nitrogen bottle racks
near each SG PORV operating station
with hose and regulators.
Install Westinghouse low-leakage
RCP seals.
Seismically upgrade the Alternate Seal
Injection (ASI) system and add an
ASI pump discharge path to the chemical
and volume control system (CVCS)
charging header.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$87,000

$170,000

$260,000

$5,700,000

$1,500,000

$3,100,000

$4,600,000

$100,000,000

$24,000

$47,000

$71,000

$1,600,000

$390,000

$770,000

$1,200,000

$25,000,000

$420,000

$850,000

$1,300,000

$28,000,000

$390,000

$770,000

$1,200,000

$25,000,000

$6,200

$12,000

$19,000

$410,000

$28,000

$56,000

$84,000

$1,800,000

$270,000

$540,000

$810,000

$18,000,000

$31,000

$61,000

$92,000

$2,000,000

$3,100,000

$6,400,000

$9,600,000

$210,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are twelve 1-unit PWR sites, twenty-four 2-unit PWR sites, and two 3-unit PWR site.

Exhibit B-19 summarizes the initial costs of onsite portable equipment compliance activities to
PWRs. The onsite portable equipment activities involve purchasing portable FLEX equipment
and other supplies as well as installing and modifying equipment for coping strategies to
maintain SFP cooling. The NRC estimates that the undiscounted total cost associated with
onsite portable equipment compliance activities is approximately $170 million. The cost per an
affected 1-unit, 2-unit, and 3-unit site is $2.7 million, $5.1 million, and $7.6 million, respectively.

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Exhibit B-19. PWR Implementation Cost: Onsite Portable Equipment
Onsite Portable Equipment
Compliance Activity
Procure portable FLEX equipment
(N+1).
Install diverse suction connections and
fill connections on each CST. Install
seismically rugged new pipes.
Install connection points downstream of
the charging pump discharge header.
Add branch connections with quick
disconnect fittings to the boric acid
transfer pump suction header. Install
permanent piping to CVCS crosstie.
Provide a branch from the CVCS drain
line. Modify vent connection. Resize
the CVCS crosstie drain line.
Add FLEX pump discharge connection
points to both trains of the essential
service water (ESW) system.
Install a connection point downstream
of the EFW Pump.
Modify spare breaker for 480V FLEX
DG connection. Install new vertical
section on switchgear for 4160V FLEX
DG connection.
Route a cable via a new penetration
through the north wall of the Auxiliary
Building.
Install supply and return connections
outside containment to supply
supplemental cooling to the
containment fan coolers.
Route a new header directly to the SFP
just above the normal water level.
Install spray nozzles in the Fuel
Handling Building.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$590,000

$940,000

$1,300,000

$32,000,000

$690,000

$1,400,000

$2,100,000

$46,000,000

$240,000

$470,000

$710,000

$16,000,000

$330,000

$660,000

$980,000

$22,000,000

$190,000

$370,000

$560,000

$12,000,000

$110,000

$220,000

$330,000

$7,300,000

$2,100

$4,100

$6,200

$140,000

$210,000

$420,000

$630,000

$14,000,000

$190,000

$380,000

$560,000

$12,000,000

$32,000

$63,000

$95,000

$2,100,000

$96,000

$190,000

$290,000

$6,400,000

$2,700,000

$5,100,000

$7,600,000

$170,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are twelve 1-unit PWR sites, twenty-four 2-unit PWR sites, and two 3-unit PWR site.

Exhibit B-20 documents the upfront costs of offsite portable equipment activities to PWRs.
Offsite portable equipment compliance activities included procuring offsite equipment and
installing equipment for coping strategies to maintain SFP cooling. Note, this cost estimate
does not include the licensee’s share of NSRC costs, which is discussed separately and in
greater detail in NSRC costs section. The NRC estimates that the undiscounted total cost
associated with offsite portable equipment compliance activities is approximately $53 million.
The cost per an affected 1-unit, 2-unit, and 3-unit site is $810,000, $1.6 million, and $2.4 million,
respectively.

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Exhibit B-20. PWR Implementation Cost: Offsite Portable Equipment
Offsite Portable Equipment
Compliance Activity
Procure offsite Phase 3 equipment.
Modify bus to allow connection of
portable DG.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$48,000

$96,000

$140,000

$3,200,000

$760,000

$1,500,000

$2,300,000

$50,000,000

$810,000

$1,600,000

$2,400,000

$53,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are twelve 1-unit PWR sites, twenty-four 2-unit PWR sites, and two 3-unit PWR site.

Exhibit B-21 presents the costs of supporting function compliance activities to PWRs. The
supporting function compliance activities involved upgrading the lighting to conserve battery life
and installing connection points. The NRC estimates that the undiscounted total cost
associated with supporting function compliance activities is approximately $150 million. The
cost per an affected 1-unit, 2-unit, and 3-unit site is $2.3 million, $4.5 million, and $6.8 million,
respectively.
Exhibit B-21. PWR Implementation Cost: Supporting Function
Supporting Functions Compliance
Activity
Upgrade dc emergency lighting units
with LED lamps.
Install a connection to drain line located
on the supply line to the emergency
diesel generator (EDG).
Add connection points at diesel fuel oil
storage tanks.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$3,300

$6,500

$9,800

$220,000

$750,000

$1,500,000

$2,300,000

$50,000,000

$1,500,000

$3,000,000

$4,500,000

$99,000,000

$2,300,000

$4,500,000

$6,800,000

$150,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are twelve 1-unit PWR sites, twenty-four 2-unit PWR sites, and two 3-unit PWR site.

Exhibit B-22 reports the costs of external event considerations compliance activities to PWRs.
The external event considerations compliance activities involved establishing a flood staging
area and building onsite FLEX storage buildings to protect equipment. The NRC estimates that
the undiscounted total cost associated with external event considerations compliance activities
is approximately $280 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $5.3
million, $8.3 million, and $11 million, respectively.

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Exhibit B-22. PWR Implementation Cost: External Event Considerations
External Event Considerations
Compliance Activity
Develop a staging area for FLEX
equipment.
Build two FLEX storage locations.
Subtotal

Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

$600,000

$1,200,000

$1,800,000

$40,000,000

$4,700,000

$7,100,000

$9,400,000

$240,000,000

$5,300,000

$8,300,000

$11,000,000

$280,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are twelve 1-unit PWR sites, twenty-four 2-unit PWR sites, and two 3-unit PWR site.

Exhibit B-23 presents the costs of programmatic controls compliance activities to PWRs. The
programmatic controls compliance activities included procedural and administrative activities
such as developing an OIP as well as procedures for site configuration control, maintenance
and testing, and setpoint calculations. Sites ensured that their FSGs were integrated with their
EOPs, EDMGs, and SAMGs and established a strategies playbook with the respective NSRC.
Additionally, sites developed training modules and programs. Furthermore, sites conducted
analyses to determine if staffing and commodities were adequate. The NRC estimates that the
undiscounted total cost associated with programmatic controls compliance activities is
$77 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $1.8 million, $2.1 million,
and $2.6 million, respectively.

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Exhibit B-23. PWR Implementation Cost: Programmatic Controls
Cost per
Affected
1-Unit Site

Cost per
Affected
2-Unit Site

Cost per
Affected
3-Unit Site

Total Cost

Develop the OIP.
Develop strategies (playbook) with
NSRC.
Develop and conduct staffing analysis.

$340,000

$420,000

$500,000

$15,000,000

$27,000

$34,000

$40,000

$1,200,000

$40,000

$1,500,000

Issue FSGs.

$340,000

$500,000

$670,000

$17,000,000

$67,000

$100,000

$130,000

$3,500,000

$34,000

$1,300,000

$84,000

$100,000

$120,000

$3,700,000

$250,000

$9,500,000

$250,000

$310,000

$380,000

$11,000,000

$170,000

$200,000

$230,000

$7,300,000

$6,700

$250,000

$63,000

$66,000

$69,000

$2,500,000

$84,000

$3,200,000

$1,800,000

$2,100,000

$2,600,000

$77,000,000

Programmatic Controls
Compliance Activity

Modify plant procedures to take into
account FSGs. Procedures to be
considered include EOP, EDMG, and
SAMGs strategies.
Modify plant configuration control
procedures to ensure that changes to
the physical layout, roads, buildings,
and miscellaneous structures will not
adversely affect the FLEX strategies.
Create maintenance and testing
procedures.
Develop training programs for operation
of FLEX equipment.
Develop training modules for personnel
that will be responsible for
implementing the FLEX strategies.
Develop design requirements and
supporting analysis for portable FLEX
equipment.
An analysis will be performed to
determine commodity requirements.
Involvement with industry group
activities.
Procedure setpoint calculations
(procedure entry, exit, and decision
criteria) and other engineering support.
Subtotal

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are twelve 1-unit PWR sites, twenty-four 2-unit PWR sites, and two 3-unit PWR site.

The NRC provides more detail on the costs presented for these PWR compliance activities (i.e.,
equipment and labor costs, quantities needed, wage rates) in Appendices H, I, and J.
AP1000s
This section details the initial compliance activities required of an AP1000 site
(i.e., programmatic controls) and the cost estimates associated with these activities. Although
the AP1000 units are currently being constructed on sites with operating units
(i.e., V.C. Summer and Vogtle), the historical cost analysis accounts for the costs for the
AP1000 units on these sites separately.
Exhibit B-24 presents the costs of programmatic controls compliance activities to AP1000s. The
programmatic controls compliance activities included procedural and administrative activities
such as developing an OIP as well as procedures for site configuration control, maintenance

Regulatory Analysis:
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Page 95

and testing, and setpoint calculations. Sites ensured that their FSGs were integrated with their
EOPs, EDMGs, and SAMGs and established a strategies playbook with the respective NSRC.
Additionally, sites developed training modules and programs. Furthermore, sites conducted
analyses to determine if staffing and commodities are adequate. The NRC estimates that the
undiscounted total cost associated with programmatic controls compliance activities is
$6.1 million. The cost per an affected 2-unit site is $2.2 million.
Exhibit B-24. AP1000 Implementation Cost: Programmatic Controls
Cost per Affected
2-Unit Site

Total Cost

Develop the OIP.

$400,000

$800,000

Develop strategies (playbook) with NSRC.

$34,000

$67,000

Develop and conduct staffing analysis.

$40,000

$80,000

Issue FSGs.

$500,000

$1,000,000

Modify plant procedures to take into account
FSGs. Procedures to be considered include
EOP, EDMG, and SAMGs strategies.

$100,000

$200,000

Modify plant configuration control procedures
to ensure that changes to the physical layout,
roads, buildings, and miscellaneous structures
will not adversely affect the FLEX strategies.

$67,000

$130,000

$100,000

$200,000

$250,000

$500,000

$300,000

$600,000

$200,000

$400,000

$6,700

$13,000

$66,000

$790,000

$100,000

$1,300,000

$2,200,000

$6,100,000

Programmatic Controls Compliance
Activity

Create maintenance and testing procedures.
Develop training programs for operation of
FLEX equipment.
Develop training modules for personnel that
will be responsible for implementing the FLEX
strategies.
Develop design requirements and supporting
analysis for portable FLEX equipment.
An analysis will be performed to determine
commodity requirements.
Involvement with industry group activities.
Procedure setpoint calculations (procedure
entry, exit, and decision criteria) and other
engineering support.
Subtotal

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***There are two 2-unit AP1000 sites.

The NRC provides more detail on the costs presented for these AP1000 compliance activities
(i.e., equipment and labor costs, quantities needed, wage rates) in Appendix K.
NSRC Costs
To comply with the Order EA-12-049 requirements, industry decided to pre-stage equipment
and resources at an offsite location. These resources will be available to sites within 24 hours
after an event, and must provide the capability to sustain core cooling, containment, and SFP
cooling indefinitely following a BDBEE. Industry established two NSRCs: one in Phoenix,
Arizona and another near Memphis, Tennessee. Exhibit B-25 presents the types of equipment
that are expected to be available through the NSRCs, the quantities of equipment available, and

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the estimated unit costs. This list of equipment was compiled based on the information provided
in the sampled OIPs (See Exhibit B-7 for the list of sites sampled). The undiscounted total cost
for both NSRCs is estimated to be $54 million. The costs for equipping the NSRCs will be
shared equally by all 62 sites. The estimated cost per site is, therefore, $870,000.
Exhibit B-25. Cost of Offsite Equipment at NSRCs

B
$900,000

Total Cost
per NSRC
(5 Sets)
C =A x B x 5
$14,000,000

Total Costs for
2 NSRCs
(10 Sets)
D =A x B x 10
$27,000,000

$66,000

$990,000

$2,000,000

1
2

$100,000
$20,000

$500,000
$200,000

$1,000,000
$400,000

$4,000

$120,000

$240,000

Communication Gear: Antenna cable

$600

$6,000

$12,000

Communication Gear: Dc automobile
outlet charger cord to charge singleand four-bay battery chargers

$20

$800

$2,000

Communication Gear: Docking
station

$2,000

$10,000

$20,000

Communication Gear: Emergency kit

$2,000

$50,000

$100,000

$200

$2,000

$4,000

$600

$24,000

$48,000

$1,000

$5,000

$10,000

$100

$8,000

$16,000

$200

$8,000

$16,000

$200

$4,000

$8,000

DG fuel transfer pump

$6,000

$90,000

$180,000

Female NPT SS hydraulic coupling

$50

$2,000

$4,000

Fuel air-lift container
Heavy equipment for transportation
and debris clearing

$2,000

$10,000

$20,000

$290,000

$1,400,000

$2,900,000

High-capacity pump (diesel driven)

$20,000

$300,000

$600,000

High-pressure hose (50 ft)
High-pressure hose (100 ft)

4
4

$2,000
$6,000

$40,000
$120,000

$80,000
$240,000

Equipment
4 kV and 6.9 kV DG
4 kV and 6.9 kV DG switchgear &
transformer
600 V generator
Boron mixing system
Cables for connecting portable
generators

Communication Gear: Fixed mast
antenna
Communication Gear: Four-bay
satellite phone battery charger
Communication Gear: Mobile phone
Communication Gear: Rechargeable
batteries
Communication Gear: Single-bay
satellite phone battery charger
Communication Gear: Solar panel
charger

Quantity in
a “Set”

Unit Cost

A
3

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Total Cost
per NSRC
(5 Sets)
C =A x B x 5

Total Costs for
2 NSRCs
(10 Sets)
D =A x B x 10

Quantity in
a “Set”

Unit Cost

High-pressure pump (diesel driven)

$20,000

$200,000

$400,000

High-pressure suction hose
Holder, hydrant wrench, & spanner
wrench

$5,000

$50,000

$100,000

$200

$1,000

$2,000

Low-pressure, high-flow dewatering
pump/ Suction booster lift pump

$55,000

$550,000

$1,100,000

Low-pressure, high-flow suction hose

$500

$30,000

$60,000

Low-pressure, medium-flow and lowpressure, high-flow discharge hose

$3,000

$720,000

$1,400,000

Low-pressure, medium-flow pump

$93,000

$470,000

$930,000

Low-pressure, medium-flow suction
hose

$500

$20,000

$40,000

Low-voltage distribution transformer

$80,000

$1,600,000

$3,200,000

Low-voltage generator (1,100 kW)

$720,000

$3,600,000

$7,200,000

Low-voltage generator (250 kW)
2
$85,000
Portable air compressor
2
$13,000
Portable diesel fuel tank
1
$5,000
Portable lighting
6
$4,000
Portable submersible pump hose
1
$400
Portable toilet
10
$800
Portable ventilation fan
3
$2,000
SG/RPV hose
9
$800
SG/RPV suction hose
4
$500
Single phase generator
2
$7,000
Storz adapter
3
$200
Storz spanner wrench with holder
1
$100
Storz, storz outlet, storz inlet
1
$1,000
Storz to NH swivel rocker lug female
2
$200
thread
Strainer
12
$1,000
Temporary housing
1
$100,000
Water purification skid
2
$40,000
Water storage
3
$9,000
Total
Total Cost Per Site
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

$850,000
$130,000
$25,000
$120,000
$2,000
$40,000
$30,000
$36,000
$10,000
$70,000
$3,000
$500
$5,000

$1,700,000
$260,000
$50,000
$240,000
$4,000
$80,000
$60,000
$72,000
$20,000
$140,000
$6,000
$1,000
$10,000

$2,000

$4,000

$60,000
$500,000
$400,000
$140,000
$28,000,000

$120,000
$1,000,000
$800,000
$270,000
$54,000,000
$870,000

Equipment

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The NRC also estimates the upfront costs to staff the NSRCs and train the workers operating
the NSRCs, as well as to move the equipment into the NSRCs. Exhibit B-26 lists the estimated
unit costs for these activities. The undiscounted total cost for both NSRCs is $18 million. The
costs for the NSRCs will be shared equally by all 62 sites. The estimated cost per site is
approximately $280,000.
Exhibit B-26. Cost of Staffing, Training, Outfitting, and Moving at NSRCs
Cost per NSRC
Staffing and Training Cost
$8,000,000
Outfitting Costs (e.g., warehousing,
$750,000
transport, positioning equipment)
Moving Cost
$8,000
Total
$8,800,000
Total Cost Per Site
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Total Cost
(2 NSRCs)
$16,000,000
$1,500,000
$16,000
$18,000,000
$280,000

B.2.1.2 Industry Operation
Exhibit B-27 reports the industry’s average annual costs. The NRC estimates that industry will
incur an average annual cost of approximately $9.9 million. The present value of these costs is
approximately $270 million (using a 7 percent discount rate) and $420 million (using a 3 percent
discount rate). With 65 sites, the estimated annual cost per site is $150,000.23
Exhibit B-27. Present Value of Industry’s Operations Cost
Cost Per
Site

Total Cost

Section
Annual Cost

Average
Annual Cost

Undiscounted

Present Value
(7 percent)

Present Value
(3 percent)

Programmatic Controls
(Annual)

$150,000

$9,900,000

$650,000,000

$270,000,000

$420,000,000

Total

$150,000

$9,900,000

$650,000,000

$270,000,000

$420,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

The costs in Exhibit B-27 are derived from the combined costs of the compliance activities from
each reactor type (i.e., BWR, PWR, and AP1000s). Because the compliance activities differ
between reactor types, the following sections provide the costs for BWR, PWR, and AP1000
sites individually.

Although Order EA-12-049 only imposed costs on 62 sites under the historical cost analysis, the NRC used
65 sites as a metric to calculate the one-time costs per site in order to have a cost that is comparable to the onetime costs per sites in the remainder of the historical analysis.

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BWRs
Exhibit B-28 presents the costs of annual programmatic controls compliance activities to BWRs.
The annual programmatic controls compliance activities include preparing and submitting 6month status updates on the implementation of the mitigation strategies, performing
maintenance and testing, conducting training, implementing change control, and maintaining the
FSGs. Note, this cost estimate does not include the licensee’s share of NSRC costs, which is
discussed separately and in greater detail in the NSRC costs section. The NRC estimates that
BWRs will incur annual costs associated with programmatic controls compliance activities of
$4.7 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $160,000, $240,000, and
$310,000, respectively.
Exhibit B-28. BWR Operations Cost: Programmatic Controls
Annual Cost
per Affected
1-Unit Site

Annual Cost
per Affected
2-Unit Site

Annual Cost
per Affected
3-Unit Site

Annual Cost

$8,400

$13,000

$17,000

$250,000

$34,000

$800,000

Conduct training.
Change control. FLEX equipment
will be documented and controlled
by the existing plant modification
process.

$84,000

$150,000

$210,000

$2,700,000

$13,000

$20,000

$27,000

$400,000

Maintenance of the FSGs.

$20,000

$26,000

$21,000

$540,000

$160,000

$240,000

$310,000

$4,700,000

Programmatic Controls

6-month status reports on
implementation of mitigation
strategies.*
Maintenance and testing.

Total

*This does not include ongoing costs for NSRCs.
**Results are rounded.
***All costs in this exhibit are presented in 2013 dollars.
****There are fourteen 1-unit BWR sites, nine 2-unit BWR sites, and one 3-unit BWR site.

The NRC provides more detail on the costs presented for these BWR compliance activities (i.e.,
equipment and labor costs, quantities needed, wage rates) in Appendices E, F, and G.
PWRs
Exhibit B-29 contains the costs of annual programmatic controls compliance activities to PWRs.
The annual programmatic controls compliance activities include preparing and submitting 6month status updates on the implementation of the mitigation strategies, performing
maintenance and testing, conducting training, implementing change control, and maintaining the
FSGs. Note, this cost estimate does not include the licensee’s share of NSRC costs, which is
discussed separately and in greater detail in the NSRC costs section. The NRC estimates that
PWRs will incur annual costs associated with programmatic controls compliance activities of
$8.3 million. The cost per an affected 1-unit, 2-unit, and 3-unit site is $160,000, $240,000, and
$320,000, respectively.

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Exhibit B-29. PWR Operations Cost: Programmatic Controls
Programmatic Controls

Annual Cost
per Affected
1-Unit Site

Annual Cost
per Affected
2-Unit Site

Annual Cost
per Affected
3-Unit Site

Annual Cost

6-month status reports on
implementation of mitigation strategies.*
Maintenance and testing.

$8,400

$13,000

$17,000

$440,000

$34,000

$1,300,000

Conduct training.

$84,000

$150,000

$210,000

$4,900,000

Change control. FLEX equipment will
be documented and controlled by the
existing plant modification process.

$13,000

$20,000

$27,000

$700,000

Maintenance of the FSGs.

$20,000

$26,000

$32,000

$930,000

$160,000

$240,000

$320,000

$8,300,000

Subtotal

*This does not include ongoing costs for NSRCs.
**Results are rounded.
***All costs in this exhibit are presented in 2013 dollars.
****There are twelve 1-unit PWR sites,twenty-four 2-unit PWR sites, and two 3-unit PWR site.

The NRC provides more detail on the costs presented for these PWR compliance activities (i.e.,
equipment and labor costs, quantities needed, wage rates) in Appendices H, I, and J.
AP1000s
Exhibit B-30 presents the costs of annual programmatic controls compliance activities to
AP1000s. The annual programmatic controls compliance activities include preparing and
submitting 6-month status updates on the implementation of the mitigation strategies,
performing maintenance and testing, conducting training, implementing change control, and
maintaining the FSGs. Note, this cost estimate does not include the licensee’s share of NSRC
costs, which is discussed separately and in greater detail in the NSRC costs section. The NRC
estimates that AP1000s will incur annual costs associated with programmatic controls
compliance activities of $480,000. The cost per an affected 2-unit site is $250,000.
Exhibit B-30. AP1000 Operations Cost: Programmatic Controls
Programmatic Controls

Annual Cost
per Affected
2-Unit Site

Annual Cost

6-month status reports on implementation of mitigation
strategies.*
Maintenance and testing.

$13,000

$25,000

$34,000

$67,000

Conduct training.

$150,000

$290,000

Change control. FLEX equipment will be documented
and controlled by the existing plant modification process.

$25,000

$50,000

Maintenance of the FSGs.

$26,000

$52,000

$250,000

$480,000

Subtotal

*This does not include ongoing costs for NSRCs.
**Results are rounded.
***All costs in this exhibit are presented in 2013 dollars.
****There are two 2-unit AP1000 sites.

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The NRC provides more detail on the costs presented for these AP1000 compliance activities
(i.e., equipment and labor costs, quantities needed, wage rates) in Appendix K.
NSRCs
Industry has chosen to comply with the Order EA-12-049 requirements by pre-staging Phase 3
equipment and resources at an offsite location. These resources must be available to sites
within 24 hours after an event, and must provide the capability to sustain core cooling,
containment, and SFP cooling indefinitely following a BDBEE. As discussed earlier in this
analysis, industry established two NSRCs (one in Phoenix, Arizona and another near Memphis,
Tennessee). Exhibit B-31 presents the types of activities that are expected to be performed by
the NSRCs (such as maintenance and transportation). The NRC estimates that transportation
costs will be approximately $5.7 million per year for the first 3 years and will decrease to
$450,000 per year for all subsequent years. The NRC assumes that costs related to the
NSRCs are variable in the sense that after a site submits its exemption analysis, it will no longer
contribute to the NSRC costs. The undiscounted total cost for both NSRCs is $9 million. The
costs for the NSRCs will be shared equally by all 62 sites. Therefore, the estimated cost per
site is $150,000.
Exhibit B-31. Quantity and Cost of Ongoing NSRC Activities
COMPONENT

Annual Cost
per NSRC

Total Annual
Costs
(2 NSRCs)
$8,000,000
$900,000
$9,000,000
$150,000

Maintenance activities
$4,000,000
Transportation capability (after 3 years)
$450,000
Total
$4,500,000
Total Cost Per Site
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***The annual transportation capability cost data represent the per year costs incurred by
sites after the first 3 years in which operating costs are incurred.

B.2.1.3 NRC Implementation
Exhibit B-32 presents the NRC’s total upfront costs of licensing activities related to Order EA12-049. The NRC estimates the total undiscounted cost of licensing activities amounted to
approximately $530,000. The total present value of these costs is approximately $490,000
(using a 7 percent discount rate) and $510,000 (using a 3 percent discount rate).
Exhibit B-32. Present Value of NRC Implementation Cost
Section

Total Cost
Present Value
(7 percent)

Present Value
(3 percent)

$530,000

$490,000

$510,000

$530,000

$490,000

$510,000

One-Time Cost

Implementation Costs
(Licensing Activities)
Total

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

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B.2.1.4 NRC Operation
The NRC also will incur ongoing, operations costs (specifically, inspection activities). These
annual costs are assumed to begin in 2014 and accrue over 2 years.
Exhibit B-33 provides the NRC’s total operations costs (i.e., inspection activities) which amount
to an annual cost of approximately $530,000. The total present value of these costs is
approximately $1.3 million (using a 7 percent discount rate) and $1.5 million (using a 3 percent
discount rate).
Exhibit B-33. Present Value of NRC Operations Cost
Section

Annual Cost

Operations Costs (Inspections)
$530,000
Total
$530,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Total Costs
Present
Value
(7 percent)
$1,300,000
$1,300,000

Present
Value
(3 percent)
$1,500,000
$1,500,000

B.2.2 Costs of Order EA-12-051
Exhibit B-34 summarizes the estimated costs of Order EA-12-051. Under the historical cost
analysis, the requirements contained in Order EA-12-051 impose costs between $210 million
and $230 million (using a 7 percent and 3 percent discount rate, respectively). These costs are
described in more detail in the following sections.
Exhibit B-34. Summary of Costs for Order EA-12-051
Average Cost Per
Site
One-Time
Cost

Annual
Cost

Total Cost
One-Time
Cost

Annual
Cost

Undiscounted
Value

Present
Value
(7 percent)

Present
Value
(3 percent)

SFP Instrumentation
Industry

$3,800,000

$15,000

$250,000,000

$1,000,000

$250,000,000

$210,000,000

$230,000,000

NRC

N/A

$390,000

$150,000

$840,000

$730,000

$790,000

Total

$3,800,000

$15,000

$250,000,000

$1,200,000

$250,000,000

$210,000,000

$230,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***The annual cost data represents the per year costs incurred by sites during their operating license term.

B.2.2.1 Industry Implementation
According to information on Order EA-12-051, 60 sites incurred implementation costs resulting
from the Order. These costs included procedural and administrative activities (such as
purchasing and installing SFP instrumentation, purchasing spare SFP instruments, developing
industry guidance, and preparing and submitting 6-month updates to their integrated plans).
These upfront costs are assumed to be incurred between 2012 and 2016.
Exhibit B-35 lists the industry’s implementation costs, which amount to a total upfront cost of
approximately $250 million. The total present value of these costs is approximately $200 million

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(using a 7 percent discount rate) and $230 million (using a 3 percent discount rate). The
average cost per site is estimated at $3.8 million.
Exhibit B-35. Present Value of Industry’s Implementation Cost

Section

Average Cost
per Site
One-Time
Cost

Total Cost
One-Time
Cost

SFP Instrumentation
$3,800,000
$250,000,000
Total
$3,800,000
$250,000,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Present Value
(7 percent)

Present Value
(3 percent)

$200,000,000
$200,000,000

$230,000,000
$230,000,000

Exhibit B-36 contains the SFP instrumentation compliance activities. The NRC assumes that
after the Order was issued, 60 operating sites purchased and installed SFP instrumentation on
a rolling basis from 2014 to 2016. The NRC estimated the number of instruments purchased
per site as follows:
•
•
•
•

Forty sites purchased two instruments,
One site purchased three instruments,
Seventeen sites purchased four instruments, and
Two sites purchased six instruments.

The NRC assumes that installation costs decreased by 20 percent for each of the first four
instruments installed. For example, installation of one instrument cost $1.8 million based on
NRC's unit cost estimates. Installation of two instruments cost $3.2 million (i.e., the first
installation cost $1.8 million and the second cost $1.4 million, 80 percent of $1.8 million).
Installation of three instruments cost $4.3 million (i.e., the third installation cost $1.1 million,
60 percent of $1.8 million).
In addition, each affected site purchased one spare instrument, and each NSRC purchased
six spare instruments for a total of 72 spare instruments. The NRC estimates that the cost of a
spare instrument is 10 percent of the cost to install one instrument ($1.8 million). The NRC
assumes that industry purchased spares on a rolling basis from 2014 to 2016.
Industry developed implementation guidance (i.e., NEI 12-02). Additionally, each site incurred
costs to prepare and submit its first and second 6-month update to its integrated plans. The
undiscounted total implementation cost is estimated to be $250 million.

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Exhibit B-36. Industry Implementation Cost: SFP Instrumentation
Activity

Purchase and install SFP instrumentation

Purchase spare instruments
Develop industry guidance (NEI 12-02)

Average Cost per
Affected Site

Total Cost

$3,200,000
$4,300,000
$5,000,000
$6,500,000
N/A

$130,000,000
$4,300,000
$86,000,000
$13,000,000
$13,000,000

N/A

$240,000

Prepare and submit first and second 6$31,000
month update to integrated plan
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.5 for additional detail on these cost estimates.

$1,900,000
$250,000,000

B.2.2.2 Industry Operation
Order EA-12-051 also resulted in operations costs. These costs include routine and recurring
activities (such as preparing and submitting 6-month status updates to integrated plans and
testing SFP instrumentation). These annual costs are assumed to begin in 2014 and accrue
over the remaining license term.
Exhibit B-37 presents the industry’s operations costs. The NRC estimates that industry will
incur an annual cost of approximately $1 million. The present value of these costs is
approximately $2.8 million (using a 7 percent discount rate) and $3.5 million (using a 3 percent
discount rate). The average annual cost per site is $15,000 (based on 65 sites).
Exhibit B-37. Present Value of Industry’s Operations Cost

Section

SFP Instrumentation

Average Cost
per Site

Total Cost

Annual Cost

Present Value
(7 percent)

Present Value
(3 percent)

$15,000

$1,000,000

$2,800,000

$3,500,000

$1,000,000

$2,800,000

$3,500,000

Total
$15,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Exhibits B-38 and B-39 present the costs of annual SFP instrumentation compliance activities
that will be incurred during sites’ operating license terms and during the first 2 years of
decommissioning, respectively.
Costs associated with testing SFP instrumentation will be incurred during the operating term
and during the first 2 years of the decommissioning period. The NRC assumes that the 58
BWR and PWR sites will incur operating costs beginning in 2017 and ending in 2040 (the
average remaining industry-wide operating license term for currently licensed BWR and PWR
sites). The two AP1000 sites will incur operating costs associated with testing SFP
instrumentation from 2017 to 2077 (the average remaining industry-wide operating license term

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for current AP1000 sites). See Section 3.1 of the regulatory analysis for more detail on how
these average license terms were derived.
Each site also will incur costs once the licensee has prepared and submitted the appropriate
decommissioning certifications to the NRC. The NRC assumes that for 2 years following the
end of the operating license term (2041 and 2042), the 58 BWR and PWR sites will incur costs
to test their SFP instrumentation, while the 2 AP1000 sites will incur these costs in 2078 and
2079.
Assumptions Related to Costs Incurred During the Operating Period
Costs associated with preparing and submitting the third through eighth update to a site’s
integrated plan will be incurred beginning in 2014 through 2017. The NRC assumes that each
of the 60 operating sites prepared and submitted eight 6-month updates to their integrated
plans. The costs associated with the first and second updates to the integrated plan are
discussed in Appendix B.2.1. The NRC assumes that the third through eighth 6-month updates
will require half the effort of the first two.
Each of the 60 operating sites will also incur costs to test SFP instrumentation on a biennial
basis. The cost to test the SFP instrumentation does not vary by the number of instruments
onsite. The NRC estimates that during the sites’ operating periods, industry will incur a cost of
$1 million.
Exhibit B-38. Industry Operations Cost: SFP Instrumentation during the
Operating Period
Activity

Average Annual
Cost per Affected
Site

Prepare and submit third through eighth 6$16,000
month updates to integrated plan
Test SFP instrumentation (operating sites)
$2,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.5 for additional detail on these cost estimates.

Annual Cost
$940,000
$59,000
$1,000,000

Assumptions Related to Costs Incurred During the First 2 Years of Decommissioning
The NRC assumes that each of the 60 sites will continue to incur costs relating to testing SFP
instrumentation on a biennial basis during the first 2 years of decommissioning. The LOE
required will not vary based on the number of SFP instruments.

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Exhibit B-39. Industry Operations Cost: SFP Instrumentation during the First 2 Years of
Decommissioning)
Average Annual
Cost per Affected
Site

Activity

Annual Cost

Test SFP instrumentation (BWR and PWR
$2,000
decommissioning sites)
Test SFP instrumentation (AP1000 sites)
$2,000
Subtotal
*Results are rounded.
**See Appendix D.2 for additional detail on these cost estimates.

$57,000
$2,000
$59,000

B.2.2.3 NRC Implementation
Order EA-12-051 also imposed implementation costs on the NRC. These costs include
procedural and administrative activities (such as inspecting SFP instrumentation, as well as
reviewing and approving industry guidance and 6-month updates to integrated plans). These
initial costs are assumed to be incurred over the period from 2012 to 2016.
Exhibit B-40 presents the NRC’s total implementation costs which amount to a one-time cost of
approximately $390,000. The total present value of these costs is approximately $360,000
(using a 7 percent discount rate) and $380,000 (using a 3 percent discount rate).
Exhibit B-40. Present Value of NRC’s Implementation Cost
Total Cost
Section
SFP Instrumentation

One-Time Cost

Present Value
(7 percent)

Present Value
(3 percent)

$390,000

$360,000

$380,000

$360,000

$380,000

Total
$390,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Exhibit B-41 presents the costs of annual SFP Instrumentation compliance activities. The NRC
reviewed the industry guidance (i.e., NEI 12-02) as well as the sites’ integrated plans. In
addition, the NRC inspected the SFP instrumentation over a 3-year period beginning in 2014.
The NRC estimates that the NRC incurred $390,000 in implementation costs.
Exhibit B-41. NRC Implementation Cost: SFP Instrumentation
Activity

Total Cost

Inspect SFP instrumentation
$60,000
Review industry guidance (NEI 12-02)
$35,000
Review first and second 6-month updates to
$300,000
integrated plans
$390,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.5 for additional detail on these cost estimates.

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B.2.2.4 NRC Operation
The NRC also will incur ongoing, operations costs (specifically, reviewing 6-month updates to
integrated plans). These annual costs are assumed to begin in 2014 and accrue over the
following 2 years.
Exhibit B-42 provides the NRC’s total operations costs which amount to an annual cost of
approximately $150,000. The total present value of these costs is approximately $360,000
(using a 7 percent discount rate) and $410,000 (using a 3 percent discount rate).
Exhibit B-42. Present Value of NRC Operations Cost
Total Cost
Section

Annual Cost

SFP Instrumentation
$150,000
Total
$150,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Present Value
(7 percent)

Present Value
(3 percent)

$360,000
$360,000

$410,000
$410,000

The NRC will review updates to the sites’ integrated plans. The NRC assumes that reviewing
the third through eighth 6-month updates will take the NRC half the LOE needed to review the
first and second 6-month updates. Exhibit B-43 presents the costs associated with this
compliance activity.
The NRC will inspect the SFP instruments within the existing Reactor Oversight Program.
Therefore, the NRC does not include annual NRC inspection costs as the costs for inspecting
the new equipment would be negligible. The NRC’s operations costs are estimated to be
$150,000.
Exhibit B-43. NRC Operations Cost: SFP Instrumentation
Activity
Review the third through eighth 6-month updates to
integrated plans
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.5 for additional detail on these cost estimates.

Annual Cost
$150,000
$150,000

B.2.3 Costs of Industry Initiatives
Exhibit B-44 summarizes the costs associated with selected industry initiatives implemented
following the Fukushima accident. In the historical cost analysis, these activities would result in
total costs between $27 million and $42 million (using a 7 percent and 3 percent discount rate,
respectively). These monetized costs, as well as the non-monetary benefits and costs, are
described in more detail in the following sections.

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Exhibit B-44. Summary of Costs for Industry Initiatives
Average Cost Per Site
One-Time
Cost

Annual
Cost

Total Cost
One-Time
Cost

Annual
Cost

Undiscounted
Value

Present
Value
(7 percent)

Present
Value
(3 percent)

Exemption Analysis
Industry
NRC
Subtotal

$510,000

N/A

$33,000,000

N/A

$33,000,000

$6,000,000

$14,000,000

N/A

$8,100,000

N/A

$8,100,000

$1,900,000

$4,100,000

$510,000

N/A

$41,000,000

N/A

$41,000,000

$7,900,000

$18,000,000

SAMGs Guidance
Industry
NRC
Subtotal

$63,000

N/A

$4,100,000

N/A

$4,100,000

$4,000,000

N/A

$63,000

N/A

$4,100,000

N/A

$4,100,000

$4,000,000

Phase 1 Staffing
Industry
NRC
Subtotal

$23,000

N/A

$1,500,000

N/A

$1,500,000

N/A

$250,000

N/A

$250,000

$23,000

N/A

$1,800,000

N/A

$1,800,000

Multiple Source Term Dose Assessment
Industry
NRC
Subtotal

$130,000

$8,500

$8,600,000

$550,000

$24,000,000

$13,000,000

$17,000,000

N/A

$150,000

$15,000

$1,100,000

$320,000

$540,000

$130,000

$8,500

$8,800,000

$570,000

$25,000,000

$13,000,000

$18,000,000

Total
Industry

$730,000

$8,500

$47,000,000

$550,000

$63,000,000

$25,000,000

$37,000,000

NRC

N/A

$8,500,000

$15,000

$9,500,000

$2,500,000

$4,900,000

Total

$730,000

$8,500

$56,000,000

$570,000

$70,000,000

$27,000,000

$42,000,000

*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***The annual cost data represents the per year costs incurred during the operating license term.

B.2.3.1 Industry Implementation
The industry initiatives were implemented by 65 sites, including operating sites and
decommissioning sites. The costs associated with industry initiatives include procedural and
administrative activities (such as developing industry implementation guidance, the SAMGs
Technical Basis Report (TBR), and generic SAMGs; conducting Phase 1 staffing assessments;
reviewing and revising procedures; and developing and customizing multiple source term dose
assessment computer software). These upfront costs are assumed to be incurred over the
period of 2012 to 2014.
Exhibit B-45 lists the industry’s historical implementation costs, which amount to a total upfront
cost of approximately $47 million. The total present value of these costs is approximately $28
million (using a 3 percent discount rate) and $19 million (using a 7 percent discount rate). The
average cost per site is estimated at $730,000 (based on 65 sites).

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Exhibit B-45. Present Value of Industry’s Implementation Cost for Industry Initiatives
Average Cost
per Site

Section

Total Cost

One-Time Cost

Present Value
(7 percent)

Present Value
(3 percent)

Exemption Analysis

$510,000

$33,000,000

$6,000,000

$14,000,000

SAMGs Guidance

$63,000

$4,100,000

$4,000,000

Phase 1 Staffing
$23,000
$1,500,000
Multiple Source Term Dose
$130,000
$8,600,000
Assessment
Total
$730,000
$47,000,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

$1,500,000

$7,500,000

$8,100,000

$19,000,000

$28,000,000

The following sections detail the compliance activities required of affected sites (i.e., related to
the exemption analysis, SAMGs, Phase 1 staffing, and multiple source term dose assessment).
Exemption Analysis
Exhibit B-46 details the historical implementation costs to industry associated with conducting
and submitting the exemption analysis to the NRC. Sites that have announced plans to
decommission have voluntarily submitted these analysis requesting that the NRC exempt them
from Order EA-12-049 and Order EA-12-051. The NRC assumes that each of the four sites that
are currently undergoing decommissioning (i.e., Crystal River, Kewaunee, San Onofre, and
Vermont Yankee) prepared and submitted exemption analyses to the NRC in 2014. Oyster
Creek has announced intentions to decommission in 2019. The NRC assumes in this analysis
that Oyster Creek will submit a rescission letter that the NRC will approve in 2019. The NRC
also assumes that currently operating sites will submit and receive approval of exemption
analyses 2 years into the decommissioning phase (in 2042). Section 3.1 of the regulatory
analysis provides additional detail on the exemption analysis and the NRC’s assumptions. The
total cost associated with the preparation and submission of the exemption analysis is
$33 million.
Exhibit B-46. Industry Implementation Cost for Industry Initiatives: Exemption Analysis
Activity

Average Cost per
Affected Site

Total Cost

Conduct and submit the exemption
analysis (Current decommissioning
$500,000
$2,500,000
sites)
Conduct and submit the exemption
analysis (BWR and PWR
$500,000
$29,000,000
decommissioning sites)
Conduct and submit the exemption
analysis (AP1000 decommissioning
$500,000
$1,000,000
sites)
$33,000,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix D.1 for additional detail on these cost estimates.

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SAMGs Guidance
Exhibit B-47 presents the upfront costs associated with industry initiatives focused on SAMGs.
Industry developed implementation guidance (i.e., NEI 14-01, Emergency Response
Procedures and Guidelines for Extreme Events and Severe Accidents (Ref. 12)), EPRI
developed the SAMG TBR, the BWROG developed the generic BWR SAG, and the PWROG
developed the generic PWR SAMG. The NRC assumes the PWROG required additional effort
to develop one generic PWROG SAMG to replace the three existing SAMGs for the
Westinghouse, Combustion Engineering, and Babcock and Wilcox reactor designs. The NRC
estimates that the undiscounted total cost associated with these SAMGs industry initiatives is
$4.1 million.
Exhibit B-47. Industry Implementation Cost for Industry Initiatives: SAMGs Guidance
Activity

Average Cost per
Affected Site

Develop industry implementation guidance (NEI 14N/A
01)
Develop the SAMG TBR (EPRI)
N/A
Develop generic BWROG SAG
N/A
Develop generic PWROG SAMG
N/A
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
**See Appendix C.1 for additional detail on these cost estimates.

Total Cost
$120,000
$530,000
$1,500,000
$2,000,000
$4,100,000

Phase 1 Staffing Assessments
Exhibit B-48 shows the estimated costs associated with the industry’s work on the Phase 1
Staffing Assessments. According to NRC estimates, 35 multi-unit operating sites and 1 multiunit decommissioning site with fuel remaining in the SFP (i.e., San Onofre) performed a Phase
1 Staffing Assessment.24,25 The NRC estimates that the undiscounted total cost associated with
Phase 1 Staffing Assessments is $1.5 million.
Exhibit B-48. Industry Implementation Cost for Industry Initiatives: Phase 1 Staffing
Activity

Average Cost per
Affected Site

Total Cost

Perform Phase 1 staffing assessment (multi-unit sites)

$42,000

$1,500,000

Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.3 for additional detail on these cost estimates.

$1,500,000

Based on NRC data, no site added ERO personnel to its minimum staffing in response to the Phase 1 Staffing
Assessments. Therefore, the historical cost analysis does not include any operational costs on behalf of industry
as a result of the staffing assessments.

Historical costs associated with performing the Phase 2 Staffing Assessment are reflected in the analysis of
Order EA-12-049. See Appendix B.2.1.

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Multiple Source Term Dose Assessment
Exhibit B-49 presents the costs associated with Multiple Source Term Dose Assessment
activities. A review of NRC data indicates that 56 operating sites and 4 decommissioning sites
with fuel remaining in the SFP implemented multiple source term dose assessment capabilities.
The remaining decommissioning site with fuel in the SFP (i.e., San Onofre) did not implement
multiple source term dose assessment capabilities. Four sites had previously implemented
multiple source term dose assessment capabilities voluntarily (i.e., Duane Arnold, Fermi, Fort
Calhoun, and Seabrook). Therefore, the NRC does not estimate the costs for these four sites.
Each of the 60 affected sites reviewed and revised their procedures, developed training
materials for its ERO team, and delivered the ERO training on how to conduct individual dose
assessments for multiple release points. Each site chose to either customize the NRC-provided
RASCAL URI software for its site-specific needs (28 sites, comprised of 26 operating sites and
2 decommissioning sites), or to develop its own software independently (32 sites, comprised of
30 operating sites and 2 decommissioning sites). As a result, the NRC estimates that the
undiscounted total cost associated with multiple source term dose assessment activities is
$8.6 million.
Exhibit B-49. Industry Implementation Cost for Industry Initiatives: Multiple Source Term
Dose Assessment
Activity
Review and revise procedures (operating sites)
Review and revise procedures (decommissioning
sites)
Develop computer software
Customize computer software
Develop training materials for ERO team (operating
sites)
Develop training materials for ERO team
(decommissioning sites)
Deliver ERO training (operating sites)
Deliver ERO training (decommissioning sites)

Average Cost per
Affected Site

Total Cost

$6,400

$360,000

$6,400

$26,000

$150,000
$70,000

$4,800,000
$2,000,000

$18,000

$1,000,000

$18,000

$74,000

$5,900
$5,900

$330,000
$23,000
$8,600,000

Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.9 for additional detail on these cost estimates.

B.2.3.2 Industry Operation
The 65 affected sites also will incur operations costs as a result of the industry initiatives. These
costs include routine and recurring activities (such as updating multiple source term dose
assessment computer software). These annual costs are assumed to begin in 2015 and accrue
up to 63 years (depending on activity, operating status, and reactor type).
Exhibit B-50 reports the industry’s operations costs. The NRC estimates industry costs to be
approximately $550,000. The present value of these costs is approximately $5.5 million (using

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a 7 percent discount rate) and $9.3 million (using a 3 percent discount rate). The average
annual cost per site is $8,500 (based on 65 sites).
Exhibit B-50. Present Value of Industry’s Operations Cost for Industry Initiatives
Average Cost
per Site

Section

Annual Cost
Multiple Source Term Dose
$8,500
Assessment
Total
$8,500
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Total Cost
Annual Cost

Present Value
(7 percent)

Present Value
(3 percent)

$550,000

$5,500,000

$9,300,000

$550,000

$5,500,000

$9,300,000

Multiple Source Term Dose Assessment
Exhibits B-51 and B-52 present the costs of annual multiple source term dose assessment
activities that will be incurred during sites’ operating license terms and during the first 2 years of
decommissioning, respectively. The NRC assumes that each of the 60 operating sites and the
5 currently decommissioning sites will incur costs to update computer software on an annual
basis. The 58 BWR and PWR sites will incur operating costs from 2015 through 2040, and the
2 AP1000 sites will incur operating costs from 2015 through 2077. The five currently
decommissioning sites will incur costs in 2015 and 2016. The NRC assumes that each site will
prepare and submit an exemption analysis to the NRC in the second year of decommissioning,
which will exempt them from multiple source term dose assessment activities.
Assumptions Related to Costs Incurred During the Operating Period
The NRC assumes that each of the 60 operating sites and the 5 currently decommissioning
sites will incur an annual cost to update their computer software. The annual cost to industry of
this activity is estimated to be $550,000.
Exhibit B-51. Industry Operations Cost for Industry Initiatives: Multiple Source Term
Dose Assessment (During the Operating Period)
Activity

Average Annual
Cost per Affected
Site

Update computer software (operating sites)
$9,100
Update computer software (decommissioning sites)
$9,100
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.9 for additional detail on these cost estimates.

Annual Cost
$510,000
$37,000
$550,000

Assumptions Related to Costs Incurred During the First 2 Years of Decommissioning
The NRC assumes that each of the 60 operating sites will continue to incur annual costs
associated with updating computer software for the first 2 years of decommissioning. The cost
to update computer software will not vary by design type or operating status, and the NRC

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estimates that industry will incur $510,000 in annual costs during the first 2 years of
decommissioning.
Exhibit B-52. Industry Operations Cost for Industry Initiatives: Multiple Source Term
Dose Assessment (During the First 2 Years of Decommissioning)
Average Annual Cost
per Affected Site

Activity

Update computer software (BWR and PWR
$9,100
decommissioning sites)
Update computer software (AP1000 decommissioning
$9,100
sites)
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix D.5 for additional detail on these cost estimates.

Annual Cost
$490,000
$18,000
$510,000

B.2.3.3 NRC Implementation
The requirements associated with the industry initiatives also will impose implementation costs
on the NRC. These costs include procedural and administrative activities (such as reviewing
sites’ staffing plan evaluations, conducting inspection activities, as well as developing multiple
source term dose assessment computer software along with training and a user’s guide).
These initial costs were incurred between 2012 and 2014.
Exhibit B-53 presents the NRC’s total implementation costs which amount to approximately
$8.5 million. The total present value of these costs is approximately $2.3 million (using a
7 percent discount rate) and $4.5 million (using a 3 percent discount rate).
Exhibit B-53. Present Value of NRC Implementation Cost for Industry Initiatives
Total Cost
Section

Exemption Analysis

One-Time Cost

Present Value
(7 percent)

Present Value
(3 percent)

$8,100,000

$1,900,000

$4,100,000

$250,000

$140,000

$150,000

$2,300,000

$4,500,000

Phase 1 Staffing
$250,000
Multiple Source Term Dose
$150,000
Assessment
Total
$8,500,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Exemption Analysis
Exhibit B-54 presents the costs to the NRC associated with reviewing and approving the
exemption analyses. The NRC assumes that the NRC reviewed the exemption analyses for the
4 currently decommissioning sites (i.e., Crystal River, Kewaunee, San Onofre, and Vermont
Yankee) and for Oyster Creek who announced intentions to decommission in 2019, and will
review the exemption analysis for each of the 60 operating sites during the second year of

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decommissioning. The NRC estimates the total undiscounted cost to review and approve
exemption analyses is $8.1 million.
Exhibit B-54. NRC Implementation Cost for Industry Initiatives: Exemption Analysis
Activity
Review and approve the exemption analyses for current
decommissioning sites
Review and approve the exemption analyses for BWR and PWR
decommissioning sites
Review and approve the exemption analyses for AP1000
decommissioning sites
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix D.1 for additional detail on these cost estimates.

Total Cost
$620,000
$7,200,000
$250,000
$8,100,000

Phase 1 Staffing Assessments
Exhibit B-55 presents the implementation costs of Phase 1 Staffing Assessments. The NRC
reviewed sites’ staffing plan evaluations and conducted inspection activities.26 The
implementation cost incurred by the NRC as a result of the Phase 1 Staffing Assessments is
estimated to be approximately $250,000.
Exhibit B-55. NRC Implementation Cost for Industry Initiatives: Phase 1 Staffing
Activity

Total Cost

Review sites' staffing plan evaluations
$220,000
Conduct inspection activities
$30,000
$250,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.3 for additional detail on these cost estimates.

Multiple Source Term Dose Assessment
Exhibit B-56 presents the implementation costs incurred by the NRC as a result of the multiple
source term dose assessment requirements. The NRC developed computer software, as well
as training and a user’s guide. The upfront cost incurred by the NRC as a result of the multiple
source term dose assessment is estimated to be approximately $150,000.

It is assumed that the NRC will perform ongoing oversight; however, this incremental effort will be integrated into
existing inspection activities. Therefore, the historical cost analysis does not estimate incremental costs for the
NRC’s oversight.

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Exhibit B-56. NRC Implementation Cost for Industry Initiatives: Multiple Source Term
Dose Assessment
Activity

Total Cost

Develop computer software, training, and user's
$150,000
guide
$150,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
*See Appendix C.9 for additional detail on these cost estimates.

B.2.3.4 NRC Operation
The NRC expects there will be annual costs to the NRC to update multiple source term dose
assessment computer software. Exhibit B-59 provides the NRC’s total operations costs which
amount to an annual cost of approximately $15,000. The total present value of these costs is
approximately $180,000 (using a 7 percent discount rate) and $400,000 (using a 3 percent
discount rate).
Exhibit B-57. Present Value of NRC’s Operations Cost
Total Cost
Section
Annual Cost
Multiple Source Term Dose Assessment
$15,000
Total
$15,000
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.

Present Value
(7 percent)

Present Value
(3 percent)

$180,000
$180,000

$400,000
$400,000

Multiple Source Term Dose Assessment
Exhibit B-58 presents the NRC’s annual costs as a result of the multiple source term dose
assessment requirements. The NRC expects that there will be annual updates to the NRCprovided computer software. As a result, the NRC estimates annual costs to NRC of
approximately $15,000.
Exhibit B-58. NRC Implementation Cost for Industry Initiatives: Multiple Source Term
Dose Assessment
Activity

Annual Cost

Update computer software
$15,000
$15,000
Subtotal
*Results are rounded.
**All costs in this exhibit are presented in 2013 dollars.
***See Appendix C.9 for additional detail on these cost estimates.

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References
1.

U.S. Nuclear Regulatory Commission, “Issuance of Order to Modify Licenses with Regard to
Requirements for Mitigation Strategies for Beyond-Design-Basis External Events,” Order EA-12-049,
March 12, 2012, ADAMS Accession No. ML12054A736.

U.S. Nuclear Regulatory Commission, “Issuance of Order to Modify Licenses with Regard to
Reliable Spent Fuel Pool Instrumentation,” Order EA-12-051, March 12, 2012, ADAMS Accession
No. ML12054A682.

U.S. Nuclear Regulatory Commission, “Memorandum and Order CLI-12-09 – In the Matter of South
Carolina Electric & Gas Co. and South Carolina Public Service Authority” (Also Referred to as
Santee Cooper; Virgil C. Summer Nuclear Station, Units 2 and 3), March 30, 2012, ADAMS
Accession No. ML12090A531.

Waier, P. R. Building Construction Cost Data, 63rd ed., RS Means Co., 2005.

Mossman, J. M., & Plotner, S. C. Facilities Construction Cost Data, 15th ed., RS Means Co., 2000.

Electric Power Research Institute, “Costs of Utility Distributed Generators, 1-10 MW: Twenty-Four
Case Studies,” Technical Update Report No. 1007760, 2003, Retrieved from:
http://www.publicpower.org/files/Deed/FinalReportCostsofUtilityDistributedGenerators.pdf.

7. U.S. Nuclear Regulatory Commission, “Generic Cost Estimates,” NUREG/CR-4627, Rev. 2,
January 1992, ADAMS Accession No. ML13137A259.
8.

FENOC, “Response to NRC Letter, Request for Information Pursuant to Title 10 of the Code of
Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task
Force Review of Insights from the Fukushima Dai-ichi Accident,” March 12, 2012. Attachment L-12193, 2012, Retrieved from: http://pbadupws.nrc.gov/docs/ML1216/ML12163A320.pdf.

Nuclear Energy Institute document 12-06, “Diverse and Flexible Coping Strategies (FLEX)
Implementation Guide,” Revision 0, August 2012, ADAMS Accession No. ML12242A378.

10. Westinghouse, “PRA Model for the Generation III Westinghouse Shutdown Seal,” PWROG-14001NP, Rev. 1, July 2014, ADAMS Accession No. ML14190A332.
11. U.S. Nuclear Regulatory Commission, “Draft Interim Staff Guidance JLD-ISG-12-05, Guidance for
Performing the Integrated Assessment for Flooding,” Revision 0, September 20, 2012, ADAMS
Accession No. ML12235A319.
12. Nuclear Energy Institute document 14-01, “Emergency Response Procedures and Guidelines for
Extreme Events and Severe Accidents,” Revision 0, March 2014, ADAMS Accession
No. ML14049A005.

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