[Federal Register Volume 71, Number 56 (Thursday, March 23, 2006)]
[Notices]
[Pages 14726-14745]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-2803]


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NUCLEAR REGULATORY COMMISSION


Notice of Availability of Model Application Concerning Technical 
Specifications for Boiling Water Reactor Plants to Risk-Inform 
Requirements Regarding Selected Required Action End States Using the 
Consolidated Line Item Improvement Process

AGENCY: Nuclear Regulatory Commission.

ACTION: Notice of availability.

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SUMMARY: Notice is hereby given that the staff of the Nuclear 
Regulatory Commission (NRC) has prepared a model application related to 
the revision of Boiling Water Reactor (BWR) plant required action end 
state requirements in technical specifications (TS). The purpose of 
this model is to permit the NRC to efficiently process amendments that 
propose to revise BWR TS required action end state requirements. 
Licensees of nuclear power reactors to which the model applies may 
request amendments utilizing the model application.

DATES: The NRC staff issued a Federal Register Notice (70 FR 74037, 
December 14, 2005) that provided a model safety evaluation (SE) and a 
model no significant hazards consideration (NSHC) determination 
relating to changing BWR TS required action end state requirements. The 
NRC staff hereby announces that the model SE and NSHC determination may 
be referenced in plant-specific applications to adopt the changes. The 
staff has posted a model application on the NRC Web site to assist 
licensees in using the consolidated line item improvement process 
(CLIIP) to revise the BWR TS required action end state requirements. 
The NRC staff can most efficiently consider applications based upon the 
model application if the application is submitted within a year of this 
Federal Register Notice.

FOR FURTHER INFORMATION CONTACT: T. R. Tjader, Mail Stop: O12H2, 
Division of Inspection and Regional Support, Office of Nuclear Reactor 
Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-
0001, telephone 301-415-1187.

SUPPLEMENTARY INFORMATION:

Background

    Regulatory Issue Summary 2000-06, ``Consolidated Line Item 
Improvement Process for Adopting Standard Technical Specification 
Changes for Power Reactors,'' was issued on March 20, 2000. The 
Consolidated Line Item Improvement Process (CLIIP) is intended to 
improve the efficiency of NRC licensing processes. This is accomplished 
by processing changes to the standard TS (STS) in a manner that 
supports subsequent license amendment applications. The CLIIP includes 
an opportunity for the public to comment on proposed changes to the STS 
following a preliminary safety assessment by the NRC staff and finding 
that the change will likely be offered for adoption by licensees. The 
CLIIP includes NRC staff evaluation of any comments received for a 
proposed change to the STS, and either a reconsideration of the change 
or an announcement of the availability of the change for adoption by 
licensees. Those licensees opting to apply for the subject change to 
their TS are responsible for reviewing the staff's evaluation, 
referencing the applicable technical justifications, and providing any 
necessary plant-specific information. Each amendment application made 
in response to the notice of availability will be processed and noticed 
in accordance with applicable rules and NRC procedures.
    This notice involves the revision of BWR TS required action end 
state requirements. This change was proposed for incorporation into the 
STS by participants in the Owners Groups Technical Specification Task 
Force (TSTF) and is designated TSTF-423, Revision 0. TSTF-423, as well 
as the NRC staff's safety evaluation and model application, may be 
examined, and/or copied for a fee, at the NRC's Public Document Room, 
located at One White Flint North, 11555 Rockville Pike (first floor), 
Rockville, Maryland. Publicly available records are accessible 
electronically from the ADAMS Public Library component on the NRC Web 
site, (the Electronic Reading Room). TSTF-423, the NRC staff's safety 
evaluation, and the model application, can be viewed on the NRC Web 
site at: (http://www.nrc.gov/reactors/operating/licensing/
techspecs.html).

Applicability

    This proposal to modify technical specification requirements by the 
adoption of TSTF-423 is applicable to all licensees of BWR plants who 
have adopted or will adopt, in conjunction with the change, technical 
specification requirements for a Bases control program consistent with 
the TS Bases Control Program described in Section 5.5 of the BWR STS. 
Licensees that have not adopted requirements for a Bases control 
program by converting to the improved STS or by other means, are 
requested to include the requirements

[[Page 14727]]

for a Bases control program consistent with the STS in their 
application for the change. The need for a Bases control program stems 
from the need for adequate regulatory control of some key elements of 
the proposal that are contained in the Bases in TSTF-423. The staff is 
requesting that the Bases changes be included with the proposed license 
amendments consistent with the Bases in TSTF-423, prior to implementing 
TSTF-423. To ensure that the overall change, including the Bases, 
includes appropriate regulatory controls, the staff plans to condition 
the issuance of each license amendment on the licensee's incorporation 
of the changes into the Bases document and on requiring the licensee to 
control the changes in accordance with the Bases Control Program. The 
CLIIP does not prevent licensees from requesting an alternative 
approach or proposing the changes without the requested Bases and Bases 
control program. However, deviations from the approach recommended in 
this notice may require additional review by the NRC staff and may 
increase the time and resources needed for the review. Significant 
variations from the approach, or inclusion of additional changes to the 
license, will result in staff rejection of the submittal. Instead, 
licensees desiring significant variations and/or additional changes 
should submit a LAR that does not claim to adopt TSTF-423.

Public Notices

    In a notice in the Federal Register dated December 14, 2005 (70 FR 
74037), the staff requested comment on the use of the CLIIP to process 
requests to revise the BWR TS regarding required action end state 
requirements, designated as TSTF-423.
    In response to the notice soliciting comments from interested 
members of the public about modifying the TS requirements regarding 
revising required action end state requirements, the staff received one 
set of comments (from the Owners Groups TSTF, representing licensees). 
Specific comments on the model SE were offered, and are summarized and 
discussed below:
    1. Comment: We commend the staff for adopting a draft Safety 
Evaluation format that simplifies the application of the model Safety 
Evaluation for TSTF-423 to individual licensees. For example, providing 
blanks for plant name, operating license number, etc. We encourage the 
staff to follow this example for future CLIIP model Safety Evaluations.
    Response: The NRC staff acknowledges the comment; no action taken.
    2. Comment: The ``Applicability'' portion of the notice states that 
each licensee applying for the changes proposed in TSTF-423 should 
include Bases for the proposed Technical Specifications (TS) consistent 
with the Bases proposed in TSTF-423. We request that the section be 
revised to not require licensees to submit Bases changes. The Bases 
changes in TSTF-423 are not integral to the change and both licensee 
and NRC resources could be saved by allowing licensees to adopt the 
necessary Bases changes using the Technical Specifications Bases 
Control Program. As a precedent, the CLIIP for TSTF-460 (Notice of 
Availability published in the Federal Register on August 23, 2004) 
allowed licensees to commit to updating their TS Bases under the TS 
Bases Control Program instead of requiring licensees to submit their 
Bases changes for NRC review. We propose that the TSTF-423 CLIIP take a 
similar approach.
    Response: The NRC staff does not agree with the comment. The 
associated TS Bases changes are an essential and integral element of 
the change, must be consistent with the Bases in TSTF-423, and should 
be submitted by the licensees with the license amendment request for 
adoption of TSTF-423.
    3. Comment: Section 1.0 of the model Safety Evaluation, in the 
first paragraph, states that TSTF-423 was proposed by the Nuclear 
Energy Institute Risk Informed Technical Specification Task Force. That 
is incorrect. TSTF-423, Revision 0, was submitted by the Owners Group 
Technical Specifications Task Force in a letter to the NRC dated August 
12, 2003.
    Response: The NRC staff agrees with the comment. The correction has 
been made.
    4. Comment: Section 1.0 of the model Safety Evaluation, the last 
sentence of section, states, ``Short duration repairs are on the order 
of 2-to-3 days, but not more than a week.'' We recommend replacing this 
sentence with the statement from the Implementation Guidance (TSTF-IG-
05-02), which states, ``A `short duration' is envisioned to be the 
duration that boiling water reactors (BWRs) are most physically and 
practicably able to remain in the hot shutdown condition (i.e., from a 
few days to approximately one week).'' This clarifies that the time 
frames are a statement of fact rather than a restriction which must be 
incorporated in plant operating controls.
    Response: The NRC staff does not agree with the comment. This issue 
was discussed thoroughly and the one week limit was determined 
appropriate. The one week limit is explicitly stated in the 
Implementation Guidance (Reference 8 to the SE) submitted by industry, 
agreed to by the NRC staff, and to which the licensees must commit. 
Section 1 paragraph 6 of the Implementation Guidance (TSTF-IG-05-02) 
states, ``Any entry into Mode 3 using this TS allowance must be limited 
to no more than seven days.'' No action has been taken.
    5. Comment: In Section 3.2, ``Assessment of TS Changes,'' of the 
model Safety Evaluation, each subsection is titled with the applicable 
Topical Report section number and the ITS LCO number. The abbreviation 
``TS'' is used to indicate the Topical Report section number (e.g., 
``TS 4.5.1.2 and LCO 3.4.3 (BWR/4); TS 4.5.2.2 and LCO 3.4.4 (BWR/6), 
Safety/Relief Valves (SRVs).'' The labels ``4.5.1.2'' and ``4.5.2.2'' 
are the Topical Report sections associated with these LCO changes. 
These references also appear in the text of Section 3.2. This 
presentation is confusing as ``TS'' is defined in the model Safety 
Evaluation as ``Technical Specifications'' and non-ITS plants have 
Technical Specification requirements with numbers similar to the 
Topical Report numbers. We recommend replacing this use of the 
abbreviation ``TS'' with either ``Topical Report section'' or defining 
another acronym, such as ``TR.''
    Response: The NRC staff agrees with the comment. The abbreviation 
for the Topical Report Section was poorly chosen, in that it was easily 
confused with the abbreviation for Technical Specification. The Topical 
Report Section abbreviation has been changed to ``TRS.''
    6. Comment: In Section 3.2.4 of the model Safety Evaluation, in the 
title and in the first paragraph, the LCO name ``Low-Low Set Logic 
(LLS) Valves'' is used. The word ``logic'' should not appear in the LCO 
name. The document should be revised to state ``Low-Low Set (LLS) 
Valves.''
    Response: The NRC staff agrees with the comment. The correction has 
been made.
    7. Comment: Section 5.0, ``Environmental Consideration,'' of the 
model Safety Evaluation states that the amendments meet the eligibility 
criteria for categorical exclusion set forth in ``10 CFR 51.22(c)(9) 
[and (c)(10)].'' 10 CFR 51.22(c)(10) pertains to issuance of an 
amendment pursuant to ``parts 30, 31, 32, 33, 34, 35, 36, 39, 40, 50, 
60, 61, 70 or part 72 of this chapter which (i) changes surety, 
insurance and/or indemnity requirements, or (ii) changes

[[Page 14728]]

recordkeeping, reporting, or administrative procedures or 
requirements.'' Paragraph (c)(10) is not applicable to this change and 
the reference should be deleted.
    Response: The NRC staff agrees with the comment. The correction has 
been made.
    8. Comment: Section 7.0, ``References,'' of the model Safety 
Evaluation, Reference 1, states the date of NEDC-32988-A, Revision 2, 
as September 2005. The correct date of the document is December 2002.
    Response: The NRC staff agrees with the comment. The correction has 
been made.
    The NRC staff has made editorial changes to the previously 
published model SE related to TSTF-423 resulting from the disposition 
of comments 3, 5, 6, 7, and 8. The staff finds that technically the 
previously published SE remains unaltered. Below are the republished 
model SE and model NSHC determination (previously published in the 
Federal Register; 70 FR 23238, December 14, 2005), and the model 
application prepared by the staff that licensees may reference in their 
plant-specific applications.

    Dated at Rockville, Maryland, this 16th day of March 2006.

    For the Nuclear Regulatory Commission.
Thomas H. Boyce,
Branch Chief, Technical Specifications Branch, Division of Inspection 
and Regional Support, Office of Nuclear Reactor Regulation.

Model Plant Specific Safety Evaluation for Technical Specification Task 
Force (TSTF) Change TSTF-423, Risk Informed Modification to Selected 
Required Action End States, a Consolidated Line Item Improvement

U.S. Nuclear Regulatory Commission, Safety Evaluation by the Office of 
Nuclear Reactor Regulation Related to Amendment No. [------] to 
Facility Operating License NFP-[----[lowbarm]] [Utility Name] [Plant 
Name], [Unit ------] Docket No. -[----]

1.0 Introduction

    By letter dated ----------, 20--, [Utility Name] (the licensee) 
proposed changes to the technical specifications (TS) for [plant name]. 
The requested changes are the adoption of TSTF-423, Revision 0, to the 
Boiling Water Reactor (BWR) Standard Technical Specifications (STS) 
(NUREG 1433 and NUREG 1434), which was proposed by the Owners Groups 
Technical Specifications Task Force (TSTF) on August 12, 2003, on 
behalf of the industry. TSTF-423, Revision 0, incorporates the BWR 
Owners Group (BWROG) approved Topical Report NEDC-32988, Revision 2, 
``Technical Justification to Support Risk Informed Modification to 
Selected Required Action End States for BWR Plants'' (Reference 1), 
into the BWR STS (NOTE: The changes in TSTF-423 are made with respect 
to Revision 2 of the BWR STS NUREGs).
    TSTF-423 is one of the industry's initiatives developed under the 
Risk Management Technical Specifications (RMTS) program. These 
initiatives are intended to maintain or improve safety through the 
incorporation of risk assessment and management techniques in TS, while 
reducing unnecessary burden and making TS requirements consistent with 
the Commission's other risk-informed regulatory requirements, in 
particular the maintenance rule.
    The Code of Federal Regulations, 10 CFR 50.36, ``Technical 
Specifications,'' states: ``When a limiting condition for operation of 
a nuclear reactor is not met, the licensee shall shut down the reactor 
or follow the remedial action permitted by the technical specification 
until the condition can be met.'' The STS and most plant TS provide a 
completion time (CT) for the plant to meet the limiting condition for 
operation (LCO). If the LCO or the remedial action cannot be met, then 
the reactor is required to be shut down. When the STS and individual 
plant technical specifications were written, the shutdown condition or 
end state specified was usually cold shutdown.
    Topical Report NEDC-32988, Revision 2, provides the technical basis 
to change certain required end states when the TS Actions for remaining 
in power operation cannot be met within the CTs. Most of the requested 
TS changes permit an end state of hot shutdown (Mode 3), if risk is 
assessed and managed, rather than an end state of cold shutdown (Mode 
4) contained in the current TS. The request was limited to those end 
states where: (1) entry into the shutdown mode is for a short interval, 
(2) entry is initiated by inoperability of a single train of equipment 
or a restriction on a plant operational parameter, unless otherwise 
stated in the applicable TS, and (3) the primary purpose is to correct 
the initiating condition and return to power operation as soon as is 
practical.
    The STS for BWR plants define five operational modes. In general, 
they are:
     Mode 1--Power Operation. The reactor mode switch is in run 
position.
     Mode 2--Reactor Startup. The reactor mode switch is in 
refuel position (with all reactor vessel head closure bolts fully 
tensioned) or in startup/hot standby position.
     Mode 3--Hot Shutdown. The reactor coolant system (RCS) 
temperature is above 200 degrees F (TS specific) and the reactor mode 
switch is in shutdown position (with all reactor vessel head closure 
bolts fully tensioned).
     Mode 4--Cold Shutdown. The RCS temperature is equal to or 
less than 200 degrees F and the reactor mode switch is in shutdown 
position (with all reactor vessel head closure bolts fully tensioned).
     Mode 5--Refueling. The reactor mode switch is in shutdown 
or refuel position, and one or more reactor vessel head closure bolts 
are less than fully tensioned.
    Criticality is not allowed in Modes 3 through 5.
    TSTF-423 generally allows a Mode 3 end state rather than a Mode 4 
end state for selected initiating conditions in order to perform short-
duration repairs which necessitate exiting the original Mode of 
operation. Short duration repairs are on the order of 2-to-3 days, but 
not more than a week.

2.0 Regulatory Evaluation

    In 10 CFR 50.36, the Commission established its regulatory 
requirements related to the content of TS. Pursuant to 10 CFR 50.36(c), 
TS are required to include items in the following five specific 
categories related to station operation: (1) Safety limits, limiting 
safety system settings, and limiting control settings; (2) limiting 
conditions for operation (LCOs); (3) surveillance requirements (SRs); 
(4) design features; and (5) administrative controls. The rule does not 
specify the particular requirements to be included in a plant's TS. As 
stated in 10 CFR 50.36(c)(2)(i), the ``Limiting conditions for 
operation are the lowest functional capability or performance levels of 
equipment required for safe operation of the facility. When a limiting 
condition for operation of a nuclear reactor is not met, the licensee 
shall shut down the reactor or follow any remedial action permitted by 
the technical specifications * * *.''
    Reference 1 states: ``Cold shutdown is normally required when an 
inoperable system or train cannot be restored to an operable status 
within the allowed time. Going to cold shutdown results in the loss of 
steam-driven systems, challenges the shutdown heat removal systems, and 
requires restarting the plant. A more preferred operational mode is one 
that maintains adequate risk levels while repairs are completed without 
causing unnecessary challenges to plant equipment during shutdown and 
startup transitions.'' In the end state changes under consideration 
here, a problem

[[Page 14729]]

with a component or train has or will result in a failure to meet a TS, 
and a controlled shutdown has begun because a TS Action requirement 
cannot be met within the TS CT.
    Most of today's TS and the design basis analyses were developed 
under the perception that putting a plant in cold shutdown would result 
in the safest condition and the design basis analyses would bound 
credible shutdown accidents. In the late 1980s and early 1990s, the NRC 
and licensees recognized that this perception was incorrect and took 
corrective actions to improve shutdown operation. At the same time, 
standard TS were developed and many licensees improved their TS. Since 
enactment of a shutdown rule was expected, almost all TS changes 
involving power operation, including a revised end state requirement, 
were postponed (see, for example the Final Policy Statement on TS 
Improvements, Reference 2). However, in the mid 1990s, the Commission 
decided a shutdown rule was not necessary in light of industry 
improvements.
    Controlling shutdown risk encompasses control of conditions that 
can cause potential initiating events and responses to those initiating 
events that do occur. Initiating events are a function of equipment 
malfunctions and human error. Responses to events are a function of 
plant sensitivity, ongoing activities, human error, defense-in-depth, 
and additional equipment malfunctions.
    In practice, the risk during shutdown operations is often addressed 
via voluntary actions and application of 10 CFR 50.65 (Reference 3), 
the maintenance rule. Section 50.65(a)(4) states: ``Before performing 
maintenance activities * * * the licensee shall assess and manage the 
increase in risk that may result from the proposed maintenance 
activities. The scope of the assessment may be limited to structures, 
systems, and components that a risk-informed evaluation process has 
shown to be significant to public health and safety.'' Regulatory Guide 
(RG) 1.182 (Reference 4) provides guidance on implementing the 
provisions of 10 CFR 50.65(a)(4) by endorsing the revised Section 11 
(published separately) to NUMARC 93-01, Revision 2. The revised Section 
11 of NUMARC 93-01, Revision 2, was subsequently incorporated into 
Revision 3 of NUMARC 93-01 (Reference 5). However, Revision 3 has not 
yet been formally endorsed by the NRC. The changes in TSTF-423 are 
consistent with the rules, regulations and associated regulatory 
guidance, as noted above.

3.0 Technical Evaluation

    The changes proposed in TSTF-423 are consistent with the changes 
proposed and justified in Topical Report GE NEDC-32988-A, Revision 2, 
(Reference 1) and approved by the associated NRC SE (Reference 6). The 
evaluation included in Reference 6, as appropriate and applicable to 
the changes of TSTF-423 (Reference 7), is reiterated here and 
differences from the SE are justified. In its application the licensee 
commits to TSTF-IG-05-02, Implementation Guidance for TSTF-423, 
Revision 0, ``Technical Specifications End States, NEDC-32988-A,'' 
(Reference 8), which addresses a variety of issues such as 
considerations and compensatory actions for risk-significant plant 
configurations. An overview of the generic evaluation and associated 
risk assessment is provided below, along with a summary of the 
associated TS changes justified by Reference 1.
3.1 Risk Assessment
    The objective of the BWROG topical report (Reference 1) risk 
assessment was to show that any risk increases associated with the 
changes in TS end states are either negligible or negative (i.e., a net 
decrease in risk).
    The BWROG topical report documents a risk-informed analysis of the 
proposed TS change. Probabilistic Risk Assessment (PRA) results and 
insights are used, in combination with results of deterministic 
assessments, to identify and propose changes in ``end states'' for all 
BWR plants. This is in accordance with guidance provided in RG 1.174 
(Reference 9) and RG 1.177 (Reference 10). The three-tiered approach 
documented in RG 1.177, ``An Approach for Plant-Specific, Risk-Informed 
Decision Making: Technical Specifications,'' was followed. The first 
tier of the three-tiered approach includes the assessment of the risk 
impact of the proposed change for comparison to acceptance guidelines 
consistent with the Commission's Safety Goal Policy Statement, as 
documented in RG 1.174. The first tier aims at ensuring that there are 
no unacceptable temporary risk increases as a result of the TS change, 
such as when equipment is taken out of service. The second tier 
addresses the need to preclude potentially high-risk configurations 
which could result if equipment is taken out of service concurrently 
with the equipment out of service as allowed by this TS change. The 
third tier addresses the application of 10 CFR 50.65(a)(4) of the 
Maintenance Rule for identifying risk-significant configurations 
resulting from maintenance related activities and taking appropriate 
compensatory measures to avoid such configurations. This TS invokes a 
risk assessment because 10 CFR 50.65(a)(4) is applicable to maintenance 
related activities and does not cover other operational activities 
beyond the effect they may have on existing maintenance related risk.
    BWROG's risk assessment approach was found comprehensive and 
acceptable in the SE for the topical report. In addition, the analyses 
show that the three-tiered approach criteria for allowing TS changes 
are met as follows:
     Risk Impact of the Proposed Change (Tier 1). The risk 
changes associated with the TS changes in TSTF-423, in terms of mean 
yearly increases in core damage frequency (CDF) and large early release 
frequency (LERF), are risk neutral or risk beneficial. In addition, 
there are no significant temporary risk increases, as defined by RG 
1.177 criteria, associated with the implementation of the TS end state 
changes.
     Avoidance of Risk-Significant Configurations (Tier 2). The 
performed risk analyses, which are based on single LCOs, shows that 
there are no high-risk configurations associated with the TS end state 
changes. The reliability of redundant trains is normally covered by a 
single LCO. When multiple LCOs occur, which affect trains in several 
systems, the plant's risk-informed configuration risk management 
program (CRMP), or the risk assessment and management program 
implemented in response to the Maintenance Rule 10 CFR 50.65(a)(4), 
shall ensure that high-risk configurations are avoided. As part of the 
implementation of TSTF-423, the licensee has committed to follow 
Section 11 of NUMARC 93-01, Revision 3, and include guidance in 
appropriate plant procedures and/or administrative controls to preclude 
high-risk plant configurations when the plant is at the proposed end 
state. The staff finds that such guidance is adequate for preventing 
risk-significant plant configurations.
     Configuration Risk Management (Tier 3). The licensee has a 
program, as described above, in place to comply with 10 CFR 50.65(a)(4) 
to assess and manage the risk from maintenance activities. This program 
can support a licensee decision in selecting the appropriate actions to 
control risk for most cases in which a risk-informed TS is entered.
    The generic risk impact of the end state mode change was evaluated 
subject to the following assumptions

[[Page 14730]]

which are incorporated into the TS, TS Bases, and TSTF-IG-05-02 
(Reference 8):
    1. The entry into the end state is initiated by the inoperability 
of a single train of equipment or a restriction on a plant operational 
parameter, unless otherwise stated in the applicable technical 
specification.
    2. The primary purpose of entering the end state is to correct the 
initiating condition and return to power as soon as is practical.
    3. When Mode 3 is entered as the repair end state, the time the 
reactor coolant pressure is above 500 psig will be minimized. If 
reactor coolant pressure is above 500 psig for more than 12 hours, the 
associated plant risk will be assessed and managed.
    These assumptions are consistent with typical entries into Mode 3 
for short duration repairs, which is the intended use of the TS end 
state changes.
    The staff concludes that, in general, going to Mode 3 (hot 
shutdown) instead of going to Mode 4 (cold shutdown) to carry out 
equipment repairs that are of short duration, does not have any adverse 
effect on plant risk.
3.2 Assessment of TS Changes
    The changes proposed by the licensee and in TSTF-423 are consistent 
with the changes in topical report GE NEDC-32988 (Reference 1), and 
approved by the NRC SE (Reference 6). The following are the changes, 
including a synopsis of the STS LCO, and a conclusion of acceptability.
    3.2.1 Topical Report Section (TRS) 4.5.1.2 and LCO 3.4.3 (BWR/4); 
TRS 4.5.2.2 and LCO 3.4.4 (BWR/6), Safety/Relief Valves (SRVs).
    The function of the SRVs is to protect the plant against severe 
overpressurization events. These TS provide the operability 
requirements for the SRVs as described below. The TS change allows the 
plant to remain in Mode 3 until the repairs are completed.

    [Note:
    Plant Applicability, BWR4/6]

    LCO: The safety function of 11 SRVs must be operable (BWR/4 
plants). The safety function of seven SRVs must be operable and the 
relief function of seven additional SRVs must be operable (BWR/6 
plants).
    Condition requiring entry into end state: If the LCO cannot be met 
with one or two SRVs inoperable, the inoperable valves must be returned 
to operability within 14 days. If the SRVs cannot be returned to 
operable status within that time, the plant must be placed in Mode 3 
within 12 hours and in Mode 4 within 36 hours.
    Modification for end state required actions: If the LCO cannot be 
met with one or two SRVs inoperable, the inoperable valves must be 
returned to operability within 14 days. If the one or two inoperable 
SRVs cannot be returned to operable status within 14 days, the plant 
must be placed in Mode 3 within 12 hours. If three or more SRVs become 
inoperable, the plant must be placed in Mode 4 within 36 hours.
    Assessment: The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and in the Mode 3 end state. The evaluation indicates that the 
core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 
for one inoperable SRV would cause loss of the high-pressure steam-
driven injection system (reactor core isolation cooling (RCIC)/high 
pressure coolant injection (HPCI)), and loss of the power conversion 
system (condenser/feedwater), and require activating the residual heat 
removal (RHR) system. In addition, emergency operating procedures 
(EOPs) direct the operator to take control of the depressurization 
function if low pressure injection/spray systems are needed for reactor 
pressure vessel (RPV) water makeup and cooling. Based on the low 
probability of loss of the necessary overpressure protection function 
and the number of systems available in Mode 3, the staff concluded in 
the SE (reference 6) for the BWROG topical report that the risks of 
staying in Mode 3 are approximately the same as, and in some cases 
lower than, the risks of going to the Mode 4 end state. The change 
allows the inoperable SRV to be repaired in a plant operating mode with 
lower risks. After repairs are made, the plant can be brought to full-
power operation with less potential for transients and errors. The 
plant is taken into cold shutdown only when three or more SRVs are 
inoperable.
    Finding: Based on the above assessment, and because the time spent 
in Mode 3 to perform the repair is infrequent and limited, and in light 
of defense-in-depth considerations (discussed in Reference 1), the 
staff finds that the requested change to allow operation in Mode 3 with 
a minimum number of SRVs inoperable, after plant risk has been assessed 
and managed, is acceptable.
    3.2.2 TRS 4.5.1.3 and LCO 3.5.1(BWR/4); TRS 4.5.2.3 and LCO 3.5.1 
(BWR/6), Emergency Core Cooling Systems (ECCS) (Operating).
    The ECCS systems provide cooling water to the core in the event of 
a loss-of-coolant accident (LOCA). This set of ECCS TS provide the 
operability requirements for the various ECCS subsystems as described 
below. This TS change would delete the secondary actions. The plant can 
remain in Mode 3 until the required repair actions are completed. The 
reactor is not depressurized.

    [Note:
    Plant Applicability, BWR4/6]

    LCO: Each ECCS injection/spray subsystem and the automatic 
depressurization system (ADS) function of seven BWR/4, or eight BWR/6, 
SRVs must be operable.
    Conditions requiring entry into end state: If the LCO cannot be 
met, the following actions must be taken for the listed conditions:
    a. If one low-pressure ECCS injection/spray subsystem is 
inoperable, the subsystem must be restored to operable status in 7 
days.
    b. If the inoperable ECCS injection/core spray cannot be restored 
to operable status, the plant must be placed in Mode 3 within 12 hours 
and Mode 4 within 36 hours (BWR/4 plants only).
    c. If two ECCS injection subsystems are inoperable or one ECCS 
injection subsystem and one ECCS spray system are inoperable, one ECCS 
injection/spray subsystem must be restored to operable status within 72 
hours. If this required action cannot be met, the plant must be placed 
in Mode 3 within 12 hours and in Mode 4 within 36 hours (BWR/6 plants 
only).
    d. If the HPCI/High Pressure Core Spray (HPCS) system is 
inoperable, the RCIC system must be verified to be operable by 
administrative means within 1 hour and the HPCI/HPCS system restored to 
operable status within 14 days.
    e. If one ADS valve is inoperable, it must be restored to operable 
status within 14 days.
    f. If one ADS valve is inoperable and one low-pressure ECCS 
injection/spray subsystem is inoperable, the ADS valve must be restored 
to operable status within 72 hours or the low-pressure ECCS injection/
spray subsystem must be restored to operable status within 72 hours.
    g. If two or more ADS valves become inoperable, or the required 
actions described in items e and/or f cannot be met, the plant must be 
placed in Mode 3 within 12 hours and the reactor steam dome pressure 
reduced to less than 150 psig within 36 hours.

Modification for End State Required Actions:

    a. No change
    b. If the ECCS injection or spray system is inoperable, the plant 
must be

[[Page 14731]]

restored to operable status within 12 hours. The plant is not taken 
into Mode 4 (cold shutdown).
    c. If two ECCS injection subsystems are inoperable or one ECCS 
injection subsystem and one ECCS spray system are inoperable, one ECCS 
injection/spray subsystem must be restored to operable status within 72 
hours. If this required action cannot be met, the plant must be placed 
in Mode 3 within 12 hours. The plant is not taken into Mode 4 (BWR/6 
plants only).
    d. No change
    e. No change
    f. No change
    g. If two or more ADS valves become inoperable or the required 
actions described in item e and/or f cannot be met, the plant must be 
placed in Mode 3 within 12 hours. The reactor is not depressurized and 
not taken to Mode 4.
    Assessment: The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and the Mode 3 end state. The evaluation indicates that the core 
damage risks are lower in Mode 3 than in the current end state Mode 4. 
Going to Mode 4 for one ECCS subsystem or one ADS valve would cause 
loss of the high-pressure steam-driven injection system (RCIC/HPCI), 
and loss of the power conversion system (condenser/feedwater), and 
require activating the RHR system. In addition, Plant Emergency 
Operating Procedures (EOPs) direct the operator to take control of the 
depressurization function if low-pressure injection/spray systems are 
needed for RPV water makeup and cooling. Based on the low probability 
of loss of the reactor coolant inventory and the number of systems 
available in Mode 3, the staff concludes in the SE to the BWR topical 
report that the risks of staying in Mode 3 are approximately the same 
as, and in some cases lower than, the risks of going to the Mode 4 end 
state.
    Finding: Based on the above assessment, and because the time spent 
in Mode 3 to perform the repair is infrequent and limited, and in light 
of defense-in-depth considerations (discussed in Reference 1), the 
change is acceptable.
    3.2.3 TRS 4.5.1.4 and LCO 3.5.3 (BWR/4 only), Reactor Core 
Isolation Cooling (RCIC) System.
    The function of the RCIC system is to provide reactor coolant 
makeup during loss of feedwater and other transient events. This TS 
provides the operability requirements for the RCIC system as described 
below. The TS change allows the plant to remain in Mode 3 until the 
repairs are completed.

    [Note:
    Plant Applicability, BWR/4]

    LCO: The RCIC system must be operable during Modes 1, 2 and 3 when 
the reactor steam dome pressure is greater than 150 psig.
    Condition requiring entry into end state: If the LCO cannot be met, 
the following actions must be taken: (a) Verify by administrative means 
within 1 hour that the HPCI system is operable, (b) restore the RCIC 
system to operable status within 14 days. If either or both actions 
cannot be completed within the allotted time, the plant must be placed 
in Mode 3 within 12 hours and the reactor steam dome pressure reduced 
to less than 150 psig within 36 hours.
    Modification for end state required actions: This TS change keeps 
the plant in Mode 3 (hot shutdown) until the required repairs are 
completed. The reactor steam dome pressure is not reduced to less than 
150 psig.
    Assessment: This change would allow the inoperable RCIC system to 
be repaired in a plant operating mode with lower risk and without 
challenging the normal shutdown systems. The BWROG topical report did a 
comparative PRA evaluation of the core damage risks of operation in the 
current end state and in the Mode 3 end state. The evaluation indicates 
that the core damage risks are lower in Mode 3 than in Mode 4. Going to 
Mode 3 with reactor steam dome pressure less than 150 psig for 
inoperability of RCIC would also cause loss of the high-pressure steam-
driven injection system HPCI and loss of the power conversion system 
(condenser/ feedwater), and would require activating the RHR system. In 
addition, Plant EOPs direct the operator to take control of the 
depressurization function if low pressure injection/spray systems are 
needed for RPV water makeup and cooling. Based on the low probability 
of loss of the necessary overpressure protection function and the 
number of systems available in Mode 3, the staff concludes in the SE to 
the BWR topical report that the risks of staying in Mode 3 are 
approximately the same as, and in some cases lower than, the risks of 
going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.4 TRS 4.5.1.6 and LCO 3.6.1.6 (BWR/4); TRS 5.5.2.5 and LCO 
3.6.1.6 (BWR/6), Low-Low Set (LLS) Valves.
    The function of LLS is to prevent excessive short-duration SRV 
cycling during an overpressure event. This TS provides operability 
requirements for the four LLS SRVs as described below. The TS change 
allows the plant to remain in Mode 3 until the repairs are completed.

    [Note:
    Plant Applicability, BWR 4/6]

    Conditions requiring entry into end state: If one LLS valve is 
inoperable, it must be returned to operability within 14 days. If the 
LLS valve cannot be returned to operable status within the allotted 
time, the plant must be placed in Mode 3 within 12 hours and in Mode 4 
within 36 hours.
    Modification for end state required actions: The TS change would 
keep the plant in Mode 3 until the required repair actions are 
completed. The plant would not be taken into Mode 4 (cold shutdown).
    Assessment: The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and the Mode 3 end state. The evaluation indicates that the core 
damage risks are lower in Mode 3 than in Mode 4, the current end state. 
Going to Mode 4 for one LLS inoperable SRV would cause loss of the 
high-pressure steam-driven injection system (RCIC/HPCI), and loss of 
the power conversion system (condenser/feedwater), and would require 
activating the RHR system. With one LLS valve inoperable, the remaining 
valves are adequate to perform the required function. EOPs direct the 
operator to take control of the depressurization function if low 
pressure injection/spray systems are needed for RPV water makeup and 
cooling. Based on the low probability of loss of the necessary 
overpressure protection function during the infrequent and limited time 
in Mode 3 and the number of systems available in Mode 3, the staff 
concludes in the SE to the BWR topical report that the risks of staying 
in Mode 3 are approximately the same as and in some cases lower than 
the risks of going to the Mode 4 end state. The change allows repairs 
of the inoperable SRV to be performed in a plant operating mode with 
lower risks.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.5 TRS 4.5.1.1, TRS 4.5.2.1 and LCO 3.3.8.2, Reactor Protection 
System (RPS) Electric Power Monitoring.
    RPS Electric Power Monitoring System is provided to isolate the RPS 
bus from the motor generator (MG) set or an alternate power supply in 
the event of over voltage, under voltage, or under frequency. This 
system protects

[[Page 14732]]

the load connected to the RPS bus against unacceptable voltage and 
frequency conditions and forms an important part of the primary success 
path of the essential safety circuits. Some of the essential equipment 
powered from the RPS buses includes the RPS logic, scram solenoids, and 
various valve isolation logic. The TS change allows the plant to remain 
in Mode 3 until the repairs are completed.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2, 3 and Modes 4 and 5 (with any control rod 
withdrawn from a core cell containing one or more fuel assemblies), two 
RPS electric power monitoring assemblies shall be operable for each in-
service RPS motor generator set or alternate power supply.
    Condition Requiring Entry into End State: If the LCO cannot be met, 
the associated in-service power supply(s) must be removed from service 
within 72 hours for one Electric Power Assembly (EPA) inoperable or 
within one hour for both EPAs inoperable. In Modes 1, 2, and 3, if the 
in-service power supply(s) cannot be removed from service within the 
allotted time, the plant must be placed in Mode 3 within 12 hours and 
Mode 4 within 36 hours.
    Modification: The change is to keep the plant in Mode 3 until the 
repair actions are completed. Delete required action in C.2 which 
required the plant to be in Mode 4.
    Assessment: To reach Mode 3 per the TS, there must be a functioning 
power supply with degraded protective circuitry in operation. However, 
the over voltage, under voltage, or under frequency condition must 
exist for an extended time period to cause damage. There is a low 
probability of this occurring in the short period of time that the 
plant would remain in Mode 3 without this protection.
    The specific failure condition of interest is not risk significant 
for BWR PRAs. If the required restoration actions cannot be completed 
within the specified time, going into Mode 4 would cause loss of the 
high-pressure steam-driven injection system (RCIC/HPCI) and loss of the 
power conversion system (condenser/feedwater), and would require 
activating the RHR system. In addition, EOPs direct the operator to 
take control of the depressurization function if low pressure 
injection/spray systems are needed for RPV water makeup and cooling. 
Based on the low probability of loss of the RPS power monitoring system 
during the infrequent and limited time in Mode 3 and the number of 
systems available in Mode 3, the staff concludes in the SE to the BWR 
topical report that the risks of staying in Mode 3 are approximately 
the same as and in some cases lower than the risks of going to the Mode 
4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.6 TRS 4.5.1.19 and LCO 3.8.1(BWR/4); TRS 4.5.2.17 and LCO 
3.8.1(BWR/6), AC Sources (Operating).
    The purpose of the AC electrical system is to provide during all 
situations the power required to put and maintain the plant in a safe 
condition and prevent the release of radioactivity to the environment.
    The Class 1E electrical power distribution system AC sources 
consist of the offsite power source (preferred power sources, normal 
and alternate(s)), and the onsite standby power sources (e.g., 
emergency diesel generators (EDGs)). In addition, many sites provide a 
crosstie capability between units.
    As required by General Design Criterion (GDC) 17 of 10 CFR Part 50, 
Appendix A, the design of the AC electrical system provides 
independence and redundancy. The onsite Class 1E AC distribution system 
is divided into redundant divisions so that the loss of any one 
division does not prevent the minimum safety functions from being 
performed. Each division has connections to two preferred offsite power 
sources and a single EDG or other Class 1E Standby AC power source.
    Offsite power is supplied to the unit switchyard(s) from the 
transmission network by two transmission lines. From the switchyard(s), 
two electrically and physically separated circuits provide AC power 
through a stepdown transformer(s) to the 4.16-kV emergency buses.
    In the event of a loss of offsite power, the emergency electrical 
loads are automatically connected to the EDGs in sufficient time to 
provide for a safe reactor shutdown and to mitigate the consequence of 
a design basis accident (DBA) such as a LOCA.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: The following AC electrical power sources shall be operable in 
Modes 1, 2, and 3:
    a. Two qualified circuits between the offsite transmission network 
and the onsite Class1E AC Electric Power Distribution System,
    b. Three EDGs,
    c. Automatic Load Sequencers.
    Condition requiring entry into end state: Plant operators must 
bring the plant to Mode 4 within 36 hours following the sustained 
inoperability of one required Automatic Load Sequencer; either or both 
required offsite circuits; either one, two or three required EDGs; or 
one required offsite circuit and one, two or three required EDGs.
    Modification for end state require actions: Delete required action 
G.2 to go to Mode 4 (cold shutdown). The plant will remain in Mode 3 
(hot shutdown).
    Assessment: Entry into any of the conditions for the AC power 
sources implies that the AC power sources have been degraded and the 
single failure protection for the safe shutdown equipment may be 
ineffective. Consequently, as specified in TS 3.8.1 at present, the 
plant operators must bring the plant to Mode 4 when the required action 
is not completed by the specified time for the associated action.
    The BWROG topical report did a comparative PRA evaluation of the 
core damage risks of operation in the current end state and in the Mode 
3 end state. Events initiated by the loss of offsite power are dominant 
contributors to core damage frequency in most BWR PRAs, and the steam-
driven core cooling systems, RCIC and HPCI, play a major role in 
mitigating these events. The evaluation indicates that the core damage 
risks are lower in Mode 3 than in Mode 4 for one inoperable AC power 
source. Going to Mode 4 for one inoperable AC power source would cause 
loss of the high-pressure steam-driven injection system (RCIC/HPCI), 
and loss of the power conversion system (condenser/feedwater), and 
require activating the RHR system. In addition, EOPs direct the 
operator to take control of the depressurization function if low 
pressure injection/spray systems are needed for RPV water makeup and 
cooling. Based on the low probability of loss of the AC power and the 
number of steam-driven systems available in Mode 3, the staff concludes 
in the SE to the BWR topical report that the risks of staying in Mode 3 
are lower than going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.7 TRS 4.5.1.20 and LCO 3.8.4 (BWR/4); TRS 4.5.2.18 and LCO 
3.8.4 DC Sources (Operating).
    The purpose of the DC power system is to provide a reliable source 
of DC power for both normal and abnormal conditions. It must supply 
power in an emergency for an adequate length of

[[Page 14733]]

time until normal supplies can be restored.
    The DC electrical system:
    a. Provides the AC emergency power system with control power,
    b. Provides motive and control power to selected safety related 
equipment, and
    c. Provides power to preferred AC vital buses (via inverters).

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2 and 3, the following DC sources are required to 
be operable: BWR/4: The (Division 1 and Division 2 station service, and 
DG 1B, 2A, and 2C) DC electrical power systems shall be operable.
    BWR/6: The (Divisions 1, 2, and 3) DC electrical power subsystems 
shall be operable.
    Condition requiring entry into end state: The plant operators must 
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours 
following the sustained inoperability of one DC electrical power 
subsystem for a period of 2 hours.
    Modification for end state required actions: The TS change is to 
remove the requirement to place the plant in Mode 4, Required Actions 
in D.2 (BWR/4) and E.2 (BWR/6) are deleted.
    Assessment: If one of the DC electrical power subsystems is 
inoperable, the remaining DC electrical power subsystems have the 
capacity to support a safe shutdown and to mitigate an accident 
condition. The BWROG topical report did a comparative PRA evaluation of 
the core damage risks of operation in the current end state and in the 
Mode 3 end state, with one DC system inoperable. Events initiated by 
the loss of offsite power are dominant contributors to core damage 
frequency in most BWR PRAs, and the steam-driven core cooling systems, 
RCIC and HPCI, play a major role in mitigating these events. The 
evaluation indicates that the core damage risks are lower in Mode 3 
than in Mode 4. Going to Mode 4 for one inoperable DC power source 
would cause loss of the high-pressure steam-driven injection system 
(RCIC/HPCI), and loss of the power conversion system (condenser/
feedwater), and require activating the RHR system. In addition, EOPs 
direct the operator to take control of the depressurization function if 
low pressure injection/spray systems are needed for RPV water makeup 
and cooling. Based on the low probability of loss of the DC power and 
the number of systems available in Mode 3, the staff concludes in the 
SE to the BWR topical report that the risks of staying in Mode 3 are 
approximately the same as and in some cases lower than the risks of 
going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.8 TRS 4.5.1.21 and LCO 3.8.7 (BWR/4); TRS 4.5.2.19 and 3.8.7 
(BWR/6), Inverters (Operating).
    In Modes 1,2,and 3, the inverters provide the preferred source of 
power for the 120-VAC vital buses which power the reactor protection 
system (RPS) and the Emergency Core Cooling Systems (ECCS) initiation. 
The inverter can be powered from an internal AC source/rectifier or 
from the station battery.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2, and 3 the following Inverters shall be 
operable:
    BWR/4: The (Division 1 and Division 2) shall be operable.
    BWR/6: The (Divisions 1, 2, and 3) shall be operable.
    Condition requiring entry into end state: The plant operators must 
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours 
following the sustained inoperability of the required inverter for a 
period of 24 hours.
    Modification for end state required actions: The TS change is to 
remove the requirement to place the plant in Mode 4. Required Actions 
in B.2 (BWR/4) and C.2 (BWR/6) are deleted.
    Assessment: If one of the Inverters is inoperable, the remaining 
Inverters have the capacity to support a safe shutdown and to mitigate 
an accident condition. The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and in the Mode 3 end state, with an inoperable Inverter. Events 
initiated by the loss of offsite power are dominant contributors to 
core damage frequency in most BWR PRAs, and the steam-driven core 
cooling systems, RCIC and HPCI, play a major role in mitigating these 
events. The evaluation indicates that the core damage risks are lower 
in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable Inverter 
power source would cause loss of the high-pressure steam-driven 
injection system (RCIC/HPCI), and loss of the power conversion system 
(condenser/feedwater), and require activating the RHR system. In 
addition, EOPs direct the operator to take control of the 
depressurization function if low pressure injection/spray systems are 
needed for RPV water makeup and cooling. Based on the low probability 
of loss of the Inverters during the infrequent and limited time in Mode 
3 and the number of systems available in Mode 3, the staff concludes in 
the SE to the BWR topical report that the risks of staying in Mode 3 
are approximately the same as and in some cases lower than the risks of 
going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.9 TRS 4.5.1.22 and LCO 3.8.9 (BWR/4); TRS 4.5.2.20 and LCO 
3.8.9 (BWR/6), Distribution Systems(Operating).
    The onsite Class 1E AC and DC electrical power distribution system 
is divided into redundant and independent AC, DC, and AC vital bus 
electrical power distribution systems. The primary AC electrical power 
distribution subsystem for each division consists of a 4.16-kV 
Engineered Safety Feature (ESF) bus having an offsite source of power 
as well as a dedicated onsite EDG source. The secondary plant 
distribution subsystems include 600-VAC emergency buses and associated 
load centers, motor control centers, distribution panels and 
transformers. The 120-VAC vital buses are arranged in four load groups 
and normally powered from DC via the inverters. There are two 
independent 125/250-VDC station service electrical power distribution 
systems and three independent 125-VDC DG electrical power distribution 
subsystems that support the necessary power for ESF functions. Each 
subsystem consists of a 125-VDC and 250-VDC bus and associated 
distribution panels.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: For Modes 1,2, and 3, the following electrical power 
distribution subsystems shall be operable:
    BWR/4: The Division 1 and Division 2 AC, DC, and AC vital buses 
shall be operable.
    BWR/6: The Divisions 1, 2, and 3 AC, DC, and AC vital buses shall 
be operable.
    Condition requiring entry into end state: The plant operators must 
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours 
following the sustained inoperability of one AC or one DC or one AC 
vital bus electrical power subsystem for a period of 8 hours, 2 hours 
and 2 hours, respectively (with a maximum 16 hour Completion Time limit 
from initial discovery of failure to

[[Page 14734]]

meet the LCO, to preclude being in the LCO indefinitely).
    Modification for end state required actions: The TS change is to 
remove the requirement to place the plant in Mode 4, Required Action in 
D.2 (BWR/4) and D.2 (BWR/6) are deleted.
    Assessment: If one of the AC/DC/AC vital subsystems is inoperable, 
the remaining AC/DC/AC vital subsystems have the capacity to support a 
safe shutdown and to mitigate an accident condition. The BWROG topical 
report did a comparative PRA evaluation of the core damage risks of 
operation in the current end state and in the Mode 3 end state, with 
one of the AC/DC/AC vital subsystems inoperable. Events initiated by 
the loss of offsite power are dominant contributors to core damage 
frequency in most BWR PRAs, and the steam-driven core cooling systems, 
RCIC and HPCI, play a major role in mitigating these events. The 
evaluation indicates that the core damage risks are lower in Mode 3 
than in Mode 4. Going to Mode 4 for one inoperable AC/DC/AC vital 
subsystem would cause loss of the high-pressure steam-driven injection 
system (RCIC/HPCI), and loss of the power conversion system (condenser/
feedwater), and require activating the RHR system. In addition, EOPs 
direct the operator to take control of the depressurization function if 
low pressure injection/spray systems are needed for RPV water makeup 
and cooling. Based on the low probability of loss of the AC/DC/AC vital 
electrical subsystems during the infrequent and limited time in Mode 3 
and the number of systems available in Mode 3, the staff concludes in 
the SE to the BWR topical report that the risks of staying in Mode 3 
are approximately the same as and in some cases lower than the risks of 
going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.10 TRS 4.5.1.5 and LCO 3.6.1.1, Primary Containment.
    The function of the primary containment is to isolate and contain 
fission products released from the Reactor Primary System following a 
design basis LOCA and to confine the postulated release of 
radioactivity. The primary containment consists of a steel-lined, 
reinforced concrete vessel, which surrounds the Reactor Primary System 
and provides an essentially leak-tight barrier against an uncontrolled 
release of radioactivity to the environment. Additionally, this 
structure provides shielding from the fission products that may be 
present in the primary containment atmosphere following accident 
conditions.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: The primary containment shall be operable.
    Condition Requiring Entry into End State: If the LCO cannot be met, 
the primary containment must be returned to operability within one hour 
(Required Action A.1). If the primary containment cannot be returned to 
operable status within the allotted time, the plant must be placed in 
Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 
hours (Required Action B.2).
    Modification for End State Required Actions: Delete Required Action 
B.2.
    Assessment: The primary containment is one of the three primary 
boundaries to the release of radioactivity. (The other two are the fuel 
cladding and the Reactor Primary System pressure boundary.) Compliance 
with this LCO ensures that a primary containment configuration exists, 
including equipment hatches and penetrations, that is structurally 
sound and will limit leakage to those leakage rates assumed in the 
safety analyses. This LCO entry condition does not include leakage 
through an unisolated release path. The BWROG topical report has 
determined that previous generic PRA work related to Appendix J 
requirements has shown that containment leakage is not risk 
significant. Should a fission product release from the primary 
containment occur, the secondary containment and related functions 
would remain operable to contain the release, and the standby gas 
treatment system would remain available to filter fission products from 
being released to the environment. By remaining in Mode 3, HPCI, RCIC, 
and the power conversion system (condensate/feedwater) remain available 
for water makeup and decay heat removal. Additionally, the EOPs direct 
the operators to take control of the depressurization function if low 
pressure injection/spray are needed for reactor coolant makeup and 
cooling. Therefore, defense-in-depth is maintained with respect to 
water makeup and decay heat removal by remaining in Mode 3.
    Finding: The requested change is acceptable. Note that the staff's 
approval relies upon the secondary containment and the standby gas 
treatment system for maintaining defense-in-depth while in this reduced 
end state.
    3.2.11 TRS 4.5.1.7 and LCO 3.6.1.7, Reactor Building-to-Suppression 
Chamber Vacuum Breakers(BWR/4 only).
    The reactor building-to-suppression chamber vacuum breakers relieve 
vacuum when the primary containment depressurizes below the pressure of 
the reactor building, thereby serving to preserve the integrity of the 
primary containment.

    [Note:
    Plant Applicability, BWR/4]

    LCO: Each reactor building-to-suppression chamber vacuum breaker 
shall be operable.
    Condition Requiring Entry into End State: If one line has one or 
more reactor building-to-suppression chamber vacuum breakers inoperable 
for opening, the breaker(s) must be returned to operability within 72 
hours (Required Action C.1). If the vacuum breaker(s) cannot be 
returned to operability within the allotted time, the plant must be 
placed in Mode 3 within 12 hours (Required Action E.1) and in Mode 4 
within 36 hours (Required Action E.2).
    Modification for End State Required Actions: Modify the Required 
Actions so that if vacuum breaker(s) cannot be returned to operable 
status within the required Completion Times, the plant is place in hot 
shutdown. That is, modify Condition E to relate only to Condition C, 
delete Required Action E.2, and add Condition F, with Required Actions 
F.1 and F.2, shutting down the plant to Mode 3 and then Mode 4 
respectively, to address an inability to comply with the required 
actions related to the other Conditions (i.e., Conditions A, B, and D).
    Assessment: The BWROG topical report has determined that the 
specific failure condition of interest is not risk significant in BWR 
PRAs. The reduced end state would only be applicable to the situation 
where the vacuum breaker(s) in one line are inoperable for opening, 
with the remaining operable vacuum breakers capable of providing the 
necessary vacuum relief function. The existing end state remains 
unchanged, as established by new Condition F, for conditions involving 
more than one inoperable line or vacuum breaker since they are needed 
in Modes 1, 2, and 3. In Mode 3, for other accident considerations, 
HPCI, RCIC, and the power conversion system (condensate/feedwater) 
remain available for water makeup and decay heat removal. Additionally, 
the EOPs direct the operators to take control of the depressurization 
function if low pressure injection/spray are needed for reactor coolant 
makeup and cooling. Therefore, defense-in-depth is maintained with 
respect to water

[[Page 14735]]

makeup and decay heat removal by remaining in Mode 3.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.12 TRS 4.5.1.8 and LCO 3.6.1.8, Suppression Chamber-to-Drywell 
Vacuum Breakers(BWR/4 only).
    The function of the suppression chamber-to-drywell vacuum breakers 
is to relieve vacuum in the drywell, thereby preventing an excessive 
negative differential pressure across the wetwell/drywell boundary.

    [Note:
    Plant Applicability, BWR/4]

    LCO: Nine suppression chamber-to-drywell vacuum breakers shall be 
operable for opening.
    Condition Requiring Entry into End State: If one suppression 
chamber-to-drywell vacuum breaker is inoperable for opening, the 
breaker must be returned to operability within 72 hours (Required 
Action A.1). If the vacuum breaker cannot be returned to operability 
within the allotted time, the plant must be placed in Mode 3 within 12 
hours (Required Action C.1) and in Mode 4 within 36 hours (Required 
Action C.2).
    Modification for End State Required Actions: Modify the Required 
Actions so that if vacuum breaker(s) cannot be returned to operable 
status within the required Completion Times, the plant is placed in hot 
shutdown. That is, modify Condition C to relate only to Condition A, 
and delete Required Action C.2, and add Condition D, with Required 
Actions D.1 and D.2, shutting down the plant to Mode 3 and then Mode 4 
respectively, to address an inability to comply with the required 
actions related to Condition B, to close the vacuum breaker.
    Assessment: The BWROG topical report has determined that the 
specific failure of interest is not risk significant in BWR PRAs. The 
reduced end state would only be applicable to the situation where one 
suppression chamber-to-drywell vacuum breaker is inoperable for 
opening, with the remaining operable vacuum breakers capable of 
providing the necessary vacuum relief function, since they are required 
in Modes 1, 2, and 3. By remaining in Mode 3, HPCI, RCIC, and the power 
conversion system (condensate/feedwater) remain available for water 
makeup and decay heat removal. Additionally, the EOPs direct the 
operators to take control of the depressurization function if low 
pressure injection/spray are needed for RCS makeup and cooling. 
Therefore, defense-in-depth is maintained with respect to water makeup 
and decay heat removal by remaining in Mode 3. The existing end state 
remains unchanged for conditions involving any suppression chamber-to-
drywell vacuum breakers that are stuck open, as established by new 
Condition D.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.13 TRS 4.5.1.9, TRS 4.5.2.8, and LCO 3.6.1.9, Main Steam 
Isolation Valve (MSIV) Leakage Control System (LCS).
    The MSIV LCS supplements the isolation function of the MSIVs by 
processing the fission products that could leak through the closed 
MSIVs after core damage, assuming leakage rate limits which are based 
on a large LOCA.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: Two MSIV LCS subsystems shall be operable.
    Condition Requiring Entry into End State: If one MSIV LCS subsystem 
is inoperable, it must be restored to operable status within 30 days 
(Required Action A.1). If both MSIV LCS subsystems are inoperable, one 
of the MSIV LCS subsystems must be restored to operable status within 
seven days (Required Action B.1). If the MSIV LCS subsystems cannot be 
restored to operable status within the allotted time, the plant must be 
placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 
within 36 hours (Required Action C.2).
    Modification for End State Required Actions: Delete Required Action 
C.2.
    Assessment: The BWROG topical report has determined that this 
system is not significant in BWR PRAs and, based on a BWROG program, 
many plants have eliminated the system altogether. The unavailability 
of one or both MSIV LCS subsystems has no impact on CDF or LERF, 
irrespective of the mode of operation at the time of the accident. 
Furthermore, the challenge frequency of the MSIV LCS system (i.e., the 
frequency with which the system is expected to be challenged to 
mitigate offsite radiation releases resulting from MSIV leaks above TS 
limits) is less than 1.0E-6/yr. Consequently, the conditional 
probability that this system will be challenged during the repair time 
interval while the plant is at either the current or the proposed end 
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This 
probability is considerably smaller than probabilities considered 
``negligible'' in Regulatory Guide 1.177 for much higher consequence 
risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.1.9, TRS 4.5.2.8, and LCO 3.6.1.9, ``Main Steam 
Isolation Valve (MSIV) Leakage Control System (LCS).'' The argument for 
staying in Mode 3 instead of going to Mode 4 to repair the MSIV LCS 
system (one or both trains) is also supported by defense-in-depth 
considerations. Section 6.2 makes a comparison between the Mode 3 and 
the Mode 4 end state, with respect to the means available to perform 
critical functions (i.e., functions contributing to the defense-in-
depth philosophy) whose success is needed to prevent core damage and 
containment failure and mitigate radiation releases. The risk and 
defense-in-depth arguments, used according to the ``integrated 
decision-making'' process of Regulatory Guides 1.174 and 1.177, support 
the conclusion that the plant in Mode 3 is as safe as Mode 4 (if not 
safer) for repairing an inoperable MSIV LCS system. Personnel safety 
must be considered separately.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.14 TRS 4.5.1.11 and LCO 3.6.2.4, Residual Heat Removal (RHR) 
Suppression Pool Spray(BWR/4 only).
    Following a DBA, the RHR suppression pool spray system removes heat 
from the suppression chamber airspace. A minimum of one RHR suppression 
pool spray subsystem is required to mitigate potential bypass leakage 
paths from drywell and maintain the primary containment peak pressure 
below the design limits.

    [Note:
    Plant Applicability, BWR/4]

    LCO: Two RHR suppression pool spray subsystems shall be operable.
    Condition Requiring Entry into End State: If one RHR suppression 
pool spray subsystem is inoperable (Condition A), it must be restored 
to operable status within seven days (Required Action A.1). If both RHR 
suppression pool spray subsystems are inoperable (Condition B), one of 
them must be restored to operable status within eight hours (Required 
Action B.1). If the RHR suppression pool spray subsystem cannot be 
restored to operable status within the allotted time, the plant must be 
placed in Mode 3 within 12 hours (Required Action C.1),

[[Page 14736]]

and in Mode 4 within 36 hours (Required Action C.2).
    Modification for End State Required Actions: Delete Required Action 
C.2.
    Assessment: The main function of the RHR suppression spray system 
is to remove heat from the suppression chamber so that the pressure and 
temperature inside primary containment remain within analyzed design 
limits. The RHR suppression spray system was designed to mitigate 
potential effects of a postulated DBA, that is, a large LOCA which is 
assumed to occur concurrently with the most limiting single failure and 
conservative inputs, such as for initial suppression pool water volume 
and temperature. Under the conditions assumed in the DBA, steam blown 
down from the break could bypass the suppression pool and end up in the 
suppression chamber air space and the RHR suppression spray system 
could be needed to condense such steam so that the pressure and 
temperature inside primary containment remain within analyzed design 
basis limits. However, the frequency of a DBA is very small and the 
containment has considerable margin to failure above the design limits. 
For these reasons, the unavailability of one or both RHR suppression 
spray subsystems has no significant impact on CDF or LERF, even for 
accidents initiated during operation at power. Therefore, it is very 
unlikely that the RHR suppression spray system will be challenged to 
mitigate an accident occurring during power operation. This probability 
becomes extremely unlikely for accidents that would occur during a 
small fraction of the year (less than three days) during which the 
plant would be in Mode 3 (associated with lower initial energy level 
and reduced decay heat load as compared to power operation) to repair 
the failed RHR suppression spray system.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.1.11 and LCO 3.6.2.4, ``Residual Heat Removal (RHR) 
Suppression Pool Spray.'' The argument for staying in Mode 3 instead of 
going to Mode 4 to repair the RHR Suppression Pool Spray system (one or 
both trains) is also supported by defense-in-depth considerations. 
Section 6.2 makes a comparison between the Mode 3 and the Mode 4 end 
state, with respect to the means available to perform critical 
functions (i.e., functions contributing to the defense-in-depth 
philosophy) whose success is needed to prevent core damage and 
containment failure and mitigate radiation releases, and precluding the 
need for RHR suppression spray subsystems.
    In addition, the probability of a DBA (large break) is much smaller 
during shutdown as compared to power operation. A DBA in Mode 3 would 
be considerably less severe than a DBA occurring during power operation 
since Mode 3 is associated with lower initial energy level and reduced 
decay heat load. Under these extremely unlikely conditions, an 
alternate method that can be used to remove heat from the primary 
containment (in order to keep the pressure and temperature within the 
analyzed design basis limits) is containment venting. For more 
realistic accidents that could occur in Mode 3, several alternate means 
are available to remove heat from the primary containment, such as the 
RHR system in the suppression pool cooling mode and the containment 
spray mode.
    The risk and defense-in-depth arguments, used according to the 
``integrated decision-making'' process of Regulatory Guides 1.174 and 
1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not 
safer) for repairing an inoperable RHR suppression spray system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.15 TRS 4.5.1.12, TRS 4.5.2.10, and LCO 3.6.4.1, Secondary 
Containment.
    Following a DBA, the function of the secondary containment is to 
contain, dilute, and stop radioactivity (mostly fission products) that 
may leak from primary containment. Its leak tightness is required to 
ensure that the release of radioactivity from the primary containment 
is restricted to those leakage paths and associated leakage rates 
assumed in the accident analysis and that fission products entrapped 
within the secondary containment structure will be treated by the 
standby gas treatment system prior to discharge to the environment.

    [Note:
     Plant Applicability, BWR 4/6]

    LCO: The secondary containment shall be operable.
    Condition Requiring Entry into End State: If the secondary 
containment is inoperable, it must be restored to operable status 
within four hours (Required Action A.1). If it cannot be restored to 
operable status within the allotted time, the plant must be placed in 
Mode 3 within 12 hours (Required Action B.1), and in Mode 4 within 36 
hours (Required Action B.2).
    Modification for End State Required Actions: Delete Required Action 
B.2.
    Assessment: This LCO entry condition does not include gross leakage 
through an unisolable release path. The BWROG topical report has 
determined that previous generic PRA work related to Appendix J 
requirements has shown that containment leakage is not risk 
significant. The primary containment, and all other primary and 
secondary containment-related functions would still be operable, 
including the standby gas treatment system, thereby minimizing the 
likelihood of an unacceptable release. By remaining in Mode 3, HPCI, 
RCIC, and the power conversion system (condensate/feedwater) remain 
available for water makeup and decay heat removal. Additionally, the 
EOPs direct the operators to take control of the depressurization 
function if low pressure injection/spray are needed for RCS makeup and 
cooling. Therefore, defense-in-depth is improved with respect to water 
makeup and decay heat removal by remaining in Mode 3.
    Finding: The requested change is acceptable. Note that the staff's 
approval relies upon the primary containment, and all other primary and 
secondary containment-related functions, to still be operable, 
including the standby gas treatment system, for maintaining defense-in-
depth while in this end state.
    3.2.16 TRS 4.5.1.13, TRS 4.5.2.11, and LCO 3.6.4.3, Standby Gas 
Treatment (SGT) System.
    The function of the SGT system is to ensure that radioactive 
materials that leak from the primary containment into the secondary 
containment following a DBA are filtered and adsorbed prior to 
exhausting to the environment.
    Applicability: BWR4/6.
    LCO: Two SGT subsystems shall be operable.
    Condition Requiring Entry into End State: If one SGT subsystem is 
inoperable, it must be restored to operable status within seven days 
(Required Action A.1). If the SGT subsystem cannot be restored to 
operable status within the allotted time, the plant must be placed in 
Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 
hours (Required Action B.2). In addition, if two SGT subsystems are 
inoperable in Mode 1, 2, or 3, LCO 3.0.3 must be entered immediately 
(Required Action D.1).
    Modification for End State Required Actions: Delete Required Action 
B.2. Change Required Action D.1 to ``Be in Mode 3'' with a Completion 
Time of ``12 hours.''

[[Page 14737]]

    Assessment: The unavailability of one or both SGT subsystems has no 
impact on CDF or LERF, irrespective of the mode of operation at the 
time of the accident. Furthermore, the challenge frequency of the SGT 
system (i.e., the frequency with which the system is expected to be 
challenged to mitigate offsite radiation releases resulting from 
materials that leak from the primary to the secondary containment above 
TS limits) is less than 1.0E-6/yr. Consequently, the conditional 
probability that this system will be challenged during the repair time 
interval while the plant is at either the current or the proposed end 
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This 
probability is considerably smaller than probabilities considered 
``negligible'' in Regulatory Guide 1.177 for much higher consequence 
risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.1.13, TRS 4.5.2.11, and LCO 3.6.4.3, ``Standby Gas 
Treatment (SGT) System.'' The argument for staying in Mode 3 instead of 
going to Mode 4 to repair the SGT system (one or both trains) is also 
supported by defense-in-depth considerations. Section 6.2 makes a 
comparison between the Mode 3 and the Mode 4 end state, with respect to 
the means available to perform critical functions (i.e., functions 
contributing to the defense-in-depth philosophy) whose success is 
needed to prevent core damage and containment failure and mitigate 
radiation releases. The risk and defense-in-depth arguments, used 
according to the ``integrated decision-making'' process of Regulatory 
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe 
as Mode 4 (if not safer) for repairing an inoperable SGT system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.17 TRS 4.5.1.14 and LCO 3.7.1, Residual Heat Removal Service 
Water (RHRSW) System (BWR/4 only).
    The RHRSW system is designed to provide cooling water for the RHR 
system heat exchangers, which are required for safe shutdown following 
a normal shutdown or DBA or transient.

    [Note:
     Plant Applicability, BWR/4]

    LCO: Two RHRSW subsystems shall be operable.
    Condition Requiring Entry into End State: If the LCO cannot be met, 
the following actions must be taken for the listed conditions:
    a. If one RHRSW pump is inoperable (Condition A), it must be 
restored to operable status within 30 days (Required Action A.1).
    b. If one RHRSW pump in each subsystem is inoperable (Condition B), 
one RHRSW pump must be restored to operable status within seven days 
(Required Action B.1).
    c. If one RHRSW subsystem is inoperable for reasons other than 
Condition A (Condition C), the RHRSW subsystem must be restored to 
operable status within seven days (Required Action C.1).
    d. If the required action and associated completion time cannot be 
met within the allotted time (Condition E), the plant must be placed in 
Mode 3 within 12 hours (Required Action E.1) and in Mode 4 within 36 
hours (Required Action E.2). {Note: Condition D addresses both RHRSW 
subsytems inoperable for reason other than Condition B, and its 
Required Action D.1 is not affected by this change.
    Modification for End State Required Actions: Renumber Conditions D 
(and Required Action D.1), and E (and Required Actions E.1 and E.2), to 
Conditions E (and Required Action E.1) and F (and Required Actions F.1 
and F.2), respectively. Modify new Condition F to address new Condition 
E, which maintains the existing requirements with respect to both RHR 
subsystems being inoperable for reasons other than Condition B. Add a 
new Condition D, which establishes requirements for existing Conditions 
A, B, and C, that are similar to existing Condition E but without 
Required Action E.2.
    Assessment: The BWROG topical report performed a comparative PRA 
evaluation of the core damage risks when operating in the current end 
state versus the Mode 3 end state. The results indicated that the core 
damage risks while operating in Mode 3 (assuming the individual failure 
conditions) are lower or comparable to the current end state. By 
remaining in Mode 3, HPCI, RCIC, and the power conversion system 
(condensate/feedwater) remain available for water makeup and decay heat 
removal. Additionally, the EOPs direct the operators to take control of 
the depressurization function if low pressure injection/spray are 
needed for RCS makeup and cooling. Therefore, defense-in-depth is 
improved with respect to water makeup and decay heat removal by 
remaining in Mode 3, and the required safety function can still be 
performed with the RHRSW subsystem components that are still operable.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.18 TRS 4.5.1.15 and LCO 3.7.2, Plant Service Water (PSW) System 
and Ultimate Heat Sink (UHS) (BWR/4 only).
    The PSW system (in conjunction with the UHS) is designed to provide 
cooling water for the removal of heat from certain safe shutdown-
related equipment heat exchangers following a DBA or transient.

    [Note:
    Plant Applicability, BWR/4]

    LCO: Two PSW subsystems and UHS shall be operable.
    Condition Requiring Entry into End State: If the LCO cannot be met, 
the following actions must be taken for the listed conditions:
    a. If one PSW pump is inoperable (Condition A), it must be restored 
to operable status within 30 days (Required Action A.1).
    b. If one PSW pump in each subsystem is inoperable (Condition B), 
one PSW pump must be restored to operable status within seven days 
(Required Action B.1).
    c. If the required action and associated completion time cannot be 
met within the allotted time, the plant must be placed in Mode 3 within 
12 hours (Required Action E.1) and in Mode 4 within 36 hours (Required 
Action E.2).
    Modification: Renumber unaffected Conditions C, D, E, and F to 
Conditions D, E, F, and G respectively, and renumber associated 
Required Actions accordingly. Add a new Condition C, for the Required 
Actions and associated Completion Time of Conditions A and B not met, 
with a Required Action C.1, to be in Mode 3 in a Completion Time of 12 
hours. Change the new Condition G to read, ``Required Action and 
associated Completion Time of Condition E not met, OR Both [PSW 
subsystems inoperable for reasons other than Condition(s) B [and D], 
[OR [UHS] inoperable for reasons other than Conditions D [or E].''
    Assessment: The BWROG topical report performed a comparative PRA 
evaluation of the core damage risks associated with operating in the 
current end state versus the Mode 3 end state. The results indicated 
that the core damage risks while operating in Mode 3 (assuming the 
individual failure conditions) are lower or comparable to the current 
end state. With one pump inoperable in one or more subsystems, the 
remaining pumps are adequate to

[[Page 14738]]

perform the PSW heat removal function. By remaining in Mode 3, HPCI, 
RCIC, and the power conversion system (condensate/feedwater) remain 
available for water makeup and decay heat removal. Additionally, the 
EOPs direct the operators to take control of the depressurization 
function if low pressure injection/spray are needed for RCS makeup and 
cooling. Therefore, defense-in-depth is improved with respect to water 
makeup and decay heat removal by remaining in Mode 3.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.19 TRS 4.5.1.16 and LCO 3.7.4, Main Control Room Environmental 
Control (MCREC) System (BWR/4 only).
    The MCREC system provides a radiologically controlled environment 
from which the plant can be safely operated following a DBA.

    [Note:
    Plant Applicability, BWR/4]

    LCO: Two MCREC subsystems shall be operable.
    Condition Requiring Entry into End State: If one MCREC subsystem is 
inoperable, it must be restored to operable status within seven days 
(Required Action A.1). If the MCREC subsystem cannot be restored to 
operable status within the allotted time, the plant must be placed in 
Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 
hours (Required Action B.2). If two MCREC subsystems are inoperable in 
Mode 1, 2, or 3, LCO 3.0.3 must be entered immediately (Required Action 
D.1).
    Modification for End State Required Actions: Delete Required Action 
B.2, and change Required Action D.1 to ``Be in Mode 3'' with a 
Completion Time of ``12 hours.''
    Assessment: The unavailability of one or both MCREC subsystems has 
no significant impact on CDF or LERF, irrespective of the mode of 
operation at the time of the accident. Furthermore, the challenge 
frequency of the MCREC system (i.e., the frequency with which the 
system is expected to be challenged to provide a radiologically 
controlled environment in the main control room following a DBA which 
leads to core damage and leaks of radiation from the containment that 
can reach the control room) is less than 1.0E-6/yr. Consequently, the 
conditional probability that this system will be challenged during the 
repair time interval while the plant is at either the current or the 
proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 
1.0E-8. This probability is considerably smaller than probabilities 
considered ``negligible'' in Regulatory Guide 1.177 for much higher 
consequence risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.1.16, and LCO 3.7.4, ``Main Control Room 
Environmental Control (MCREC) System.'' The argument for staying in 
Mode 3 instead of going to Mode 4 to repair the MCREC system (one or 
both trains) is also supported by defense-in-depth considerations. 
Section 6.2 makes a comparison between the Mode 3 and the Mode 4 end 
state, with respect to the means available to perform critical 
functions (i.e., functions contributing to the defense-in-depth 
philosophy) whose success is needed to prevent core damage and 
containment failure and mitigate radiation releases. The risk and 
defense-in-depth arguments, used according to the ``integrated 
decision-making'' process of Regulatory Guides 1.174 and 1.177, support 
the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for 
repairing an inoperable MCREC system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.20 TRS 4.5.1.17 and LCO 3.7.5, Control Room Air Conditioning 
(AC) System (BWR/4 only).
    The Control Room AC system provides temperature control for the 
control room following control room isolation during accident 
conditions.

    [Note:
    Plant Applicability, BWR/4]

    LCO: Two control room AC subsystems shall be operable.
    Condition Requiring Entry into End State: If one control room AC 
subsystem is inoperable, the subsystem must be restored to operable 
status within 30 days (Required Action A.1). If the required actions 
and associated completion times cannot be met, the plant must be placed 
in Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 
hours (Required Action B.2). If two control room AC subsystems are 
inoperable, LCO 3.0.3 must be entered immediately (Required Action 
D.1).
    Modification for End State Required Actions: Delete Required Action 
B.2, and change Required Action D.1 to ``Be in Mode 3'' with a 
Completion Time of ``12 hours.''
    Assessment: The unavailability of one or both AC subsystems has no 
significant impact on CDF or LERF, irrespective of the mode of 
operation at the time of the accident. Furthermore, the challenge 
frequency of the AC system (i.e., the frequency with which the system 
is expected to be challenged to provide temperature control for the 
control room following control room isolation following a DBA) is less 
than 1.0E-6/yr. Consequently, the conditional probability that this 
system will be challenged during the repair time interval while the 
plant is at either the current or the proposed end state (i.e., Mode 4 
or Mode 3, respectively) is less than 1.0E-8. This probability is 
considerably smaller than probabilities considered ``negligible'' in 
Regulatory Guide 1.177 for much higher consequence risks, such as large 
early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.1.17, and LCO 3.7.5, ``Control Room Air 
Conditioning (AC) System.'' The argument for staying in Mode 3 instead 
of going to Mode 4 to repair the AC system (one or both trains) is also 
supported by defense-in-depth considerations. Section 6.2 makes a 
comparison between the Mode 3 and the Mode 4 end state, with respect to 
the means available to perform critical functions (i.e., functions 
contributing to the defense-in-depth philosophy) whose success is 
needed to prevent core damage and containment failure and mitigate 
radiation releases. The risk and defense-in-depth arguments, used 
according to the ``integrated decision-making'' process of Regulatory 
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe 
as Mode 4 (if not safer) for repairing an inoperable AC system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.21 TRS 4.5.1.18 and LCO 3.7.6, Main Condenser Off gas (BWR/4 
only).
    The Off gas from the main condenser normally includes radioactive 
gases. The gross gamma activity rate is controlled to ensure that 
accident analysis assumptions are satisfied and that offsite dose 
limits will not be exceeded during postulated accidents. The main 
condenser Off gas (MCOG) gross gamma activity rate is an initial 
condition of a DBA which assumes a gross failure of the MCOG system 
pressure boundary.


[[Page 14739]]


    [Note:
    Plant Applicability, BWR/4]

    LCO: The gross gamma activity rate of the noble gases measured at 
the main condenser evacuation system pretreatment monitor station shall 
be <=240 mCi/second after decay of 30 minutes.
    Condition Requiring Entry into End State: If the gross gamma 
activity rate of the noble gases in the main condenser Off gas (MCOG) 
system is not within limits, the gross gamma activity rate of the noble 
gases in the main condenser Off gas must be restored to within limits 
within 72 hours (Required Action A.1). If the required action and 
associated completion time cannot be met, one of the following must 
occur:
    a. All steam lines must be isolated within 12 hours (Required 
Action B.1).
    b. The steam jet air ejector (SJAE) must be isolated within 12 
hours (Required Action B.2).
    c. The plant must be placed in Mode 3 within 12 hours (Required 
Action B.3.1) and in Mode 4 within 36 hours (Required Action B.3.2).
    Modification for End State Required Actions: Delete Required Action 
B.3.2.
    Assessment: The failure to maintain the gross gamma activity rate 
of the noble gases in the main condenser Off gas (MCOG) within limits 
has no significant impact on CDF or LERF, irrespective of the mode of 
operation at the time of the accident. Furthermore, the challenge 
frequency of the MCOG system (i.e., the frequency with which the system 
is expected to be challenged to mitigate offsite radiation releases 
following a DBA) is less than 1.0E-6/yr. Consequently, the conditional 
probability that this system will be challenged during the repair time 
interval while the plant is at either the current or the proposed end 
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This 
probability is considerably smaller than probabilities considered 
``negligible'' in Regulatory Guide 1.177 for much higher consequence 
risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.1.18 and LCO 3.7.6, ``Main Condenser Off gas.'' The 
argument for staying in Mode 3 instead of going to Mode 4 to repair the 
MCOG system (one or both trains) is also supported by defense-in-depth 
considerations. Section 6.2 makes a comparison between the Mode 3 and 
the Mode 4 end state, with respect to the means available to perform 
critical functions (i.e., functions contributing to the defense-in-
depth philosophy) whose success is needed to prevent core damage and 
containment failure and mitigate radiation releases. The risk and 
defense-in-depth arguments, used according to the ``integrated 
decision-making'' process of Regulatory Guides 1.174 and 1.177, support 
the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for 
repairing an inoperable MCOG system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.22 TRS 4.5.2.6 and LCO 3.6.1.7, Residual Heat Removal (RHR) 
Containment Spray System (BWR/6 only).
    The primary containment must be able to withstand a postulated 
bypass leakage pathway that allows the passage of steam from the 
drywell directly into the primary containment airspace, bypassing the 
suppression pool. The primary containment also must be able to 
withstand a low energy steam release into the primary containment 
airspace. The RHR Containment Spray System is designed to mitigate the 
effects of bypass leakage and low energy line breaks.

    [Note:
    Plant Applicability, BWR/6]

    LCO: Two RHR containment spray subsystems shall be operable.
    Condition Requiring Entry into End State: If one RHR Containment 
Spray Subsystem is inoperable, it must be restored to operable status 
within seven days (Required Action A.1). If two RHR Containment Spray 
Subsystems are inoperable, one of them must be restored to operable 
status within eight hours (Required Action B.1). If the RHR Containment 
Spray System cannot be restored to operable status within the allotted 
time, the plant must be placed in Mode 3 within 12 hours (Required 
Action C.1), and in Mode 4 within 36 hours (Required Action C.2)
    Modification for End State Required Actions: Delete Required Action 
C.2.
    Assessment: The primary containment is designed with a suppression 
pool so that, in the event of a LOCA, steam released from the primary 
system is channeled through the suppression pool water and condensed 
without producing significant pressurization of the primary 
containment. The primary containment is designed so that with the pool 
initially at the minimum water level and the worst single failure of 
the primary containment heat removal systems, suppression pool energy 
absorption combined with subsequent operator controlled pool cooling 
will prevent the primary containment pressure from exceeding its design 
value. However, the primary containment must also withstand a 
postulated bypass leakage pathway that allows the passage of steam from 
the drywell directly into the primary containment airspace, bypassing 
the suppression pool. The primary containment also must withstand a 
postulated low energy steam release into the primary containment 
airspace. The main function of the RHR containment spray system is to 
suppress steam, which is postulated to be released into the primary 
containment airspace through a bypass leakage pathway and a low energy 
line break under DBA conditions, without producing significant 
pressurization of the primary containment (i.e., ensure that the 
pressure inside primary containment remains within analyzed design 
limits).
    Under the conditions assumed in the DBA, steam blown down from the 
break could find its way into the primary containment through a bypass 
leakage pathway. In addition to the DBA, a postulated low energy pipe 
break could add more steam into the primary containment airspace. Under 
such an extremely unlikely scenario (very small frequency of a DBA 
combined with the likelihood of a bypass pathway and a concurrent low 
energy pipe brake inside the primary containment), the RHR containment 
spray system could be needed to condense steam so that the pressure 
inside the primary containment remains within analyzed design limits. 
Furthermore, containments have considerable margin to failure above the 
design limit (it is very likely that the containment will be able to 
withstand pressures as much as three times the design limit). For these 
reasons, the unavailability of one or both RHR containment spray 
subsystems has no significant impact on CDF or LERF, even for accidents 
initiated during operation at power. Therefore, it is very unlikely 
that the RHR containment spray system will be challenged to mitigate an 
accident occurring during power operation. This probability becomes 
extremely unlikely for accidents that would occur during a small 
fraction of the year (less than three days) during which the plant 
would be in Mode 3 (associated with lower initial energy level and 
reduced decay heat load as compared to power operation) to repair the 
failed RHR containment spray system.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.2.6 and LCO 3.6.1.7, ``Residual Heat Removal (RHR) 
Containment Spray

[[Page 14740]]

System.'' The argument for staying in Mode 3 instead of going to Mode 4 
to repair the RHR containment spray system (one or both trains) is also 
supported by defense-in-depth considerations. Section 6.2 makes a 
comparison between the Mode 3 and the Mode 4 end state, with respect to 
the means available to perform critical functions (i.e., functions 
contributing to the defense-in-depth philosophy) whose success is 
needed to prevent core damage and containment failure and mitigate 
radiation releases. The risk and defense-in-depth arguments, used 
according to the ``integrated decision-making'' process of Regulatory 
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe 
as Mode 4 (if not safer) for repairing an inoperable RHR containment 
spray system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.23 TRS 4.5.2.7 and LCO 3.6.1.8, Penetration Valve Leakage 
Control System (PVLCS) (BWR/6 only).
    The PVLCS supplements the isolation function of primary containment 
isolation valves (PCIVs) in process lines that also penetrate the 
secondary containment. These penetrations are sealed by air from the 
PVLCS to prevent fission products leaking past the isolation valves and 
bypassing the secondary containment after a design basis loss-of-
coolant accident (LOCA).

    [Note:
    Plant Applicability, BWR/6]

    LCO: Two PVLCS subsystems shall be operable.
    Condition Requiring Entry into End State: If one PVLCS subsystem is 
inoperable, it must be restored to operable status within 30 days 
(Required Action A.1). If two PVLCS subsystems are inoperable, one of 
the PVLCS subsystems must be restored to operable status within seven 
days (Required Action B.1). If the PVLCS subsystem cannot be restored 
to operable status within the allotted time, the plant must be placed 
in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 within 36 
hours (Required Action C.2).
    Assessment: The BWROG topical report has determined that this 
system is not significant in BWR PRAs. The unavailability of one or 
both PVLCS subsystems has no impact on CDF or LERF, irrespective of the 
mode of operation at the time of the accident. Furthermore, the 
challenge frequency of the PVLCS system (i.e., the frequency with which 
the system is expected to be challenged to prevent fission products 
leaking past the isolation valves and bypassing the secondary 
containment) is less than 1.0E-6/yr. Consequently, the conditional 
probability that this system will be challenged during the repair time 
interval while the plant is at either the current or the proposed end 
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This 
probability is considerably smaller than probabilities considered 
``negligible'' in Regulatory Guide 1.177 for much higher consequence 
risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.2.7 and LCO 3.6.1.8, ``Penetration Valve Leakage 
Control System (PVLCS).'' The argument for staying in Mode 3 instead of 
going to Mode 4 to repair the PVLCS system (one or both trains) is also 
supported by defense-in-depth considerations. Section 6.2 makes a 
comparison between the Mode 3 and the Mode 4 end state, with respect to 
the means available to perform critical functions (i.e., functions 
contributing to the defense-in-depth philosophy) whose success is 
needed to prevent core damage and containment failure and mitigate 
radiation releases. The risk and defense-in-depth arguments, used 
according to the ``integrated decision-making'' process of Regulatory 
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe 
as Mode 4 (if not safer) for repairing an inoperable PVLCS system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.24 TRS 4.5.1.10, TRS 4.5.2.9 and LCO 3.6.2.3, Residual Heat 
Removal (RHR) Suppression Pool Cooling.
    Some means must be provided to remove heat from the suppression 
pool so that the temperature inside the primary containment remains 
within design limits. This function is provided by two redundant RHR 
suppression pool cooling subsystems.

    [Note:
    Plant Applicability, BWR 4/6]

    LCO: Two RHR suppression pool cooling subsystems shall be operable.
    Condition Requiring Entry into End State: If one RHR suppression 
pool cooling subsystem is inoperable (Condition A), it must be restored 
to operable status within seven days (Required Action A.1). If the RHR 
suppression pool spray subsystem cannot be restored to operable status 
within the allotted time (Condition B), the plant must be placed in 
Mode 3 within 12 hours (Required Action B.1), and in Mode 4 within 36 
hours (Required Action B.2).
    Modification for End State Required Actions: Delete Required Action 
B.2, and retain Condition B and Required Action B.1 for one RHR 
suppression pool spray subsystem inoperable. Add Condition C, with 
Required Actions C.1 and C.2, identical to existing Condition B, with 
Required Actions B.1 and B.2, to maintain existing requirements 
unchanged for two RHR suppression pool subsystems inoperable.
    Assessment: The BWROG topical report has completed a comparative 
PRA evaluation of the core damage risks of operation in the current end 
state versus operation in the Mode 3 end state. The results indicated 
that the core damage risks while operating in Mode 3 (assuming the 
individual failure conditions) are lower or comparable to the current 
end state. One loop of the RHR suppression pool cooling system is 
sufficient to accomplish the required safety function. By remaining in 
Mode 3, HPCS, RCIC, and the power conversion system (condensate/
feedwater) remain available for water makeup and decay heat removal. 
Additionally, the EOPs direct the operators to take control of the 
depressurization function if low pressure injection/spray are needed 
for RCS makeup and cooling. Therefore, defense-in-depth is improved 
with respect to water makeup and decay heat removal by remaining in 
Mode 3.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.25 TRS 4.5.2.12 and LCO 3.6.5.6, Drywell Vacuum Relief System 
(BWR/6 only).
    The Mark III pressure suppression containment is designed to 
condense, in the suppression pool, the steam released into the drywell 
in the event of a loss-of-coolant accident (LOCA). The steam 
discharging to the pool carries the non-condensibles from the drywell. 
Therefore, the drywell atmosphere changes from low humidity air to 
nearly 100% steam (no air) as the event progresses. When the drywell 
subsequently cools and depressurizes, non-condensibles in the drywell 
must be replaced to avoid excessive weir wall overflow into the 
drywell. Rapid weir wall overflow must be controlled in a large break 
LOCA, so that essential

[[Page 14741]]

equipment and systems located above the weir wall in the drywell are 
not subjected to excessive drag and impact loads. The drywell post-LOCA 
and the drywell purge vacuum relief subsystems are the means by which 
non-condensibles are transferred from the primary containment back to 
the drywell.

    [Note:
     Plant Applicability, BWR/6]

    LCO: Two drywell post-LOCA and two drywell purge vacuum relief 
subsystems shall be operable.
    Condition Requiring Entry into End State: If one or two drywell 
post-LOCA vacuum relief subsystems are inoperable (Condition A), or if 
one drywell purge vacuum relief subsystem is inoperable (Condition B), 
for reasons other than being not closed, the subsystem(s) must be 
restored to operable status within 30 days (Required Actions B.1 and 
C.1, respectively). If the required actions cannot be completed within 
the allotted time, the plant must be placed in Mode 3 within 12 hours 
and in Mode 4 within 36 hours.
    Modification for End State Required Actions: Renumber Conditions D, 
E, F and G, to Conditions E, F, G, and H respectively, and renumber 
associated Required Actions accordingly. Add a new Condition D for when 
Required Action and associated Completion Time of Condition B or C not 
met, with Required Action D.1 to be in Mode 3 in a Completion Time of 
12 hours. Change new Condition G to read, ``Required Action and 
associated Completion Time of Condition A, E or F not met.''
    Assessment: The BWROG topical report has determined that the 
specific failure conditions of interest are not risk significant in BWR 
PRAs. With one or two drywell post-LOCA vacuum relief subsystems 
inoperable or one drywell purge vacuum relief subsystem inoperable, for 
reasons other than not being closed, the remaining operable vacuum 
relief subsystems are adequate to perform the depressurization 
mitigation function. By remaining in Mode 3, HPCS, RCIC, and the power 
conversion system (condensate/feedwater) remain available for water 
makeup and decay heat removal. Additionally, the EOPs direct the 
operators to take control of the depressurization function if low 
pressure injection/spray are needed for RCS makeup and cooling. 
Therefore, defense-in-depth is improved with respect to water makeup 
and decay heat removal by remaining in Mode 3.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.26 TRS 4.5.2.13 and LCO 3.7.1, Standby Service Water (SSW) 
System and Ultimate Heat Sink (UHS) (BWR/6 only).
    The SSW system (in conjunction with the UHS) is designed to provide 
cooling water for the removal of heat from certain safe shutdown-
related equipment heat exchangers following a DBA or transient.

    [Note:
    Plant Applicability, BWR/6]

    LCO: Division 1 and 2 SSW subsystems and UHS shall be operable.
    Condition Requiring Entry into End State: If one or more cooling 
towers with one cooling tower fan is inoperable (Condition A), the 
cooling tower fan(s) must be restored to operable status within seven 
days (Required Action A.1). If one SSW subsystem is inoperable for 
reasons other than Condition A (Condition C), the SSW subsystem must be 
restored to operable status within 72 hours (Required Action C.1). If 
the required action(s) and associated completion time(s) (of Conditions 
A or C) cannot be met (Condition D), the plant must be placed in Mode 3 
within 12 hours (Required Action D.1) and in Mode 4 within 36 hours 
(Required Action D.2).
    Modification: The existing second and third conditions of existing 
Condition D have been transferred to a new Condition E in an unchanged 
form (with Required Actions E.1 and E.2 identical to existing Required 
Actions D.1 and D.2). Existing Condition B with its associated Required 
Actions and Associated Completion Times, has been transferred to a new 
Condition D in an unchanged form. Existing Condition C, with its 
associated Required Action and Associated Completion Time, has been 
moved to a new Condition B in unchanged form. A new Condition C has 
been created. If the Required Actions and Associated Completion Times 
for new Condition A or B are not met (new Condition C), then the plant 
must be placed in Mode 3 in 12 hours (new Required Action C.1).
    Assessment: The BWROG topical report determined that the specific 
failure condition of interest is not risk significant in BWR PRAs. With 
the specified inoperable components/subsystems, a sufficient number of 
operable components/subsystems are still available to perform the heat 
removal function. By remaining in Mode 3, HPCS, RCIC, and the power 
conversion system (condensate/feedwater) remain available for water 
makeup and decay heat removal. Additionally, the EOPs direct the 
operators to take control of the depressurization function if low 
pressure injection/spray are needed for RCS makeup and cooling. 
Therefore, defense-in-depth is improved with respect to water makeup 
and decay heat removal by remaining in Mode 3.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.27 TRS 4.5.2.14 and LCO 3.7.3, Control Room Fresh Air (CRFA) 
System (BWR/6 only).
    The CRFA system provides a radiologically controlled environment 
from which the unit can be safely operated following a DBA. The CRFA 
system consists of two independent and redundant high efficiency air 
filtration subsystems for treatment of recirculated air or outside 
supply air. Each subsystem consists of a demister, an electric heater, 
a prefilter, a high efficiency particulate air (HEPA) filter, an 
activated charcoal adsorber section, a second HEPA filter, a fan, and 
the associated ductwork and dampers. Demisters remove water droplets 
from the airstream. Prefilters and HEPA filters remove particulate 
matter that may be radioactive. The charcoal adsorbers provide a holdup 
period for gaseous iodine, allowing time for decay.

    [Note:
    Plant Applicability, BWR/6]

    LCO: Two CRFA subsystems shall be operable.
    Condition Requiring Entry into End State: If one CRFA subsystem is 
inoperable (Condition A), it must be restored to operable status within 
seven days (Required Action A.1). If two CRFA subsystems are inoperable 
(Condition B for control room boundary and Condition E for reasons for 
inoperability), one CRFA subsystem must be restored to operable status 
in 24 hours (Required Action B.1) or enter LCO 3.0.3 (Required Action 
E.1). If Conditions A or B, and associated Required Actions A.1 and 
B.1) cannot be met in the required Completion Time (Condition C), the 
plant must be placed in Mode 3 within 12 hours (Required Action C.1) 
and in Mode 4 within 36 hours (Required Action C.2).
    Modification for End State Required Actions: Delete Required Action 
C.2, and change Required Action E.1 to ``Be in Mode 3'' within a 
Completion Time of ``12 hours.''
    Assessment: The unavailability of one or both CRFA subsystems has 
no significant impact on CDF or LERF,

[[Page 14742]]

irrespective of the mode of operation at the time of the accident. 
Furthermore, the challenge frequency of the CRFA system (i.e., the 
frequency with which the system is expected to be challenged to provide 
a radiologically controlled environment in the main control room 
following a DBA which leads to core damage and leaks of radiation from 
the containment that can reach the control room) is less than 1.0E-6/
yr. Consequently, the conditional probability that this system will be 
challenged during the repair time interval while the plant is at either 
the current or the proposed end state (i.e., Mode 4 or Mode 3, 
respectively) is less than 1.0E-8. This probability is considerably 
smaller than probabilities considered ``negligible'' in Regulatory 
Guide 1.177 for much higher consequence risks, such as large early 
release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.2.14 and LCO 3.7.3, ``Control Room Fresh Air (CRFA) 
System.'' The argument for staying in Mode 3 instead of going to Mode 4 
to repair the CRFA system (one or both trains) is also supported by 
defense-in-depth considerations. Section 6.2 makes a comparison between 
the Mode 3 and the Mode 4 end state, with respect to the means 
available to perform critical functions (i.e., functions contributing 
to the defense-in-depth philosophy) whose success is needed to prevent 
core damage and containment failure and mitigate radiation releases. 
The risk and defense-in-depth arguments, used according to the 
``integrated decision-making'' process of Regulatory Guides 1.174 and 
1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not 
safer) for repairing an inoperable CRFA system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.28 TRS 4.5.2.15 and LCO 3.7.4, Control Room Air Conditioning 
(CRAC) System (BWR/6 only).
    The control room AC system provides temperature control for the 
control room following control room isolation. The control room AC 
system consists of two independent, redundant subsystems that provide 
cooling and heating of recirculated control room air. Each subsystem 
consists of heating coils, cooling coils, fans, chillers, compressors, 
ductwork, dampers, and instrumentation and controls to provide for 
control room temperature control. The control room AC system is 
designed to provide a controlled environment under both normal and 
accident conditions. A single subsystem provides the required 
temperature control to maintain a suitable control room environment for 
a sustained occupancy of 12 persons.

    [Note:
    Plant Applicability, BWR/6]

    LCO: Two control room AC subsystems shall be operable.
    Condition Requiring Entry into End State: If one control room AC 
subsystem is inoperable, it must be restored to operable status within 
30 days (Required Action A.1). If the required actions and associated 
completion times cannot be met, the plant must be placed in Mode 3 
within 12 hours (Required Action B.1) and in Mode 4 within 36 hours 
(Required Action B.2). If two control room AC subsystems are 
inoperable, LCO 3.0.3 must be entered immediately (Condition D).
    Modification for End State Required Actions: Delete Required Action 
B.2, and change Required Action D.1 to ``Be in Mode 3'' with a 
Completion Time of ``12 hours.''
    Assessment: The unavailability of one or both AC subsystems has no 
significant impact on CDF or LERF, irrespective of the mode of 
operation at the time of the accident. Furthermore, the challenge 
frequency of the AC system (i.e., the frequency with which the system 
is expected to be challenged to provide temperature control for the 
control room following control room isolation following a DBA which 
leads to core damage) is less than 1.0E-6/yr. Consequently, the 
conditional probability that this system will be challenged during the 
repair time interval while the plant is at either the current or the 
proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 
1.0E-8. This probability is considerably smaller than probabilities 
considered ``negligible'' in Regulatory Guide 1.177 for much higher 
consequence risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.2.15 and LCO 3.7.4, ``Control Room Air Conditioning 
(AC) System.'' The argument for staying in Mode 3 instead of going to 
Mode 4 to repair the CRAC system (one or both trains) is also supported 
by defense-in-depth considerations. Section 6.2 makes a comparison 
between the Mode 3 and the Mode 4 end state, with respect to the means 
available to perform critical functions (i.e., functions contributing 
to the defense-in-depth philosophy) whose success is needed to prevent 
core damage and containment failure and mitigate radiation releases. 
The risk and defense-in-depth arguments, used according to the 
``integrated decision-making'' process of Regulatory Guides 1.174 and 
1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not 
safer) for repairing an inoperable CRAC system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.
    3.2.29 TRS 4.5.2.16 and LCO 3.7.5, Main Condenser Off gas (BWR/6 
only).
    The Off gas from the main condenser normally includes radioactive 
gases. The gross gamma activity rate is controlled to ensure that 
accident analysis assumptions are satisfied and that offsite dose 
limits will not be exceeded during postulated accidents.

    [Note:
    Plant Applicability, BWR/6]

    LCO: The gross gamma activity rate of the noble gases measured at 
the Off gas recombiner effluent shall be <=380 mCi/second after decay 
of 30 minutes.
    Condition Requiring Entry into End State: If the gross gamma 
activity rate of the noble gases in the main condenser Off gas is not 
within limits (Condition A), the gross gamma activity rate of the noble 
gases in the main condenser Off gas must be restored to within limits 
within 72 hours (Required Action A.1). If the required action and 
associated completion time cannot be met, one of the following must 
occur:
    a. All steam lines must be isolated within 12 hours (Required 
Action B.1).
    b. The steam jet air ejector (SJAE) must be isolated within 12 
hours (Required Action B.2).
    c. The plant must be placed in Mode 3 within 12 hours (Required 
Action B.3.1) and in Mode 4 within 36 hours (Required Action B.3.2).
    Modification for End State Required Actions: Delete Required Action 
B.3.2.
    Assessment: The failure to maintain the gross gamma activity rate 
of the noble gases in the main condenser Off gas (MCOG) within limits 
has no significant impact on CDF or LERF, irrespective of the mode of 
operation at the time of the accident. Furthermore, the challenge 
frequency of the MCOG system (i.e., the frequency with which the system 
is expected to be challenged to mitigate offsite radiation releases 
following a DBA) is less than 1.0E-6/yr. Consequently, the conditional 
probability that this system will be challenged during the repair time 
interval while the plant is at either the

[[Page 14743]]

current or the proposed end state (i.e., Mode 4 or Mode 3, 
respectively) is less than 1.0E-8. This probability is considerably 
smaller than probabilities considered ``negligible'' in Regulatory 
Guide 1.177 for much higher consequence risks, such as large early 
release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TRS 4.5.2.16 and LCO 3.7.5, ``Main Condenser Off gas.'' The 
argument for staying in Mode 3 instead of going to Mode 4 to repair the 
MCOG system (one or both trains) is also supported by defense-in-depth 
considerations. Section 6.2 makes a comparison between the Mode 3 and 
the Mode 4 end state, with respect to the means available to perform 
critical functions (i.e., functions contributing to the defense-in-
depth philosophy) whose success is needed to prevent core damage and 
containment failure and mitigate radiation releases. The risk and 
defense-in-depth arguments, used according to the ``integrated 
decision-making'' process of Regulatory Guides 1.174 and 1.177, support 
the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for 
repairing an inoperable MCOG system.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations (discussed in Reference 1), 
the change is acceptable.

4.0 State Consultation

    In accordance with the Commission's regulations, the [--------] 
State official was notified of the proposed issuance of the amendment. 
The State official had [(1) no comments or (2) the following comments--
with subsequent disposition by the staff].

5.0 Environmental Consideration

    The amendment changes requirements with respect to the installation 
or use of a facility component located within the restricted area as 
defined in 10 CFR Part 20. The NRC staff has determined that the 
amendment involves no significant increase in the amounts and no 
significant change in the types of any effluents that may be released 
offsite, and that there is no significant increase in individual or 
cumulative occupational radiation exposure. The Commission has 
previously issued a proposed finding that adopting TSTF-423, Rev 0, 
involves no significant hazards considerations, and there has been no 
public comment on the finding in Federal Register Notice 70 FR 74037, 
December 14, 2005. Accordingly, the amendments meet the eligibility 
criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). 
Pursuant to 10 CFR 51.22(b), no environmental impact statement or 
environmental assessment need be prepared in connection with the 
issuance of the amendment.

6.0 Conclusion

    The Commission has concluded, on the basis of the considerations 
discussed above, that (1) there is reasonable assurance that the health 
and safety of the public will not be endangered by operation in the 
proposed manner, (2) such activities will be conducted in compliance 
with the Commission's regulations, and (3) the issuance of the 
amendments will not be inimical to the common defense and security or 
to the health and safety of the public.

7.0 References

    1. NEDC-32988-A, Revision 2, ``Technical Justification to Support 
Risk-Informed Modification to Selected Required Action End States for 
BWR Plants,'' December 2002.
    2. Federal Register, Vol. 58, No. 139, p. 39136, ``Final Policy 
Statement on Technical Specifications Improvements for Nuclear Power 
Plants,'' July 22, 1993.
    3. 10 CFR 50.65, Requirements for Monitoring the Effectiveness of 
Maintenance at Nuclear Power Plants.''
    4. Regulatory Guide 1.182, ``Assessing and Managing Risk Before 
Maintenance Activities at Nuclear Power Plants,'' May 2000. 
(ML003699426)
    5. NUMARC 93-01, ``Industry Guideline for Monitoring the 
Effectiveness of Maintenance at Nuclear Power Plants,'' Nuclear 
Management and Resource Council, Revision 3, July 2000.
    6. NRC Safety Evaluation for Topical Report NEDC-32988, Revision 2, 
September 27, 2002. (ML022700603)
    7. TSTF-423, Revision 0, ``Technical Specifications End States, 
NEDC-32988-A.''
    8. TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 0, 
``Technical Specifications End States, NEDC-32988-A,'' September 2005.
    9. Regulatory Guide 1.174, ``An Approach for Using Probabilistic 
Risk Assessment in Risk-Informed Decision Making on Plant Specific 
Changes to the Licensing Basis,'' USNRC, August 1998. (ML003740133)
    10. Regulatory Guide 1.177, ``An Approach for Pant Specific Risk-
Informed Decision Making: Technical Specifications,'' USNRC, August 
1998. (ML003740176)

Proposed No Significant Hazards Consideration Determination

    Description of Amendment Request: A change is proposed to the 
technical specifications (TS) of [plant name], consistent with 
Technical Specifications Task Force (TSTF) change TSTF-423 to the 
standard technical specifications (STS) for BWR Plants (NUREG 1433 and 
NUREG 1434) to allow, for some systems, entry into hot shutdown rather 
than cold shutdown to repair equipment, if risk is assessed and managed 
consistent with the program in place for complying with the 
requirements of 10 CFR 50.65(a)(4). Changes proposed in will be made to 
the [plant name] TS for selected Required Action end states providing 
this allowance.
    Basis for proposed no-significant-hazards-consideration 
determination: As required by 10 CFR 50.91(a), an analysis of the issue 
of no-significant-hazards-consideration is presented below:

Criterion 1--The Proposed Change Does Not Involve a Significant 
Increase in the Probability or Consequences of an Accident Previously 
Evaluated

    The proposed change allows a change to certain required end states 
when the TS Completion Times for remaining in power operation will be 
exceeded. Most of the requested technical specification (TS) changes 
are to permit an end state of hot shutdown (Mode 3) rather than an end 
state of cold shutdown (Mode 4) contained in the current TS. The 
request was limited to: (1) Those end states where entry into the 
shutdown mode is for a short interval, (2) entry is initiated by 
inoperability of a single train of equipment or a restriction on a 
plant operational parameter, unless otherwise stated in the applicable 
technical specification, and (3) the primary purpose is to correct the 
initiating condition and return to power operation as soon as is 
practical. Risk insights from both the qualitative and quantitative 
risk assessments were used in specific TS assessments. Such assessments 
are documented in Section 6 of GE NEDC-32988, Revision 2, ``Technical 
Justification to Support Risk Informed Modification to Selected 
Required Action End States for BWR Plants.'' They provide an integrated 
discussion of deterministic and probabilistic issues, focusing on 
specific technical specifications, which are used to support the 
proposed TS end state and associated restrictions. The staff finds that 
the risk insights support the conclusions of the specific TS 
assessments. Therefore, the probability

[[Page 14744]]

of an accident previously evaluated is not significantly increased, if 
at all. The consequences of an accident after adopting proposed TSTF-
423, are no different than the consequences of an accident prior to 
adopting TSTF-423. Therefore, the consequences of an accident 
previously evaluated are not significantly affected by this change. The 
addition of a requirement to assess and manage the risk introduced by 
this change will further minimize possible concerns. Therefore, this 
change does not involve a significant increase in the probability or 
consequences of an accident previously evaluated.

Criterion 2--The Proposed Change Does Not Create the Possibility of a 
New or Different Kind of Accident From Any Previously Evaluated

    The proposed change does not involve a physical alteration of the 
plant (no new or different type of equipment will be installed). If 
risk is assessed and managed, allowing a change to certain required end 
states when the TS Completion Times for remaining in power operation 
are exceeded, i.e., entry into hot shutdown rather than cold shutdown 
to repair equipment, will not introduce new failure modes or effects 
and will not, in the absence of other unrelated failures, lead to an 
accident whose consequences exceed the consequences of accidents 
previously evaluated. The addition of a requirement to assess and 
manage the risk introduced by this change and the commitment by the 
licensee to adhere to the guidance in TSTF-IG-05-02, Implementation 
Guidance for TSTF-423, Revision 0, ``Technical Specifications End 
States, NEDC-32988-A,'' will further minimize possible concerns. Thus, 
this change does not create the possibility of a new or different kind 
of accident from an accident previously evaluated.

Criterion 3--The Proposed Change Does Not Involve a Significant 
Reduction in the Margin of Safety

    The proposed change allows, for some systems, entry into hot 
shutdown rather than cold shutdown to repair equipment, if risk is 
assessed and managed. The BWROG's risk assessment approach is 
comprehensive and follows staff guidance as documented in RGs 1.174 and 
1.177. In addition, the analyses show that the criteria of the three-
tiered approach for allowing TS changes are met. The risk impact of the 
proposed TS changes was assessed following the three-tiered approach 
recommended in RG 1.177. A risk assessment was performed to justify the 
proposed TS changes. The net change to the margin of safety is 
insignificant. Therefore, this change does not involve a significant 
reduction in a margin of safety.
    The Following Example of an Application Was Prepared by the NRC 
Staff To Facilitate Use of the Consolidated Line Item Improvement 
Process (CLIIP). The Model Provides the Expected Level of Detail and 
Content for an Application To Adopt TSTF-423, Revisions 0, ``Risk-
Informed Modifications to Selected Required Action End States,'' for 
BWR Plants (and Adoption of a Technical Specification Bases Control 
Program)* Using CLIIP. Licensees Remain Responsible for Ensuring That 
Their Actual Application Fulfills Their Administrative Requirements as 
Well as Nuclear Regulatory Commission Regulations.

U.S. Nuclear Regular Commission,
Document Control Desk,
Washington, DC 20555.

Subject: Plant Name, Docket No. 50--Application for Technical 
Specification Change TSTF-423, Risk Informed Modification To 
Selected Required Action End States for BWR Plants, (and Adoption of 
a Technical Specifications Bases Control Program)* Using the 
Consolidated Line Item Improvement Process

    Gentleman: In accordance with the provisions of 10 CFR 50.90 
[Licensee] is submitting a request for an amendment to the technical 
specifications (TS) for [Plant Name, Unit Nos.].
    The proposed amendment would modify TS to risk-inform 
requirements regarding selected Required Action End States, (and, in 
conjunction with the proposed change, TS requirements for a Bases 
control program consistent with TS Bases Control Program described 
in Section 5.5 of the BWR Standard Technical Specifications.)*
    Enclosure 1 provides a description of the proposed change, the 
requested confirmation of applicability, and plant-specific 
verifications. Enclosure 2 provides the existing TS pages marked up 
to show the proposed change. Enclosure 3 provides revised (clean) TS 
pages. Enclosure 4 provides a summary of the regulatory commitments 
made in this submittal. Enclosure 5 provides the existing TS Bases 
pages marked up to show the proposed change (for information only).)
    [Licensee] requests approval of the proposed license amendment 
by [Date], with the amendment being implemented [by Date or Within X 
Days].
    In accordance with 10 CFR 50.91, a copy of this application, 
with enclosures, is being provided to the designated [State] 
Official.

    * If not already in the facility Technical Specifications.

    I declare under penalty of perjury under the laws of the United 
States of America that I am authorized by [Licensee] to make this 
request and that the foregoing is true and correct. (Note that 
request may be notarized in lieu of using this oath or affirmation 
statement).
    If you should have any questions regarding this submittal, 
please contact [Name, Telephone Number]
    Sincerely,
[Name, Title]

Enclosures:
1. Description and Assessment
2. Proposed Technical Specification Changes
3. Revised Technical Specification Pages
4. Regulatory Commitments
5. Proposed Technical Specification Bases Changes

cc: NRC Project Manager

NRC Regional Office
NRC Resident Inspector
State Contact

ENCLOSURE 1

Description and Assessment

1.0 Description

    The proposed amendment would modify technical specifications to 
risk-inform requirements regarding selected Required Action End 
States.\1\
---------------------------------------------------------------------------

    \1\ [In conjunction with the proposed change, technical 
specifications (TS) requirements for a Bases Control Program, 
consistent with the TS Bases Control Program described in Section 
5.5 of the applicable vendor's standard TS (STS), shall be 
incorporated into the licensee's TS, if not already in the TS.]
---------------------------------------------------------------------------

    The changes are consistent with Nuclear Regulatory Commission 
(NRC) approved Industry/Technical Specification Task Force (TSTF) 
TSTF-423 Revision 0. The availability of this TS improvement was 
published in the Federal Register on [Date] as part of the 
consolidated line item improvement process (CLIIP).

2.0 Assessment

2.1 Applicability of Topical Report, TSTF-423, and Published Safety 
Evaluation

    [Licensee] has reviewed GE topical report (Reference 1), TSTF-
423 (Reference 2), and the NRC model safety evaluation (Reference 3) 
as part of the CLIIP. [Licensee] has concluded that the information 
in the GE topical report and TSTF-423, as well as the safety 
evaluation prepared by the NRC staff are applicable to [Plant, Unit 
Nos.] and justify this amendment for the incorporation of the 
changes to the [Plant] TS. [Note: Only those changes proposed in 
TSTF-423 are addressed in the model SE. The model SE and associated 
topical report address the entire fleet of BWR plants, and the 
plants adopting TSTF-423 must confirm the applicability of the 
changes to their plant.]

2.2 Optional Changes and Variations

    [Licensee] is not proposing any variations or deviations from 
the GE topical report and the TS changes described in the TSTF-423 
Revision 0 or the NRC staff's model safety evaluation dated [Date]. 
[Note: The CLIIP does not prevent licensees from requesting an 
alternate approach or proposing changes without the requested Bases 
or Bases control program. However, deviations from the approach 
recommended in this notice may require additional review by the NRC 
staff and may increase the time and resources needed for the review. 
Significant variations

[[Page 14745]]

from the approach, or inclusion of additional changes to the 
license, will result in staff rejection of the submittal. Instead, 
licensees desiring significant variations and/or additional changes 
should submit a LAR that does not claim to adopt TSTF-423.]

3.0 Regulatory Analysis

3.1 No Significant Hazards Consideration Determination

    [Licensee] has reviewed the proposed no significant hazards 
consideration determination (NSHCD) published in the Federal 
Register as part of the CLIIP. [Licensee] has concluded that the 
proposed NSHCD presented in the Federal Register notice is 
applicable to [Plant] and is hereby incorporated by reference to 
satisfy the requirements of 10 CFR 50.91(a).

3.2 Verification and Commitments

    As discussed in the notice of availability published in the 
Federal Register on [Date] for this TS improvement, plant-specific 
verifications were performed as follows:
    [Licensee] commits to the regulatory commitments in Enclosure 4. 
In addition, [Licensee] has proposed TS Bases consistent with the GE 
topical report and TSTF-423, which provide guidance and details on 
how to implement the new requirements. Implementation of TSTF-423 
requires that risk be managed and assessed, and the licensee's 
configuration risk management program is adequate to satisfy this 
requirement. The risk assessment need not be quantified, but may be 
a qualitative assessment of the vulnerability of systems and 
components when one or more systems are not able to perform their 
associated function. Finally, [Licensee] has a Bases Control Program 
consistent with Section 5.5 of the Standard Technical Specifications 
(STS).

4.0 Environmental Evaluation

    The amendment changes requirements with respect to the 
installation or use of a facility component located within the 
restricted area as defined in 10 CFR Part 20. The NRC staff has 
determined that the amendment adopting TSTF-423, Rev 0, involves no 
significant increase in the amounts and no significant change in the 
types of any effluents that may be released offsite, and that there 
is no significant increase in individual or cumulative occupational 
radiation exposure. The Commission has previously issued a proposed 
finding that TSTF-423, Rev 0, involves no significant hazards 
considerations, and there has been no public comment on the finding 
in Federal Register Notice 70 FR 74037, December 14, 2005. 
Accordingly, the amendment meets the eligibility criteria for 
categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 
10 CFR 51.22(b), no environmental impact statement or environmental 
assessment need be prepared in connection with the issuance of the 
amendment.

5.0 References

    1. NEDC-32988-A, Revision 2, ``Technical Justification to 
Support Risk-Informed Modification to Selected Required Action End 
States for BWR Plants,'' December 2002.
    2. TSTF-423, Revision 0, ``Technical Specifications End States, 
NEDC-32988-A.''
    3. Federal Register, Vol. XX, No. XX, p. XXXXX, ``Notice of 
Availability of Model Application Concerning Technical 
Specifications for Boiling Water Reactor Plants to Risk-Inform 
Requirements Regarding Selected Required Action End States Using the 
Consolidated Line Item Improvement Process, and NRC Model Safety 
Evaluation,'' [Date].

Enclosure 2

Proposed Technical Specification Changes (Mark-up)

Enclosure 3

Proposed Technical Specification Pages

    [Clean copies of Licensee specific Technical Specification (TS) 
pages, corresponding to the TS pages changed by TSTF-423, Rev 0, are 
to be included in Enclosure 3]

Enclosure 4

List of Regulatory Commitments

    The following table identifies those actions committed to by 
[Licensee] in this document. Any other statements in this submittal 
are provided for information purposes and are not considered to be 
regulatory commitments. Please direct questions regarding these 
commitments to [Contact Name].

------------------------------------------------------------------------
           Regulatory committments                   Due date/event
------------------------------------------------------------------------
[Licensee] will follow the guidance            [Ongoing, or implement
 established in Section 11 of NUMARC 93-01,     with amendment].
 ``Industry Guidance for Monitoring the
 Effectiveness of Maintenance at Nuclear
 Power Plants,'' Nuclear Management and
 Resource Council, Revision 3, July 2000.
[Licensee] will follow the guidance            [Implement with
 established in TSTF-IG-05-02, Implementation   amendment, when TS
 Guidance for TSTF-423, Revision 0,             Required Action End
 ``Technical Specifications End States, NEDC-   State remains within the
 32988-A,'' September 2005.                     Applicability of TS].
------------------------------------------------------------------------

Enclsoure 5

Proposed Changes to Technical Specification Bases Pages

[FR Doc. 06-2803 Filed 3-22-06; 8:45 am]
BILLING CODE 7590-01-P