[Federal Register Volume 70, Number 214 (Monday, November 7, 2005)]
[Proposed Rules]
[Pages 67597-67630]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E5-6090]



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Part IV





Nuclear Regulatory Commission





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10 CFR Part 50



Risk-Informed Changes to Loss-of-Coolant Accident Technical 
Requirements; Proposed Rule

Federal Register / Vol. 70, No. 214 / Monday, November 7, 2005 / 
Proposed Rules

[[Page 67598]]


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NUCLEAR REGULATORY COMMISSION

10 CFR Part 50

RIN 3150-AH29


Risk-Informed Changes to Loss-of-Coolant Accident Technical 
Requirements

AGENCY: Nuclear Regulatory Commission.

ACTION: Proposed rule.

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SUMMARY: The Nuclear Regulatory Commission (NRC) proposes to amend its 
regulations to permit current power reactor licensees to implement a 
voluntary, risk-informed alternative to the current requirements for 
analyzing the performance of emergency core cooling systems (ECCS) 
during loss-of-coolant accidents (LOCAs). In addition, the proposed 
rule would establish procedures and criteria for requesting changes in 
plant design and procedures based upon the results of the new analyses 
of ECCS performance during LOCAs.

DATES: Submit comments by February 6, 2006. Submit comments specific to 
the information collections aspects of this proposed rule by December 
7, 2005. Comments received after the above dates will be considered if 
it is practical to do so, but assurance of consideration cannot be 
given to comments received after these dates.

ADDRESSES: You may submit comments on the proposed rule by any one of 
the following methods. Please include the following number, RIN 3150-
AH29, in the subject line of your comments. Comments on rulemakings 
submitted in writing or in electronic form will be made available for 
public inspection. Because your comments will not be edited to remove 
any identifying or contact information, the NRC cautions you against 
including any information in your submission that you do not want to be 
publicly disclosed.
    Mail comments to: Secretary, U.S. Nuclear Regulatory Commission, 
Washington, DC 20555-0001, ATTN: Rulemakings and Adjudications Staff.
    E-mail comments to: [email protected]. If you do not receive a reply e-
mail confirming that we have received your comments, contact us 
directly at (301) 415-1966. You may also submit comments via the NRC's 
rulemaking Web site at http://ruleforum.llnl.gov. Address questions 
about our rulemaking Web site to Carol Gallagher (301) 415-5905; e-mail 
[email protected]. Comments can also be submitted via the Federal eRulemaking 
Portal http://www.regulations.gov.
    Hand deliver comments to: 11555 Rockville Pike, Rockville, Maryland 
20852, between 7:30 a.m. and 4:15 p.m. Federal workdays. (Telephone 
(301) 415-1966).
    Fax comments to: Secretary, U.S. Nuclear Regulatory Commission at 
(301) 415-1101.
    You may submit comments on the information collections by the 
methods indicated in the Paperwork Reduction Act Statement.
    Publicly available documents related to this rulemaking may be 
viewed electronically on the public computers located at the NRC's 
Public Document Room (PDR), O1 F21, One White Flint North, 11555 
Rockville Pike, Rockville, Maryland. The PDR reproduction contractor 
will copy documents for a fee. Selected documents, including comments, 
may be viewed and downloaded electronically via the NRC rulemaking Web 
site at http://ruleforum.llnl.gov.
    Publicly available documents created or received at the NRC after 
November 1, 1999, are available electronically at the NRC's Electronic 
Reading Room at http://www.nrc.gov/reading-rm/adams.html. From this 
site, the public can gain entry into the NRC's Agencywide Document 
Access and Management System (ADAMS), which provides text and image 
files of NRC's public documents. If you do not have access to ADAMS or 
if there are problems in accessing the documents located in ADAMS, 
contact the NRC Public Document Room (PDR) Reference staff at 1-800-
397-4209, (301) 415-4737 or by e-mail to [email protected].

FOR FURTHER INFORMATION CONTACT: Richard Dudley, Office of Nuclear 
Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington DC 
20555-0001; telephone (301) 415-1116; e-mail: [email protected],

SUPPLEMENTARY INFORMATION: 

Table of Contents

I. Background
    A. Deterministic Approach
    B. History of Requirements and Design for LOCAs
    C. Probabilistic Approach
    D. Commission Policy on Risk-Informed Regulation
II. Rulemaking Initiation
III. Proposed Action
    A. Overview of Rule Framework
    B. Determination of the Transition Break Size (TBS)
    1. Historical Estimates of LOCA Frequencies
    2. Expert Opinion Elicitation Process
    3. Adjustments To Address Failure Mechanisms Not Considered by 
the Expert Elicitation
    a. LOCAs caused by failure of active components, such as stuck-
open valves and blown out seals or gaskets.
    b. Seismically-induced LOCAs, both with and without material 
degradation.
    c. LOCAs caused by dropped heavy loads.
    4. Consideration of Connected Auxiliary Piping
    5. Considerations of Break Location and Flow Characteristic
    6. Effects of Future Plant Modifications on TBS
    7. Future Adjustments to TBS
    C. Alternative ECCS Analysis Requirements and Acceptance 
Criteria
    1. Acceptable Methodologies and Analysis Assumptions
    2. Acceptance Criteria
    3. Plant Operational Requirements Related to ECCS Analyses
    4. Restrictions on Reactor Operation
    D. Risk-Informed Changes to the Facility, Technical 
Specifications, or Procedures
    1. Requirements for the Risk-Informed Integrated Safety 
Performance (RISP) Assessment Process
    a. Risk acceptance criteria for plant changes under 10 CFR 50.90
    b. Risk acceptance criteria for plant changes under 10 CFR 50.59
    c. Cumulative risk acceptance criteria
    d. Defense-in-depth
    e. Safety margins
    f. Performance measuring programs
    2. Requirements for risk assessments
    a. Probabilistic Risk Assessment (PRA) requirements
    b. Requirements for risk assessments other than PRA
    3. Operational Requirements
    a. Maintain ECCS model(s) and/or analysis method(s)
    b. Do not place the plant in unanalyzed at-power operating 
configurations
    c. Evaluate all facility changes using the RISP assessment 
process
    d. Implement adequate performance-measurement programs
    e. Periodically re-evaluate and update risk assessments
    E. Reporting Requirements
    1. ECCS analysis of record and reporting requirements
    2. Risk assessment reporting requirements
    3. Minimal risk plant change reporting requirement
    F. Documentation Requirements
    G. Submittal and Review of Applications Under Sec.  50.46a
    1. Initial application for implementing alternative Sec.  50.46a 
requirements
    2. Subsequent applications for plant changes under Sec.  50.46a 
requirements
    H. Potential Revisions Based on LOCA Frequency Reevaluations
    I. Changes to General Design Criteria
    J. Specific Topics Identified for Public Comment
IV. Public Meeting During Development of Proposed Rule
V. Section-by-Section Analysis of Substantive Changes
VI. Criminal Penalties
VII. Compatibility of Agreement State Regulations
VIII. Availability of Documents

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IX. Plain Language
X. Voluntary Consensus Standards
XI. Finding of No Significant Environmental Impact: Environmental 
Assessment
XII. Paperwork Reduction Act Statement
XIII. Regulatory Analysis
XIV. Regulatory Flexibility Certification
XV. Backfit Analysis

I. Background

    During the last few years, the NRC has had numerous initiatives 
underway to make improvements in its regulatory requirements that would 
reflect current knowledge about reactor risk. The overall objectives of 
risk-informed modifications to reactor regulations include:
    (1) Enhancing safety by focusing NRC and licensee resources in 
areas commensurate with their importance to health and safety;
    (2) Providing NRC with the framework to use risk information to 
take action in reactor regulatory matters, and
    (3) Allowing use of risk information to provide flexibility in 
plant operation and design, which can result in reduction of burden 
without compromising safety, improvements in safety, or both.
    In stakeholder interactions, one candidate area identified for 
possible revision was emergency core cooling system (ECCS) requirements 
in response to postulated loss-of-coolant accidents (LOCAs). The NRC 
considers that large break LOCAs to be very rare events. Requiring 
reactors to conservatively withstand such events focuses attention and 
resources on extremely unlikely events. This could have a detrimental 
effect on mitigating accidents initiated by other more likely events. 
Nevertheless, because of the interrelationships between design features 
and regulatory requirements, making changes to technical requirements 
of certain parts of the regulations on ECCS performance has the 
potential to affect many other aspects of plant design and operation. 
The NRC has evaluated various aspects of its requirements for ECCS and 
LOCAs in light of the very low estimated frequency of the large LOCA 
initiating event.

A. Deterministic Approach

    The NRC has established a set of regulatory requirements for 
commercial nuclear reactors to ensure that a reactor facility does not 
impose an undue risk to the health and safety of the public, thereby 
providing reasonable assurance of adequate protection to public health 
and safety. The current body of NRC regulations and their 
implementation are largely based on a ``deterministic'' approach.
    This deterministic approach establishes requirements for 
engineering margin and quality assurance in design, manufacture, and 
construction. In addition, it assumes that adverse conditions can exist 
(e.g., equipment failures and human errors) and establishes a specific 
set of design basis events (DBEs) for which specified acceptance 
criteria must be satisfied. Each DBE encompasses a spectrum of similar 
but less severe accidents. The deterministic approach then requires 
that the licensed facility include safety systems capable of preventing 
and/or mitigating the consequences of those DBEs to protect public 
health and safety. While the requirements are stated in deterministic 
terms, the approach contains implied elements of probability 
(qualitative risk considerations), from the selection of accidents to 
be analyzed to the system level requirements for emergency core cooling 
(e.g., safety train redundancy and protection against single failure). 
Structures, systems or components (SSC) necessary to defend against the 
DBEs were defined as ``safety-related,'' and these SSCs were the 
subject of many regulatory requirements designed to ensure that they 
were of high quality, high reliability, and had the capability to 
perform during postulated design basis conditions.
    Defense-in-depth is an element of the NRC's safety philosophy that 
employs successive measures, and often layers of measures, to prevent 
accidents or mitigate damage if a malfunction, accident, or naturally 
caused event occurs at a nuclear facility. Defense-in-depth is used by 
the NRC to provide redundancy through the use of a multiple-barrier 
approach against fission product releases. The defense-in-depth 
philosophy ensures that safety will not be wholly dependent on any 
single element of the design, construction, maintenance, or operation 
of a nuclear facility. The net effect of incorporating defense-in-depth 
into reactor design, construction, maintenance and operation is that 
the facility or system in question tends to be less susceptible to, as 
well as more tolerant of failures and external challenges.
    The LOCA is one of the design basis accidents established under the 
deterministic approach. If coolant is lost from the reactor coolant 
system and the event cannot be terminated (isolated) or the coolant is 
not restored by normally operating systems, it is considered an 
``accident'' and then subject to mitigation and consideration of 
potential consequences. If the amount of coolant in the reactor is 
insufficient to provide cooling of the reactor fuel, the fuel would be 
damaged, resulting in loss of fuel integrity and release of radiation.

B. History of Requirements and Design for LOCAs

    When the first commercial reactors were being licensed, design-
basis LOCAs were assumed to have the potential of leading to 
substantial fuel melting. Therefore, emphasis was placed on containment 
capability, low containment leak rate, heat transfer out of the 
containment to prevent unacceptable pressure buildup, and containment 
atmospheric cleanup systems. The earliest commercial reactor 
containments were designed to confine the fluid release from a double-
ended guillotine break (DEGB) of the largest pipe in the reactor 
coolant system (RCS). These early designs had long-term core cooling 
capability, but before 1966, high-capacity emergency makeup systems 
were not required.
    During the review of applications for construction permits for 
large power reactors in 1966, evaluations of the possibility of 
containment basemat melt-through made it apparent to the Atomic Energy 
Commission (AEC) and the Advisory Committee on Reactor Safeguards 
(ACRS) that a containment might not survive a core meltdown accident. 
An ECCS task force was appointed to study the problem. In 1967, the 
task force concluded that a more reliable, high-capacity ECCS was 
needed to ensure that larger plants could safely cope with a major 
LOCA. The General Design Criteria (GDC) in Appendix A to 10 CFR Part 
50, which were being developed at the time, included requirements to 
this effect. The ECCS was to be designed to accommodate pipe breaks up 
to and including a DEGB of the largest pipe in the RCS.
    In 1971, General Design Criterion 35 was finalized (36 FR 3256; 
February 20, 1971, as corrected, 36 FR 12733; July 7, 1971). GDC 35 
states:

    Emergency core cooling. A system to provide abundant emergency 
core cooling shall be provided. The system safety function shall be 
to transfer heat from the reactor core following any loss of reactor 
coolant at a rate such that (1) fuel and clad damage that could 
interfere with continued effective core cooling is prevented and (2) 
clad metal-water reaction is limited to negligible amounts.
    Suitable redundancy in components and features, and suitable 
interconnections, leak detection, and isolation capabilities shall 
be provided to assure that for onsite electric power system 
operation (assuming offsite power is not available) and for offsite 
electric power system operation (assuming onsite

[[Page 67600]]

power is not available) the system safety function can be 
accomplished, assuming a single failure.

    On January 4, 1974, (39 FR 1002) the Commission adopted 10 CFR 
50.46, Acceptance Criteria for Emergency Core Cooling for Light Water 
Cooled Nuclear Power Reactors. Appendix K to 10 CFR 50 was promulgated 
with 10 CFR 50.46 to specify required and acceptable features of ECCS 
evaluation models. Appendix K included assumptions regarding initial 
and boundary conditions, acceptable models, and imposed conditions for 
the analysis. In developing Appendix K, conservative assumptions and 
models were imposed to cover areas where data were lacking or 
uncertainties were large or unquantifiable.
    Later in 1974, the Commission began an effort to quantify the 
conservatism in the Sec.  50.46 rule and Appendix K to 10 CFR Part 50. 
From 1974 until the mid-1980's, the AEC, and subsequently the NRC, as 
well as the regulated industry; embarked on an extensive research 
program to quantify the conservative safety margins. In 1988, as a 
result of these research programs, 10 CFR 50.46 was revised to permit 
the use of realistic (or best-estimate) analyses in lieu of the more 
conservative Appendix K calculations, provided that uncertainties in 
the best-estimate calculations are quantified (53 FR 36004; September 
16, 1988). Regulatory Guide 1.157 presents acceptable procedures and 
methods for realistic ECCS evaluation models.
    The ECCS cooling performance must be calculated for a number of 
LOCA sizes (up to and including a double-ended rupture \1\ of the 
largest pipe in the RCS), locations and other properties sufficient to 
provide assurance that the most severe postulated LOCAs are calculated, 
using one of the following two types of acceptable evaluation models:
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    \1\ In this document, the terms ``rupture'' and ``break'' are 
used interchangeably with no intended difference in meaning.
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    (1) An ECCS model with the required and acceptable features of 10 
CFR Part 50, Appendix K, or
    (2) A best-estimate ECCS evaluation model which realistically 
represents the behavior of the reactor system during a LOCA, and 
includes an assessment of uncertainties which demonstrates that there 
is a high level of probability that the above acceptance criteria are 
not exceeded.
    The requirements of 10 CFR 50.46 are in addition to any other 
requirements applicable to ECCS set forth in Part 50, and implement the 
general requirements for ECCS cooling performance design set forth in 
GDC 35. Thus, in order to mitigate LOCAs, an ECCS is required to be 
included in the design of light water reactors. The ECCS is currently 
required to be designed to mitigate a LOCA from breaks in RCS pipes up 
to and including a break equivalent in size to a DEGB of the largest 
diameter RCS pipe. The ECCS is required to have sufficient redundancy 
that it can successfully perform its function with or without the 
availability of offsite power and with the occurrence of an additional 
single active failure.
    GDC 35 requires that the ECCS be capable of providing sufficient 
core cooling during a LOCA even when a single failure is assumed. 
Standard Review Plan 6.3 interprets this as requiring the ECCS to 
perform its function during the short-term injection mode in the event 
of the failure of a single active component and to perform its long-
term recirculation function in the event of a single active or passive 
failure.
    All power reactors operating in the United States have multiple 
trains of ECCS capable of mitigating the full spectrum of LOCAs. 
Redundant divisions of electrical power and trains of cooling water are 
also available in pressurized-water reactors (PWRs) and boiling water 
reactors (BWRs) to support ECCS operation and together, provide the 
redundancy necessary to meet the single failure criterion.

C. Probabilistic Approach

    A probabilistic approach to regulation enhances and extends the 
traditional deterministic approach by allowing consideration of a 
broader set of potential challenges to safety, providing a logical 
means for prioritizing these challenges based on safety significance, 
and allowing consideration of a broader set of resources to defend 
against these challenges. In contrast to the deterministic approach, 
PRAs address a very wide range of credible initiating events and assess 
the event frequency. Mitigating system reliability is then assessed, 
including the potential for common cause failures. The probabilistic 
treatment considers the possibility of multiple failures, not just the 
single failure requirements used in the deterministic approach. The 
probabilistic approach to regulation is therefore considered an 
extension and enhancement of traditional regulation that considers risk 
(i.e. product of probability and consequences) in a more coherent and 
complete manner.

D. Commission Policy on Risk-Informed Regulation

    The Commission published a Policy Statement on the Use of 
Probabilistic Risk Assessment (PRA) on August 16, 1995 (60 FR 42622). 
In the policy statement, the Commission stated that the use of PRA 
technology should be increased in all regulatory matters to the extent 
supported by the state-of-the-art in PRA methods and data, and in a 
manner that complements the deterministic approach and that supports 
the NRC's defense-in-depth philosophy. PRA evaluations in support of 
regulatory decisions should be as realistic as practicable and 
appropriate supporting data should be publicly available. The policy 
statement also stated that, in making regulatory judgments, the 
Commission's safety goals for nuclear power reactors and subsidiary 
numerical objectives (on core damage frequency and containment 
performance) should be used with appropriate consideration of 
uncertainties.
    In addition to quantitative risk estimates, the defense-in-depth 
philosophy is invoked in risk-informed decision-making as a strategy to 
ensure public safety because both unquantified and unquantifiable 
uncertainties exist in engineering analyses (both deterministic 
analyses and risk assessments). The primary need with respect to 
defense-in-depth in a risk-informed regulatory system is guidance to 
determine which measures are appropriate and how good these should be 
to provide sufficient defense-in-depth.
    Risk insights can clarify the elements of defense-in-depth by 
quantifying their benefit to the extent practicable. Although the 
uncertainties associated with the importance of some elements of 
defense-in-depth may be substantial, the quantification of the 
resulting safety enhancement can aid in determining how best to achieve 
defense-in-depth. Decisions on the adequacy of, or the necessity for, 
elements of defense should reflect risk insights gained through 
identification of the individual performance of each defense system in 
relation to overall performance.
    To implement the Commission Policy Statement, the NRC developed 
guidance on the use of risk information for reactor license amendments 
and issued Regulatory Guide (RG) 1.174, ``An Approach for Using 
Probabilistic Risk Assessments in Risk-Informed Decisions on Plant 
Specific Changes to the Licensing Basis,'' (ADAMS No. ML023240437). 
This RG provided guidance on an acceptable approach to risk-informed 
decision-making

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consistent with the Commission's policy, including a set of key 
principles. These principles include:
    (1) Being consistent with the defense-in-depth philosophy;
    (2) Maintaining sufficient safety margins;
    (3) Allowing only changes that result in no more than a small 
increase in core damage frequency or risk (consistent with the intent 
of the Commission's Safety Goal Policy Statement); and
    (4) Incorporating monitoring and performance measurement 
strategies.
    Regulatory Guide 1.174 further clarifies that in implementing these 
principles, the NRC expects that all safety impacts of the proposed 
change are evaluated in an integrated manner as part of an overall risk 
management approach in which the licensee is using risk analysis to 
improve operational and engineering decisions broadly by identifying 
and taking advantage of opportunities to reduce risk; and not just to 
eliminate requirements that a licensee sees as burdensome or 
undesirable.

II. Rulemaking Initiation

    The process described in RG 1.174 is applicable to changes to plant 
licensing bases. As experience with the process and applications grew, 
the Commission recognized that further development of risk-informed 
regulation would require making changes to the regulations. In June 
1999, the Commission decided to implement risk-informed changes to the 
technical requirements of Part 50. The first risk-informed revision to 
the technical requirements of Part 50 consisted of changes to the 
combustible gas control requirements in 10 CFR 50.44 (68 FR 54123; 
September 16, 2003). The NRC also decided to examine the requirements 
for large break LOCAs. A number of possible changes were considered, 
including changes to GDC 35 and changes to Sec.  50.46 acceptance 
criteria, evaluation models, and functional reliability requirements. 
The NRC also proposed to refine previous estimates of LOCA frequency 
for various sizes of LOCAs to more accurately reflect the current state 
of knowledge with respect to the mechanisms and likelihood of primary 
coolant system rupture.
    Industry interest in a redefined LOCA was shown by filing of a 
Petition for Rulemaking (PRM 50-75) by the Nuclear Energy Institute 
(NEI) in February 2002 (ADAMS No. ML020630082). Notice of that petition 
was published in the Federal Register for comment on April 8, 2002 (67 
FR16654). The petition requested the NRC to amend Sec.  50.46 and 
Appendices A and K to allow an option [to the double-ended rupture of 
the largest pipe in the RCS] for the maximum LOCA break size as ``up to 
and including an alternate maximum break size that is approved by the 
Director of the Office of Nuclear Reactor Regulation.'' Seventeen sets 
of comments were received, mostly from the power reactor industry in 
favor of granting the petition. A few stakeholders were concerned about 
potential impacts on defense-in-depth or safety margins if significant 
changes were made to reactor designs based upon use of a smaller break 
size. The Commission is addressing the technical issues raised by the 
petitioner and stakeholders in this proposed rulemaking.
    During public meetings, industry representatives expressed interest 
in a number of possible changes to licensed power reactors resulting 
from redefinition of the large break LOCA. These include: containment 
spray system design optimization, fuel management improvements, 
elimination of potentially required actions for postulated sump 
blockage issues, power uprates, and changes to the required number of 
accumulators, diesel start times, sequencing of equipment, and valve 
stroke times; among others. In later written comments provided after an 
August 17, 2004, public meeting, the Westinghouse Owners Group 
concluded that the redefinition of the large break LOCA should have a 
substantial safety benefit (September 16, 2004; ADAMS No. ML042680079). 
NEI submitted comments (September 17, 2004; ADAMS No. ML042680080) 
which included a discussion of six possible plant changes made possible 
by such a rule. NEI stated its expectation that all six changes would 
most likely result in a safety benefit. The submittal from the Boiling 
Water Reactors Owners' Group (BWROG) (September 10, 2004; ADAMS No. ML 
042680077) did not specifically address potential safety benefits from 
redefining the large break LOCA. The BWROG stated that certain design 
changes (recovering some operating margin, reducing blowdown loads, 
reducing use of snubbers, etc.) could be made possible by the 
redefinition.
    The Commission SRM of March 31, 2003, (ML030910476), on SECY-02-
0057, ``Update to SECY-01-0133, `Fourth Status Report on Study of Risk-
Informed Changes to the Technical Requirements of 10 CFR Part 50 
(Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.46 
(ECCS Acceptance Criteria)' '' (ML020660607), approved most of the NRC 
staff recommendations related to possible changes to LOCA requirements 
and also directed the NRC staff to prepare a proposed rule that would 
provide a risk-informed alternative maximum break size. The NRC began 
to prepare a proposed rule responsive to the SRM direction. However, 
after holding two public meetings, the NRC found that there were 
significant differences between stated Commission and industry 
interests. The original concept for Option 3 in SECY-98-300, ``Options 
for Risk-Informed Revisions to 10 CFR Part 50--`Domestic Licensing of 
Production and Utilization Facilities','' (ML992870048) was to make 
risk-informed changes to technical requirements in all of Part 50. The 
March 2003 SRM, as it related to LOCA redefinition, preserved design 
basis functional requirements (i.e., retaining installed structures, 
systems and components), but allowed relaxation in more operational 
aspects, such as sequencing of emergency diesel generator loads. The 
Commission supported a rule that allowed for operational flexibility, 
but did not support risk-informed removal of installed safety systems 
and components. Stakeholders expressed varying expectations about how 
broadly LOCA redefinition should be applied and the extent of changes 
to equipment that might result, based upon their understanding of the 
intended purpose of the Option 3 initiative.
    To reach a common understanding about the objectives of the LOCA 
redefinition rulemaking, the NRC staff requested additional direction 
and guidance from the Commission in SECY-04-0037, ``Issues Related to 
Proposed Rulemaking to Risk-Inform Requirements Related to Large Break 
Loss-of-Coolant Accident (LOCA) Break Size and Plans for Rulemaking on 
LOCA with Coincident Loss-of-Offsite Power,'' (March 3, 2004; 
ML040490133). The Commission provided direction in a SRM dated July 1, 
2004 (ML041830412). The Commission stated that the NRC staff should 
determine an appropriate risk-informed alternative break size and that 
breaks larger than this size should be removed from the design basis 
event category. The Commission indicated that the proposed rule should 
be structured to allow operational as well as design changes and should 
include requirements for licensees to maintain capability to mitigate 
the full spectrum of LOCAs up to the DEGB of the largest RCS pipe. The 
Commission stated that the mitigation capabilities for beyond design-
basis events should be controlled by NRC requirements commensurate with 
the safety significance of these capabilities. The Commission also

[[Page 67602]]

stated that LOCA frequencies should be periodically reevaluated and 
should increases in frequency require licensees to restore the facility 
to its original design basis or make other compensating changes, the 
backfit rule (10 CFR 50.109) would not apply. Regarding the current 
requirement to assume a loss-of-offsite power (LOOP) coincident with 
all LOCAs, the Commission accepted the NRC staff recommendation to 
first evaluate the BWROG pilot exemption request before proceeding with 
a separate rulemaking on that topic.

III. Proposed Action

    The Commission proposes to establish an alternative set of risk-
informed requirements with which licensees may voluntarily choose to 
comply in lieu of meeting the current emergency core cooling system 
requirements in 10 CFR 50.46. Using the alternative ECCS requirements 
will provide some licensees with opportunities to change other aspects 
of facility design. The overall structure of the risk-informed 
alternative is described below. The initial focus for this rulemaking 
is on operating plants. The Commission does not now have enough 
information to develop generic ECCS evaluation requirements appropriate 
to the potentially wide variations in designs for new nuclear power 
reactors. Promulgation of a similar rule applicable to future plants 
may be undertaken separately, at a later time, as the Commission's 
understanding of advanced reactor designs increases.\2\ The potential 
rule changes discussed in this document would, at this time, only apply 
to nuclear power reactors which currently hold operating licenses. 
Proposed changes would consist of a new Sec.  50.46a and conforming 
changes to existing Sec. Sec.  50.34, 50.46, 50.46a (to be redesignated 
as Sec.  50.46b), 50.109, 10 CFR Part 50, Appendix A, General Design 
Criteria 17, 35, 38, 41, 44, and 50.
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    \2\ The Commission notes that it is undertaking an effort to 
develop a technology-neutral licensing framework applicable to 
future advanced reactor designs. See 70 FR 5228 (February 1, 2005).
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A. Overview of Rule Framework

    The proposed rule would divide the current spectrum of LOCA break 
sizes into two regions. The division between the two regions is 
delineated by a ``transition break size'' (TBS).\3\ The first region 
includes small size breaks up to and including the TBS. The second 
region includes breaks larger than the TBS up to and including the DEGB 
of the largest RCS pipe. ``Break'' in the term, ``TBS'', does not mean 
a double-ended offset break. Rather, it relates to an equivalent 
opening in the reactor coolant boundary. Details on selection of the 
risk-informed LOCA TBS are presented in Section III.B of this 
supplementary information.
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    \3\ Different TBSs for pressurized water reactors and boiling 
water reactors would be established due to the differences in design 
between those two types of reactors.
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    Pipe breaks in the smaller break size region are considered more 
likely than pipe breaks in the larger break size region. Consequently, 
each break size region will be subject to different ECCS requirements, 
commensurate with likelihood of the break. LOCAs in the smaller break 
size region must be analyzed by the methods, assumptions and criteria 
currently used for LOCA analysis; accidents in the larger break size 
region will be analyzed by less stringent methods based on their lower 
likelihood. Although LOCAs for break sizes larger than the transition 
break will become ``beyond design-basis accidents,'' the NRC would 
promulgate regulations ensuring that licensees maintain the ability to 
mitigate all LOCAs up to and including the DEGB of the largest RCS 
pipe. Design information for systems and components addressing the 
capability to mitigate LOCAs in the larger than TBS region would still 
be part of a plant's ``design basis,'' as that term is defined in Sec.  
50.2, even though that equipment would be used to mitigate a beyond 
design-basis accident. Since they would be mitigated to prevent core 
damage, LOCAs in the larger than TBS region would not be considered 
``severe accidents,'' which are addressed by voluntary industry 
guidelines. The ECCS requirements for both regions are discussed in 
detail in Section III.C of this supplementary information.
    Licensees who perform LOCA analyses using the risk-informed 
alternative requirements may find that their plant designs are no 
longer limited by certain parameters associated with previous DEGB 
analyses. Reducing the DEGB limitations could enable licensees to 
propose a wide scope of design or operational changes up to the point 
of being limited by some other parameter associated with any of the 
required accident analyses. Potential design changes include 
optimization of containment spray designs, modifying core peaking 
factors, optimizing setpoints on accumulators or removing some from 
service, eliminating fast starting of one or more emergency diesel 
generators, increasing power, etc. Some of these design and operational 
changes could increase plant safety since a licensee could optimize its 
systems to better mitigate the more likely LOCAs. The risk-informed 
Sec.  50.46a option would establish risk acceptance criteria for 
evaluating all design changes, including those that are made possible 
by the revised ECCS requirements. These acceptance criteria would be 
consistent with the criteria for risk-informed license amendments 
contained in RG 1.174. These criteria would ensure both the 
acceptability of the changes from a risk perspective and the 
maintenance of sufficient defense-in-depth. They are discussed in 
detail in Section III.D of this supplementary information.
    The rule would require that all future changes \4\ to a facility, 
technical specifications,\5\ or operating procedures made by licensees 
who adopt 10 CFR 50.46a be evaluated by a risk-informed integrated 
safety performance (RISP) assessment process which has been reviewed 
and approved by the NRC via the routine process for license 
amendments.\6\ The RISP assessment process would ensure that all plant 
changes involved acceptable changes in risk and were consistent with 
other criteria from RG 1.174 to ensure adequate defense-in-depth, 
safety margins and performance measurement. Licensees with an approved 
RISP assessment process would be allowed to make certain facility 
changes without NRC review if they met Sec.  50.59 \7\ and Sec.  50.46a 
requirements, including the criterion that risk increases cannot exceed 
a ``minimal'' level. Licensees could make other facility changes after 
NRC approval if they met the Sec.  50.90 requirements for license 
amendments

[[Page 67603]]

and the criteria in Sec.  50.46a, including the criterion that risk 
increases cannot exceed a ``small'' threshold. Potential impacts of the 
plant changes on facility security would be evaluated as part of the 
license amendment review process. The safety and security review 
process for plant changes is discussed further in Section III.G.2 of 
this supplementary information.
---------------------------------------------------------------------------

    \4\ The scope of changes subject to the change criteria in 
paragraph (f) of the proposed rule would be greater than the changes 
currently subject to Sec.  50.59, which applies only to changes to 
``the facility as described in the FSAR.'' The change criteria in 
the proposed rule would apply to all facility and procedure changes, 
regardless of whether they are described in the FSAR.
    \5\ The Commission notes that under the Atomic Energy Act of 
1954, as amended, technical specifications are part of the license. 
Therefore, plant-specific technical specifications must be changed 
by a license amendment.
    \6\ Requirements for license amendments are specified in 
Sec. Sec.  50.90, 50.91 and 50.92. They include public notice of all 
amendment requests in the Federal Register and an opportunity for 
affected persons to request a hearing. In implementing license 
amendments, the NRC typically prepares an appropriate environmental 
analysis and a detailed NRC technical evaluation to ensure that the 
facility will continue to provide adequate protection of public 
health and safety and common defense and security after the 
amendment is implemented.
    \7\ Requirements in Sec.  50.59 establish a screening process 
that licensees may use to determine whether facility changes require 
prior review and approval by the NRC. Licensees may make changes 
meeting the Sec.  50.59 requirements without requesting NRC approval 
of a license amendment under Sec.  50.90.
---------------------------------------------------------------------------

    The NRC would periodically evaluate LOCA frequency information. If 
estimated LOCA frequencies significantly increase, the NRC would 
undertake rulemaking (or issue orders, if appropriate) to change the 
TBS. In such a case, the backfit rule (10 CFR 50.109) would not apply.
    If previous plant changes were invalidated because of a change to 
the TBS, licensees would have to modify or restore components or 
systems as necessary so that the facility would continue to comply with 
Sec.  50.46a acceptance criteria (see Sections III.B.6 and III.H of 
this supplementary information). The backfit rule (10 CFR 50.109) also 
would not apply in these cases.

B. Determination of the Transition Break Size

    To help establish the TBS, the NRC developed pipe break frequencies 
as a function of break size using an expert opinion elicitation process 
for degradation-related pipe breaks in typical BWR and PWR RCSs (SECY-
04-0060, ``Loss-of-Coolant Accident Break Frequencies for the Option 
III Risk-Informed Reevaluation of 10 CFR 50.46, Appendix K to 10 CFR 
Part 50, and General Design Criteria (GDC) 35;'' April 13, 2004; 
ML040860129). This elicitation process is used for quantifying 
phenomenological knowledge when data or modeling approaches are 
insufficient. The elicitation focused solely on determining event 
frequencies that initiate by unisolable primary system side failures 
related to material degradation.
    A baseline TBS was established using these pipe break frequencies 
as a starting point. This baseline TBS was then adjusted to account for 
other significant contributing factors that were not explicitly 
addressed in the expert elicitation process. The following three-step 
process was used by the NRC in establishing the TBS.
    (1) Break sizes for each reactor type (i.e., PWR and BWR) were 
selected that corresponded to a break frequency of once per 100,000 
reactor-years (i.e., 1.0E-5 per reactor-year) from the expert 
elicitation results.
    (2) The NRC then considered uncertainty in the elicitation process, 
other potential mechanisms that could cause pipe failure that were not 
explicitly considered in the expert elicitation process, and the higher 
susceptibility to rupture/failure of specific piping in the RCS.
    (3) The NRC adjusted the TBS upwards to account for these factors.
    The remainder of this section discusses this process and the bases 
for the NRC's decision in greater detail.
1. Historical Estimates of LOCA Frequencies
    Previous studies documented in WASH-1400 (``Reactor Safety Study--
An Assessment of Accident Risks in U.S. Commercial Nuclear Power 
Plants,'' October 1975), NUREG-1150 (``Severe Accident Risks: An 
Assessment for Five U.S. Nuclear Power Plants,'' December 1990), and 
NUREG/CR-5750 (``Rates of Initiating Events at U.S. Nuclear Power 
Plants: 1987-1995,'' February 1999) developed pipe break frequencies as 
a function of break size. The earliest studies (i.e., WASH-1400 and 
NUREG-1150) were based primarily on non-nuclear industry operating 
experience. A more recent study (i.e., NUREG/CR-5750) was based on a 
significant amount of nuclear operating experience; however, it only 
considered the LOCA frequencies associated with precursor leak events 
and did not separately evaluate the effects of known degradation 
mechanisms. These previous studies did not comprehensively evaluate the 
contribution to LOCA frequency for non-piping components other than 
steam generator tube ruptures. They also did not address all current 
passive system degradation concerns and did not discriminate among 
breaks having effective diameters larger than 6 inches. Because of 
these limitations, these earlier studies were not sufficient to develop 
a TBS for use within 10 CFR 50.46a.
    With over 3,000 reactor-years of operating experience, there is now 
a much better understanding of the failure frequencies for the various 
types of piping systems and sizes that are found in light water 
reactors. In addition, there is a more extensive knowledge of 
degradation mechanisms that could cause failures in these piping 
systems. To apply this operating experience and knowledge to risk-
informing ECCS requirements, the NRC formed a group of experts with 
extensive knowledge of plant design, operation, and material 
performance to develop LOCA frequency estimates using an expert opinion 
elicitation process.
2. Expert Opinion Elicitation Process
    In establishing pipe break frequencies as a function of break size, 
the NRC used an expert opinion elicitation process with a panel of 12 
experts as documented in SECY-04-0060, ``Loss-of-Coolant Accident Break 
Frequencies for the Option III Risk-Informed Reevaluation of 10 CFR 
50.46, Appendix K to 10 CFR Part 50, and General Design Criteria (GDC) 
35,'' (April 13, 2004, ML040860129) and NUREG-1829, ``Estimating Loss-
of-Coolant Accident (LOCA) Frequencies Through the Elicitation Process, 
Draft Report for Comment,'' (June 30, 2005; ML052010464). The LOCA 
frequency contributions from pipe breaks in the reactor coolant 
pressure boundary as well as non-piping passive failures were 
considered in this study. Non-piping passive failure contributions were 
evaluated in reactor coolant pressure boundary components including the 
pressurizer, reactor vessel, steam generator, pumps, and valves, as 
appropriate, for BWR and PWR plant types. LOCA frequencies under normal 
operational loading and transients expected over a 60 year reactor 
operating life were developed separately for PWR and BWR plant types, 
which comprise all the nuclear plants in the U.S. These frequencies 
represent generic values applicable to the currently operating U.S. 
commercial nuclear reactor fleet, based on an important assumption 
implicit in the elicitation, which is that all U.S. nuclear plant 
construction and operation is in accordance with applicable codes and 
standards. In addition, plant operation, inspection, and maintenance 
were generally assumed to occur within the expected parameters 
allowable by the regulations and technical specifications.
    The uncertainty associated with each expert's generic frequency 
estimates was also estimated. This uncertainty was associated with each 
expert's confidence in their generic estimates and frequency 
differences stemming from broad plant-specific factors, but did not 
consider factors specific to any individual plants. Thus, the 
uncertainty bounds of the expert elicitation do not represent LOCA 
frequency estimates for individual plants that deviate from the generic 
values. Variability among the various experts' results was also 
examined. A number of sensitivity analyses were conducted to examine 
the robustness of the LOCA frequency estimates to assumptions made 
during the analysis of the experts' responses.
    The LOCA frequency estimates developed using this process are 
consistent with operating experience for

[[Page 67604]]

small breaks and precursor leaks and exhibit trends that are expected 
based on an understanding of passive system failure processes. This is 
important because it is expected from the results that the most 
significant LOCA frequency contribution occurs from degradation-induced 
precursors such as cracking and wall thinning. The LOCA frequency 
estimates are also comparable to prior LOCA frequency estimates.
    There is significant uncertainty associated with the final LOCA 
frequency estimates caused by both individual expert opinion 
uncertainty and variability among the experts' opinions. The estimates 
also depend on certain assumptions used to process the experts' input. 
In addition, the effect of licensees' safety culture can significantly 
influence the cause, detection, and mitigation of degradation of safety 
components.
    As a starting point, the NRC selected break sizes associated with a 
mean frequency of 10-5 per reactor-year using both geometric 
and arithmetic aggregations of individual expert opinion. For PWRs, 
this corresponds to a range of values from approximately 4 inches to 7 
inches equivalent diameter, and for BWRs, from approximately 6 inches 
to 14 inches equivalent diameter. To address the uncertainty in the 
expert opinion elicitation estimates, the staff selected a pipe break 
frequency having approximately a 95th percentile probability of 
10-5 per reactor-year which resulted in a range of values 
from approximately 6 inches to 10 inches equivalent diameter for PWRs 
and from approximately 13 inches to 20 inches equivalent diameter for 
BWRs. However, this does not account for all failure mechanisms. In 
addition, the results of an expert opinion elicitation do not have the 
same weight as actual failure data. Therefore, choosing the 95th 
percentile values gathered from the expert opinion elicitation leaves 
additional margin for uncertainty than would be necessary if the mean 
frequency had been calculated from actual failure data.
3. Adjustments To Address Failure Mechanisms Not Considered by the 
Expert Elicitation
    The expert elicitation process was chartered to consider only LOCAs 
that could result from material degradation-related failures of passive 
components under normal operational conditions. There are also LOCAs 
resulting from failures of active components and other LOCAs resulting 
from low probability events (such as earthquakes of magnitude larger 
than the safe shutdown earthquake, etc.) that contribute to the 
determination of pipe break frequencies. These LOCAs have a strong 
dependency on plant-specific factors. The NRC has evaluated the 
applicability of both LOCAs caused by failures of active components and 
those that could result from low probability events, as discussed 
below.
    The NRC approach for the selection of the TBS is to use the 
frequency estimates of various degradation-related pipe breaks as a 
starting reference point. The frequencies for degradation-related 
breaks represent generic information, broadly applicable for indicating 
the trend of the frequency as the break size increases. In addition to 
the degradation-related frequency estimates, there are other important 
considerations in estimating overall LOCA frequencies. These include 
LOCAs caused by failures of active components; seismically-induced 
LOCAs (both with and without pipe degradation), and LOCAs caused by 
dropped heavy loads. Each is discussed below.
    a. LOCAs caused by failure of active components, such as stuck-open 
valves and blown out seals or gaskets.
    LOCAs caused by failure of these active components have a greater 
frequency of occurrence than LOCAs resulting from the failure of 
passive components. LOCAs resulting from the failure of active 
components are considered small-break (SB) LOCAs, when considering 
components which could fail open or blow out (e.g., safety valves, pump 
seals). Active LOCAs resulting from stuck-open valves are limited by 
the size of the auxiliary pipe. In some PWRs, there are large loop 
isolation valves in the hot and cold leg piping. However, a complete 
failure of the valve stem packing is not expected to result in a large 
flow area, since the valves are back-seated in the open configuration. 
Based on these considerations, active LOCAs are relatively small in 
size and are bounded by the selected TBS.
    b. Seismically-induced LOCAs, both with and without material 
degradation.
    Seismically-induced LOCA break frequencies can vary greatly from 
plant to plant because of factors such as site seismicity, seismic 
design considerations, and plant-specific layout and spatial 
configurations. Seismic break frequencies are also affected by the 
amount of pipe degradation occurring prior to postulated seismic 
events. Seismic PRA insights have been accumulated from the NRC Seismic 
Safety Margins Research Program and the Individual Plant Examination of 
External Events submittals. Based on these studies, piping and other 
passive RCS components generally exhibit high seismic capacities and, 
therefore, are not significant risk contributors. However, these 
studies did not explicitly consider the effect of degraded component 
performance on the risk contributions.
    The NRC is conducting a study to evaluate the seismic performance 
of undegraded and degraded passive system components. This effort is 
examining operating experience, seismic probabilistic risk assessment 
(PRA) insights, and models to evaluate the failure likelihood of 
undegraded and degraded piping. The operating experience review is 
considering passive component failures that have occurred as a result 
of strong motion earthquakes in nuclear and fossil power plants as well 
as other industrial facilities. No catastrophic failures of large pipes 
resulting from earthquakes between 0.2g and 0.5g peak ground 
acceleration have occurred in power plants. However, piping degradation 
could increase the LOCA frequency associated with seismically-induced 
piping failures. When completed, the results of this study could 
indicate that licensees choosing to implement this voluntary rule must 
perform a site-specific seismic assessment. The purpose of the 
assessment would be to demonstrate that RCS piping, assuming 
degradation that would not be precluded by implementing a licensee's 
inspection and repair programs, will withstand earthquakes such that 
the seismic contribution to the overall frequency of pipe breaks larger 
than the TBS is insignificant. If needed, this assessment would be 
required to be submitted as a part of a licensee's application for 
approval to implement the Sec.  50.46a alternative ECCS requirements. 
Specific guidance for making these determinations would be provided by 
the NRC in the regulatory guide pertaining to this rule.
    Plant-specific assessments could be needed because the seismically-
induced break frequencies (direct and indirect) are governed by site 
hazard estimates, plant-specific configurations, and individual plant 
design. The NRC's generic analysis, by its very nature, cannot 
reasonably encompass all potential plant-to-plant variations. For some 
plants, a plant-specific assessment could be a relatively simple 
evaluation to show that the likelihood of breaks larger than the TBS is 
sufficiently low because of a low seismic hazard and consequently very 
low stresses. For other plants, an assessment might involve performing 
more detailed plant-specific calculations to better estimate seismic 
stresses and other parameters, or developing augmented plant-specific

[[Page 67605]]

in-service inspection programs for very strict control of pipe 
degradation. These programs would be designed to detect and repair 
piping flaws that could increase the likelihood of seismically-induced 
pipe breaks with cumulative area larger than the TBS. Other approaches, 
including more detailed studies, generically or for group of plants 
with similar characteristics from the perspective of this issue, could 
also be undertaken.
    The NRC is continuing work to assess the likelihood of seismically-
induced pipe breaks larger than the TBS. These analyses are generic in 
nature and make use of a combination of insights from deterministic and 
probabilistic considerations. To facilitate public comment on the 
technical aspects of this issue, an NRC report outlining the details 
and results of the NRC's approach will be posted in December 2005 on 
the NRC rulemaking Web site at http://ruleforum.llnl.gov. Stakeholders 
should periodically check the NRC rulemaking web site for this 
information. (See Section III.J.2 of this supplementary information.)
    Since a plant-specific seismic assessment requirement might be 
included in the final rule, the NRC is requesting specific public 
comments on potential options and approaches to address this issue. 
(See Section III.J.3. of this supplementary information)
    c. LOCAs caused by dropped heavy loads.
    Another consideration in selecting the TBS is the possibility of 
dropping heavy loads and causing a breach of the RCS piping. During 
power operation, personnel entry into the containment is typically 
infrequent and of short duration. The lifting of heavy loads that if 
dropped would have the potential to cause a LOCA or damage safety-
related equipment is typically performed while the plant is shutdown. 
The majority of heavy loads are lifted during refueling evolutions when 
the primary system is depressurized, which further reduces the risk of 
a LOCA and a loss of core cooling. If loads are lifted during power 
operation, they would not be loads similar to the heavy loads lifted 
during plant shutdown, e.g., vessel heads and reactor internals. In 
addition, the RCS is inherently protected by surrounding concrete 
walls, floors, missile shields and biological shielding. Therefore, 
based on this information, the contribution of heavy load drops on LOCA 
frequency is not considered to be significant. Finally, the resolution 
of GSI-186 (NUREG-0933; ML04250049) resulted in recommendations which 
are expected to further reduce the overall risk due to heavy load drops 
in the future.
4. Consideration of Connected Auxiliary Piping
    Other considerations in selecting the TBS were actual piping system 
design (e.g., sizes) and operating experience. For example, due to 
configuration and operating environment, certain piping is considered 
to be more susceptible than other piping in the same size range. For 
PWRs the range of pipe break sizes determined from the various 
aggregations of expert opinion was 6 to 10 inches in diameter (i.e., 
inside dimension) for the 95th percentile. This is only slightly 
smaller than the PWR surge lines, which are attached to the RCS main 
loop piping and are typically 12 to 14 inch diameter Schedule 160 
piping (i.e., 10.1 to 11.2 inch inside diameter piping). The RCS main 
loop piping is in the range of 30 inches in diameter and has 
substantially thicker walls than the surge lines. The expert 
elicitation panel concluded that this main loop piping is much less 
likely to break than other RCS piping. The shutdown cooling lines and 
safety injection lines may also be 12 to 14 inch diameter Schedule 160 
piping and are likewise connected to the RCS. The difference in 
diameter and thickness of the reactor coolant piping and the piping 
connected to it forms a reasonable line of demarcation to define the 
TBS. Therefore, to capture the surge, shutdown cooling, and safety 
injection lines in the range of piping considered to be equal to or 
less than the TBS, the NRC specified the TBS for PWRs as the cross-
sectional flow area of the largest piping attached to the RCS main 
loop.
    For BWRs, the arithmetic and geometric means of the break sizes 
having approximately a 95th percentile probability of 10-5 
per reactor-year ranged from values of approximately 13 inches to 20 
inches equivalent diameter. The information gathered from the expert 
opinion elicitation for BWRs showed that the estimated frequency of 
pipe breaks dropped markedly for break sizes beyond the range of 
approximately 18 to 20 inches. In looking at BWR designs, it was 
determined that typical residual heat removal piping connected to the 
recirculation loop piping and feedwater piping is about 20 to 24 inches 
in diameter. It was also recognized that the sizes of attached pipes 
vary somewhat among plants. Accordingly, the NRC chose a TBS for BWRs 
based on the larger of either the feedwater or the residual heat 
removal (RHR) piping inside primary containment. Selecting these pipes 
results in a TBS equivalent diameter of about 20 inches. Thus, for 
BWRs, the TBS is specified as the cross-sectional flow area of the 
larger of either the feedwater or the RHR piping inside primary 
containment.
    The NRC believes these definitions of the TBS provide necessary 
conservatism to address uncertainties in estimation of break 
frequencies. In addition, these TBS values are within the range 
supported by the expert opinion elicitation estimates when considering 
the uncertainty inherent in processing the degradation-related 
frequency estimates. Furthermore, the NRC expects that these values 
will provide regulatory stability such that future LOCA frequency 
reevaluations are less likely to result in a requirement that licensees 
undo plant modifications made as a result of implementing 10 CFR 
50.46a.
5. Considerations of Break Location and Flow Characteristic
    Because the effects of TBS breaks on core cooling vary with the 
break location, the NRC evaluated whether the frequency of TBS breaks 
varies with location and whether TBS breaks should, therefore, vary in 
size with location.
    In PWRs, the pressurizer surge line is only connected to one hot 
leg and the pipes attached to the cold legs are generally smaller than 
the surge line in size. The cold legs (including the intermediate legs) 
operate at slightly cooler temperatures and any degradation mechanism 
that might appear would be expected to progress more slowly in the cold 
leg than in the hot leg. Therefore, the NRC evaluated whether it may be 
appropriate to specify a TBS for the cold leg which would be smaller in 
size than the surge lines. The frequency of occurrence of a break of a 
given size is composed of both the frequency of a completely severed 
pipe of that size (a circumferential break) plus the frequency of a 
partial break of that size in an equal or larger size pipe (a 
longitudinal break). Therefore, the NRC evaluated an option where the 
TBS for the hot and cold legs would be distinctly different and would 
be composed of two components: (1) Complete breaks of the pipes 
attached to the hot or cold legs at the limiting locations within each 
attached pipe, and (2) partial breaks of a constant size, as 
appropriate for either the hot or cold leg, at the limiting locations 
within the hot or cold legs. The NRC attempted to estimate the 
appropriate size of the partial break component for the TBS by 
reviewing the expert elicitation results to determine the frequencies 
of occurrence of partial breaks in the hot

[[Page 67606]]

and cold legs which would be equivalent to the frequency of a complete 
surge line break. From this, it was found that frequencies of 
occurrence of partial breaks of a given size are generally lower for 
the cold leg than for the hot leg. However, other than this general 
trend, the elicitation results do not contain enough specific detailed 
information to adequately quantify any specific differences in the 
frequencies compared to a complete surge line break. Because a smaller 
size partial break TBS criterion in either the hot or cold legs could 
not be established, it was determined that the required TBS partial 
breaks in the hot and cold legs should remain equivalent in size to the 
internal cross sectional area of the surge line. There is no 
significant difference in piping or service conditions in BWRs compared 
to the PWR hot and cold leg differences described above, where a 
difference in the rates of degradation could be identified. Thus, a 
smaller size partial break TBS criterion also could not be established 
for BWRs.
    The NRC also evaluated whether TBS breaks should be analyzed as 
single-ended or double-ended breaks. To address this issue the NRC 
reviewed the expert elicitation process and the guidance given to the 
experts in developing their frequency estimates. The NRC concluded that 
the expert elicitation estimates are based on knowledge of physical 
pressure retaining component behavior and are not premised on breaks 
being either single-ended or double-ended. This is a feature of the 
response of the particular system configuration to the occurrence of 
the break, i.e., whether reactor coolant can feed either end of the 
break.
    The current design basis analysis for light water reactors requires 
analysis of a DEGB of the largest pipe in the RCS. Under the proposed 
rule, all breaks up to and including the TBS would be analyzed in 
accordance with existing requirements. A possible reason for specifying 
the TBS for PWRs as double-ended could be that a complete break of the 
pressurizer surge line would result in reactor coolant exiting both 
ends of the break. While this is true, the dominant effect in terms of 
core cooling is loss of the fluid exiting from the hot leg side of the 
break, with much less effect due to fluid exiting from the pressurizer 
side. Therefore, specifying the TBS break as an area equivalent to a 
double-ended break of the surge line would be overly conservative. For 
BWRs, the effect of a double-ended break area is also considered to be 
overly conservative. The selected TBS for BWRs based on the larger of 
the RHR or main feedwater lines would bound breaks of the smaller lines 
in the reactor recirculation and feedwater piping where a complete 
break would result in a double-ended discharge flow. Therefore, the NRC 
has determined that the assumption of a single-ended characteristic of 
the TBS break reasonably represents the effect of RCS breaks. This 
conclusion is not inconsistent with the expert opinion elicitation 
estimates of break frequencies.
6. Effects of Future Plant Modifications on TBS
    For the proposed TBS to remain valid at a particular facility, 
future plant modifications must not significantly increase the LOCA 
pipe break frequency estimates generated during the expert elicitation 
and used as the basis for the TBS. For example, the expert elicitation 
panel did not consider the effects of power uprates in deriving the 
break frequency estimates. The expert elicitation panel assumed that 
future plant operating characteristics would remain consistent with 
past operating practices. The NRC recognizes that significant power 
uprate allowances may change plant performance and relevant operating 
characteristics to a degree that they might impact future LOCA 
frequencies. In applications for power uprates that use or intend to 
use Sec.  50.46a, the NRC will expect licensees to explain why uprate 
conditions (e.g., increased flow-induced vibrations and increased 
potential for flow-assisted corrosion in the reactor coolant pressure 
boundary piping) do not significantly increase break frequencies.
7. Future Adjustments to TBS
    The initial TBS was adjusted upward to account for uncertainties 
and failure mechanisms leading to pipe rupture that were not considered 
in the expert elicitation process. As the NRC obtains additional 
information that may tend to reduce those uncertainties or allow for 
more structured consideration of mechanisms, the NRC will assess 
whether the TBS (as defined in the rule) should be adjusted, and may 
initiate rulemaking to revise the TBS definition to account for this 
new information. The NRC will also continue to assess the precursors 
that might be indicative of an increase in pipe break frequencies in 
plants operating under power uprate conditions to establish whether the 
TBS would need to be adjusted.

C. Alternative ECCS Analysis Requirements and Acceptance Criteria

    The proposed rule would require licensees to analyze ECCS cooling 
performance for breaks up to and including a double-ended rupture of 
the largest pipe in the RCS. These analyses must be performed by 
acceptable methods and must demonstrate that ECCS cooling performance 
conforms to the acceptance criteria set forth in the rule. For breaks 
at or below the TBS, Sec.  50.46a(e)(1) of the proposed rule specifies 
requirements identical to the existing ECCS analysis requirements set 
forth in Sec.  50.46. However, commensurate with the lower probability 
of breaks larger than the TBS, Sec.  50.46a(e)(2) of the proposed rule 
specifies more realistic requirements associated with the rigor and 
conservatism of the analyses and associated acceptance criteria for 
breaks larger than the TBS. LOCA analyses for break sizes equal to or 
smaller than the TBS should be applied to all locations in the RCS to 
find the limiting break location. LOCA analyses for break sizes larger 
than the TBS (but using the more realistic analysis requirements) 
should also be applied to all locations in the RCS to find the limiting 
break size and location. This analytical approach is consistent with 
current practice.
1. Acceptable Methodologies and Analysis Assumptions
    Under existing Sec.  50.46 requirements, prior NRC approval is 
required for ECCS evaluation models. Acceptable evaluation models are 
currently of two types; those that realistically describe the behavior 
of the RCS during a LOCA, and those that conform with the required and 
acceptable features specified in Appendix K. Appendix K evaluation 
models incorporate conservatism as a means to justify that the 
acceptance criteria are satisfied by an ECCS design. In contrast, the 
realistic or best-estimate models attempt to accurately simulate the 
expected phenomena. As a result, comparisons to applicable experimental 
data must be made and uncertainty in the evaluation model and inputs 
must be identified and assessed. This is necessary so that the 
uncertainty in the results can be estimated so that when the calculated 
ECCS cooling performance is compared to the acceptance criteria, there 
is a high level of probability that the criteria would not be exceeded. 
Appendix K, Part II contains the documentation requirements for 
evaluation models. All of these existing requirements would be retained 
in Sec.  50.46a(e)(1) of the proposed rule for breaks at or below the 
TBS.
    The NRC expects that the level of conservatism of an analysis 
method used for breaks larger than the TBS would be less than for 
breaks at or below the TBS. This concept is reflected

[[Page 67607]]

in the differences between paragraphs (e)(1) and (e)(2) of Sec.  
50.46a, which respectively describe ECCS evaluation requirements for 
breaks at or below the TBS and breaks larger than the TBS. As noted 
above, for breaks at or below the TBS, all current requirements, 
including use of an ECCS evaluation model as defined in the rule, are 
retained. For larger breaks, paragraph (e)(2) of Sec.  50.46a indicates 
that only the most important phenomena must be addressed by the 
analysis method, and that the model must reasonably describe the 
behavior of the RCS during the LOCA. The term ``analysis method'' is 
used for the larger than TBS break sizes to indicate that these methods 
need not be the same as the ECCS evaluation models required for breaks 
at or below the TBS. To analyze breaks larger than the TBS, a licensee 
need not use an NRC currently approved evaluation model, plant-specific 
or generic. A licensee may use a presently approved best-estimate 
methodology for breaks larger than the TBS. Such an evaluation model 
would exceed the requirements for analysis methods, and would likely 
yield margin to the acceptance criteria. Also, these approved models 
are available for use at most plants for some break sizes.
    Licensees would not be required to submit detailed analysis method 
documentation for LOCAs larger than the TBS. Section 50.46a would not 
require prior NRC approval of these analysis methods. Licensees would 
only be required to describe the analysis methods used. Analyses using 
methods unfamiliar to the NRC or of questionable accuracy would be 
reviewed by NRC via the inspection process.
    As currently required under Sec.  50.46, the analysis must 
demonstrate with a high level of probability that the acceptance 
criteria will not be exceeded for breaks at or below the TBS. What 
constitutes a high level of probability is not delineated in the rule. 
The position taken in RG 1.157 has been that 95 percent probability 
constitutes an acceptably high probability. Section 50.46a(e)(1) of the 
proposed rule retains the high level of probability as the statistical 
acceptance criterion for breaks at or below the TBS. Because of the 
much lower frequency of pipe breaks larger than the TBS, proposed Sec.  
50.46a(e)(2) relaxes the criterion to ``reasonably'' describe the 
system behavior for breaks larger than the TBS. The NRC is preparing a 
regulatory guide which would provide more detailed guidance about 
meeting this criterion.
    Paragraphs 50.46a(e)(1) and (e)(2) would require that the worst 
break size and location be calculated separately for breaks at or below 
the TBS and for breaks larger than the TBS up to and including a 
double-ended rupture of the largest pipe in the RCS. Different 
methodologies, analytical assumptions, and acceptance criteria will be 
used for each break size region. Consistent with current Sec.  50.46 
requirements, breaks at or below the TBS will be analyzed assuming the 
worst single failure concurrent with a loss-of-offsite power, limiting 
operating conditions, and only crediting safety systems. For breaks 
larger than the TBS, credit may be taken for operation of any and all 
equipment supported by availability data, along with the use of nominal 
operating conditions rather than technical specifications limits. This 
would also include combining actual fuel burnup in decay heat 
predictions with the corresponding operating peaking factors at the 
appropriate time in the fuel cycle. The assumptions of loss-of-offsite 
power and the worst single failure are not required. These more 
realistic requirements are appropriate because breaks larger than the 
TBS are very unlikely. Thus, less margin is needed in the analysis of 
breaks in this region.
    As discussed further in Section III.C.3, ``Plant operational 
requirements related to ECCS analyses,'' Sec.  50.46a(d)(2) would 
prohibit plant operation in any at-power operating configuration for 
which maintenance of coolable geometry and long-term cooling for LOCAs 
larger than the TBS has not been demonstrated. A licensee could analyze 
planned operating configurations or justify that a particular 
configuration is bounded by failures assumed in other analyses to limit 
the number of calculations necessary to support plant operation when 
equipment is out of service or equipment performance is degraded. The 
NRC will provide further guidance on analysis methods and assumptions 
in the regulatory guide issued with the final rule.
2. Acceptance Criteria
    ECCS acceptance criteria in proposed Sec.  50.46a(e)(3) for breaks 
at or below the TBS are the same as those currently required in Sec.  
50.46. Therefore, licensees would be required to use an approved 
methodology to demonstrate that the following acceptance criteria are 
met for the limiting LOCA at or below the TBS:
    i. PCT less than 2200[deg]F;
    ii. Maximum local cladding oxidation (MLO) less than 17 percent;
    iii. Maximum hydrogen production--core wide cladding oxidation 
(CWO) less than 1 percent;
    iv. Maintenance of coolable geometry; and
    v. Maintenance of long-term cooling.
    The first two criteria are established to ensure that the clad 
retains adequate ductility as it is quenched from the elevated 
temperatures anticipated during a LOCA. Loss of ductility would 
potentially result in fragmentation of the fuel and loss of a coolable 
geometry. Clad temperatures in the range of 2200 [deg]F result in rapid 
decreases in cladding ductility and ductility is reduced when oxidation 
levels reach 17 percent. The calculated maximum local cladding 
oxidation must account for the pre-existing oxidation accumulated 
during burnup and that generated during the LOCA. In addition, 
oxidation on the inside of the clad surface must also be considered 
once the clad is calculated to have ruptured. For the majority of 
current plants, operation is limited by the PCT criterion, as total 
oxidation levels typically calculated do not exceed approximately 10 
percent for most plants. However, as the break size definition for a 
design basis accident decreases, cladding oxidation can become 
limiting. Small breaks result in extended periods of time at moderate 
temperatures, in the range of 1800[deg]F, which can produce oxidation 
levels as great or greater than short time spans at higher 
temperatures. The limit on hydrogen production is important for small 
breaks for the same reason--long periods at moderate temperatures can 
cause greater clad oxidation and hydrogen production. Only hydrogen 
calculated to be produced during the LOCA is compared to the CWO limit. 
The CWO limit was not removed from the breaks at or below the TBS 
because the requirements of 10 CFR 50.44, ``Combustible Gas Control for 
Nuclear Power Reactors,'' ensure combustible gas control for beyond 
design basis accidents only and thus can rely on non-safety systems and 
less rigorous analysis techniques to demonstrate compliance.
    Commensurate with the lower probability of occurrence, the 
acceptance criteria in proposed Sec.  50.46a(e)(4) for breaks larger 
than the TBS are less prescriptive:
    i. Maintenance of coolable geometry, and
    ii. Maintenance of long-term cooling.
    The proposed rule would afford licensees flexibility in 
establishing appropriate metrics and quantitative acceptance criteria 
for maintenance of coolable geometry. A licensee's metrics and 
acceptance criteria must realistically demonstrate that coolable core 
geometry and long-term cooling will be maintained. Unless data or other 
valid justification criteria are provided, licensees should use 2200 
[deg]F and 17 percent for the limits on PCT and MLO,

[[Page 67608]]

respectively, as metrics and quantitative acceptance criteria for 
meeting the proposed rule's acceptance criteria. Other less 
conservative criteria would be acceptable if properly justified by 
licensees. In addition, the requirements of 10 CFR 50.44 specify that 
all containments have the capability for ensuring a mixed atmosphere, 
thus reducing the potential for hydrogen combustion in the event of a 
beyond design-basis LOCA. The rule requires that BWRs with Mark III 
containments and all PWRs with ice condenser containments must have the 
capability for controlling combustible gas generated from a metal-water 
reaction involving 75 percent of the fuel cladding surrounding the 
active fuel region, and BWRs with Mark I and II containments must have 
inerted containments. Analyses performed to support the Sec.  50.44 
rulemaking (68 FR 54141; September 16, 2003) demonstrated that PWRs 
with large dry containments do not require additional measures to 
control combustible gas generated from a metal-water reaction involving 
75 percent of the fuel cladding surrounding the active fuel region. 
This bounds the level of oxidation expected in the event of a LOCA 
larger than the TBS.
3. Plant Operational Requirements Related to ECCS Analyses
    The proposed rule would require that a facility be able to mitigate 
LOCA break sizes larger than the TBS up to and including a double-ended 
rupture of the largest pipe in the RCS at the limiting location. The 
licensee must demonstrate this mitigative ability, in part, using 
evaluation models or analysis methods under Sec.  50.46a(e)(2) to 
demonstrate compliance with the acceptance criteria in Sec.  
50.46a(e)(4). For LOCAs larger than the TBS, licensees must demonstrate 
compliance with the acceptance criteria in Sec.  50.46a(e)(4) under all 
at-power operating conditions (i.e., all modes of operation when the 
reactor is critical). This demonstration is required at-power because 
LOCAs are most likely to challenge the ECCS acceptance criteria during 
power operation. These analyses will identify ECCS components and 
trains (including sufficiently reliable non-safety related systems) 
that are required to operate to mitigate LOCA break sizes larger than 
the TBS.
    The proposed rule would not require assuming a loss-of-offsite 
power or a limiting single failure of the ECCS for LOCA analyses 
performed for breaks larger than the TBS. Thus, it is possible that a 
licensee's analyses would credit that the full complement of ECCS was 
available. To ensure that the facility will continue to comply with the 
acceptance criteria for LOCAs larger than the TBS under any at-power 
operating configuration allowed by the license, the Commission would 
require both that the acceptance criteria not be exceeded during any 
at-power condition that has been analyzed, and that the plant not be 
placed in any unanalyzed condition.
    One circumstance where the ability to comply with the acceptance 
criteria might be called into question would be if an ECCS train or 
component was removed from service (such as for maintenance) while the 
plant is in operation. For this time period, the assumed set of 
mitigation systems would not be available to respond should a beyond 
TBS LOCA occur, and the acceptance criteria might not be satisfied. 
Thus, the licensee would either have to demonstrate that under such 
conditions the acceptance criteria would not be exceeded, or not place 
the facility in that configuration. To satisfy this requirement a 
licensee might prepare analyses showing acceptable results with 
expected complements of equipment that might be taken out of service or 
could propose suitable Technical Specifications as part of its 
application for the facility change that would restrict plant operation 
to acceptable conditions.
    Accordingly, in Sec.  50.46a(d)(2) of the proposed rule, the 
Commission would require that the facility may not operate in any at-
power configuration of operable ECCS components where the ECCS cooling 
performance for LOCAs larger than the TBS has not been demonstrated to 
meet the acceptance criteria in Sec.  50.46a(e)(4). The evaluation must 
be calculated in accordance with Sec.  50.46a(e)(2). Bounding analyses 
may be performed to reduce the number of model calculations.
4. Restrictions on Reactor Operation
    Proposed Sec.  50.46a(e)(5) would allow the Director of the Office 
of Nuclear Reactor Regulation to impose restrictions on reactor 
operation if it is determined that the evaluations of ECCS cooling 
performance are not consistent with the requirements for evaluation 
models and analysis methods specified in Sec.  50.46a(e)(1) through 
(e)(4) of this section. Non-compliance may be due to factors such as 
lack of a sufficient data base upon which to assess model uncertainty, 
use of a model outside the range of an appropriate data base, models 
inconsistent with the requirements of Appendix K of Part 50, or 
phenomena unknown at the time of approval of the methodology. Lack of 
compliance with methodological requirements would not necessarily 
result in failure to meet the acceptance criteria of Sec.  50.46a(e)(3) 
and (e)(4), but, rather, would provide results that could not be relied 
upon to demonstrate compliance with the appropriate acceptance 
criteria. Thus, depending upon the specific circumstances, it might be 
necessary for the NRC to impose restrictions on operation until such 
issues are settled. This requirement would be included in the proposed 
rule for consistency with the current ECCS regulations, since it is 
comparable to existing Sec.  50.46(a)(2).

D. Risk-Informed Changes to the Facility, Technical Specifications, or 
Procedures

    The Commission proposes that licensees who adopt Sec.  50.46a would 
use an integrated, risk-informed change process to demonstrate the 
acceptability of all future facility changes, both with and without NRC 
approval, made under Sec.  50.90 or Sec.  50.59, respectively. This 
risk-informed integrated safety performance assessment, or RISP 
assessment, would be required to demonstrate that (1) increases in 
plant risk (if any) meet appropriate risk acceptance criteria, (2) 
defense-in-depth is maintained, (3) adequate safety margins are 
maintained, and (4) adequate performance-measurement programs are 
implemented.
    The Commission considered adopting two sets of change control 
criteria: One for changes enabled by the new rule,\8\ and one for all 
other changes. The Commission rejected this option because it may be 
difficult to distinguish between facility changes enabled by Sec.  
50.46a and changes that are permitted by the current ECCS requirements 
in Sec.  50.46.
---------------------------------------------------------------------------

    \8\ As discussed in Section III.A of this supplementary 
information, licensees approved to implement Sec.  50.46a would be 
able to make facility changes which would not have been permitted 
without the revised ECCS analyses allowed by the rule. These are 
considered to be Sec.  50.46a enabled changes. Other changes that 
licensees could make after adopting this rule could be unrelated to 
the new Sec.  50.46a, insofar as the basis of the changes and NRC 
approval, when necessary, would rely on requirements or analyses 
that do not depend on the new ECCS analyses and acceptance criteria.
---------------------------------------------------------------------------

1. Requirements for the Risk-Informed Integrated Safety Performance 
(RISP) Assessment Process
    A licensee who wishes to implement Sec.  50.46a requirements would 
submit a license amendment request under Sec.  50.90 and receive prior 
NRC approval to implement the alternative requirements. As discussed in 
Section III.C.1 of this supplementary information, the proposed rule 
would require a description of the method(s)

[[Page 67609]]

and the results of the analyses to demonstrate compliance with the 
Sec.  50.46a ECCS acceptance criteria and a description of the RISP 
assessment process to be used in evaluating whether proposed changes to 
the facility, technical specifications, or procedures meet the 
requirements in 50.46a(f). In particular, Sec.  50.46a(c)(1)(ii)(A) 
would require a description of the licensee's PRA model and risk 
assessment methods, and Sec.  50.46a(c)(1)(ii)(B) would require a 
description of the methods and decisionmaking process for evaluating 
compliance with the risk criteria, defense-in-depth criteria, safety 
margin criteria, and performance measurement criteria in Sec.  
50.46a(f). The information required to be submitted in the application 
would form the basis for the NRC's determination of whether the 
licensee's process will ensure that the requirements of Sec.  
50.46a(f)(1) are met for future changes made according to the Sec.  
50.59 requirements.
    The Commission could approve a licensee's application to implement 
10 CFR 50.46a if the criteria in Sec.  50.46a(c)(2) were met. Section 
50.46a(c)(2) would require that:
    1. The licensee's ECCS analyses and results demonstrate compliance 
with the ECCS acceptance criteria,
    2. The RISP assessment process assures that all facility changes 
meet the risk assessment requirements of Sec.  50.46a(f), and
    3. The RISP assessment process ensures that changes not requiring 
prior NRC review and approval are evaluated and comply with Sec.  
50.59.
    Compliance with the ECCS acceptance criteria is necessary to ensure 
that licensed facilities are able to adequately mitigate LOCAs of 
varying sizes and locations. Compliance with the Sec.  50.59 
requirements is necessary to ensure that facility changes made without 
NRC approval do not result in plant conditions that could impact public 
health and safety. Compliance with the Sec.  50.46a(f) requirements for 
RISP assessments is required to ensure that facility changes result in 
acceptable changes in risk, adequate defense-in-depth and safety 
margins are maintained, and acceptable performance-measurement programs 
are implemented. The Sec.  50.46a(f) requirements are discussed 
individually below.
    Sections Sec.  50.46a(f)(1)(ii) and (f)(2)(ii) would describe the 
risk acceptance criteria that the RISP assessment must demonstrate are 
met. Paragraph (f)(3) would describe the requirements on the defense-
in-depth and safety margin evaluations, and on the performance 
measurement programs. Paragraphs (f)(4) and (f)(5) would describe the 
requirements on the PRA or non-PRA risk assessment models and 
methodologies used to determine the impact of the changes on risk.
    A RISP assessment process would include quantitative and 
qualitative risk analysis tools, a framework for evaluating defense-in-
depth implications of changes, a framework for evaluating safety 
margins, and performance-measurement programs that monitor the facility 
and provide feedback of information for timely corrective actions. 
These attributes have been identified by the Commission as a necessary 
set of evaluation tools to ensure that changes to the facility do not 
endanger the public health and safety.
    a. Risk acceptance criteria for plant changes under 10 CFR 50.90.
    Section 50.46a(f)(2)(ii) would require that the RISP demonstrate, 
for changes made under Sec.  50.90, that the total increases in core 
damage frequency (CDF) and large early release frequency (LERF) are 
small and that the overall plant risk remains small. CDF and LERF are 
surrogates for early and latent health effects, which are used in the 
NRC's Safety Goals (Safety Goals for the Operation of Nuclear Power 
Plants; Policy Statement, 51 FR 30028; August 4, 1986). The NRC has 
used CDF and LERF in making regulatory decisions for over 20 years. 
Most recently, the NRC endorsed the use of CDF and LERF as appropriate 
measures for evaluating risk and ensuring safety in nuclear power 
plants when it adopted RG 1.174 in 1997. Application-specific 
regulatory guides have been developed on risk-informed IST, ISI, graded 
quality assurance, and technical specifications. Since the adoption of 
RG 1.174, the Commission has had eight years of experience in applying 
risk-informed regulation to support a variety of applications, 
including amending facility procedures and programs (e.g., IST and ISI 
programs), amending facility operating licenses (e.g., power up-rates, 
license renewals, and changes to the FSAR), and amending technical 
specifications. On the basis of this experience, the Commission 
believes that CDF and LERF are acceptable measures for evaluating 
changes in risk as the result of changes to a facility, technical 
specifications, and procedures, with the exception of certain changes 
that affect containment performance but do not affect CDF or LERF. 
Changes that affect containment performance are considered as part of 
the defense-in-depth evaluation.
    Paragraph 50.46a(f)(2)(ii) would require the total increases in CDF 
and LERF to be small, and the overall plant risk to remain small.\9\ As 
discussed in RG 1.174, whether a change in risk is small depends on a 
plant's overall risk as measured by the current CDF and LERF. For 
plants with an overall baseline CDF of 10-\4\ per year or 
less, small CDF increases are considered to be up to 10-\5\ 
per year. For plants with an overall baseline CDF greater than 
10-\4\ per year, small CDF increases are those of up to 
10-\6\ per year. For plants with an overall baseline LERF of 
10-\5\ per year or less, small LERF increases are considered 
to be up to 10-\6\ per year, and for plants with an overall 
baseline LERF greater than 10-\5\ per year, small LERF 
increases are considered to be up to 10-\7\ per year. Since 
1997, the Commission has applied these quantitative guidelines to 
individual plant changes and to sequences of plant changes implemented 
over time. The Commission has found these guidelines and these values 
(when used together with the defense in depth, safety monitoring, and 
performance-measurement criteria) are capable of differentiating 
between changes, and sequences of changes, that are not expected to 
endanger the public health and safety from those that might. The 
Commission proposes to use these quantitative guidelines as the basis 
for determining whether the total increase in CDF and LERF are small 
and that the overall plant risk remains small.
---------------------------------------------------------------------------

    \9\ Section 2.2.4 in RG 1.174 clarifies that the acceptance 
criteria for changes to CDF and LERF are to be compared with the 
results of a full-scope risk assessment including internal events, 
external events, full power, low power, and shutdown. All references 
to CDF and LERF refer to estimates that include the risk from 
internal events, external events, full power, low power, and 
shutdown. Therefore the CDF and LERF estimates to be used in Sec.  
50.46a evaluations are directly comparable to the acceptance 
guidelines on CDF and LERF in RG 1.174.
---------------------------------------------------------------------------

    The Commission requests specific public comments on the 
acceptability of applying the change in risk acceptance guidelines from 
RG 1.174 to the total cumulative change in risk from all changes in the 
plant after adoption of Sec.  50.46a. Should other risk guidelines be 
used and, if so, what guidelines should be used? (See Section III.J.13 
of this supplementary information.)
    b. Risk acceptance criteria for plant changes under 10 CFR 50.59.
    After the adoption of Sec.  50.46a by a licensee and the approval 
of the proposed RISP assessment program by the NRC, a risk assessment 
would be required for all changes to the facility, technical 
specifications, and procedures that a licensee proposes to make. 
Section 50.46a(f)(1)(ii) of the proposed

[[Page 67610]]

rule would require that the RISP demonstrate, for changes made under 
Sec.  50.59, that any increases in the estimated risk are ``minimal'' 
compared to the overall \10\ plant risk profile. In the Commission's 
view, plant changes which individually and taken together involve 
minimal changes in risk and have no significant impact upon defense-in-
depth or safety margins (and do not involve a change to the license), 
do not result in significant issues involving public health and safety 
or common defense and security. For such changes, a qualitative 
assessment instead of a quantitative estimate of the change in risk may 
be sufficient to demonstrate that the proposed change meets the minimal 
increase in risk criteria.
    For plant changes for which it is possible to quantitatively 
estimate the resulting change in plant risk, existing guidance in RG 
1.174 for NRC review of risk-informed changes does not address a 
threshold for changes that result in risk increases that might be small 
enough (i.e., minimal) that the proposed plant change does not warrant 
review by the NRC. Section 50.59, however, contains guidance on 
determining when non risk-informed plant changes do not warrant review 
by the NRC. Consequently, the Commission proposes to develop the new 
criteria proposed in Sec.  50.46a(f)(1)(ii) to be consistent with 
``minimal'' as it is described in supplementary information published 
with the December 2001 amendment to 10 CFR 50.59 (66 FR 64738).
---------------------------------------------------------------------------

    \10\ As with plant changes made under Sec.  50.90, ``overall'' 
plant risk includes the risk from internal events, external events, 
full power, low power, and shutdown.
---------------------------------------------------------------------------

    The Commission believes that if a change in risk is so small that 
it cannot be reasonably concluded that the risk has actually changed 
(i.e., there is no clear trend toward increasing the risk), the change 
need not be considered an increase in risk. If defense-in-depth, safety 
margins, and performance measurement program criteria are also met, 
such changes would always have a ``minimal'' increase in risk. However, 
the Commission believes that the appropriate threshold for ``minimal'' 
should provide more flexibility than afforded by the description above.
    In the December 2001 amendment to Sec.  50.59, the Commission also 
stated that ``minimal'' as used in Sec.  50.59 is intended to limit the 
amount of increase in probability or consequences of accidents such 
that it remains substantially less than a ''significant increase'' as 
referred to in Sec.  50.92. Therefore the Commission proposes that the 
``minimal'' in Sec.  50.46a(f)(1)(ii) should limit the amount of 
increase in risk such that it remains less than the ``small'' increase 
permitted in Sec.  50.46a(f)(2)(ii).
    As discussed below, RG 1.174 guidelines state that, if the overall 
CDF is greater than 10-\4\ per year, an increase in CDF 
greater than 10-\6\ per year is not small. Similarly, if the 
overall LERF is greater than 10-\5\ per year, an increase in 
LERF greater than 10-\7\ per year is not small. Conversely, 
increases in CDF less than 10-\6\ per year and increases in 
LERF 10-\7\ per year are always small. The Commission 
proposes to define ``minimal'' as 10 percent of the risk increases that 
would be small for any licensee. An alternative, consistent with RG 
1.174, would be to define minimal as 10 percent of small, and allow 
small to vary from plant to plant according to the overall plant 
specific CDF and LERF. For example, minimal could be defined as an 
increase in CDF less than 10-\6\ per year if the overall CDF 
is less than 10-\4\ per year, or less than 10-\7\ 
per year otherwise. However, if correction of a PRA error or new 
information caused the overall CDF to rise from below to above 
10-\4\ per year, the acceptance criteria for minimal would 
drop from 10-\6\ per year to 10-\7\ per year from 
one moment to the next. Existing Sec. Sec.  50.59 and 50.92 provide 
acceptance criteria that are applicable to all the plants and that do 
not change with time. Therefore, the Commission believes that, when 
quantified, a ``minimal'' risk increase would be an increase in CDF 
less than 10-\7\ per year and an increase in LERF less than 
10-\8\ per year. This permits a single risk level to be 
applied to all plants and limits the likelihood of the acceptable risk 
level changing as the plant overall risk changes.
    Paragraph 50.46a(f)(ii) would also require that the increase in 
risk from each change is minimal compared to the overall plant-specific 
risk profile. For licensed facilities which have very low overall risk 
estimates, the proposed criteria of 10-\7\ per year and 
10-\8\ per year for CDF and LERF, respectively, may permit 
increases that are significantly large compared to the overall plant 
risk profile. Permitting a licensee to make changes without NRC review 
that are not minimal compared to the overall plant risk is contrary to 
the intent of the proposed rule. Therefore, the Commission proposes 
that, when quantified, a ``minimal'' increase in CDF and LERF must also 
be an increase of less than 1 percent of the overall plant-specific 
risk. The Commission expects that the fixed risk threshold on 
``minimal'' changes discussed above (i.e., less than 10-\7\ 
per year and 10-\8\ per year increase in CDF and LERF 
respectively) will be applicable to most, if not all, plants.
    For the reasons discussed above, the Commission proposes that a 
risk increase, when evaluated quantitatively, would be considered to be 
``minimal compared to the overall plant risk profile'' if it meets both 
of the following criteria:
    (1) The increase in CDF less than 10-\7\ per year and an 
increase in LERF less than 10-\8\ per year, and
    (2) The increases in CDF and LERF are increases of less than 1 
percent of the overall plant-specific risk.
    c. Cumulative risk acceptance criteria.
    To satisfy the Commission's proposed requirement in Sec.  
50.46a(f)(2)(ii) that the total increases in CDF and LERF are small and 
overall plant risk remains small, the total risk from all changes since 
the adoption of Sec.  50.46a must be tracked. It is important to track 
the total change in risk from changes to the facility, technical 
specifications, and procedures to ensure that these changes, when taken 
in total as they are implemented over time, do not contribute more than 
a small increase in risk. A licensee may always choose to implement a 
series of changes over time. If tracking the total increase in CDF and 
LERF criteria were not implemented, a number of smaller changes where 
every individual change is kept below the proposed rule's risk 
acceptance criteria could, considered cumulatively, result in a 
significant increase in risk. The proposed rule's requirement for risk 
tracking is consistent with RG 1.174, the application-specific RG's, 
and current staff practice. Tracking the total risk increase caused by 
implementing related changes over time and comparison of the total 
against the RG 1.174 criteria has been used for risk-informed in-
service testing (IST), in-service inspection (ISI), and integrated leak 
rate interval extension and is included as part of the Sec.  50.69 risk 
assessment process. However, tracking the total risk increase caused by 
sequential risk-informed extensions of technical specification allowed 
outage times is not required under RG 1.177 guidance for risk-informed 
technical specification changes. Instead, approved changes must include 
provisions to control the potential total risk increase by a 
configuration risk management program that prevents unacceptable risk 
increases that could be caused by overlapping the extended allowed 
outage times permitted by the changes.
    This rule would require that the cumulative risk increase from all 
changes be evaluated against the

[[Page 67611]]

``small'' criteria. Requiring that the total change in risk from a 
series of changes be compared to the Sec.  50.46a acceptance criteria 
instead of allowing the risk to be partitioned and individually 
compared to the acceptance criteria will ensure that the total risk 
increase of all changes, as they are implemented over time, would not 
constitute more than a small increase in risk. Current staff practice, 
consistent with RG 1.174, is to compare the cumulative risk increase 
from all related changes, and only related changes, to the acceptance 
guidelines. Regulatory Guide 1.174 also provides additional acceptance 
guidelines that must be met before permitting unrelated plant changes 
that might decrease risk to be combined (bundled) together with a group 
of related changes in a change in risk estimate. Defining and tracking 
related and bundled changes and separating out the cumulative impact on 
risk of these changes from all other changes is a complex process. The 
proposed rule would simplify this process by combining the cumulative 
increase of all plant changes after adoption of the new rule consistent 
with the Commission decision that all changes be evaluated using the 
RISP assessment process. Under this proposal, there is no need to 
differentiate between related and unrelated changes, and the total 
cumulative change in risk is directly related to the change in the 
overall CDF and LERF over time.
    The Commission believes that including this requirement in the 
proposed rule is required to ensure that risk tracking is performed by 
all licensees and is a necessary element for ensuring that changes 
which would be permitted by the revised ECCS analyses allowed under 
Sec.  50.46a do not result in a greater change in risk than intended by 
the Commission. Comparing the risk increase from each change to the 
acceptance criteria independently of all previous changes would render 
the use of the ``small'' criteria inadequate to monitor and control 
increases in risk from a series of plant changes implemented over time. 
Defining and tracking the cumulative risk impact of ``related'' changes 
is complex and impracticable. Furthermore, licensees who approach the 
acceptance criteria on risk increases may choose to implement other 
plant changes that reduce risk in order to take advantage of further 
changes that might otherwise increase risk above the criteria. 
Comparing the total risk increase to the risk increase criteria will 
support the Commission philosophy that, consistent with the principles 
of risk-informed integrated decision making, licensees should have a 
risk management philosophy in which risk insights are not just used to 
systematically increase risk, but also to help reduce risk where 
appropriate and where it is shown to be cost effective.
    The Commission requests specific public comments on whether there 
is an alternative to tracking the cumulative risk increase that is 
sufficient to provide reasonable assurance of protection to public 
health and safety and common defense and security. (See Section 
III.J.12 of this supplementary information.)
    The Commission also requests specific public comments on the 
acceptability of combining Sec.  50.46a related and unrelated changes 
to meet the risk acceptance criteria. (See Section III.J.11 of this 
supplementary information.)
    Section 50.46a(f)(2)(ii) requires tracking of all proposed plant 
changes (i.e., changes to the facility, technical specifications, and 
procedures), but would not require a licensee to include risk increases 
caused by previous risk-informed changes that were implemented before 
Sec.  50.46a was adopted. Conversely, licensees who adopt Sec.  50.46a, 
will be required to include every risk increase caused by every 
facility, technical specification, or procedure change. Consequently, 
licensees who adopt Sec.  50.46a before implementing other risk-
informed applications, will effectively have a smaller risk increase 
``available'' compared to licensees that have already incorporated some 
risk-informed changes into their overall plant risk before adopting 
Sec.  50.46a. The Commission does not consider this a safety issue but 
requests specific public comment on whether this potential 
inconsistency should be addressed and, if so, how? (See Section 
III.J.14 of this supplementary information.)
    d. Defense-in-depth.
    Section 50.46a(f)(3)(i) would require that the RISP assessment 
demonstrate that defense-in-depth is maintained. Defense-in-depth is an 
element of the NRC's safety philosophy that employs successive measures 
to prevent accidents or mitigate damage if a malfunction, accident, or 
naturally caused event occurs at a nuclear facility. As conceived and 
implemented by the NRC, defense-in-depth provides redundancy in 
addition to a multiple-barrier approach against fission product 
releases. Defense-in-depth continues to be an effective way to account 
for uncertainties in equipment and human performance. The NRC has 
determined that retention of adequate defense-in-depth must be assured 
in all risk-informed regulatory activities. Upon implementation of 
Sec.  50.46a, all changes to the facility, technical specifications, 
and procedures will become risk-informed regulatory activities.
    In RG 1.174, the NRC developed seven elements that should be 
utilized in evaluating the level of defense-in-depth provided for 
nuclear power plants in making risk-informed changes to the licensing 
basis. Since the adoption of RG 1.174 in 1997, the Commission has had 
eight years of experience in applying its guidance to a variety of 
applications, as discussed above. On the basis of this experience, the 
Commission believes that these elements have generally been effective 
in either identifying licensee-proposed changes with unacceptable 
reductions in defense-in-depth, or precluding submission of licensee-
initiated changes with unacceptable reductions in defense-in-depth. 
Accordingly, proposed Sec.  50.46a(f)(3)(i)(A) through (C) would 
incorporate three of the higher level defense-in-depth elements as 
criteria that the Commission believes are generally applicable to all 
proposed risk informed changes. They are:
    (1) Preserving a reasonable balance among prevention of core 
damage, prevention of containment failure (early and late), and 
consequence mitigation;
    (2) Preserving system redundancy, independence, and diversity 
commensurate with the expected frequency and consequences of challenges 
to structures, systems and components, and uncertainties; and
    (3) Ensuring that the independence of barriers is not degraded.
    Criterion 1 is intended to assure that licensees do not unduly rely 
upon prevention for accident sequences. Demonstration of reasonable 
balance requires that any increase in the probability of containment 
failure (early and late) does not significantly increase the frequency 
of a significant fission product release. Licensees must also retain a 
level of mitigation to ensure that mitigation capabilities are 
maintained for accident sequences that lead to relatively late 
containment failure and result in late radiological releases to the 
public. Plant changes, and in particular some changes enabled by the 
new Sec.  50.46a, include a wide variety of containment related 
changes, including some that may affect the frequency of late 
containment failure without affecting either CDF or LERF. Thus, this 
criterion explicitly includes consideration of the impact of a proposed 
change on late containment failure.
    The second criterion, which addresses redundancy, independence, and

[[Page 67612]]

diversity, refers to design principles that the Commission has 
historically employed and that are proven concepts for maintaining 
safety in the nuclear and other industries.
    The third criterion, which requires that independence of barriers 
is not degraded, is a fundamental aspect of defense-in-depth. As with 
the second criterion, independence of barriers has long been used to 
successfully ensure public health and safety.
    The proposed rule states that demonstrating that a change satisfies 
the above three criteria provides assurance, in part, that defense-in-
depth is maintained. The four remaining RG 1.174 elements of defense-
in-depth relate to over-reliance on programmatic activities, defenses 
against common cause failures, defenses against human errors, and 
compliance with the intent of the GDC in Appendix A to 10 CFR Part 50 
are not included in the proposed rule. These criteria are relatively 
specific and their applicability depends on the specific change under 
consideration. Each of these remaining elements should be evaluated for 
applicability to each change and, if applicable, the licensee should 
include these effects in their integrated decision for the proposed 
change.
    e. Safety margins.
    Proposed Sec.  50.46a(f)(3)(ii) would require that adequate safety 
margins are retained to account for uncertainties. These uncertainties 
include phenomenology, modeling, and how the plant was constructed or 
is operated. The Commission's concern is that plant changes could 
inappropriately reduce safety margins, resulting in an unacceptable 
increase in risk or challenge to plant SSCs. This paragraph would 
ensure that an adequate safety margin exists to account for these 
uncertainties, such that there are no unacceptable results or 
consequences (e.g., structural failure) if an acceptance criterion or 
limit is exceeded.
    f. Performance measuring programs.
    Proposed Sec.  50.46a(f)(3)(iii) would require that adequate 
performance measurement programs and feedback strategies are 
implemented to ensure that the RISP assessment continues to reflect 
actual plant design and operation. The RISP assessment includes the 
risk assessment, maintenance of defense-in-depth, and adequate safety 
margins. Results from implementation of monitoring and feedback 
strategies can provide an early indication of unanticipated degradation 
of performance of plant elements that may invalidate the demonstration 
by the RISP assessment that the change satisfied all the change 
criteria.
    The section requires that the monitoring programs be designed to 
detect degradation of SSCs before plant safety is compromised. 
Permitting degradation to advance until plant safety could be 
compromised would be inconsistent with the Commission's regulatory 
responsibility of protecting public safety. The associated strategies 
should ensure that relevant observations of the monitoring program are 
fed back into the RISP assessment and result in timely corrective 
actions as appropriate. Consistent with all risk informed activities, 
the monitoring, feedback, and corrective action programs should target 
resources and emphasis on SSCs at a level commensurate with their 
safety significance.
    The Commission expects that licensee will integrate the performance 
measuring programs required by this section with existing programs for 
monitoring equipment performance and other operating experience on 
their site and throughout industry. In particular, monitoring that is 
performed in conformance with the Maintenance Rule (Sec.  50.65) could 
be used when the monitoring performed under the maintenance rule is 
sufficient to meet the requirements in Sec.  50.46a(f)(3)(iii). 
Licensees who have implemented previous risk-informed regulatory 
actions have normally also been required to implement risk-informed 
monitoring and feedback programs, particularly in the area of risk 
assessment; for example, licensees who adopt Sec.  50.69 will need to 
develop relatively extensive risk-informed monitoring and feedback 
programs. These should be integrated into the proposed paragraph 
(f)(3)(iii) performance measuring programs to the extent practicable.
2. Requirements for Risk Assessments
    The proposed rule is based upon the regulatory premise that the 
acceptability of licensee-initiated changes should be judged in a risk-
informed manner. Thus, risk assessment plays a key role in the 
regulatory structure of the proposed rule. Various provisions of 
proposed Sec.  50.46a require the licensee to submit risk information 
for the purpose of demonstrating that one or more of the criteria in 
the rule have been met. Inasmuch as PRA methodologies are generally 
recognized as the best current approach for conducting risk assessments 
suitable for making decisions in areas of potential safety 
significance, Sec.  50.46a(f)(4) of the proposed rule requires that a 
technically adequate PRA be used in demonstrating compliance with the 
requirements of Sec.  50.46a that would affect the regulatory decision 
in a substantive manner.
    However, the Commission recognizes that non-quantitative PRA 
assessment methodologies and approaches could also be used to 
complement or supplement the quantitative aspects of a PRA, especially 
where performance of a quantitative PRA methodology of the level needed 
to support a particular decision is not technically justifiable because 
the safety significance of the decision does not warrant the level of 
technical sophistication inherent in a PRA. Accordingly, Sec.  
50.46a(f)(5) is written to recognize that non-quantitative risk 
assessment may be utilized.
    Because risk information forms a key role in the agency's 
decisionmaking under this proposed rule, the Commission has determined 
that it would be prudent to establish in this rule minimum requirements 
for PRAs and nonquantitative risk assessments to be used in 
implementing the rule.\11\ Establishment of minimum requirements for 
PRAs and other risk assessments would provide assurance that the 
numerical and qualitative insights produced by the risk assessments are 
adequate to support decisions in areas of potential safety 
significance.
---------------------------------------------------------------------------

    \11\ These requirements are only intended to be used in 
conjunction with the proposed rule, and are not intended to be 
established as generic requirements applicable to other regulatory 
applications at this time. Although these requirements are drawn 
from RG 1.174, the Commission has not yet determined whether the 
requirements should be adopted by rule for generic use outside of 
Sec.  50.46a.
---------------------------------------------------------------------------

    a. Probabilistic Risk Assessment (PRA) requirements.
    Proposed Sec.  50.46a(f)(4)(i) through (iv) would set forth the 
four general attributes of an acceptable PRA for the purposes of this 
proposed rule. Section 50.46a(f)(4)(i) would require that the PRA 
address initiating events from internal and external sources, and for 
all modes of operation including low power and shutdown, that would 
affect the regulatory decision in a substantial manner. Plant risk is a 
function of initiating events from both internal and external sources. 
In addition, plant risk can vary significantly depending upon the 
plant's operating mode. Studies (``Proposed Staff Plan for Low Power 
and Shutdown Risk Analysis Research to Support Risk-informed Regulatory 
Decision Making'', SECY-00-0007, January 12, 2000) have shown that 
relatively high levels of risk can occur during low power and shutdown 
modes. Failure to consider sources of risk from internal and external 
events, or from

[[Page 67613]]

operating modes that the plant may be placed in, could result in an 
inaccurate characterization of the level of risk associated with a 
plant change. Therefore, initiating events from internal and external 
sources and during all modes of operation must be considered by the 
PRA, in order to ensure that the effect on risk from licensee-initiated 
changes is adequately characterized in a manner sufficient to support a 
technically defensible determination of the level of risk.
    Proposed Sec.  50.46a(f)(4)(ii) would require that the PRA 
calculates CDF and LERF inasmuch as this proposed rule would require 
that these measures be compared against acceptance criteria established 
in this proposed rule.
    Proposed Sec.  50.46a(f)(4)(iii) states that the PRA must 
reasonably represent the current configuration and operating practices 
at the plant. A plant's risk may vary as a plant's configuration or its 
procedures change. Failure to update the PRA based upon these 
configuration or procedure changes may result in inaccurate or invalid 
PRA results when analyzing a proposed change. Accordingly, to ensure 
that estimates of CDF and LERF adequately reflect the facility for 
which a decision must be made, the proposed rule would require that the 
PRA address current plant configuration and operating practices.
    Finally, Sec.  50.46a(f)(4)(iv) would require that the PRA have 
``sufficient technical adequacy'' including consideration of 
uncertainty, as well as a sufficient level of detail to provide 
confidence that the total CDF and LERF, and changes in total CDF and 
LERF adequately reflect the proposed change. The proposed rule would 
require the PRA to consider uncertainty because the decision maker must 
understand the limitations of the particular PRA that was performed to 
ensure that the decision is robust and accommodates relevant 
uncertainties. With respect to level of detail, failure to model the 
plant (or relevant portion of the plant) at the appropriate level of 
detail may result in calculated risk values that do not appropriately 
capture the risk significance of the proposed change.
    b. Requirements for risk assessments other than PRA.
    Risk assessment need not always be performed using PRA. The 
proposed rule explicitly recognizes the possibility of using risk 
assessment methods other than PRA to demonstrate compliance with 
various acceptance criteria in the rule. However, as with PRA 
methodologies, the Commission believes that minimum quality 
requirements for PRAs and risk assessments used by a licensee in 
implementing the rule must be established in the rule. Accordingly, 
Sec.  50.46a(f)(5) of the proposed rule would establish the minimum 
requirement for risk assessment methodologies other than PRA. This 
paragraph would require that the licensee demonstrate that any non-PRA 
risk assessment methods used in demonstrating compliance with one or 
more requirements of the proposed rule produce realistic results. The 
Commission believes that this requirement would provide flexibility to 
licensees to use the non-PRA risk methodology (or combination of 
different methodologies) which produces results that are sufficient 
upon which to base decisions that the various acceptance criteria in 
the proposed rule have been met.
3. Operational Requirements
    The Commission proposes five specific operational requirements that 
would apply to licensees who are approved to implement Sec.  50.46a. 
These requirements are set forth in Sec.  50.46a(d) and would remain in 
effect until such time as the licensee permanently ceases operations by 
submitting the decommissioning certifications required under Sec.  
50.82(a). They are:
    (1) Maintain ECCS model(s) and/or analysis method(s) meeting the 
acceptance requirements of the rule,
    (2) Do not exceed ECCS acceptance criteria under any allowed at-
power operating configuration and do not place the plant in any at-
power operating configuration not analyzed and shown to meet ECCS 
acceptance criteria,
    (3) Evaluate all changes to the facility, technical specifications, 
or procedures as described in the FSAR, using the NRC-approved RISP 
assessment process to demonstrate that the risk, defense-in-depth, 
safety margin and performance-measurement criteria are satisfied,
    (4) Implement adequate performance-measurement programs to ensure 
that the RISP assessment process reflects actual plant design and 
operation, and
    (5) Periodically re-evaluate and update the risk assessments 
required under Sec.  50.46a(f) to address changes to the plant, 
operational practices, equipment performance, plant operational 
experience, and PRA model, and revisions in analysis methods, model 
scope, data, and modeling assumptions.
    Each of the five operational requirements is discussed in detail 
below.
    a. Maintain ECCS model(s) and/or analysis method(s).
    Section 50.46a(d)(1) and (d)(2) would require the licensee to 
maintain the ECCS models and/or methods that are used to demonstrate 
ECCS performance meets Section 50.46a(e). As stated above, the RISP 
assessment process must be used for all changes made under Sec.  50.59 
or Sec.  50.90. For changes made under Sec.  50.90, the licensee would 
submit information demonstrating that the ECCS acceptance criteria in 
Section 50.46a(e)(3) and (e)(4) are met for the change. For changes 
made under Sec.  50.46a(f)(1), the licensee would need to assure that 
any impact of the change upon the ECCS performance meets the 
requirements of Sec.  50.59. Therefore, the proposed rule would require 
the ECCS models and/or analysis methods to be maintained that meet the 
requirements of Sec.  50.46a(e)(1) and (e)(2), to ensure that the 
acceptance criteria in Sec.  50.46a(e)(3) and (e)(4) continue to be met 
for the plant.
    b. Do not place the plant in unanalyzed at-power operating 
configurations.
    The Commission would require in Sec.  50.46a(d)(2) that a facility 
be provided with an ECCS designed so that its calculated cooling 
performance conforms to the criteria in Sec.  50.46a(e)(4) for LOCAs 
involving breaks larger than the TBS, up to and including a double-
ended rupture of the largest pipe in the RCS. For LOCAs involving 
breaks larger than the TBS, the analyses performed will identify ECCS 
components and trains (including sufficiently reliable non-safety 
related systems) that are assumed to function in order to demonstrate 
compliance with the acceptance criteria in paragraph 50.46a(e)(4). The 
proposed rule would not require assumption of loss-of-offsite power or 
a limiting single failure of the ECCS for the analyses performed to 
show acceptance criteria in (e)(4) are met for breaks larger than TBS. 
Thus, it is possible that a licensee's analysis may take credit for the 
availability of the full complement of ECCS. To ensure that the 
facility will continue to comply with the acceptance criteria under any 
at-power operating configurations (allowed by the license), the 
Commission will require both that the acceptance criteria not be 
exceeded during any at-power condition that has been analyzed, and 
further that the plant not be placed in any unanalyzed condition.
    One circumstance where the ability to comply with the acceptance 
criteria might be called into question would be if an ECCS train or 
component was removed from service (such as for maintenance) while the 
plant is in operation, where this would result in the available ECCS 
trains or components

[[Page 67614]]

being less than that assumed in the licensee's analysis for LOCAs 
involving breaks larger than the TBS. For this time period, the assumed 
set of mitigation systems would not be available to respond should a 
LOCA occur, and the acceptance criteria might not be satisfied. Thus, 
the licensee would either have to be able to demonstrate that under 
such conditions the acceptance criteria would not be exceeded, or not 
place the facility in that configuration. To satisfy this requirement a 
licensee might prepare analyses showing acceptable results with 
expected complements of equipment that might be taken out of service or 
could propose suitable technical specifications as part of its 
application for the facility change that would restrict plant operation 
to acceptable conditions.
    Accordingly, in Sec.  50.46a(d)(2) of the proposed rule, the 
Commission would require that the facility not operate in any at-power 
configuration where the ECCS cooling performance available from 
operable ECCS components has not been evaluated and found to be 
sufficient to assure that the acceptance criteria in paragraph (e)(4) 
will be met. The evaluation must be calculated in accordance with Sec.  
50.46a(e)(2). Bounding analyses may be performed to reduce the number 
of model calculations.
    c. Evaluate all facility changes using the RISP assessment process.
    Section 50.46a(d)(3) would require that, for licensees that use 
Sec.  50.46a, the integrated, risk-informed change process should be 
used for all changes made under Sec.  50.59 or Sec.  50.90. For changes 
made under Sec.  50.90, the licensee would submit the information 
required in Sec.  50.46a(f)(2), which would include information from 
the RISP assessment performed for the change. The NRC would review the 
change as described above. For changes made under Sec.  50.46a(f)(1), 
which must also meet the requirements of Sec.  50.59, the licensee 
would be required to evaluate the change using the NRC-approved RISP 
assessment process and demonstrate that the acceptance criteria in 
Sec.  50.46a(f) are met.
    d. Implement adequate performance-measurement programs.
    The Commission acknowledged the importance of monitoring and 
feedback in risk-informed decisionmaking in RG 1.174, which identified 
these as one of the five key principles of risk-informed changes to a 
plant's licensing basis. These programs are important to ensure that 
(1) the RISP assessment conducted to examine the impact of proposed 
change(s) continues to reflect the actual design and operation of the 
plant and (2) no adverse safety degradation occurs as a result of 
facility, technical specification or procedure changes implemented 
after a licensee adopts 10 CFR 50.46a as the licensing basis for its 
facility. NRC experience with RG 1.174 has confirmed that monitoring 
and feedback are necessary to provide confidence that new information 
that could change the results of the assessment of proposed changes or 
affect the acceptability of a previously acceptable change is collected 
and incorporated into the assessments. Accordingly, the Commission 
proposes that licensees be required to implement appropriate monitoring 
and feedback programs. Paragraph (d)(4) would require the licensee to 
implement performance monitoring programs capable of meeting the 
acceptance criteria for such programs as described in paragraph 
(f)(3)(iii).
    Section 50.46a(f)(3)(iii)(A) through (C) would require that the 
performance-measurement programs be designed to detect degradation in 
SSCs, monitor the SSCs at a level commensurate with their safety 
significance, and provide feedback of information to allow timely 
corrective actions to be implemented before plant safety is 
compromised. When successfully implemented, these programs would ensure 
that the RISP assessment continues to reflect the risk, defense-in-
depth and safety margin attributes during the evaluation of proposed 
changes, and will ensure that the conclusions that have been drawn from 
the evaluation about previous changes remain valid.
    e. Periodically re-evaluate and update risk assessments.
    Key components of risk-informed regulation are the monitoring of 
changes in plant risk and feedback to the risk assessment and/or plant 
design activities and processes which are the subject of the risk 
assessment. Proposed Sec.  50.46a(d)(5) would set forth the proposed 
rule's requirements governing the periodic re-evaluation and updating 
of licensee's risk assessments.\12\ This paragraph would mandate that a 
licensee must, following implementation of a change to its facility, 
technical specifications, or procedures after adopting Sec.  50.46a, 
periodically reevaluate and update the risk assessments (both PRA and 
non-PRA) required under Sec.  50.46a(f)(1) and (f)(2). In particular, 
Sec.  50.46a(d)(5) specifies that the reevaluation and updating must 
address changes in the risk assessments; revisions in analysis methods, 
model scope, and modeling assumptions; and changes to the plant, 
operational practices, equipment performance, and operational data. In 
addition, the risk assessments may be updated to address, among other 
things, known errors or limitations in the model, or new information. 
Accordingly, it is necessary that the risk assessments be updated so 
that the licensee (and the NRC) will have an accurate understanding of 
risk at its facility, and that changes implemented since the licencee 
adopted Sec.  50.46a continue to be acceptable from a safety and risk 
standpoint (i.e., the facility design and operation continue to be 
consistent with the assumptions of the risk assessments used to meet 
the acceptance criteria in Sec.  50.46a(f)(1) or (f)(2)).
---------------------------------------------------------------------------

    \12\ Reporting requirements relevant to the PRA updating 
required by this paragraph are set forth in Sec.  50.46a(g)(2) of 
the proposed rule.
---------------------------------------------------------------------------

    The updated risk assessments must continue to meet the minimum 
quality requirements in Sec.  50.46a(f)(4) and (f)(5) in order to 
ensure that the updated risk assessments provide the requisite level of 
quality deemed by the Commission to be the minimum necessary to support 
reasoned decision making under the proposed rule.
    The proposed rule would specify that the reevaluation and updating 
be conducted ``periodically,'' but no less often than once every two 
refueling outages. The Commission believes that this is an appropriate 
period because the uncertainty of risk changes occurring during the two 
refueling outage period is tolerable and unlikely to result in high 
risk situations developing as a result of the implementation of plant 
changes. The Commission's preliminary determination in this regard is 
based upon the stringent acceptance criteria governing changes 
initiated under Sec.  50.46a, as well as the existing deterministic 
criteria in the substantive technical requirements in Part 50 and the 
criteria utilized in determining the acceptability of plant changes, 
e.g., Sec. Sec.  50.46a(f)(1) and 50.59. The updating period specified 
in the proposed rule is also comparable to other NRC requirements 
governing updating and reporting of safety information, e.g, Sec. Sec.  
50.59, 50.71(e), as well as the current ASME consensus standard on PRA 
quality.
    With respect to feedback, Sec.  50.46a(d)(5) would require the 
licensee to take ``appropriate action'' to ensure that all facility 
design and operation continue to be consistent with the risk assessment 
assumptions used to meet the acceptance criteria in Sec.  50.46a(f)(1) 
or (f)(2). Such actions may include (but are not limited to) 
improvements or corrections to the risk

[[Page 67615]]

analyses to demonstrate compliance, implementation of changes to offset 
adverse changes in risk or defense in depth, or reversal of changes 
previously made under the provisions of Sec.  50.46a(f). The Commission 
believes that this requirement would provide appropriate flexibility to 
the licensee to determine the actions necessary to ensure continued 
compliance with the Sec.  50.46a(f) acceptance criteria, and is 
consistent with the concept of performance-based regulation.
    Finally, Sec.  50.46a(d)(5) would specify that the reevaluation and 
updating of the risk assessments, and any changes to the facility, 
technical specifications, or procedures necessary as a result of this 
periodic reevaluation and updating, shall not be deemed backfitting. 
The Commission regards the reevaluation and updating to be an inherent 
part of the regulatory concept of the proposed rule. Hence, this 
activity, and any licensee action necessary to ensure the continued 
validity of the associated risk assessments are understood to be part 
of the regulatory process under this rulemaking, and licensees who 
voluntarily choose to implement Sec.  50.46a understand that the 
regulatory process involves such updating, reevaluation, and possible 
need for making changes to its facility, technical specifications, or 
procedures.

E. Reporting Requirements

1. ECCS Aanalysis of Record and Reporting Requirements
    Reporting requirements for the proposed Sec.  50.46a would be 
patterned after the existing reporting requirements in Sec.  50.46. 
Existing 10 CFR 50.46(a)(1) requires that a licensee demonstrate that 
its ECCS is adequate to meet the acceptance criteria using an approved 
evaluation model. The results obtained with the evaluation model are 
often referred to as the ``analysis of record'' (AOR). This AOR is 
documented in the licensee's FSAR and is also used to establish core 
operating limits for each cycle according to the licensee's approved 
reload methodology. Because changes (such as changes to the moderator 
temperature coefficient and peaking factors) are made to the plant on a 
cycle specific basis, deviations from the AOR PCT are permitted. 
Existing requirements in 10 CFR 50.46(a)(3)(i) specify that the 
licensee estimate the deviation in PCT from such changes (or error 
corrections). The amount of deviation is calculated by summing the 
absolute value of each of the individual changes. The licensee's 
estimate must be accurate but is typically not evaluated by running the 
accordingly revised evaluation model. Deviations greater than 50[deg]F 
are deemed ``significant.'' The purpose of the 50[deg]F restriction is 
to ensure that the evaluation model accurately reflects the plant 
conditions, the methodology used by the licensee is that reviewed and 
approved by the NRC, and the changes made to the plant or operation of 
the plant do not appreciably change the ECCS response.
    Existing 10 CFR 50.46(a)(3)(ii) requires the licensee to submit an 
annual report of these estimated deviations to the NRC. When they are 
``significant,'' the licensee is required to contact the NRC within 30 
days to schedule a re-analysis or get approval for other actions that 
may be needed to show compliance with Sec.  50.46 requirements. In 
establishing the schedule, the NRC will consider the safety 
significance of the deviation and the proximity of the AOR PCT to the 
acceptance criterion of 2200 [deg]F. To ensure safety, existing 10 CFR 
50.46(a)(3)(ii) also requires the licensee to algebraically sum the 
estimated individual changes in PCT to ensure that the estimated PCT 
does not exceed 2200 [deg]F. If this algebraic sum exceeds 2200 [deg]F, 
or if the changes cause the licensee to not comply with any other 
acceptance criteria specified in 10 CFR 50.46(b), the licensee must 
take immediate action to comply with 10 CFR 50.46 and report the event 
per 10 CFR 50.55(e), 50.72, and 50.73.
    When 10 CFR 50.46 was first promulgated, the regulations focused 
primarily on large break LOCAs (LBLOCAs). Cladding oxidation is a 
function of both temperature and time at temperature. In LBLOCAs, 
because of the short period of time at high temperature, oxidation can 
be treated as a simple function of temperature and is not expected to 
change if the calculated PCT does not change (as long as the time 
period at high temperature does not change either). Therefore, the PCT 
reporting requirement alone was adequate to control changes to ECCS 
analyses.
    However, under the proposed Sec.  50.46a, ECCS capability would be 
focused on the more likely small break LOCAs where the fuel is subject 
to high temperatures for longer periods of time. Because time at 
temperature is just as important as temperature in determining 
oxidation, cladding oxidation is expected to be the controlling factor 
in many instances, not PCT. Thus, the Commission proposes to include an 
additional reporting requirement in Sec.  50.46a. Licensees would 
report model changes or errors whenever the change in the calculated 
oxidation or the sum of the absolute values of the changes equals or 
exceeds 0.4 percent oxidation. This would make the proposed Sec.  
50.46a oxidation reporting requirement the same, on a percentage basis, 
as the existing PCT change reporting requirement.
    Under the proposed Sec.  50.46a, for each change to or error 
discovered in an ECCS evaluation model or analysis method that affects 
the calculated temperature or level of oxidation, the licensee would be 
required to report the change or error and its estimated effect on the 
limiting ECCS analysis to the Commission at least annually. If the 
change or error is significant, the licensee would provide this report 
within 30 days and include with the report a proposed schedule for 
providing a re-analysis or taking other action to show compliance with 
Sec.  50.46a requirements. For any changes or errors where calculated 
results exceeded the approved regulatory limit, licensees would be 
required to take immediate action to come back into compliance with the 
acceptance criteria.
    For breaks equal to or smaller than the TBS (consistent with the 
existing requirements in Sec.  50.46), Sec.  50.46a(g)(1)(i) would 
define a significant change as one in which the change in calculated 
peak fuel temperature differs by more than 50 [deg]F from the peak fuel 
temperature calculated by the last model or is an accumulation of 
changes and errors such that the sum of the absolute magnitudes of the 
respective temperature changes is greater than 50 [deg]F. For 
oxidation, proposed Sec.  50.46a(g)(1)(i) would define a significant 
change as when the change in the calculated oxidation, or the sum of 
the absolute values of the changes in calculated oxidation equals or 
exceeds 0.4 percent oxidation. For breaks larger than the TBS, Sec.  
50.46a(g)(1)(ii) would define a significant change as one which results 
in a significant reduction in the capability to meet the ECCS 
acceptance criteria in Sec.  50.46a(e)(4). Guidance for determining 
what would be considered a significant reduction will be provided in 
the associated regulatory guide.
2. Risk Assessment Reporting Requirements
    Proposed Sec.  50.46a(g)(2) sets forth reporting requirements with 
respect to the PRA reevaluation and updating required by Sec.  
50.46a(d)(5). When reevaluating and updating the PRA and non-PRA risk 
assessments, Sec.  50.46a(g)(2) would require the licensee to report 
changes to the NRC if they result in a significant reduction in the 
capability to meet the requirements of Sec.  50.46a(f).

[[Page 67616]]

Changes would be reported to the NRC within 60 days of completion of 
the PRA update, and would include a description of the PRA changes, as 
well as an explanation of the reasons for the increase in CDF and/or 
LERF. The 60 day period is twice the time allowed for reporting of 
``significant'' errors and changes to an evaluation model under the 
current Sec.  50.46. This period ensures sufficient time for the 
licensee to complete its evaluation and explanation of the significance 
of such changes, and determine the course of action necessary to 
address adverse changes in risk, while not unduly delaying the report 
to the NRC and thereby delaying NRC oversight. The Commission proposed 
this reporting level to establish a threshold that avoids trivial 
changes in the relevant calculated risk measures, but provides for NRC 
awareness of changes that may warrant further oversight. In addition, 
this paragraph would require that the licensee report include a 
schedule for implementation of any corrective actions required under 
Sec.  50.46a(d)(5) for failure to comply with the acceptance criteria 
in Sec.  50.46a(f)(1) or (f)(2). The Commission believes it should be 
informed of the licensee's implementation schedule so the NRC can 
ensure that the licensee takes corrective action on a timely basis, 
consistent with the safety significance of the change.
3. Minimal Risk Plant Change Reporting Requirement
    In Sec.  50.46a(g)(3) the Commission is proposing to require 
periodic reports by licensees who make ``minimal'' risk plant changes 
pursuant to Sec.  50.46a(f)(1). This process is comparable in many 
respects to the Sec.  50.59 process that requires similar reports. The 
NRC would rely on these reports to identify unexpected numbers of 
minimal risk changes which would provide for NRC awareness of changes 
that, taken together, may result in a significant increase in risk.
    An alternative would be to require that the cumulative risk 
increases from minimal risk changes be tracked separately from the 
cumulative risk increase from all changes, and be compared to another 
quantitative criterion. In Section III.J.11 of this supplementary 
information, the Commission seeks public comment about whether there 
are less burdensome or more effective ways of ensuring that the 
cumulative impact of an unbounded number of minimal risk changes 
remains minimal. The Commission notes that other reporting requirements 
(FSAR updates, ECCS model changes or PRA update results) exist. If 
reporting of minimal risk changes is required, should reporting be 
required every 24 months, every two refueling cycles (like the PRA 
updating), or on a different frequency?

F. Documentation Requirements

    The proposed rule contains several documentation requirements. 
Proposed Sec.  50.46a(h) contains documentation requirements for 
changes made to a facility and/or operating procedures. When making 
plant changes under Sec.  50.46a(f), licensees would be required to 
document the bases for concluding that the acceptance criteria in Sec.  
50.46a(f)(1) or (f)(2) and (f)(3) are satisfied. Licensees would also 
be required under Part II of Appendix K to this part to document the 
bases of evaluation models used to perform ECCS calculations for break 
sizes at or below the TBS. For ECCS analysis methods used for breaks 
larger than the TBS, licensees would be required under Sec.  
50.46a(e)(2) to maintain sufficient supporting justification, including 
the methodology used, to demonstrate that the analytical technique 
reasonably describes the behavior of the reactor system during LOCAs of 
varying size from the TBS up to the double-ended rupture of the largest 
reactor coolant pipe. This information would be reviewed during NRC 
inspections and/or audits to ensure that the risk criteria in Sec.  
50.46a(f) are satisfied and to determine whether the analysis methods 
(including computer codes) used by licensees adequately demonstrate 
ECCS performance such that the ECCS acceptance criteria in Sec.  
50.46a(e) are met.

G. Submittal and Review of Applications Under Sec.  50.46a

1. Initial Application for Implementing Alternative Sec.  50.46a 
Requirements
    When a licensee first decides to comply with the optional Sec.  
50.46a requirements, that licensee must submit an application under 10 
CFR 50.90 for NRC review and approval of a license amendment request. 
The initial application must contain the information required by Sec.  
50.46a(c)(1)(i). This includes information required by Sec.  
50.46a(e)(1) sufficient to allow the NRC to approve the licensee's 
evaluation models \13\ for design-basis accident LOCAs equal to or 
smaller than the TBS and a discussion of the method used for analyzing 
LOCAs larger than the TBS. Analysis methods for LOCAs larger than the 
TBS would be required to meet the criteria specified in Sec.  
50.46a(e)(4), but the proposed rule would not require prior NRC review 
and approval of these methods.
---------------------------------------------------------------------------

    \13\ If a licensee wishes to continue to use an already approved 
evaluation model meeting the requirements of Appendix K to 10 CFR 
Part 50, the licensee should specify the approved model that will be 
utilized.
---------------------------------------------------------------------------

    Licensees must also submit the results of the ECCS analyses 
performed for LOCAs up to and including the TBS and LOCAs larger than 
the TBS showing compliance with the acceptance criteria in Sec.  
50.46a(e)(3) and (e)(4). A licensee's initial change from its existing 
ECCS analysis need not be reviewed by the licensee under the provisions 
of 10 CFR 50.59. Because the proposed rule would require NRC review and 
approval of the initial license amendment application for compliance 
with the alternative Sec.  50.46a requirements, there is no purpose 
served by also requiring licensees to perform a Sec.  50.59 evaluation, 
since Sec.  50.59 is a process to determine the need for prior NRC 
approval of a change to a facility or its procedures as described in 
the FSAR. Once the new Sec.  50.46a evaluation models and initial ECCS 
LOCA analyses have been approved for use, subsequent changes would be 
controlled by the existing process in Sec.  50.59 (which provides 
criteria for determining which changes are within the licensee's 
authority) and the other requirements in Sec.  50.46a(h) for reporting 
when changes to evaluation models and analysis methods (whether from 
correction of errors or changes) is significant.
    Proposed Sec.  50.46a(c)(1)(ii) would require the initial 
application to also contain a description of the RISP assessment 
process. The RISP assessment process would contain a description of the 
licensee's PRA and non-PRA risk assessment methods and a description of 
the methods and decisionmaking process used to show that proposed 
facility changes comply with the defense-in-depth, safety margins, and 
performance measurement criteria in proposed Sec.  50.46a(f)(3). The 
RISP assessment process must also ensure that all future licensee 
changes to the facility, technical specifications, and procedures as 
described in the FSAR be evaluated by a RISP assessment which 
demonstrates that the acceptance criteria in Sec.  50.46a(f) are met 
and requires that changes made pursuant to Sec.  50.46a(f)(1) are also 
evaluated under Sec.  50.59.
2. Subsequent Applications for Plant Changes Under Sec.  50.46a 
Requirements
    After NRC approval of a licensee's initial license amendment 
application addressing ECCS analyses and RISP assessment processes, 
licensees may submit individual license amendment

[[Page 67617]]

applications for plant changes which may not be made under Sec.  50.59 
or Sec.  50.46a(f)(1). These individual license amendment applications 
must contain:
    a. The information required by Sec.  50.90,
    b. Information from the RISP assessment demonstrating that the risk 
criteria, defense-in-depth criteria, safety margins and performance 
monitoring criteria in Sec.  50.46a(f)(2) and (f)(3) are met, and
    c. Information demonstrating that the ECCS acceptance criteria in 
Sec.  50.46a(e)(3) and (e)(4) are met.
    After review of the individual plant change license amendment 
application, the NRC may approve the change if it complies with the 
above criteria and all other applicable NRC regulations, including 
requirements for plant physical security. The NRC would evaluate 
potential impacts of the proposed change on facility security to ensure 
that the change does not significantly reduce the ``built-in 
capability'' of the plant to resist security threats, thus ensuring 
that the change is not inimical to the common defense and security and 
provides adequate protection to public health and safety.

H. Potential Revisions Based on LOCA Frequency Reevaluations

    The NRC plans to periodically evaluate LOCA frequency information. 
Selection of the TBS was based on several factors including the generic 
frequency estimates provided by the expert elicitation process. The NRC 
recognizes that due to unforeseen factors (operating experience, 
identified degradation or other plant changes), our estimation of LOCA 
frequencies could change in the future. Although the margins in the TBS 
as defined in the proposed rule are intended to preclude plant changes 
as a result of minor changes in break frequency estimates, the NRC 
believes it is important to include provisions in the rule so that if 
LOCA frequencies significantly increase, appropriate actions would be 
taken to protect public health and safety. If an increase in LOCA 
frequency were sufficient to invalidate the basis for selecting the TBS 
defined in the proposed rule, the NRC would undertake rulemaking (or 
issue orders to specific licensees, if appropriate) to change the TBS. 
In such a case, the backfit rule (10 CFR 50.109) would not apply. 
Likewise, if future reevaluations of LOCA frequency invalidate the 
bases for facility changes implemented by a licensee, that licensee 
would be required to take appropriate action to reduce facility risk to 
acceptable levels; either by reversing previous facility changes or by 
making other changes to compensate for the increased risk. In these 
cases, the backfit rule (10 CFR 50.109) would also not apply (see 
further discussion in section XV).

I. Changes to General Design Criteria

    In several instances, the proposed Sec.  50.46a rule is not 
consistent with some of the GDC for nuclear power plants contained in 
10 CFR Part 50, Appendix A. To eliminate inconsistencies between the 
deterministic GDC and the risk-informed Sec.  50.46a, the NRC reviewed 
all of the GDC and is proposing revisions to GDC 17, Electrical power 
systems, GDC 35, Emergency core cooling, GDC 38, Containment heat 
removal, GDC 41, Containment atmosphere cleanup, and GDC 44, Cooling 
water systems. These GDC contain design requirements related to LOCAs, 
and the definition of LOCA in 10 CFR Part 50 includes breaks larger 
than the TBS up to and including the DEGB of the largest RCS pipe. 
Under proposed Sec.  50.46a, breaks larger than the TBS would be beyond 
design-basis accidents. As a consequence, these GDC would be modified 
to allow certain LOCA-related Sec.  50.46a requirements for pipe breaks 
larger than the TBS to differ from the design-basis accident 
requirements in the GDC. These exceptions are needed because Sec.  
50.46a analysis requirements for LOCAs larger than the TBS would not 
require the assumption of a LOOP and a single failure, which are 
required by each of these GDC. The likelihood of these large LOCAs is 
judged to be low enough that the additional mitigation capability 
currently afforded by the redundancy requirements in these GDC is not 
necessary. The modifications made to each of the above GDC removes the 
requirements for assuming a single failure and a LOOP in the assessment 
of the ECCS capability to perform its intended safety function for 
beyond design-basis loss of coolant accidents involving pipe breaks 
larger than the TBS. However, assessment of the ECCS capability for 
LOCAs involving pipe breaks up to and including the TBS is unchanged 
from current requirements and must still assume both a single failure 
and LOOP.
    The NRC also reviewed GDC 50, Containment design basis. GDC 50 
specifies, in part, that the reactor containment structure shall be 
designed to accommodate, with sufficient margin, the calculated 
pressure and temperature from any LOCA. It also lists several factors 
that should be considered when determining the available margin. The 
NRC has determined that these factors should also be considered when 
determining the available margin for accommodating LOCAs larger than 
the TBS. Under Sec.  50.46a, however, LOCAs larger than the TBS are not 
design-basis accidents since they are highly unlikely. Nevertheless, 
reactor containment designs should continue to consider beyond TBS 
LOCAs, but the methods used to calculate containment temperatures and 
pressures need not be as conservative as they are for design-basis 
accidents. Thus, the NRC proposes to modify GDC 50 to specify that 
under Sec.  50.46a, leak tight containment capability should be 
maintained for ``realistically'' calculated temperatures and pressures 
for LOCAs larger than the TBS.
    Should licensees make plant modifications under Sec.  50.46a 
resulting in containment pressures and temperatures that exceed the 
current design values by a small amount, the NRC will evaluate the 
acceptability of revised containment structural integrity criteria. 
Criteria will be provided in a regulatory guide for containment 
structural integrity that could be used with Sec.  50.46a. However, the 
acceptability of containment pressures and temperatures exceeding 
current values will also be evaluated for conformance with the LERF 
acceptance criteria specified in Sec.  50.46a(f)(2) and the defense-in-
depth acceptance criteria in Sec.  50.46a(f)(3). The basis for allowing 
revision to containment structural integrity criteria is that LOCAs 
involving pipe breaks larger than the TBS are judged to be of very low 
probability and are no longer considered to be design basis accidents. 
The likelihood of LOCAs involving pipe breaks larger than the TBS is 
judged to be low enough that the large margins currently required in 
design basis accident assessments are not necessary. However, a 
realistic assessment of containment structural capability for LOCAs 
involving pipe breaks larger than the TBS (without consideration of a 
loss-of-offsite-power and a single failure) is still required to 
provide defense-in-depth for these low probability initiating events.
    The inherent physical robustness of current reactor containments 
contributes significantly to the ``built-in capability'' of the plant 
to resist security threats. The Commission expects licensees not to 
make design modifications to the containment under Sec.  50.46a that 
would reduce its structural capability (based on realistically 
calculated containment pressures and temperatures for breaks larger 
than the TBS) to a level that would compromise plant security.
    The NRC considered modifying GDC 4, Environmental and dynamic 
effects

[[Page 67618]]

design bases, based on the TBS as defined in proposed Sec.  50.46a. 
However, the NRC decided to leave this GDC unchanged for the following 
reasons. GDC 4, as currently written, contains a provision whereby 
licensees can exclude designing for dynamic effects associated with 
piping ruptures from their plants' design bases based on the 
probability of piping ruptures being extremely low. This provision of 
the GDC has historically been implemented by the NRC's review and 
approval of a leak-before-break (LBB) analysis (reference Standard 
Review Plan Section 3.6.3). Approval of LBB technology for PWRs only 
was based, in part, on fracture mechanics and the absence of any active 
degradation mechanisms. This mechanistic rationale for not having to 
address dynamic effects (i.e., defined and controlled loadings) is 
still necessary to ensure that piping will not tear unexpectedly, 
including piping larger than the TBS. Absent an approved LBB analysis 
for piping larger than the TBS (for plants implementing Sec.  50.46a), 
PWR licensees would still need to consider dynamic effects because 
asymmetric blowdown loads could cause fuel rods to bow which could in 
turn impede control rod insertion. In addition, excluding dynamic 
effects from consideration for breaks larger than the TBS would permit 
removal of pipe whip restraints and jet impingement barriers at BWRs. 
Without pipe whip restraints and jet impingement barriers, a double-
ended rupture of the largest pipe in the RCS could result in loss of 
more than one train of ECCS and could challenge the integrity of the 
containment. Finally, the dynamic loads associated with a double-ended 
rupture of the largest pipe in the RCS must be considered to preclude 
subcompartment pressurization and structural failure of reinforced 
concrete walls inside the containment that could affect multiple trains 
in multiple systems. In sum, licensees that voluntarily adopt Sec.  
50.46a must continue to comply with GDC 4 and evaluate the dynamic and 
environmental effects of pipe breaks larger than the TBS, unless a 
leak-before-break analysis has been approved by the NRC in accordance 
with GDC 4. Analyses addressing GDC 4, including dynamic effects, 
approved leak-before-break, and environmental effects, will continue to 
be part of the design basis of the plant.
    As stated in GDC 4, ``dynamic effects associated with postulated 
pipe ruptures in nuclear power units may be excluded from the design 
basis when analyses reviewed and approved by the Commission demonstrate 
that the probability of fluid system piping ruptures is extremely low 
under conditions consistent with the design basis for the piping.'' 
Without such an approved analysis, licensees would be required to 
address the dynamic effects (including the effects of missiles, pipe 
whipping, and discharging fluids) in their piping system design and 
analysis. The Commission has not historically required licensees to 
consider such dynamic effects in performing the ECCS analysis required 
by Sec.  50.46, containment analysis required by GDC 16 and GDC 50, and 
probabilistic risk assessments (PRAs). Dynamic effects have been 
excluded from these analyses because of certain design features (e.g., 
pipe whip restraints, jet impingement barriers, ECCS train separation) 
or because of the extremely low likelihood of a double-ended rupture of 
the largest pipe in the RCS (i.e. leak-before-break analysis). This NRC 
staff position will be maintained for licensees that voluntarily adopt 
Sec.  50.46a. However, licensees who voluntarily adopt Sec.  50.46a 
need to consider environmental and dynamic effects in these analyses 
where non-safety related equipment is credited for mitigating breaks 
larger than the TBS.

J. Specific Topics Identified for Public Comment

    The NRC seeks specific public comments on numerous questions and 
issues. All specific topics for comment are identified in this section, 
but some have been discussed elsewhere in this supplementary 
information.
    1. In proposed Sec.  50.46a(b), the Commission specifically 
precluded the application of the Sec.  50.46a alternative requirements 
to future reactors. However, future light water reactors might benefit 
from Sec.  50.46a. The Commission requests specific public comments 
regarding whether Sec.  50.46a should be made available to future light 
water reactors.
    2. The TBS specified by the NRC in the proposed rule does not 
include an adjustment to address the effects of seismically-induced 
LOCAs. NRC is currently performing work to obtain better estimates of 
the likelihood of seismically-induced LOCAs larger than the TBS. By 
limiting the extent of degradation of reactor coolant system piping, 
the likelihood of seismically-induced LOCAs may not affect the basis 
for selecting the proposed TBS. However, if the results of the ongoing 
work indicate that seismic events could have a significant effect on 
overall LOCA frequencies, the NRC may need to develop a new TBS. To 
facilitate public comment on this issue, a report from this evaluation 
will be posted on the NRC rulemaking Web site at http://ruleforum.llnl.gov before the end of the comment period. In December 
2005, stakeholders should periodically check the NRC rulemaking web 
site for this information. The NRC requests specific public comments on 
the effects of pipe degradation on seismically-induced LOCA frequencies 
and the potential for affecting the selection of the TBS. The NRC also 
requests public comments on the results of the NRC evaluation that will 
be made available during the comment period. (See Section III.B.3 of 
this supplementary information.)
    3. Depending on the outcome of an ongoing NRC study (see Section 
III.B.3 of this supplementary information), the final rule could 
include requirements for licensees to perform plant-specific 
assessments of seismically-induced pipe breaks. These assessments would 
need to consider piping degradation that would not be prejudiced by 
implementation of the licensee's inspection and repair programs. The 
assessments would have to demonstrate that reactor coolant system 
piping will withstand earthquakes such that the seismic contribution to 
the overall frequency of pipe breaks larger than the TBS is 
insignificant. The NRC requests specific public comments on this and 
any other potential options and approaches to address this issue.
    4. The ACRS noted that ``a better quantitative understanding of the 
possible benefits of a smaller break size is needed before finalizing 
the selection of the transition break size.'' The TBS to be included in 
the final rule should be selected to maximize the potential safety 
improvements. Thus, the NRC is soliciting comments on the relationship 
between the size of the TBS and potential safety improvements that 
might be made possible by reducing the maximum design-basis accident 
break size.
    5. The proposed Sec.  50.46a includes an integrated, risk-informed 
change process to allow for changes to the facility following 
reanalysis of beyond design basis LOCAs larger than the TBS. However, 
the current regulations in 10 CFR Part 50 already have requirements 
addressing changes to the facility (Sec.  50.59 and Sec.  50.90). It 
might be more efficient to include the integrated, risk-informed change 
(RISP) requirements, for plants that use Sec.  50.46a, under these 
existing change processes. The Commission solicits specific public 
comments on whether to revise existing Sec. Sec.  50.59 and 50.90 to 
accommodate the requirements for making plant changes under Sec.  
50.46a.

[[Page 67619]]

    6. The proposed Sec.  50.46a rule would rely on risk information. 
The NRC has included specifically applicable PRA quality and scope 
requirements in the proposed rule. However, there are other NRC 
regulations that also rely on risk information (e.g. Sec.  50.65 
maintenance rule and Sec.  50.69 alternative special treatment 
requirements). Consistent with the Commission policy on a phased 
approach to PRA quality, it might be more efficient and effective to 
describe PRA requirements (e.g., contents, scope, reporting, changes, 
etc.), in one location in the regulations so that the PRA requirements 
would be consistent among all regulations. The NRC is seeking specific 
public comments on whether it would be better to consolidate all PRA 
requirements into a single location in the regulations so that they 
were consistent for all applications or to locate them separately with 
the specific regulatory applications that they support.
    7. The proposed Sec.  50.46a rule would include the requirement 
that all allowable at-power operating configurations be included in the 
analysis of LOCAs larger than the TBS and demonstrated to meet the ECCS 
acceptance criteria. Historically, operational restrictions have not 
been contained in Sec.  50.46 but were controlled through other 
requirements (e.g., technical specifications and maintenance rule 
requirements). It might be more practical to control the availability 
of equipment credited in the beyond design-basis LOCA analyses in a 
manner more consistent with other operational restrictions. As a 
result, the NRC is soliciting public comments on the most effective 
means for implementing appropriate operational restrictions and 
controlling equipment availability to ensure that ECCS acceptance 
criteria are continually met for beyond design-basis LOCAs.
    8. Given the Commission's intent (See SRM for SECY-04-0037) that 
plant changes made possible by this rule should be constrained in areas 
where the current design requirements ``contribute significantly to the 
`built-in capability' of the plant to resist security threats,'' the 
Commission seeks examples on either side of this threshold (plant 
changes allowed vs. changes prohibited), and additionally any examples 
of changes made possible by Sec.  50.46a that could enhance plant 
security and defense against radiological sabotage or attack. (See 
Section III.G.2 of this supplementary information.) The Commission also 
solicits comments on whether the Sec.  50.46a rule should explicitly 
include a requirement to maintain plant security when making changes 
under Sec.  50.46a or otherwise rely on a separate rulemaking now being 
considered by the NRC to more globally address safety and security 
requirements when making plant changes under Sec. Sec.  50.59 and 
50.90. Any examples of plant changes that involve Safeguards 
Information should be marked and submitted using the appropriate 
procedures.
    9. Given the potential impact to the licensee (since the backfit 
rule would not apply) of the NRC's periodic re-evaluation of estimated 
LOCA frequencies which could cause the NRC to increase the TBS, should 
the rule require licensees to maintain the capability to bring the 
plant into compliance with an increased transition break size (TBS), 
within a reasonable period of time?
    10. Is the proposed rule sufficiently clear as to be 
``inspectable?'' That is, does the rule language lend itself to timely 
and objective NRC conclusions regarding whether or not a licensee is in 
compliance with the rule, given all the facts? In particular, are the 
proposed requirements for PRA quality sufficient in this regard?
    11. The proposed Sec.  50.46a rule would impose no limitations on 
``bundling'' of different facility changes together in a single 
application. Changes which would increase plant risk substantially or 
create risk outliers could be grouped with other plant changes which 
would reduce risk so that the net change would meet the risk acceptance 
criteria. Are the net change in risk acceptance criteria in the 
proposed rule adequate or should some additional limitations be imposed 
to avoid allowing facility changes which are known to increase plant 
risk?
    12. Is there an alternative to tracking the cumulative risk 
increases associated with plant changes made after implementing Sec.  
50.46a that is sufficient to provide reasonable assurance of protection 
to public health and safety and common defense and security? (See 
Section III.D.1 of this supplementary information.)
    13. The Commission requests specific public comments on the 
acceptability of applying the change in risk acceptance guidelines in 
RG 1.174 to the total cumulative change in risk from all changes in the 
plant after adoption of Sec.  50.46a. Should other risk guidelines be 
used and, if so, what guidelines should be used? (See Section III.D.1.c 
of this supplementary information.)
    14. After approval to implement Sec.  50.46a, the proposed rule 
would require tracking risk associated with all proposed plant changes 
but would not require a licensee to include risk increases caused by 
previous risk-informed changes that were implemented before Sec.  
50.46a was adopted. Licensees who adopt Sec.  50.46a before 
implementing other risk-informed applications will have a smaller risk 
increase ``available'' compared to licensees who have already 
incorporated some risk-informed changes into their overall plant risk 
before adopting Sec.  50.46a. The Commission does not consider this a 
safety issue but requests specific public comments on whether this 
potential inconsistency should be addressed and, if so, how? (See 
Section III.D.1 of this supplementary information.)
    15. The proposed Sec.  50.46a would require licensees to report 
every 24 months all ``minimal'' risk facility changes made under Sec.  
50.46a(f)(1) without NRC review. Are there less burdensome or more 
effective ways of ensuring that the cumulative impact of an unbounded 
number of ``minimal'' changes remains inconsequential? (See Section 
III.E.3 of this supplementary information.)
    16. Should the Sec.  50.46a rule itself include high-level criteria 
and requirements for the risk evaluation process and acceptance 
criteria described in Reg Guide 1.174, as is currently proposed? If 
these criteria were included in the regulatory guide only, and not in 
the rule, how could the NRC take enforcement action for licensees who 
failed to meet the acceptance criteria?

IV. Public Meeting During Development of Proposed Rule

    The NRC first prepared a ``conceptual basis'' document and draft 
rule language indicating the rulemaking approach that was being 
considered. This conceptual basis was made public on the NRC website on 
August 2, 2004 (69 FR 46110). The NRC then held a public meeting on 
August 17, 2004, to inform stakeholders of the rule concept and early 
draft rule language and to solicit industry stakeholder information 
about possible plant design changes made possible by the draft rule and 
their associated costs and benefits. Comments received from 
stakeholders during the August public meeting are discussed below.
    Industry stakeholders asked the NRC to clarify the rule 
requirements in several areas to allow them to assess the potential 
costs and benefits of the proposed rule. The NRC has clarified the 
proposed rule by describing in more detail how the single failure 
criterion would be applied to ECCS analysis and to other required 
analyses for pipe breaks larger than the TBS.

[[Page 67620]]

    Industry stakeholders stated that several GDC other than GDC 35 on 
ECCS would need to be modified to be consistent with the alternative 
ECCS requirements in 10 CFR 50.46a. The NRC agrees with this comment 
and has proposed additional changes to GDC 17, Electrical power 
systems, GDC 38, Containment heat removal, GDC 41, Containment 
atmosphere cleanup, GDC 44, Cooling water systems and GDC 50, 
Containment design basis.
    Industry stakeholders asked the NRC (1) to define a threshold for 
Sec.  50.46a plant changes below which license amendments would not be 
required, and (2) if the NRC could review and approve a licensee's PRA 
and process and then allow licensees to make plant changes without 
further NRC review. The NRC has added language in the proposed rule 
which allows a licensee to submit a PRA and a plant change evaluation 
(RISP assessment) process to the NRC for approval. After NRC approval 
is granted, licensees can make certain plant changes that do not exceed 
a ``minimal risk'' threshold without further NRC review or approval. 
Industry stakeholders asked the NRC to address how Sec.  50.46a could 
be used to increase plant operational flexibility without changing 
facility design. The NRC intends for licensees to make plant 
operational changes under Sec.  50.46a using the same processes used to 
make facility design changes. As noted above, after NRC approval of a 
licensee's RISP assessment process, licensees are free to make plant 
operational changes that satisfy the minimal risk change criteria. Any 
operational changes that do not qualify as minimal risk changes or 
involve changes to the technical specifications or the license must be 
submitted to the NRC for review and approval as license amendments.
    Industry stakeholders asked if the NRC could reduce the ECCS 
analytical burden associated with Sec.  50.46a by reducing the number 
of required analyses or eliminating the need for or reducing the extent 
of required NRC reviews. The NRC has reviewed the analytical 
requirements incumbent upon licensees who adopt the 10 CFR 50.46a 
alternative requirements. In this case, the NRC modified its analysis 
requirements to be less prescriptive, affording licensees flexibility 
in demonstrating that the ECCS can successfully mitigate LOCAs up to 
and including the double-ended rupture of the largest pipe in the RCS. 
Analysis, documentation and code review requirements are reduced 
commensurate with the lower likelihood of the larger breaks. Submittal 
of detailed documentation of licensees' analysis methods used for 
breaks larger than the TBS is not required, nor is formal NRC approval 
of analysis methods. The NRC will explicitly define its expectations in 
the regulatory guide before the final rule is promulgated.
    Industry stakeholders asked the NRC to explain its position on the 
effects of increasing plant power levels on the expert elicitation 
process for estimating pipe break frequency. The expert elicitation 
process did not consider potential increases in power. Nevertheless, in 
determining the TBS, the NRC increased the break size resulting from 
the expert elicitation process to account for several types of known 
uncertainties while still maintaining margin for unanticipated 
uncertainties. These uncertainties are discussed in Section III.B of 
this supplementary information. While the NRC believes that the 
proposed rule adequately accounts for modest increases in power, 
significant power uprates may change plant performance and relevant 
operating characteristics (e.g., temperature, environment, flow rate, 
etc.) to a degree which could significantly impact LOCA frequencies. 
For example, higher temperatures could increase the likelihood of 
stress corrosion cracking and higher flow rates could increase flow-
induced vibration which might accelerate the growth of any pre-existing 
cracks in the piping. In reviewing applications for power uprates for 
licensees who comply with Sec.  50.46a, the NRC would determine whether 
the information provided by the licensee is adequate to ensure that 
frequencies of LOCAs larger than the TBS are not significantly affected 
and that adequate performance monitoring programs were implemented 
under Sec.  50.46a(f)(3)(iii). These performance measurement programs 
would be required to monitor SSCs commensurate with their safety 
significance, detect degradation of SSCs before plant safety was 
compromised, and provide feedback to ensure timely corrective actions. 
In the longer term, the NRC would continue to assess the precursors 
that might indicate an increase in pipe break frequencies in plants 
operating under power uprate conditions to establish whether the TBS 
would need to be adjusted.

V. Section-by-Section Analysis of Substantive Changes

A. Section 50.34 Contents of Application; Technical Information

    Paragraph (a)(4) of this section would clarify that Sec.  50.46a is 
applicable to reactors whose construction permits were issued before 
the effective date of the rule and that preliminary safety analysis 
reports (PSARs) for facilities whose construction permits are issued 
after the effective date of this rule and design approvals and design 
certifications issued after the effective date of this rule are not 
allowed to use Sec.  50.46a.

B. Section 50.46 Acceptance Criteria for Emergency Core Cooling Systems 
for Light-Water Nuclear Power Plants

    This section would be modified to allow the optional use of a new 
Sec.  50.46a containing alternative, risk-informed requirements for 
emergency core cooling systems for reactors whose operating licenses 
were issued before the effective date of the rule change.

C. Section 50.46a Alternative Acceptance Criteria for Emergency Core 
Cooling Systems for Light-Water Reactors

    Paragraph (a) would provide definitions for terms used in other 
parts of this section. Two of the definitions, loss-of-coolant 
accidents and evaluation model, are based on the existing definitions 
used in Sec.  50.46 but have been modified to indicate that pipe breaks 
larger than the TBS are beyond design-basis accidents. The two new 
definitions are: (1) Transition break size, which is used to 
distinguish between requirements applicable to pipe breaks at or below 
this size from those applicable to pipe breaks above this size; and (2) 
operating configuration, which is used in Sec.  50.46a(d)(2) to specify 
plant equipment availability conditions that must be analyzed for 
conformance with acceptance criteria.
    Paragraph (b) would provide the applicability and scope of the 
requirements of this section. Proposed Sec.  50.46a would apply only to 
the current fleet of licensed light-water nuclear power reactors 
(licensed before the effective date of the rule). Its requirements 
would be in addition to any other requirements applicable to ECCS set 
forth in 10 CFR 50, with the exception of Sec.  50.46.
    Paragraph (c) would specify the contents of and acceptance criteria 
for initial licensee applications for implementing the alternative ECCS 
requirements in Sec.  50.46a. Paragraph (c)(1)(i) requires that an 
application contain specific information about the ECCS models and 
analysis methods to be used by a licensee. Paragraph (c)(1)(ii) 
requires a description of the RISP assessment process, including (A) a 
description of the PRA model and other risk assessment methods 
demonstrating compliance with the risk

[[Page 67621]]

assessment quality requirements in Sec.  50.46a(f)(4) & (f)(5) and (B) 
a description of the methods and decisionmaking process to be used to 
show compliance with the risk, defense in depth, safety margins and 
performance measurement criteria specified in Sec.  50.46a(f)(1), 
(f)(2) and (f)(3). Paragraph (c)(2) would specify that the acceptance 
criteria that must be met by a licensee before the NRC may approve an 
application to comply with Sec.  50.46a. Paragraph (c)(2)(i) would 
specify the ECCS acceptance criteria; paragraph (c)(2)(ii) would 
require that the RISP assessment processes meets the requirements in 
Sec.  50.46a(f); and paragraph (c)(2)(iii) would require that the RISP 
process ensures that plant changes made without NRC review pursuant to 
Sec.  50.46a(f)(1) are also permitted under Sec.  50.59.
    Paragraph (d) would specify the requirements with which licensees 
approved by the NRC to utilize Sec.  50.46a must comply throughout the 
operating lifetime of the facility. In paragraph (d)(1), licensees 
would be required to maintain ECCS evaluation models and analysis 
methods meeting the requirements in Sec.  50.46a(e)(1) & (e)(2). In 
paragraph (d)(2), licensees would be required to control plant 
operation to ensure that for LOCAs larger than the TBS, the ECCS 
acceptance criteria in Sec.  50.46a(e)(4) would not be exceeded under 
any allowed at-power operating configuration. In paragraph (d)(3), 
licensees would be required to ensure that changes to the facility, 
technical specifications, or procedures are evaluated by an NRC-
approved RISP which demonstrates that acceptance criteria in Sec.  
50.46a(f) are met. In paragraph (d)(4), licensees would be required to 
implement a performance-measurement program meeting the requirements in 
Sec.  50.46a(f)(3)(iii) so that the RISP assessment process reflects 
actual plant design and operation. In paragraph (d)(5), licensees would 
be required to update risk assessments to address plant changes and 
conditions no less often than once every 2 refueling outages. Risk 
assessments would be required to continue to meet the quality 
requirements in Sec.  50.46a(f)(4) and (f)(5). Licensees would be 
required to take action to ensure that facility design and operation 
continue to be consistent with the risk assessment assumptions used to 
meet the acceptance criteria in (f)(1) or (f)(2). Any necessary changes 
to facility caused by updating risk assessments would not be deemed 
backfitting.
    Paragraph (e) would provide the ECCS evaluation requirements and 
acceptance criteria for the two LOCA break size regions. Paragraph 
(e)(1) would specify methods for evaluating ECCS cooling performance 
for breaks at or below the TBS. These requirements are the same as the 
current requirements for LOCA analyses in existing Sec.  50.46. 
Paragraph (e)(2) would specify methods for evaluating ECCS cooling 
performance for breaks larger than the TBS. ECCS cooling performance 
for LOCA breaks larger than the TBS may be analyzed by realistic 
methods. Paragraph (e)(3) would provide ECCS acceptance criteria for 
LOCAs up to and including the TBS. The criteria specified would be 
equivalent to the current requirements in Sec.  50.46 (e.g., 2200 
[deg]F PCT and 17 percent fuel cladding oxidation). Paragraph (e)(4) 
would provide ECCS acceptance criteria for LOCAs larger than the TBS. 
These acceptance criteria would be based on coolable geometry and long 
term cooling and are less prescriptive than the criteria presently used 
for LOCA analysis. Paragraph (e)(5) would provide that the Director of 
the Office of Nuclear Reactor Regulation may impose restrictions on 
reactor operation if ECCS requirements are not met. This paragraph 
would be added to be consistent with existing Sec.  50.46 which also 
contains this requirement.
    Paragraph (f) would provide requirements for implementing changes 
to the facility, technical specifications, and procedures under Sec.  
50.46a.
    Paragraph (f)(1) would specify that licensees may make changes 
without NRC approval if (i) the changes are permitted under Sec.  50.59 
and (ii) a RISP assessment has been performed which demonstrates that 
any possible increases in risk are minimal and that the criteria in 
paragraph (f)(3) are met.
    Paragraph (f)(2) would state that for plant changes not permitted 
under paragraph (f)(1), licensees must submit an application for a 
license amendment containing: (i) the information required by Sec.  
50.90; (ii) information from the RISP assessment demonstrating that any 
increases in CDF and LERF are small, overall plant risk is small, and 
that the criteria in paragraph (f)(3) are met; and (iii) information 
demonstrating that the ECCS acceptance criteria in Sec.  50.46a(e)(3) 
and (e)(4) are met.
    Paragraph (f)(3) would specify requirements for all plant changes. 
Paragraph (f)(3)(i) would require that defense-in-depth is maintained, 
in part, by assuring that: (A) Reasonable balance is provided among 
prevention of core damage, containment failure (early and late), and 
consequence mitigation; (B) system redundancy, independence, and 
diversity is commensurate with expected frequency of accidents, 
consequences of those accidents, and uncertainties; and (C) 
independence of barriers is not degraded. Paragraph (f)(3)(ii) would 
require that (ii) adequate safety margins are maintained. Paragraph 
(f)(3)(iii) would require that adequate performance-measurement 
programs will be implemented that: (A) Detect degradation before plant 
safety is compromised, (B) provide feedback of information and timely 
corrective actions, and (C) monitor SSCs commensurate with their safety 
significance.
    Paragraph (f)(4) would provide the quality and scope requirements 
for risk assessments using PRA. Paragraph (f)(4)(i) would require that 
the PRA address internal and external events and all plant operating 
modes that would affect a regulatory decision. Paragraph (f)(4)(ii) 
would require that the PRA calculate both CDF and LERF. Paragraph 
(f)(4)(iii) would require that the PRA reasonably represent the current 
plant configuration and operating practices. Paragraph (f)(4)(iv) would 
require the PRA to have sufficient technical adequacy and level of 
detail to be confident that calculated CDF and LERF reflects the actual 
plant risk.
    Paragraph (f)(5) would require licensees using risk assessment 
methods other than PRA to justify that the methods used produce 
realistic results.
    Paragraph (g) would provide the requirements for making reports to 
the NRC. Paragraph (g)(1) would require reporting of all errors or 
changes to ECCS analyses at least annually as specified in Sec.  50.4. 
For significant changes or errors, licensees would be required to 
report within 30 days including a schedule for reanalysis or other 
action as needed to show compliance with ECCS requirements. Under 
paragraph (g)(1)(i), for LOCAs involving pipe breaks equal to or 
smaller than the TBS, significant changes would be defined as a change 
in peak cladding temperature of greater than 50 [deg]F or a change in 
calculated cladding oxidation that equals or exceeds 0.4 percent 
oxidation. Under paragraph (g)(1)(ii), for LOCAs involving pipe breaks 
larger than the TBS, a significant change would be defined as one 
resulting in a significant reduction in the capability to meet the ECCS 
acceptance criteria in Sec.  50.46a(e)(4). Paragraph (g)(2) would 
contain reporting requirements for errors or changes to PRA analyses. 
Errors or changes that result in a significant reduction in the 
capability to meet the requirements in Sec.  50.46a(f) would be 
reported within 60 days of completing a PRA update. Paragraph (g)(3) 
would contain reporting requirements for plant changes made under Sec.  
50.46a(f)(1) involving minimal risk. A short

[[Page 67622]]

description of these changes would be reported every 24 months.
    Paragraph (h) would provide documentation requirements for plant 
changes. For all plant changes made under Sec.  50.46a(f), licensees 
would be required to document the bases for meeting the acceptance 
criteria in Sec.  50.46a(f)(1) or (f)(2) and (f)(3). These plant 
changes would also be required to be reflected in updates to the 
licensee's FSAR.
    Paragraphs (i) through (l) would be reserved for future use.
    Paragraph (m) would provide that changes made by the NRC to the TBS 
and all changes required to return the plant to compliance with the 
acceptance criteria after a change in the TBS are not deemed to be 
backfitting under 10 CFR 50.109.

D. Section 50.46a Acceptance Criteria for Reactor Coolant System 
Venting Systems

    This section would be redesignated as Sec.  50.46b.

E. Section 50.109 Backfitting

    This section would be modified to provide that changes made by the 
NRC to the TBS and changes made by licensees to continue to comply with 
are not deemed to be backfitting under 10 CFR 50.109.

F. Appendix A to Part 50--General Design Criteria for Nuclear Power 
Plants

    Five of the general design criteria contained in Appendix A would 
be modified to remove the requirement to assume a single failure and a 
loss-of-offsite power in the systems subject to these criteria for pipe 
breaks larger than the TBS up to and including the DEGB of the largest 
RCS pipe for those plants implementing Sec.  50.46a. The specific 
criteria are: GDC 17, Electrical power systems, GDC 35, Emergency core 
cooling, GDC 38, Containment heat removal, GDC 41, Containment 
atmosphere cleanup, and GDC 44, Cooling water systems. General Design 
Criterion 50, Containment design basis, would also be modified to 
specify that for plants under Sec.  50.46a, leak tight containment 
capability should maintained for ``realistically'' calculated 
temperatures and pressures for LOCAs larger than the TBS.

VI. Criminal Penalties

    For the purposes of Section 223 of the Atomic Energy Act (AEA), as 
amended, the Commission is issuing the proposed rule to amend Sec.  
50.46, add Sec.  50.46a and redesignate existing Sec.  50.46a and Sec.  
50.46b under one or more of sections 161b, 161i, or 161o of the AEA. 
Willful violations of the rule would be subject to criminal 
enforcement. Criminal penalties, as they apply to regulations in Part 
50 are discussed in Sec.  50.111.

VII. Compatibility of Agreement State Regulations

    Under the ``Policy Statement on Adequacy and Compatibility of 
Agreement States Programs,'' approved by the Commission on June 20, 
1997, and published in the Federal Register (62 FR 46517, September 3, 
1997), this rule is classified as compatibility ``NRC.'' Compatibility 
is not required for Category ``NRC'' regulations. The NRC program 
elements in this category are those that relate directly to areas of 
regulation reserved to the NRC by the AEA or the provisions of Title 10 
of the Code of Federal Regulations, and although an Agreement State may 
not adopt program elements reserved to NRC, it may wish to inform its 
licensees of certain requirements via a mechanism that is consistent 
with the particular State's administrative procedure laws, but does not 
confer regulatory authority on the State.

VIII. Availability of Documents

    The NRC is making the documents identified below available to 
interested persons through one or more of the following methods as 
indicated.
    Public Document Room (PDR). The NRC Public Document Room is located 
at 11555 Rockville Pike, Rockville, Maryland.
    Rulemaking Website (Web). The NRC's interactive rulemaking Website 
is located at http://ruleforum.llnl.gov. These documents may be viewed 
and downloaded electronically via this Web site.
    NRC's Public Electronic Reading Room (PERR). The NRC's public 
electronic reading room is located at www.nrc.gov/reading-rm.html.

----------------------------------------------------------------------------------------------------------------
                    Document                         PDR         Web                       PERR
----------------------------------------------------------------------------------------------------------------
Conceptual basis and draft rule................          X           X   ML042160503
WOG comment letter.............................          X   ..........  ML042680079
NEI comment letter.............................          X   ..........  ML042680080
BWROG comment letter...........................          X   ..........  ML042680077
SRM of March 31, 2003..........................          X           X   ML030910476
SECY-02-0057...................................          X           X   ML020660607
SECY-98-300....................................          X           X   ML992870048
SECY-04-0037...................................          X           X   ML040490133
SRM of July 1, 2004............................          X           X   ML041830412
RG 1.174.......................................          X           X   ML023240437
Petition for Rulemaking 50-75..................          X           X   ML020630082
SECY-04-0060...................................          X           X   ML040860129
NUREG-0933.....................................          X           X   ML042540049
Regulatory Analysis............................          X   ..........  ML052870368
SECY-05-0052...................................          X           X   ML050480155
SRM of July 29, 2005...........................          X           X   ML052100416
NUREG 1829.....................................          X           X   ML052010464
----------------------------------------------------------------------------------------------------------------

IX. Plain Language

    The Presidential memorandum dated June 1, 1998, entitled ``Plain 
Language in Government Writing'' directed that the Government's writing 
be in plain language. This memorandum was published on June 10, 1998 
(63 FR 31883). The NRC requests comments on the proposed rule 
specifically with respect to the clarity and reflectiveness of the 
language used. Comments should be sent to the address listed under the 
ADDRESSES caption of the preamble.

X. Voluntary Consensus Standards

    The National Technology Transfer and Advancement Act of 1995, Pub. 
L. 104-113, requires that Federal agencies use technical standards that 
are developed or adopted by voluntary consensus standards bodies unless 
using such a standard is inconsistent

[[Page 67623]]

with applicable law or is otherwise impractical. In this proposed rule, 
the NRC proposes to use the following Government-unique standard: 10 
CFR 50.46a. The Commission notes the development of voluntary consensus 
standards on PRAs, such as an ASME Standard on Probabilistic Risk 
Assessment for Nuclear Power Plant Applications. The government 
standards would allow the use of voluntary consensus standards, but 
would not require their use. The Commission does not believe that these 
other standards are sufficient to specify the necessary requirements 
for licensees who wish to modify plant ECCS analysis methods and 
nuclear power reactor designs based on the results of probabilistic 
risk analysis. The NRC is not aware of any voluntary consensus standard 
addressing risk-informed ECCS design and consequent changes in a light-
water power reactor facility, technical specifications, or procedures 
that could be used instead of the proposed Government-unique standard. 
The NRC will consider using a voluntary consensus standard if an 
appropriate standard is identified. If a voluntary consensus standard 
is identified for consideration, the submittal should explain how the 
voluntary consensus standard is comparable and why it should be used 
instead of the proposed Government-unique standard.

XI. Finding of No Significant Environmental Impact: Environmental 
Assessment

    The Commission has determined under the National Environmental 
Policy Act of 1969, as amended, and the Commission's regulations in 
Subpart A of 10 CFR Part 51, that this rule, if adopted, would not be a 
major Federal action significantly affecting the quality of the human 
environment and, therefore, an environmental impact statement is not 
required. The basis for this determination is as follows:
    This action stems from the Commission's ongoing efforts to risk-
inform its regulations. If adopted, the proposed rule would establish a 
voluntary alternative set of risk-informed requirements for emergency 
core cooling systems. Using the alternative ECCS requirements \14\ will 
provide some licensees with opportunities to change other aspects of 
plant design to increase safety, increase operational flexibility or 
decrease costs. Accordingly, licensee actions taken under the proposed 
rule could either decrease the probability of an accident or slightly 
increase the probability of an accident. Mitigation of LOCAs of all 
sizes would still be required but with less redundancy and margin for 
the larger, low probability breaks. Increases in risk, if any, would be 
required to be small enough that adequate assurance of public health 
and safety is maintained. When considered together, the net effect of 
the licensee actions is expected to have a negligible effect on 
accident probability.
---------------------------------------------------------------------------

    \14\ The alternative requirements are less stringent in the area 
of large break LOCAs. The NRC believes that large break LOCAs are 
very rare events; hence requiring reactors to conservatively 
withstand such events focuses attention and resources on extremely 
unlikely events and could have a detrimental effect on mitigating 
accidents initiated by other more likely events.
---------------------------------------------------------------------------

    Thus, the proposed action would not significantly increase the 
probability or consequences of an accident, when considered in a risk-
informed manner. No changes would be made in the types of quantities of 
radiological effluents that may be released offsite, and there is no 
significant increase in public radiation exposure since there is no 
change to facility operations that could create a new or significantly 
affect a previously analyzed accident or release path.
    With regard to non-radiological impacts, no changes would be made 
to non-radiological plant effluents and there would be no changes in 
activities that would adversely affect the environment. Therefore, 
there are no significant non-radiological impacts associated with the 
proposed action.
    The primary alternative would be the no action alternative. The no 
action alternative, at worst, would result in no changes to current 
levels of safety, risk, or environmental impact. The no action 
alternative would also prevent licensees from making certain plant 
modifications that could be implemented under the proposed rule that 
could increase plant safety. The no action alternative would also 
continue existing regulatory burdens for which there may be little or 
no safety, risk, or environmental benefit.
    The determination of this environmental assessment is that there 
will be no significant offsite impact to the public from this action. 
However, the general public should note that the NRC is seeking public 
participation on this assessment. Comments on any aspect of the 
environmental assessment may be submitted to the NRC as indicated under 
the ADDRESSES heading.
    The NRC has sent a copy of the environmental assessment and this 
proposed rule to every State Liaison Officer and requested their 
comments on the environmental assessment.

XII. Paperwork Reduction Act Statement

    This proposed rule contains new or amended information collection 
requirements that are subject to the Paperwork Reduction Act of 1995 
(44 U.S.C. 3501 et seq). This rule has been submitted to the Office of 
Management and Budget for review and approval of the information 
collection requirements.
    Type of submission, new or revision: Revision.
    The title of the information collection: 10 CFR Part 50, ``Risk-
Informed Changes to Loss-Of-Coolant Accident Technical Requirements''.
    The form number if applicable: Not applicable.
    How often the collection is required: One-time submission of a risk 
assessment of ECCS performance, submission of PRAs and corrective 
actions on occasion, ongoing recordkeeping.
    Who will be required or asked to report: Licensees authorized to 
operate a nuclear power reactor that choose to implement the risk-
informed alternative for analyzing the performance of emergency core 
cooling systems during loss-of-coolant accidents.
    An estimate of the number of annual responses: 46.
    The estimated number of annual respondents: 23.
    An estimate of the total number of hours needed annually to 
complete the requirement or request: 324,208 hours total, including 
268,640 hours for reporting (an average of 11,680 hours per respondent) 
+ 55,568 hours recordkeeping (an average of 2,416 hours per 
recordkeeper).
    Abstract: The Nuclear Regulatory Commission (NRC) proposes to amend 
its regulations to permit current power reactor licensees to implement 
a voluntary, risk-informed alternative to the current requirements for 
analyzing the performance of emergency core cooling systems (ECCS) 
during loss-of-coolant accidents (LOCAs). In addition, the proposed 
rule would establish procedures and criteria for making changes in 
plant design and procedures based upon the results of the new analyses 
of ECCS performance during LOCAs.
    The U.S. Nuclear Regulatory Commission is seeking public comment on 
the potential impact of the information collections contained in this 
proposed rule and on the following issues:
    1. Is the proposed information collection necessary for the proper 
performance of the functions of the NRC, including whether the 
information will have practical utility?

[[Page 67624]]

    2. Is the estimate of burden accurate?
    3. Is there a way to enhance the quality, utility, and clarity of 
the information to be collected?
    4. How can the burden of the information collection be minimized, 
including the use of automated collection techniques?
    A copy of the OMB clearance package may be viewed free of charge at 
the NRC Public Document Room, One White Flint North, 11555 Rockville 
Pike, Room O 1F21, Rockville, MD 20852. The OMB clearance package and 
rule are available at the NRC Worldwide Web site: http://www.nrc.gov/public-involve/doc-comment/omb/index.html for 60 days after the 
signature date of this notice and are also available at the rule forum 
site, http://ruleforum.llnl.gov.
    Send comments on any aspect of these proposed information 
collections, including suggestions for reducing the burden and on the 
above issues, by December 7, 2005, to the Records and FOIA/Privacy 
Services Branch (T-5 F52), U.S. Nuclear Regulatory Commission, 
Washington, DC 20555-0001, or by Internet electronic mail to 
[email protected] and to the Desk Officer, John A. Asalone, Office 
of Information and Regulatory Affairs, NEOB-10202, (3150-0011), Office 
of Management and Budget, Washington, DC 20503. Comments received after 
this date will be considered if it is practical to do so, but assurance 
of consideration cannot be given to comments received after this date. 
You may also e-mail your comments to John A. [email protected] or 
comment by telephone at (202) 395-4650.

Public Protection Notification

    The NRC may not conduct or sponsor, and a person is not required to 
respond to, a request for information or an information collection 
requirement unless the requesting document displays a currently valid 
OMB control number.

XIII. Regulatory Analysis

    The Commission has prepared a draft regulatory analysis on this 
proposed regulation. The analysis examines the costs and benefits of 
the alternatives considered by the Commission. The Commission requests 
public comment on the draft regulatory analysis. Availability of the 
regulatory analysis is provided in Section VIII. Comments on the draft 
analysis may be submitted to the NRC as indicated under the ADDRESSES 
heading.

XIV. Regulatory Flexibility Certification

    In accordance with the Regulatory Flexibility Act (5 U.S.C. 
605(b)), the Commission certifies that this rule will not, if 
promulgated, have a significant economic impact on a substantial number 
of small entities. This proposed rule affects only the licensing and 
operation of nuclear power plants. The companies that own these plants 
do not fall within the scope of the definition of ``small entities'' 
set forth in the Regulatory Flexibility Act or the size standards 
established by the NRC (10 CFR 2.810).

XV. Backfit Analysis

    The NRC has determined that the proposed rulemaking generally does 
not constitute backfitting as defined in the Backfit Rule, 10 CFR 
50.109(a)(1), and that three provisions of the proposed rule 
effectively excluding certain actions from the purview of the Backfit 
Rule, viz., Sec.  50.109(b)(2); Sec.  50.46a(f)(5), and Sec.  
50.46a(j), are appropriate. The bases for each of these determinations 
follows.
    The NRC has determined that the proposed rulemaking does not 
constitute backfitting because it provides a voluntary alternative to 
the existing requirements in 10 CFR 50.46 for evaluating the 
performance of an ECCS for light-water nuclear power plants. A licensee 
may decide to either comply with the requirements of Sec.  50.46a, or 
to continue to comply with the existing licensing basis of their plant 
with respect to ECCS analyses. Therefore, the Backfit Rule does not 
require the preparation of a backfit analysis for the proposed rule.
    As discussed in Section III.H, ``Potential Revisions Based on LOCA 
Frequency Reevaluations,'' the Commission may undertake future 
rulemaking to revise the TBS based upon re-evaluations of LOCA 
frequencies occurring after the effective date of a final rule. A 
proposed amendment to the Backfit Rule, Sec.  50.109(b)(2), would 
provide that future changes to the TBS would not be subject to the 
Backfit Rule. The Commission has determined that there is no statutory 
bar to the adoption of such a provision. The Commission also believes 
that the proposed exclusion of such rulemakings from the Backfit Rule 
is appropriate. The Commission intends to revise the TBS in Sec.  
50.46a rarely and only if necessary based upon public health and safety 
and/or common defense and security considerations. The Commission also 
does not regard the proposed exclusion as allowing the Commission to 
adopt cost-unjustified changes to the TBS. The NRC prepares a 
regulatory analysis for each substantive regulatory action which 
identifies the regulatory objectives of the proposed action, and 
evaluates the costs and benefits of proposed alternatives for achieving 
those regulatory objectives. The Commission has also adopted guidelines 
governing treatment of individual requirements in a regulatory analysis 
(69 FR 29187; May 21, 2004). The Commission believes that a regulatory 
analysis performed in accordance with these guidelines will be 
effective in identifying unjustified regulatory proposals. In addition, 
such rulemaking as applied to licensees who have not yet transferred to 
Sec.  50.46a would not constitute backfitting for those licensees, 
inasmuch as the Backfit Rule does not protect a future applicant who 
has no reasonable expectation that requirements will remain static. The 
policies underlying the Backfit Rule apply only to licensees who have 
already received regulatory approval. Accordingly, the Commission 
concludes that the proposed exclusion in Sec.  50.109(b)(2) of future 
changes to the TBS from the requirements of the Backfit Rule is 
appropriate.
    As discussed in Section III.D.3.e, Sec.  50.46a(d)(5) would require 
that a PRA used to demonstrate compliance with the risk acceptance 
criteria in Sec.  50.46a(f)(1) or (f)(2) be periodically re-evaluated 
and updated, and that the licensee implement changes to the facility 
and procedures as necessary to ensure that the acceptance criteria 
continue to be met. To ensure that such re-evaluation and updating of 
the PRA and any necessary changes to a facility and its procedures 
under paragraph (d)(5) are not considered backfitting, Sec.  
50.46a(d)(5) would provide that such re-evaluation, updating, and 
changes are not deemed to be backfitting. The Commission believes that 
this exclusion from the Backfit Rule is appropriate, inasmuch as 
application of the Backfit Rule in this context would effectively favor 
increases in risk. This is because most facility and procedure changes 
involve an up-front cost to implement a change which must be recovered 
over the remaining operating life of the facility in order to be 
considered cost-effective. For example, assume that after a change is 
implemented, subsequent PRA analyses suggest that the change should be 
``rescinded'' (either the hardware is restored to the original 
configuration or the new configuration is not credited in design bases 
analyses) in order to maintain the assumed risk level. The cost/benefit 
determination of the second, ``restoring'' change must address: (i) The 
unrecovered cost of the first change; and (ii) the cost of the second, 
``restoring'' change. In most cases, application of cost/benefit

[[Page 67625]]

analyses in evaluating the second, ``restoring'' change would skew the 
decision-making in favor of accepting the existing plant with the 
higher risk. Accumulation of such incremental increases in risk does 
not appear to be an appropriate regulatory approach. Accordingly, the 
Commission concludes that the backfitting exclusion in Sec.  
50.46a(d)(5) is appropriate.
    Section 50.46a(m) would provide that if the NRC changes the TBS 
specified in Sec.  50.46a, licensees who have evaluated their ECCS 
under Sec.  50.46a shall undertake additional actions to ensure that 
the relevant acceptance criteria for ECCS performance are met with the 
new TBSs, and that such licensee actions are not to be considered 
backfitting. Consequently, the NRC may require licensees to take action 
under Sec.  50.46a(m) without consideration of the Backfit Rule. The 
Commission has determined that there is no statutory bar to the 
adoption of this provision, and that the proposed provision represents 
a justified departure from the principles underlying the Backfit Rule. 
First, the Commission's decision on this matter recognizes that any 
future rulemaking to alter the TBS will require preparation of a 
regulatory analysis. As discussed, the regulatory analysis will 
ordinarily include a cost/benefit analysis addressing whether the costs 
of the TBS redefinition are justified in view of the benefits 
attributable to the redefinition. Second, the licensee has substantial 
flexibility under the proposed rule to determine the actions 
(reanalysis, procedure and operational changes, design-related changes, 
or a combination thereof) necessary to demonstrate compliance with the 
relevant ECCS acceptance criteria. In this sense, the performance-based 
approach of the proposed rule lends substantial flexibility to the 
licensee and may tend to reduce the burden associated with changes in 
the TBS. Accordingly, the Commission concludes that the backfitting 
exclusion in Sec.  50.46a(m) is appropriate.

List of Subjects in 10 CFR Part 50

    Antitrust, Classified information, Criminal penalties, Fire 
protection, Intergovernmental relations, Nuclear power plants and 
reactors, Radiation protection, Reactor siting criteria, Reporting and 
recordkeeping requirements.

    For the reasons set out in the preamble and under the authority of 
the Atomic Energy Act of 1954, as amended; the Energy Reorganization 
Act of 1974, and 5 U.S.C. 553, the NRC is proposing to adopt the 
following amendments to 10 CFR part 50.

PART 50--DOMESTIC LICENSING OF PRODUCTION AND UTILIZATION 
FACILITIES

    1. The authority citation for part 50 continues to read as follows:

    Authority: Secs. 102, 103, 104, 105, 161, 182, 183, 186, 189, 68 
Stat. 936, 937, 938, 948, 953, 954, 955, 956, as amended, sec. 234, 
83 Stat. 444, as amended (42 U.S.C. 2132, 2133, 2134, 2135, 2201, 
2232, 2233, 2236, 2239, 2282); secs. 201, as amended, 202, 206, 88 
Stat. 1242, as amended, 1244, 1246 (42 U.S.C. 5841, 5842, 5846); 
sec. 1704, 112 Stat. 2750 (44 U.S.C. 3504 note).
    Section 50.7 also issued under Pub. L. 95-601, sec. 10, 92 Stat. 
2951 (42 U.S.C. 5841). Section 50.10 also issued under secs. 101, 
185, 68 Stat. 955, as amended (42 U.S.C. 2131, 2235); sec. 102, Pub. 
L. 91-190, 83 Stat. 853 (42 U.S.C. 4332).
    Sections 50.13, 50.54(dd), and 50.103 also issued under sec. 
108, 68 Stat. 939, as amended (42 U.S.C. 2138). Sections 50.23, 
50.35, 50.55, and 50.56 also issued under sec. 185, 68 Stat. 955 (42 
U.S.C. 2235). Sections 50.33a, 50.55a and Appendix Q also issued 
under sec. 102, Pub. L. 91-190, 83 Stat. 853 (42 U.S.C. 4332). 
Sections 50.34 and 50.54 also issued under sec. 204, 88 Stat. 1245 
(42 U.S.C. 5844). Sections 50.58, 50.91, and 50.92 also issued under 
Pub. L. 97-415, 96 Stat. 2073 (42 U.S.C. 2239). Section 50.78 also 
issued under sec. 122, 68 Stat. 939 (42 U.S.C. 2152). Sections 
50.80-50.81 also issued under sec. 184, 68 Stat. 954, as amended (42 
U.S.C. 2234). Appendix F also issued under sec. 187, 68 Stat. 955 
(42 U.S.C. 2237).

    2. In Sec.  50.34, paragraphs (a)(4) and (b)(4) are revised to read 
as follows:


Sec.  50.34  Contents of application; technical information.

    (a) * * *
    (4) A preliminary analysis and evaluation of the design and 
performance of structures, systems, and components of the facility with 
the objective of assessing the risk to public health and safety 
resulting from operation of the facility and including determination of 
the margins of safety during normal operations and transient conditions 
anticipated during the life of the facility, and the adequacy of 
structures, systems, and components provided for the prevention of 
accidents and the mitigation of the consequences of accidents. Analysis 
and evaluation of ECCS cooling performance and the need for high point 
vents following postulated loss-of-coolant accidents must be performed 
in accordance with the requirements of Sec.  50.46 or Sec.  50.46a, and 
Sec.  50.46b for facilities for which construction permits may be 
issued after December 28, 1974, but before [EFFECTIVE DATE OF RULE]. 
Such analyses must be performed in accordance with the requirements of 
Sec.  50.46 and Sec.  50.46b for facilities for which construction 
permits may be issued after [EFFECTIVE DATE OF RULE], and design 
approvals and standard design certifications under part 52 of this 
chapter issued after [EFFECTIVE DATE OF RULE].
* * * * *
    (b) * * *
    (4) A final analysis and evaluation of the design and performance 
of structures, systems, and components with the objective stated in 
paragraph (a)(4) of this section and taking into account any pertinent 
information developed since the submittal of the preliminary safety 
analysis report. Analysis and evaluation of ECCS cooling performance 
following postulated LOCAs must be performed in accordance with the 
requirements of Sec. Sec.  50.46 or 50.46a, and 50.46b for facilities 
for which a license to operate may be issued after December 28, 1974, 
but before [EFFECTIVE DATE OF RULE]. The analyses must be performed in 
accordance with the requirements of Sec. Sec.  50.46 and 50.46b for 
facilities for which construction permits may be issued after 
[EFFECTIVE DATE OF RULE], and design approvals and standard design 
certifications under part 52 of this chapter issued after [EFFECTIVE 
DATE OF RULE].
* * * * *
    3. In Sec.  50.46, paragraph (a) introductory text is added and 
paragraph (a)(1)(i) is revised to read as follows:


Sec.  50.46  Acceptance criteria for emergency core cooling systems for 
light-water nuclear power plants.

    (a) Each boiling or pressurized light-water nuclear power reactor 
fueled with uranium oxide pellets within cylindrical zircalloy or ZIRLO 
cladding must be provided with an emergency core cooling system (ECCS). 
Reactors whose operating licenses were issued before [EFFECTIVE DATE OF 
RULE] must be designed in accordance with the requirements of either 
this section or Sec.  50.46a. Reactors whose construction permits were 
issued prior to, but have not received operating licenses as of 
[EFFECTIVE DATE OF RULE], and those reactors whose construction permits 
are issued after [EFFECTIVE DATE OF RULE] must be designed in 
accordance with this section.
    (1)(i) The ECCS system must be designed so that its calculated 
cooling performance following postulated LOCAs conforms to the criteria 
set forth in paragraph (b) of this section. ECCS cooling performance 
must be calculated

[[Page 67626]]

in accordance with an acceptable evaluation model and must be 
calculated for a number of postulated LOCAs of different sizes, 
locations, and other properties sufficient to provide assurance that 
the most severe postulated LOCAs are calculated. Except as provided in 
paragraph (a)(1)(ii) of this section, the evaluation model must include 
sufficient supporting justification to show that the analytical 
technique realistically describes the behavior of the reactor system 
during a LOCA. Comparisons to applicable experimental data must be made 
and uncertainties in the analysis method and inputs must be identified 
and assessed so that the uncertainty in the calculated results can be 
estimated. This uncertainty must be accounted for, so that, when the 
calculated ECCS cooling performance is compared to the criteria set 
forth in paragraph (b) of this section, there is a high level of 
probability that the criteria would not be exceeded. Appendix K, Part 
II Required Documentation, sets forth the documentation requirements 
for each evaluation model. This section does not apply to a nuclear 
power reactor facility for which the certifications required under 
Sec.  50.82(a)(1) have been submitted.
* * * * *
    4. Section 50.46a is redesignated as Sec.  50.46b.
    5. A new Sec.  50.46a is added to read as follows:


Sec.  50.46a  Alternative acceptance criteria for emergency core 
cooling systems for light-water nuclear power reactors.

    (a) Definitions. For the purposes of this section:
    (1) Evaluation model means the calculational framework for 
evaluating the behavior of the reactor system during a postulated 
design-basis loss-of-coolant accident (LOCA). It includes one or more 
computer programs and all other information necessary for application 
of the calculational framework to a specific LOCA, such as mathematical 
models used, assumptions included in the programs, procedure for 
treating the program input and output information, specification of 
those portions of analysis not included in computer programs, values of 
parameters, and all other information necessary to specify the 
calculational procedure.
    (2) Loss-of-coolant accidents (LOCAs) means the hypothetical 
accidents that would result from the loss of reactor coolant, at a rate 
in excess of the capability of the reactor coolant makeup system, from 
breaks in pipes in the reactor coolant pressure boundary up to and 
including a break equivalent in size to the double-ended rupture of the 
largest pipe in the reactor coolant system. LOCAs involving breaks at 
or below the transition break size (TBS) are considered design-basis 
accidents. LOCAs involving breaks larger than the TBS are considered 
beyond design-basis accidents.
    (3) Operating configuration means those plant characteristics, such 
as power level, equipment unavailability (including unavailability 
caused by corrective and preventive maintenance), and equipment 
capability that affect plant response to a LOCA.
    (4) Transition break size (TBS) is a break of area equal to the 
cross-sectional flow area of the inside diameter of specified piping 
for a specific reactor. The specified piping for a pressurized water 
reactor is the largest piping attached to the reactor coolant system. 
The specified piping for a boiling water reactor is the larger of the 
feedwater line inside containment or the residual heat removal line 
inside containment.
    (b) Applicability and scope. (1) The requirements of this section 
apply to each boiling or pressurized light-water nuclear power reactor 
fueled with uranium oxide pellets within cylindrical zircalloy or ZIRLO 
cladding for which a license to operate was issued prior to [EFFECTIVE 
DATE OF RULE], but do not apply to such a reactor for which the 
certification required under Sec.  50.82(a)(1) has been submitted.
    (2) The requirements of this section are in addition to any other 
requirements applicable to ECCS set forth in this part, with the 
exception of Sec.  50.46. The criteria set forth in paragraphs (e)(3) 
and (e)(4) of this section, with cooling performance calculated in 
accordance with an acceptable evaluation model or analysis method under 
paragraphs (e)(1) and (e)(2) of this section, are in implementation of 
the general requirements with respect to ECCS cooling performance 
design set forth in this part, including in particular Criterion 35 of 
Appendix A to this part.
    (c) Application. (1) A licensee voluntarily choosing to implement 
this section shall submit an application for a license amendment under 
Sec.  50.90 that contains the following information:
    (i) A description of the method(s) for demonstrating compliance 
with the ECCS criteria in paragraph (e) of this section;
    (ii) A description of the risk-informed integrated safety 
performance (RISP) assessment process to be used in evaluating whether 
proposed changes to the facility, technical specifications, or 
procedures meet the requirements in paragraph (f) of this section; 
including:
    (A) a description of the licensee's PRA model and non-PRA risk 
assessment methods demonstrating compliance with paragraphs (f)(4) and 
(f)(5) of this section, and
    (B) a description of the methods and decisionmaking process for 
evaluating compliance with the risk criteria, defense-in-depth 
criteria, safety margin criteria, and performance measurement criteria.
    (2) Acceptance criteria. The Commission may approve an application 
to use this section if:
    (i) The method(s) for demonstrating compliance with the ECCS 
acceptance criteria in paragraphs (e)(3) and (e)(4) of this section 
meet the requirements in paragraphs (e)(1) and (e)(2);
    (ii) The RISP assessment process (including any PRA model and other 
risk assessment methods) meets the requirements in paragraph (f) of 
this section; and
    (iii) The RISP assessment process ensures that changes made 
pursuant to paragraph (f)(1) are permitted under Sec.  50.59.
    (d) Requirements during operation. A licensee whose application 
under paragraph (c) of this section is approved by the NRC shall comply 
with the following requirements until the licensee submits the 
certifications required by Sec.  50.82(a):
    (1) The licensee shall maintain ECCS model(s) and/or analysis 
method(s) meeting the acceptance requirements in paragraphs (e)(1) and 
(e)(2) of this section,
    (2) For LOCAs larger than the TBS, the acceptance criteria in 
paragraph (e)(4) shall not be exceeded under any allowed at-power 
operating configurations analyzed under paragraph (e), and the plant 
may not be placed in any at-power operating configuration not addressed 
under paragraph (e) of this section.
    (3) The licensee shall evaluate any change to the facility as 
described in the FSAR, technical specifications, or procedures using 
the NRC-approved RISP assessment process and shall demonstrate that the 
acceptance criteria in paragraph (f) of this section are met.
    (4) The licensee shall implement adequate performance-measurement 
programs to ensure that the RISP assessment process reflects actual 
plant design and operation. These programs must meet the criteria in 
paragraph (f)(3)(iii) of this section.
    (5) The licensee shall periodically re-evaluate and update its risk 
assessments required under paragraph (c)(1)(ii) of this section to 
address changes to the

[[Page 67627]]

plant, operational practices, equipment performance, plant operational 
experience, and PRA model, and revisions in analysis methods, model 
scope, data, and modeling assumptions. The re-evaluation and updating 
must be completed in a timely manner, but no less often than once every 
two refueling outages. The updated risk assessments must continue to 
meet the requirements in paragraphs (f)(4) and (f)(5) of this section. 
Based upon the risk assessments, the licensee shall take appropriate 
action to ensure that facility design and operation continue to be 
consistent with the risk assessment assumptions used to meet the 
acceptance criteria in paragraphs (f)(1) or (f)(2) of this section, as 
applicable. The re-evaluation and updating required by this section, 
and any necessary changes to the facility, technical specifications and 
procedures as a result of this re-evaluation and updating, shall not be 
deemed to be backfitting under any provision of this chapter.
    (e) ECCS Performance. Each nuclear power reactor subject to this 
section must be provided with an ECCS that must be designed so that its 
ECCS calculated cooling performance following postulated LOCAs conforms 
to the criteria set forth in this section. The evaluation models for 
LOCAs involving breaks at or below the TBS must meet the criteria in 
this paragraph, and must be approved for use by the NRC. Appendix K, 
Part II, 10 CFR Part 50, sets forth the documentation requirements for 
evaluation models for LOCAs involving breaks at or below the TBS. The 
analysis methods for LOCAs involving breaks larger than the TBS must be 
maintained, available for inspection, and include the analytical 
approaches, equations, approximations and assumptions.
    (1) ECCS evaluation for LOCAs involving breaks at or below the TBS. 
ECCS cooling performance at or below the TBS must be calculated in 
accordance with an evaluation model that meets the requirements of 
either section I to Appendix K of this part, or the following 
requirements, and demonstrate that the acceptance criteria in paragraph 
(e)(3) of this section are satisfied. The evaluation model must be used 
for a number of postulated LOCAs of different sizes, locations, and 
other properties sufficient to provide assurance that the most severe 
postulated LOCAs involving breaks at or below the TBS are analyzed. The 
evaluation model must include sufficient supporting justification to 
show that the analytical technique realistically describes the behavior 
of the reactor system during a LOCA. Comparisons to applicable 
experimental data must be made and uncertainties in the analysis method 
and inputs must be identified and assessed so that the uncertainty in 
the calculated results can be estimated. This uncertainty must be 
accounted for, so that when the calculated ECCS cooling performance is 
compared to the criteria set forth in paragraph (e)(3) of this section, 
there is a high level of probability that the criteria would not be 
exceeded.
    (2) ECCS analyses for LOCAs involving breaks larger than the TBS. 
ECCS cooling performance for LOCAs involving breaks larger than the TBS 
must be calculated and must demonstrate that the acceptance criteria in 
paragraph (e)(4) of this section are satisfied. The analysis method 
must address the most important phenomena in analyzing the course of 
the accident. The evaluation must be performed for a number of 
postulated LOCAs of different sizes and locations sufficient to provide 
assurance that the most severe postulated LOCAs larger than the TBS up 
to the double-ended rupture of the largest pipe in the reactor coolant 
system are analyzed. Sufficient supporting justification, including the 
methodology used, must be available to show that the analytical 
technique reasonably describes the behavior of the reactor system 
during a LOCA from the TBS up to the double-ended rupture of the 
largest reactor coolant system pipe. Comparisons to applicable 
experimental data must be made. These calculations may take credit for 
the availability of offsite power and do not require the assumption of 
a single failure. Realistic initial conditions and availability of 
equipment may be assumed if supported by plant-specific data or 
analysis.
    (3) Acceptance criteria for LOCAs involving breaks at or below the 
TBS. The following acceptance criteria must be used in determining the 
acceptability of ECCS cooling performance:
    (i) Peak cladding temperature. The calculated maximum fuel element 
cladding temperature must not exceed 2200 [deg]F.
    (ii) Maximum cladding oxidation. The calculated total oxidation of 
the cladding must not at any location exceed 0.17 times the total 
cladding thickness before oxidation. As used in this paragraph, total 
oxidation means the total thickness of cladding metal that would be 
locally converted to oxide if all the oxygen absorbed by and reacted 
with the cladding locally were converted to stoichiometric zirconium 
dioxide. If cladding rupture is calculated to occur, the inside 
surfaces of the cladding must be included in the oxidation, beginning 
at the calculated time of rupture. Cladding thickness before oxidation 
means the radial distance from inside to outside the cladding, after 
any calculated rupture or swelling has occurred but before significant 
oxidation. Where the calculated conditions of transient pressure and 
temperature lead to a prediction of cladding swelling, with or without 
cladding rupture, the unoxidized cladding thickness must be defined as 
the cladding cross-sectional area, taken at a horizontal plane at the 
elevation of the rupture, if it occurs, or at the elevation of the 
highest cladding temperature if no rupture is calculated to occur, 
divided by the average circumference at that elevation. For ruptured 
cladding the circumference does not include the rupture opening.
    (iii) Maximum hydrogen generation. The calculated total amount of 
hydrogen generated from the chemical reaction of the cladding with 
water or steam must not exceed 0.01 times the hypothetical amount that 
would be generated if all of the metal in the cladding cylinders 
surrounding the fuel, excluding the cladding surrounding the plenum 
volume, were to react.
    (iv) Coolable geometry. Calculated changes in core geometry must be 
such that the core remains amenable to cooling.
    (v) Long term cooling. After any calculated successful initial 
operation of the ECCS, the calculated core temperature must be 
maintained at an acceptably low value and decay heat must be removed 
for the extended period of time required by the long-lived 
radioactivity remaining in the core.
    (4) Acceptance criteria for LOCAs involving breaks larger than the 
TBS. The following acceptance criteria must be used in determining the 
acceptability of ECCS cooling performance:
    (i) Coolable geometry. Calculated changes in core geometry must be 
such that the core remains amenable to cooling.
    (ii) Long term cooling. After any calculated successful initial 
operation of the ECCS, the calculated core temperature must be 
maintained at an acceptably low value and decay heat must be removed 
for the extended period of time required by the long-lived 
radioactivity remaining in the core.
    (5) Imposition of restrictions. The Director of the Office of 
Nuclear Reactor Regulation may impose restrictions on reactor operation 
if it is found that the evaluations of ECCS cooling performance 
submitted are not consistent with paragraph (e) of this section.

[[Page 67628]]

    (f) Changes to facility, technical specifications, or procedures. A 
licensee who wishes to make changes to the facility or procedures or to 
the technical specifications shall perform a RISP assessment.
    (1) The licensee may make such changes without prior NRC approval 
if:
    (i) The change is permitted under Sec.  50.59, and
    (ii) The RISP assessment demonstrates that any increases in the 
estimated risk are minimal compared to the overall plant risk profile, 
and the criteria in paragraph (f)(3) of this section are met.
    (2) For implementing changes which are not permitted under 
paragraph (f)(1) of this section, the licensee must submit an 
application for license amendment under Sec.  50.90. The application 
must contain:
    (i) The information required under Sec.  50.90;
    (ii) Information from the RISP assessment demonstrating that the 
total increases in core damage frequency and large early release 
frequency are small and the overall risk remains small, and the 
criteria in paragraph (f)(3) of this section are met; and
    (iii) Information demonstrating that the criteria in paragraphs 
(e)(3) and (e)(4) of this section are met.
    (3) All changes to a facility or procedures or to the technical 
specifications must meet the following criteria:
    (i) Defense in depth is maintained, in part, by assuring that:
    (A) Reasonable balance is provided among prevention of core damage, 
containment failure (early and late), and consequence mitigation;
    (B) System redundancy, independence, and diversity are provided 
commensurate with the expected frequency of postulated accidents, the 
consequences of those accidents, and uncertainties; and
    (C) Independence of barriers is not degraded;
    (ii) Adequate safety margins are retained to account for 
uncertainties; and
    (iii) Adequate performance-measurement programs are implemented to 
ensure the RISP assessment continues to reflect actual plant design and 
operation. These programs shall be designed to:
    (A) Detect degradation of the system, structure or component before 
plant safety is compromised,
    (B) Provide feedback of information and timely corrective actions, 
and
    (C) Monitor systems, structures or components at a level 
commensurate with their safety significance.
    (4) Requirements for risk assessment--PRA. To the extent that a PRA 
is used in the RISP assessment, the PRA must:
    (i) Address initiating events from sources both internal and 
external to the plant and for all modes of operation, including low 
power and shutdown modes, that would affect the regulatory decision in 
a substantial manner;
    (ii) Calculate CDF and LERF;
    (iii) Reasonably represent the current configuration and operating 
practices at the plant; and
    (iv) Have sufficient technical adequacy (including consideration of 
uncertainty) and level of detail to provide confidence that the total 
CDF and LERF and the change in total CDF and LERF adequately reflect 
the plant and the effect of the proposed change on risk.
    (5) Requirements for risk assessment other than PRA. To the extent 
that risk assessment methods other than PRAs are used to develop 
quantitative or qualitative estimates of changes to CDF and LERF in the 
RISP assessment, a licensee shall justify that the methods used produce 
realistic results.
    (g) Reporting. (1) Each licensee shall estimate the effect of any 
change to or error in evaluation models or analysis methods or in the 
application of such models or methods to determine if the change or 
error is significant. For each change to or error discovered in an ECCS 
evaluation model or analysis method or in the application of such a 
model that affects the calculated results, the licensee shall report 
the nature of the change or error and its estimated effect on the 
limiting ECCS analysis to the Commission at least annually as specified 
in Sec.  50.4. If the change or error is significant, the licensee 
shall provide this report within 30 days and include with the report a 
proposed schedule for providing a reanalysis or taking other action as 
may be needed to show compliance with Sec.  50.46a requirements. This 
schedule may be developed using an integrated scheduling system 
previously approved for the facility by the NRC. For those facilities 
not using an NRC-approved integrated scheduling system, a schedule will 
be established by the NRC staff within 60 days of receipt of the 
proposed schedule. Any change or error correction that results in a 
calculated ECCS performance that does not conform to the criteria set 
forth in paragraphs (e)(3) or (e)(4) of this section is a reportable 
event as described in Sec. Sec.  50.55(e), 50.72 and 50.73. The 
licensee shall propose immediate steps to demonstrate compliance or 
bring plant design or operation into compliance with Sec.  50.46a 
requirements. For the purpose of this paragraph, a significant change 
or error is:
    (i) For LOCAs involving pipe breaks at or below the TBS, one which 
results either in a calculated peak fuel cladding temperature different 
by more than 50 [deg]F from the temperature calculated for the limiting 
transient using the last acceptable model, or is a cumulation of 
changes and errors such that the sum of the absolute magnitudes of the 
respective temperature changes is greater than 50 [deg]F; or a change 
in the calculated oxidation, or the sum of the absolute value of the 
changes in calculated oxidation, equals or exceeds 0.4 percent 
oxidation; or
    (ii) For LOCAs involving pipe breaks larger than the TBS, one which 
results in a significant reduction in the capability to meet the 
requirements of paragraph (e)(4) of this section.
    (2) As part of the PRA update under paragraph (d)(5) of this 
section, the licensee shall report the change to the NRC if the change 
results in a significant reduction in the capability to meet the 
requirements in paragraph (f) of this section. The report must be filed 
with the NRC no more than 60 days after completing the PRA update and 
must include a description of the relevant PRA updates performed by the 
licensee, an explanation of the changes in the PRA modeling, plant 
design, or plant operation that led to the increase(s) in CDF or LERF 
after completing the PRA update, a description of any corrective 
actions required under paragraph (d)(5) of this section, and a schedule 
for implementation.
    (3) Every 24 months, the licensee shall submit, as specified in 
Sec.  50.4, a short description of all changes involving minimal 
changes in risk made under paragraph (f)(1) of this section since the 
last report.
    (h) Documentation of changes to facility, technical specification, 
and procedures. When making changes under paragraph (f) of this 
section, the licensee shall document the bases for demonstrating 
compliance with the acceptance criteria in paragraphs (f)(1) or (f)(2) 
and (f)(3) of this section. Upon the approval of the change under 
paragraph (f)(2) of this section or licensee implementation of the 
change under paragraph (f)(1) of this section, the licensee shall 
update the final safety analysis report in accordance with Sec.  
50.71(e).
    (i) through (l)--[RESERVED]
    (m) Changes to TBS. If the NRC increases the TBS specified in this 
section applicable to a licensee's nuclear power plant, each licensee 
subject to this section shall perform the

[[Page 67629]]

evaluations required by paragraphs (e)(1) and (e)(2) of this section 
and reconfirm compliance with the acceptance criteria in paragraphs 
(e)(3) and (e)(4) of this section. If the licensee cannot demonstrate 
compliance with the acceptance criteria, then the licensee shall change 
its facility, technical specifications or procedures so that the 
acceptance criteria are met. The evaluation required by this paragraph, 
and any necessary changes to the facility, technical specifications or 
procedures as the result of this evaluation, must not be deemed to be 
backfitting under any provision of this chapter.
    6. In Sec.  50.109, paragraph (b) is revised to read as follows:


Sec.  50.109  Backfitting.

* * * * *
    (b) Paragraph (a)(3) of this section shall not apply to:
    (1) Backfits imposed prior to October 21, 1985; and
    (2) Any changes made to the TBS specified in Sec.  50.46a or as 
otherwise applied to a licensee.
* * * * *
    7. In Appendix A to 10 CFR Part 50, under the heading, 
``CRITERIA,'' Criterion 17, 35, 38, 41, 44 and 50 are revised to read 
as follows:

Appendix A to Part 50--General Design Criteria for Nuclear Power Plants

* * * * *

Criteria

* * * * *
    Criterion 17--Electrical power systems. An on-site electric 
power system and an offsite electric power system shall be provided 
to permit functioning of structures, systems, and components 
important to safety. The safety function for each system (assuming 
the other system is not functioning) shall be to provide sufficient 
capacity and capability to assure that (1) specified acceptable fuel 
design limits and design conditions of the reactor coolant pressure 
boundary are not exceeded as a result of anticipated operational 
occurrences and (2) the core is cooled and containment integrity and 
other vital functions are maintained in the event of postulated 
accidents.
    The onsite electric power supplies, including the batteries, and 
the onsite electrical distribution system, shall have sufficient 
independence, redundancy and testability to perform their safety 
functions assuming a single failure, except for loss of coolant 
accidents involving pipe breaks larger than the transition break 
size under Sec.  50.46a, where a single failure of the onsite power 
supplies and electrical distribution system need not be assumed for 
plants under Sec.  50.46a.
    Electric power from the transmission network to the onsite 
electric distribution system shall be supplied by two physically 
independent circuits (not necessarily on separate rights of way) 
designed and located so as to minimize to the extent practical the 
likelihood of their simultaneous failure under operating and 
postulated accident conditions. A switchyard common to both circuits 
is acceptable. Each of these circuits shall be designed to be 
available in sufficient time following a loss of all onsite 
alternating current power supplies and the other offsite electric 
power circuit, to assure that specified acceptable fuel design 
limits and design conditions of the reactor coolant pressure 
boundary are not exceeded. One of these circuits shall be designed 
to be available within a few seconds following a LOCA to assure that 
core cooling, containment integrity, and other vital safety 
functions are maintained.
    Provisions shall be included to minimize the probability of 
losing electric power from any of the remaining supplies as a result 
of, or coincident with, the loss of power generated by the nuclear 
power unit, the loss of power from the transmission network, or the 
loss of power from the onsite electric power supplies.
* * * * *
    Criterion 35--Emergency core cooling. A system to provide 
abundant emergency core cooling shall be provided. The system safety 
function shall be to transfer heat from the reactor core following 
any loss of reactor coolant at a rate such that (1) fuel and clad 
damage that could interfere with continued effective core cooling is 
prevented and (2) clad metal-water reaction is limited to negligible 
amounts.
    Suitable redundancy in components and features, and suitable 
interconnections, leak detection, isolation, and containment 
capabilities shall be provided to assure that for onsite electric 
power system operation (assuming offsite power is not available) and 
for offsite electric power system operation (assuming onsite power 
is not available) the system safety function can be accomplished, 
assuming a single failure, except for loss of coolant accidents 
involving pipe breaks larger than the transition break size under 
Sec.  50.46a. For those accidents, a single failure need not be 
assumed and the unavailability of offsite power need not be assumed 
for onsite electric power system operation.
* * * * *
    Criterion 38--Containment heat removal. A system to remove heat 
from the reactor containment shall be provided. The system safety 
function shall be to reduce rapidly, consistent with the functioning 
of other associated systems, the containment pressure and 
temperature following any LOCA and maintain them at acceptably low 
levels.
    Suitable redundancy in components and features, and suitable 
interconnections, leak detection, isolation, and containment 
capabilities shall be provided to assure that for onsite electric 
power system operation (assuming offsite power is not available) and 
for offsite electric power system operation (assuming onsite power 
is not available) the system safety function can be accomplished, 
assuming a single failure, except for analysis of loss of coolant 
accidents involving pipe breaks larger than the transition break 
size under Sec.  50.46a, where a single failure and the 
unavailability of offsite power need not be assumed.
* * * * *
    Criterion 41--Containment atmosphere cleanup. Systems to control 
fission products, hydrogen, oxygen, and other substances which may 
be released into the reactor containment shall be provided as 
necessary to reduce, consistent with the functioning of other 
associated systems, the concentration and quality of fission 
products released to the environment following postulated accidents, 
and to control the concentration of hydrogen or oxygen and other 
substances in the containment atmosphere following postulated 
accidents to assure that containment integrity is maintained.
    Each system shall have suitable redundancy in components and 
features, and suitable interconnections, leak detection, isolation, 
and containment capabilities to assure that for onsite electric 
power system operation (assuming offsite power is not available) and 
for offsite electric power system operation (assuming onsite power 
is not available) its safety function can be accomplished, assuming 
a single failure, except for analysis of loss of coolant accidents 
involving pipe breaks larger than the transition break size under 
Sec.  50.46a, where a single failure and the unavailability of 
offsite power need not be assumed.
* * * * *
    Criterion 44--Cooling water. A system to transfer heat from 
structures, systems, and components important to safety, to an 
ultimate heat sink shall be provided. The system safety function 
shall be to transfer the combined heat load of these structures, 
systems, and components under normal operating and accident 
conditions.
    Suitable redundancy in components and features, and suitable 
interconnections, leak detection, and isolation capabilities shall 
be provided to assure that for onsite electric power system 
operation (assuming offsite power is not available) and for offsite 
electric power system operation (assuming onsite power is not 
available) the system safety function can be accomplished, assuming 
a single failure, except for analysis of loss of coolant accidents 
involving pipe breaks larger than the transition break size under 
Sec.  50.46a, where a single failure and the unavailability of 
offsite power need not be assumed.
* * * * *
    Criterion 50--Containment design basis. The reactor containment 
structure, including access openings, penetrations, and the 
containment heat removal system shall be designed so that the 
containment structure and its internal compartments can accommodate, 
without exceeding the design leakage rate and with sufficient 
margin, the calculated pressure and temperature conditions resulting 
from any loss-of-coolant accident. This margin shall reflect 
consideration of (1) the effects of potential energy sources which 
have not been included in the determination of the peak conditions, 
such as energy in steam generators and as required by Sec.  50.44 
energy from metal-water and other chemical reactions that may result 
from degradation but not total failure of

[[Page 67630]]

emergency core cooling functioning, (2) the limited experience and 
experimental data available for defining accident phenomena and 
containment responses, and (3) the conservatism of the calculational 
model and input parameters.
    For licensees voluntarily choosing to comply with Sec.  50.46a, 
the structural and leak tight integrity of the reactor containment 
structure, including access openings, penetrations, and its internal 
compartments, shall be maintained for realistically calculated 
pressure and temperature conditions resulting from any loss of 
coolant accident larger than the transition break size.
* * * * *

    Dated at Rockville, Maryland, this 28th day of October, 2005.

    For the Nuclear Regulatory Commission.
Annette L. Vietti-Cook,
Secretary of the Commission.

 [FR Doc. E5-6090 Filed 11-4-05; 8:45 am]
BILLING CODE 7590-01-P