Biweekly Notice; Applications and Amendments to Facility Operating Licenses Involving No Significant Hazards Considerations, 33210-33225 [E5-2848]

Agencies

• NUCLEAR REGULATORY COMMISSION

[Federal Register Volume 70, Number 108 (Tuesday, June 7, 2005)]
[Notices]
[Pages 33210-33225]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E5-2848]


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NUCLEAR REGULATORY COMMISSION


Biweekly Notice; Applications and Amendments to Facility 
Operating Licenses Involving No Significant Hazards Considerations

Background

    Pursuant to section 189a.(2) of the Atomic Energy Act of 1954, as 
amended (the Act), the U.S. Nuclear Regulatory Commission (the 
Commission or NRC staff) is publishing this regular biweekly notice. 
The Act requires the Commission publish notice of any amendments 
issued, or proposed to be issued and grants the Commission the 
authority to issue and make immediately effective any amendment to an 
operating license upon a determination by the Commission that such 
amendment involves no significant hazards consideration, 
notwithstanding the pendency before the Commission of a request for a 
hearing from any person.
    This biweekly notice includes all notices of amendments issued, or 
proposed to be issued from May 13, 2005 to May 25, 2005. The last 
biweekly notice was published on May 24, 2005 (70 FR 29785).

Notice of Consideration of Issuance of Amendments to Facility Operating 
Licenses, Proposed No Significant Hazards Consideration Determination, 
and Opportunity for a Hearing

    The Commission has made a proposed determination that the following 
amendment requests involve no significant hazards consideration. Under 
the Commission's regulations in 10 CFR 50.92, this means that operation 
of the facility in accordance with the proposed amendment would not (1) 
involve a significant increase in the probability or consequences of an 
accident previously evaluated; or (2) create the possibility of a new 
or different kind of accident from any accident previously evaluated; 
or (3) involve a significant reduction in a margin of safety. The basis 
for this proposed determination for each amendment request is shown 
below.
    The Commission is seeking public comments on this proposed 
determination. Any comments received within 30 days after the date of 
publication of this notice will be considered in making any final 
determination. Within 60 days after the date of publication of this 
notice, the licensee may file a request for a hearing with respect to 
issuance of the amendment to the subject facility operating license and 
any person whose interest may be affected by this proceeding and who 
wishes to participate as a party in the proceeding must file a written 
request for a hearing and a petition for leave to intervene.
    Normally, the Commission will not issue the amendment until the 
expiration of 60 days after the date of publication of this notice. The 
Commission may issue the license amendment before expiration of the 60-
day period provided that its final determination is that the amendment 
involves no significant hazards consideration. In addition, the 
Commission may issue the amendment prior to the expiration of the 30-
day comment period should circumstances change during the 30-day 
comment period such that failure to act in a timely way would result, 
for example in derating or shutdown of the facility. Should the 
Commission take action prior to the expiration of either the comment 
period or the notice period, it

[[Page 33211]]

will publish in the Federal Register a notice of issuance. Should the 
Commission make a final No Significant Hazards Consideration 
Determination, any hearing will take place after issuance. The 
Commission expects that the need to take this action will occur very 
infrequently.
    Written comments may be submitted by mail to the Chief, Rules and 
Directives Branch, Division of Administrative Services, Office of 
Administration, U.S. Nuclear Regulatory Commission, Washington, DC 
20555-0001, and should cite the publication date and page number of 
this Federal Register notice. Written comments may also be delivered to 
Room 6D22, Two White Flint North, 11545 Rockville Pike, Rockville, 
Maryland, from 7:30 a.m. to 4:15 p.m. Federal workdays. Copies of 
written comments received may be examined at the Commission's Public 
Document Room (PDR), located at One White Flint North, Public File Area 
O1F21, 11555 Rockville Pike (first floor), Rockville, Maryland. The 
filing of requests for a hearing and petitions for leave to intervene 
is discussed below.
    Within 60 days after the date of publication of this notice, the 
licensee may file a request for a hearing with respect to issuance of 
the amendment to the subject facility operating license and any person 
whose interest may be affected by this proceeding and who wishes to 
participate as a party in the proceeding must file a written request 
for a hearing and a petition for leave to intervene. Requests for a 
hearing and a petition for leave to intervene shall be filed in 
accordance with the Commission's ``Rules of Practice for Domestic 
Licensing Proceedings'' in 10 CFR part 2. Interested persons should 
consult a current copy of 10 CFR 2.309, which is available at the 
Commission's PDR, located at One White Flint North, Public File Area 
01F21, 11555 Rockville Pike (first floor), Rockville, Maryland. 
Publicly available records will be accessible from the Agencywide 
Documents Access and Management System's (ADAMS) Public Electronic 
Reading Room on the Internet at the NRC Web site, https://www.nrc.gov/
reading-rm/doc-collections/cfr/. If a request for a hearing or petition 
for leave to intervene is filed within 60 days, the Commission or a 
presiding officer designated by the Commission or by the Chief 
Administrative Judge of the Atomic Safety and Licensing Board Panel, 
will rule on the request and/or petition; and the Secretary or the 
Chief Administrative Judge of the Atomic Safety and Licensing Board 
will issue a notice of a hearing or an appropriate order.
    As required by 10 CFR 2.309, a petition for leave to intervene 
shall set forth with particularity the interest of the petitioner in 
the proceeding, and how that interest may be affected by the results of 
the proceeding. The petition should specifically explain the reasons 
why intervention should be permitted with particular reference to the 
following general requirements: (1) The name, address, and telephone 
number of the requestor or petitioner; (2) the nature of the 
requestor's/petitioner's right under the Act to be made a party to the 
proceeding; (3) the nature and extent of the requestor's/petitioner's 
property, financial, or other interest in the proceeding; and (4) the 
possible effect of any decision or order which may be entered in the 
proceeding on the requestor's/petitioner's interest. The petition must 
also set forth the specific contentions which the petitioner/requestor 
seeks to have litigated at the proceeding.
    Each contention must consist of a specific statement of the issue 
of law or fact to be raised or controverted. In addition, the 
petitioner/requestor shall provide a brief explanation of the bases for 
the contention and a concise statement of the alleged facts or expert 
opinion which support the contention and on which the petitioner/
requestor intends to rely in proving the contention at the hearing. The 
petitioner/requestor must also provide references to those specific 
sources and documents of which the petitioner is aware and on which the 
petitioner/requestor intends to rely to establish those facts or expert 
opinion. The petition must include sufficient information to show that 
a genuine dispute exists with the applicant on a material issue of law 
or fact. Contentions shall be limited to matters within the scope of 
the amendment under consideration. The contention must be one which, if 
proven, would entitle the petitioner/requestor to relief. A petitioner/
requestor who fails to satisfy these requirements with respect to at 
least one contention will not be permitted to participate as a party.
    Those permitted to intervene become parties to the proceeding, 
subject to any limitations in the order granting leave to intervene, 
and have the opportunity to participate fully in the conduct of the 
hearing.
    If a hearing is requested, and the Commission has not made a final 
determination on the issue of no significant hazards consideration, the 
Commission will make a final determination on the issue of no 
significant hazards consideration. The final determination will serve 
to decide when the hearing is held. If the final determination is that 
the amendment request involves no significant hazards consideration, 
the Commission may issue the amendment and make it immediately 
effective, notwithstanding the request for a hearing. Any hearing held 
would take place after issuance of the amendment. If the final 
determination is that the amendment request involves a significant 
hazards consideration, any hearing held would take place before the 
issuance of any amendment.
    A request for a hearing or a petition for leave to intervene must 
be filed by: (1) First class mail addressed to the Office of the 
Secretary of the Commission, U.S. Nuclear Regulatory Commission, 
Washington, DC 20555-0001, Attention: Rulemaking and Adjudications 
Staff; (2) courier, express mail, and expedited delivery services: 
Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 
Rockville Pike, Rockville, Maryland, 20852, Attention: Rulemaking and 
Adjudications Staff; (3) e-mail addressed to the Office of the 
Secretary, U.S. Nuclear Regulatory Commission, HearingDocket@nrc.gov; 
or (4) facsimile transmission addressed to the Office of the Secretary, 
U.S. Nuclear Regulatory Commission, Washington, DC, Attention: 
Rulemakings and Adjudications Staff at (301) 415-1101, verification 
number is (301) 415-1966. A copy of the request for hearing and 
petition for leave to intervene should also be sent to the Office of 
the General Counsel, U.S. Nuclear Regulatory Commission, Washington, DC 
20555-0001, and it is requested that copies be transmitted either by 
means of facsimile transmission to (301) 415-3725 or by e-mail to 
OGCMailCenter@nrc.gov. A copy of the request for hearing and petition 
for leave to intervene should also be sent to the attorney for the 
licensee.
    Nontimely requests and/or petitions and contentions will not be 
entertained absent a determination by the Commission or the presiding 
officer of the Atomic Safety and Licensing Board that the petition, 
request and/or the contentions should be granted based on a balancing 
of the factors specified in 10 CFR 2.309(a)(1)(i)-(viii).
    For further details with respect to this action, see the 
application for amendment which is available for public inspection at 
the Commission's PDR, located at One White Flint North, Public File 
Area 01F21, 11555 Rockville Pike (first floor), Rockville, Maryland. 
Publicly available records will be accessible from the ADAMS Public 
Electronic Reading Room on the Internet at the NRC Web site, https://

[[Page 33212]]

www.nrc.gov/reading-rm/adams.html. If you do not have access to ADAMS 
or if there are problems in accessing the documents located in ADAMS, 
contact the PDR Reference staff at 1 (800) 397-4209, (301) 415-4737 or 
by e-mail to pdr@nrc.gov.

Detroit Edison Company, Docket No. 50-341, Fermi 2, Monroe County, 
Michigan

    Date of amendment request: May 18, 2005.
    Description of amendment request: The proposed amendment would 
revise Fermi 2 Technical Specifications (TSs) to add Actions to 
Limiting Condition for Operation (LCO) 3.8.1, ``AC Sources--
Operating,'' for one offsite circuit inoperable, for two offsite 
circuits inoperable, and for one offsite circuit and one or both 
emergency diesel generators (EDGs) in one Division inoperable, in 
accordance with Regulatory Guide 1.93, ``Availability of Electric Power 
Sources.'' The current Fermi 2 TSs contain only a single Action for one 
or two offsite circuits inoperable.
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), the licensee has 
provided its analysis of the issue of no significant hazards 
consideration, which is presented below:

    1. The proposed change does not involve a significant increase 
in the probability or consequences of an accident previously 
evaluated.
    The proposed change to replace the existing LCO 3.8.1 Action C 
for one or two offsite circuits inoperable with a required 
Completion Time of 12 hours to be in MODE 3, and 36 hours to be in 
MODE 4, with new Actions C, D, and E to allow a single offsite 
circuit to be inoperable for up to 72 hours, two offsite circuits to 
be inoperable for up to 24 hours, and one offsite circuit and one or 
both EDGs in one Division to be inoperable for up to 12 hours, 
provided other Required Actions are taken is consistent with the 
NUREG 1433, ``Standard Technical Specifications General Electric 
Plants, BWR/4,'' criteria, and with the guidelines in Regulatory 
Guide 1.93. There is no change in plant design, and [Title 10 of the 
Code of Federal Regulations (10 CFR)] 10 CFR 50, Appendix A, General 
Design Criteria 17, ``Electric Power Systems'' will continue to be 
met. Increasing the Completion Times for inoperable offsite circuits 
will not significantly increase the potential for a loss of offsite 
power. This is due to the redundancy and diversity of the offsite 
electrical configuration at Fermi 2. Inoperability of an offsite 
circuit does slightly increase the potential for a loss of 
divisional power. The probability of losing the opposite division of 
offsite power in this condition is extremely small due to the 
physical separation of the offsite power sources that feed Fermi 2. 
Furthermore, the 10 CFR 50.65(a)(4) program monitors the condition 
of the offsite electrical system and switchyard configuration for 
each entry into the extended completion time to ensure that there is 
no significant increase in the probability or consequences of an 
accident.
    The proposed change does not alter the operation of any plant 
equipment assumed to function in response to an analyzed event or 
otherwise increase its failure probability. Therefore, this change 
does not involve a significant increase in the probability or the 
consequences of any accident previously evaluated.
    2. The proposed change does not create the possibility of a new 
or different kind of accident from any accident previously 
evaluated.
    The proposed change does not alter the design, configuration, or 
method of operation of the plant. It simply provides longer 
Completion Times for inoperable offsite circuits. No physical or 
operational changes to the components of the A. C. power systems are 
being made by this change; therefore, no new system interactions are 
being created. The proposed change does not produce any parameters 
or conditions that could contribute to the initiation of accidents 
different from those already evaluated. Therefore, this change does 
not create the possibility of a new or different kind of accident 
from any accident previously evaluated.
    3. The change does not involve a significant reduction in the 
margin of safety.
    The proposed change will replace the existing LCO 3.8.1 Action C 
for one or two offsite circuits inoperable with a required 
Completion Time of 12 hours to be in MODE 3, and 36 hours to be in 
MODE 4, with new Actions C, D, and E to allow a single offsite 
circuit to be inoperable for up to 72 hours, two offsite circuits to 
be inoperable for up to 24 hours, and one offsite circuit and one or 
both EDGs in one Division to be inoperable for up to 12 hours, 
provided other Required Actions are taken. This change is consistent 
with NUREG 1433, ``Standard Technical Specifications General 
Electric Plants, BWR/4,'' and with the guidelines in Regulatory 
Guide 1.93. The proposed change does not affect any analysis that is 
used to establish safety margins, nor does it alter the design, 
configuration, or method of operation of the plant. Therefore, the 
proposed change does not involve a significant reduction in a margin 
of safety.

    The NRC staff has reviewed the licensee's analysis and, based on 
this review, it appears that the three standards of 10 CFR 50.92(c) are 
satisfied. Therefore, the NRC staff proposes to determine that the 
amendment request involves no significant hazards consideration.
    Attorney for licensee: David G. Pettinari, Legal Department, 688 
WCB, Detroit Edison Company, 2000 2nd Avenue, Detroit, Michigan 48226-
1279.
    NRC Section Chief: L. Raghavan.

Energy Northwest, Docket No. 50-397, Columbia Generating Station, 
Benton County, Washington

    Date of amendment request: April 19, 2005.
    Description of amendment request: The proposed amendment would 
revise technical specifications (TS) testing frequency for the 
surveillance requirement (SR) in TS 3.1.4, ``Control Rod Scram Times.'' 
Specifically, the proposed change would revise the frequency for SR 
3.1.4.2, Control Rod Scram Time Testing, from ``120 days cumulative 
operation in MODE 1'' to ``200 days cumulative operation in MODE 1.''
    The NRC staff issued a notice of availability of a model no 
significant hazards consideration (NSHC) determination for referencing 
in licensing amendment applications in the Federal Register on August 
23, 2004 (69 FR 51864). The licensee affirmed the applicability of the 
model NSHC determination in its application dated April 19, 2005.
    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:

    1. Does the proposed change involve a significant increase in 
the probability or consequences of an accident previously evaluated?
    Response: No.
    The proposed change extends the frequency for testing control 
rod scram time testing from every 120 days of cumulative Mode 1 
operation to 200 days of cumulative Mode 1 operation. The frequency 
of surveillance testing is not an initiator of any accident 
previously evaluated. The frequency of surveillance testing does not 
affect the ability to mitigate any accident previously evaluated, as 
the tested component is still required to be operable. Therefore, 
the proposed change does not involve a significant increase in the 
probability or consequences of an accident previously evaluated.
    2. Does the change create the possibility of a new or different 
kind of accident from any accident previously evaluated?
    Response: No.
    The proposed change extends the frequency for testing control 
rod scram time testing from every 120 days of cumulative Mode 1 
operation to 200 days of cumulative Mode 1 operation. The proposed 
change does not result in any new or different modes of plant 
operation. Therefore, the proposed change does not create the 
possibility of a new or different kind of accident from any 
previously evaluated.
    3. Does the proposed change involve a significant reduction in a 
margin of safety?
    Response: No.
    The proposed change extends the frequency for testing control 
rod scram time

[[Page 33213]]

testing from every 120 days of cumulative Mode 1 operation to 200 
days of cumulative Mode 1 operation. The proposed change continues 
to test the control rod scram time to ensure the assumptions in the 
safety analysis are protected. Therefore, the proposed change does 
not involve a significant reduction in a margin of safety.

    Based on the above, the proposed change presents no significant 
hazards consideration under the standards set forth in 10 CFR 50.92(c), 
and accordingly, a finding of ``no significant hazards consideration'' 
is justified.
    Attorney for licensee: Thomas C. Poindexter, Esq., Winston & 
Strawn, 1400 L Street, NW., Washington, DC 20005-3502.
    NRC Section Chief: Robert A. Gramm.

Entergy Nuclear Operations, Docket Nos. 50-247 and 50-286, Indian Point 
Nuclear Generating Unit Nos. 2 and 3 (IP2 and 3), Westchester County, 
New York

    Date of amendment request: April 22, 2005.
    Description of amendment request: The amendments would revise the 
surveillance requirements (SRs) for Technical Specification (TS) 3.3.5, 
``Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation.'' 
Specifically, a note would be added to IP2 TS SR 3.3.5.2 to indicate 
that the verification of the setpoint is not required for the 480 volt 
(V) bus degraded voltage function when performing the trip actuating 
device operational test (TADOT). A similar note would be added to IP3 
TS SR 3.3.5.1 for the 480V degraded voltage and undervoltage functions.
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), the licensee has 
provided its analysis of the issue of no significant hazards 
consideration, which is presented below:

    1. Does the proposed change involve a significant increase in 
the probability or consequences of an accident previously 
evaluated[?]
    Response: No.
    The proposed change adds a note to indicate that the IP2 and IP3 
degraded voltage relays and the IP3 undervoltage relays do not 
require setpoint verification when the TADOT required by TS 
surveillances is performed on a monthly basis. Setpoint verification 
of these relays occurs as part of the channel calibration that is 
performed at either an 18 month or a 24 month frequency. These 
relays are used to sense either degraded voltage or undervoltage on 
the 480 volt safety related buses and to initiate the start of the 
EDG [emergency diesel generator] for all events where the loss of 
offsite power is postulated. This function has no effect on the 
probability of an accident previously evaluated since it is not 
associated with the initiation of any accident. The relay setpoint 
verification frequency of 18 or 24 months has no significant effect 
on the consequences of an accident because the relays are intended 
to be calibrated on this frequency. This frequency of calibration is 
based on operating experience, and is consistent with industry 
practice. Therefore, the proposed change does not involve a 
significant increase in the probability or consequences of an 
accident previously evaluated.
    2. Does the proposed change create the possibility of a new or 
different kind of accident from any accident previously evaluated?
    Response: No.
    The proposed change adds a note to indicate that the IP2 and IP3 
degraded voltage relays and the IP3 undervoltage relays do not 
require setpoint verification when the TADOT required by TS 
surveillances is performed on a monthly basis. This effectively 
changes the frequency required by the surveillance requirement from 
31 days to either 18 months or 24 months. The change does not affect 
the function of the relays or otherwise affect the design and 
operation of plant systems and components and therefore no new 
accident scenarios would be created. The change does not affect the 
manner is which equipment is operated but does affect the manner in 
which it is maintained by extending the frequency for setpoint 
verification. The frequency change continues to provide adequate 
verification of the operability of equipment and limits the time 
which the relay function is inoperable or degraded while performing 
verification. Therefore, no new failure modes are being introduced 
that could lead to different accidents.
    3. Does the proposed change involve a significant reduction in a 
margin of safety?
    Response: No.
    The proposed change adds a note to indicate that the IP2 and IP3 
degraded voltage relays and the IP3 undervoltage relays do not 
require setpoint verification when the TADOT required by TS 
surveillances is performed on a monthly basis. Setpoint verification 
of these relays occurs as part of the channel calibration that is 
performed at either an 18 month or a 24 month frequency. The margin 
associated with these relays is the assurance that these relays will 
properly sense either degraded voltage or undervoltage on the 480 
volt safety related buses and to initiate the start of the EDG for 
all events where the loss of offsite power is postulated. The 
proposed frequency of calibration is based on operating experience, 
and is consistent with industry practice. These indicate that 
setpoint verification at 18 month or 24 month [frequency] is 
adequate to assure performance of the function. Verification of 
setpoints on a monthly basis either degrades the reliability of the 
function or makes it inoperable. Therefore, the proposed change does 
not involve a significant reduction in [a] margin of safety.

    The NRC staff has reviewed the licensee's analysis and, based on 
this review, it appears that the three standards of 10 CFR 50.92(c) are 
satisfied. Therefore, the NRC staff proposes to determine that the 
amendment request involves no significant hazards consideration.
    Attorney for licensee: Mr. John Fulton, Assistant General Counsel, 
Entergy Nuclear Operations, Inc., 440 Hamilton Avenue, White Plains, NY 
10601.
    NRC Section Chief: Richard J. Laufer.

Exelon Generation Company, LLC, Docket Nos. 50-373 and 50-374, LaSalle 
County Station, Units 1 and 2, LaSalle County, Illinois

    Date of amendment request: April 13, 2005.
    Description of amendment request: The proposed amendments would 
extend the completion time (CT) for required Action A.1, ``Restore 
Residual Heat Removal Service Water (RHRSW) subsystem to OPERABLE 
status,'' associated with Technical Specification (TS) Section 3.7.1 
from 7 days to 10 days. This proposed change would only be used during 
the upcoming Unit 1 2006 refueling outage. The establishment of a 6 day 
(for Division 2 core standby cooling system (CSCS) maintenance) or 10 
day (for Division 1 CSCS maintenance ) CT for TS Section 3.7.2 when one 
or more required diesel generator cooling water (DGCW) subsystem(s) are 
inoperable. This proposed change will only be used during each of the 
upcoming Unit 1 2006, and Unit 2 2007, refueling outages, and during 
the subsequent Unit 1 2008, refueling outage. An extension of the CT 
for required Action C.4, ``Restore required Diesel Generator (DG) to 
OPERABLE status,'' associated with TS Section 3.8.1 from 72 hours to 6 
days. This proposed change will only be used during the upcoming Unit 2 
2007 refueling outage, and during subsequent Unit 1, 2008, refueling 
outage. An extension of the CT for required Action F.1, ``Restore one 
required Diesel Generator (DG) to OPERABLE status,'' associated with TS 
Section 3.8.1 from 2 hours to 6 days. This proposed change will only be 
used during the upcoming Unit 2, 2007, refueling outage, and during 
subsequent Unit 1, 2008, refueling outage.
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), the licensee has 
provided its analysis of the issue of no significant hazards 
consideration, which is presented below:

    1. The proposed TS change does not involve a significant 
increase in the probability or consequences of an accident 
previously evaluated.

[[Page 33214]]

    The proposed changes have been evaluated using the risk-informed 
processes described in RG [Regulatory Guide] 1.174, ``An Approach 
for Using Probabilistic Risk Assessment in Risk-Informed Decisions 
on Plant-Specific Changes to the Licensing Basis,'' dated July 1998, 
and RG 1.177, ``An Approach for Plant-Specific, Risk-Informed 
Decision Making: Technical Specifications,'' dated August 1998. The 
risk associated with the proposed change was found to be acceptable.
    The previously analyzed accidents are initiated by the failure 
of plant structures, systems, or components. The proposed change 
does not have a detrimental impact on the integrity of any plant 
structure, system, or component that initiates an analyzed event. No 
active or passive failure mechanisms that could lead to an accident 
are affected. Non-code line stops required to isolate the Unit 1 
portion of the common discharge header from the Unit 2 portion of 
the header during the specified CSCS maintenance will maintain the 
availability of the online unit's Division 2 CSCS system. The non-
code line stops being used to isolate the system during the 
specified refueling outages are being designed to the same pressure 
rating and seismic requirements as the CSCS piping.
    Redundancy is provided by designing the CSCS system as multiple 
independent subsystems. Separation between subsystems assures that 
no single failure can affect more than one subsystem. Therefore, 
assuming a single failure in any subsystem including the subsystem 
shared between units, two subsystems in each unit will remain 
unaffected. These two subsystems can supply the minimum required 
cooling water for safe shutdown of a unit or mitigate the 
consequences of an accident.
    The proposed limited use of increased CT's of the operating 
unit's CSCS system maintains the design basis assumptions; 
therefore, the proposed change does not involve a significant 
increase in the consequences of an accident previously evaluated.
    2. The proposed TS change does not create the possibility of a 
new or different kind of accident from any accident previously 
evaluated.
    The proposed change involves the temporary installation of new 
equipment (mechanical line stops) that will be designed and 
installed to the same pressure rating and seismic design as the CSCS 
piping. The currently installed equipment will not be operated in a 
new or different manner. No new or different system interactions are 
created and no new processes are introduced. The proposed changes 
will not introduce any new failure mechanisms, malfunctions, or 
accident initiators not already considered in the design and 
licensing bases. Based on this evaluation, the proposed change does 
not create the possibility of a new or different kind of accident 
from any accident previously evaluated.
    3. The proposed TS change does not involve a significant 
reduction in a margin of safety.
    The proposed change does not alter any existing setpoints at 
which protective actions are initiated and no new setpoints or 
protective actions are introduced. The design and operation of the 
CSCS system remains unchanged. The risk assessment with the proposed 
increase in the CTs for TS 3.7.1, TS 3.7.2, and TS 3.8.1 were 
evaluated using the risk-informed processes described in RG 1.174, 
``An Approach for Using Probabilistic Risk Assessment in Risk-
Informed Decisions on Plant-Specific Changes to the Licensing 
Basis,'' dated July 1998, and RG 1.177, ``An Approach for Plant-
Specific, Risk-Informed Decision Making: Technical Specifications,'' 
dated August 1998. The risk was shown to be acceptable. Based on 
this evaluation, the proposed change does not involve a significant 
reduction in a margin of safety.

    The NRC staff has reviewed the licensee's analysis and, based on 
this review, it appears that the three standards of 10 CFR 50.92(c) are 
satisfied. Therefore, the NRC staff proposes to determine that the 
requested amendments involve no significant hazards consideration.
    Attorney for licensee: Mr. Thomas S. O'Neill, Associate General 
Counsel, Exelon Generation Company, LLC, 4300 Winfield Road, 
Warrenville, IL 60555.
    NRC Section Chief : Gene Y. Suh.

FirstEnergy Nuclear Operating Company, et al., Docket No. 50-412, 
Beaver Valley Power Station, Unit No. 2 (BVPS-2), Beaver County, 
Pennsylvania

    Date of amendment request: April 11, 2005.
    Description of amendment request: The proposed amendment would 
revise the BVPS-2 Technical Specification (TS) 3.4.5 to change the 
scope of the steam generator (SG) tubesheet examinations required in 
the SG tubesheet region by using the F* inspection methodology. 
Specifically, the proposed amendment would alter the tube inspection to 
exclude the portion of the SG tube within the tubesheet below the F* 
distance and to exclude the tube-to-tubesheet weld, by crediting the 
methodology described in Westinghouse Topical Report, WCAP-16385, 
Revision 1. The F* distance is the distance from the top of the 
tubesheet to the bottom of the F* length (the maximum length of tubing 
below the bottom of the roll transition (BRT) which must be 
demonstrated to be non-degraded and which is defined as 1.97 inches on 
the hot leg side) plus the distance to the BRT and non-destructive 
examination uncertainties. The licensee's proposed amendment also would 
revise the TS requirements to require tubes with service-induced 
degradation identified in the F* distance or less than or equal to 3.0 
inches below the top of the tubesheet, whichever is greater, to be 
repaired or removed from service upon detection. The TS Index, affected 
TS pages and Bases would also be revised and repaginated as necessary 
to reflect the proposed TS change.
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), the licensee has 
provided its analysis of the issue of no significant hazards 
consideration, which is presented below:

    1. Does the proposed change involve a significant increase in 
the probability or consequences of an accident previously evaluated?
    No. The proposed change modifies the BVPS Unit 2 TSs to 
incorporate steam generator tube inspection scope based on WCAP-
16385, Revision 1. Of the various accidents previously evaluated in 
the BVPS Unit 2 Updated Final Safety Analysis Report (UFSAR), the 
proposed changes only affect the steam generator tube rupture (SGTR) 
event evaluation and the postulated steam line break (SLB) accident 
evaluation. Loss-of-coolant accident (LOCA) conditions cause a 
compressive axial load to act on the tube. Therefore, since the LOCA 
tends to force the tube into the tubesheet rather than pull it out, 
it is not a factor in this amendment request. Another faulted load 
consideration is a safe shutdown earthquake (SSE); however, the 
seismic analysis of Model 51M SGs has shown that axial loading of 
the tubes is negligible during an SSE.
    For the SGTR event, the required structural margins of the steam 
generator tubes will be maintained by the presence of the tubesheet. 
Tube rupture is precluded for cracks in the tube expansion region 
due to the constraint provided by the tubesheet. Therefore, 
Regulatory Guide (RG) 1.121, ``Bases for Plugging Degraded PWR 
[pressurized-water reactor] Steam Generator Tubes,'' margins against 
burst are maintained for both normal and postulated accident 
conditions.
    The F* length supplies the necessary resistive force to preclude 
pullout loads under both normal operating and accident conditions. 
The contact pressure results from the tube expansion process used 
during manufacturing and from the differential pressure between the 
primary and secondary side. The proposed changes do not affect other 
systems, structures, components or operational features. Therefore, 
the proposed change results in no significant increase in the 
probability of the occurrence of an SGTR or SLB accident.
    The consequences of an SGTR event are affected by the primary-
to-secondary leakage flow during the event. Primary-to-secondary 
leakage flow through a postulated broken tube is not affected by the 
proposed change since the tubesheet enhances the tube integrity in 
the region of the expansion by precluding tube deformation beyond 
its initial expanded outside diameter. The resistance to both tube 
rupture and collapse is strengthened by the tubesheet in that 
region. At normal operating pressures, leakage from primary water 
stress corrosion cracking (PWSCC) below the F* length is limited by 
both the tube-to-tubesheet crevice and the limited crack opening 
permitted by

[[Page 33215]]

the tubesheet constraint. Consequently, negligible normal operating 
leakage is expected from cracks within the tubesheet region.
    SLB leakage is limited by leakage flow restrictions resulting 
from the crack and tube-to-tubesheet contact pressures that provide 
a restricted leakage path above the indications and also limit the 
degree of crack face opening compared to free span indications. The 
total leakage (i.e., the combined leakage for all such tubes) meets 
the industry performance criterion, plus the combined leakage 
developed by any other alternate repair criteria, and will be 
maintained below the maximum allowable SLB leak rate limit, such 
that off-site doses are maintained less than 10 CFR [Part] 100 
guideline values and the limits evaluated in the BVPS Unit 2 UFSAR.
    Therefore, based on the above evaluation, the proposed changes 
do not involve a significant increase in the probability or 
consequences of an accident previously evaluated.
    2. Does the proposed change create the possibility of a new or 
different kind of accident from any accident previously evaluated?
    No. The proposed changes do not introduce any changes or 
mechanisms that create the possibility of a new or different kind of 
accident. Tube bundle integrity will continue to be maintained for 
all plant conditions upon implementation of the F* methodology.
    The proposed changes do not introduce any new equipment or any 
change to existing equipment. No new effects on existing equipment 
are created nor are any new malfunctions introduced.
    Therefore, the proposed change does not create the possibility 
of a new or different kind of accident from any previously 
evaluated.
    3. Does the proposed change involve a significant reduction in a 
margin of safety?
    No. The proposed changes maintain the required structural 
margins of the steam generator tubes for both normal and accident 
conditions, including the planned uprated power level of 2910 Mwt. 
NRC [Nuclear Regulatory Commission] Regulatory Guide (RG) 1.121 is 
used as the basis in the development of the F* methodology for 
determining that steam generator tube integrity considerations are 
maintained within acceptable limits. RG 1.121 describes a method 
acceptable to the NRC staff for meeting General Design Criteria 14, 
15, 31, and 32 by reducing the probability and consequences of an 
SGTR. RG 1.121 concludes that by determining the limiting safe 
conditions of tube wall degradation beyond which tubes with 
unacceptable cracking, as established by inservice inspection, 
should be removed from service or repaired, the probability and 
consequences of an SGTR are reduced. This RG uses safety factors on 
loads for tube burst that are consistent with the requirements of 
Section III of the American Society of Mechanical Engineers (ASME) 
Code.
    For primarily axially oriented cracking located within the 
tubesheet, tube burst is precluded due to the presence of the 
tubesheet. WCAP-16385, Revision 1, defines a length, F*, of 
degradation-free expanded tubing that provides the necessary 
resistance to tube pullout due to the pressure-induced forces (with 
applicable safety factors applied). Application of the F* criteria 
will preclude unacceptable primary-to-secondary leakage during all 
plant conditions. The methodology for determining leakage provides 
for large margins between calculated and actual leakage values in 
the F* criteria.
    Plugging of the steam generator tubes reduces the reactor 
coolant flow margin for core cooling. Implementation of F* 
methodology at Beaver Valley Unit 2 will result in maintaining the 
margin of flow that may have otherwise been reduced by tube 
plugging.
    Based on the above, it is concluded that the proposed changes do 
not result in a significant reduction of margin with respect to 
plant safety as defined in the Final Safety Analysis Report Update 
or bases of the plant Technical Specifications.

    The NRC staff has reviewed the licensee's analysis and, based on 
this review, it appears that the three standards of 10 CFR 50.92(c) are 
satisfied. Therefore, the NRC staff proposes to determine that the 
amendment request involves no significant hazards consideration.
    Attorney for licensee: Mary O'Reilly, FirstEnergy Nuclear Operating 
Company, FirstEnergy Corporation, 76 South Main Street, Akron, OH 
44308.
    NRC Section Chief: Richard J. Laufer.

Florida Power and Light Company, Docket No. 50-389, St. Lucie Plant, 
Unit No. 2 (SL2), St. Lucie County, Florida

    Date of amendment request: March 31, 2005.
    Description of amendment request: The proposed amendment would 
revise Administrative Technical Specification Section 6.8.4.h, 
``Containment Leakage Rate Testing Program,'' to allow a one-time 
extension of the currently approved 15-year test interval to 
approximately 15.5 years.
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), the licensee has 
provided its analysis of the issue of no significant hazards 
consideration, which is presented below:

    (1) Operation of the facility in accordance with the proposed 
amendment would not involve a significant increase in the 
probability or consequences of an accident previously evaluated.
    The proposed change does not involve a significant increase in 
the probability or consequences of an accident previously evaluated. 
The proposed amendment of the Technical Specifications adds a one-
time extension to the current surveillance interval for Type A 
testing (ILRT [integrated leak rate testing]). The current test 
interval of 15 years from the last Type A test would be extended to 
end prior to startup from the SL2-17 refueling. This is anticipated 
to be an approximately six-month addition to the 15 year interval. 
The proposed extension to the Type A testing interval does not 
significantly increase the probability of an accident previously 
evaluated since the containment Type A test is not a modification, 
nor a change in the way that plant systems, structures or components 
(SSC) are operated, and is not an activity that could lead to 
equipment failure or accident initiation. The proposed extension of 
the test interval does not involve a significant increase in the 
consequences of an accident since research documented in NUREG-1493 
has found that generically, very few potential leak paths are not 
identified with Type B and C tests (LLRT [local leak-rate test]). 
The Type B and C testing are unaffected by this proposed change. The 
NUREG concluded that an increase in the Type A test interval to 
twenty years resulted in an imperceptible increase in risk. St. 
Lucie Unit 2 provides a high degree of assurance through testing and 
inspection that the containment will not degrade in a manner only 
detectable by Type A testing. Inspections required by the ASME 
[American Society of Mechanical Engineers] Code, the containment 
leakage rate testing program, the plant protective coatings program, 
and Maintenance Rule are performed in order to identify indications 
of containment degradation that could affect leak tightness. Type B 
and C testing required by 10 CFR 50, Appendix J, are not affected by 
this proposed extension to the Type A test interval and will 
identify openings in containment penetrations that would otherwise 
require a Type A test.
    (2) Operation of the facility in accordance with the proposed 
amendment would not create the possibility of a new or different 
kind of accident from any previously evaluated.
    The proposed change does not result in facility operation that 
would create the possibility of a new or different kind of accident 
from any accident previously evaluated. The proposed extension to 
Type A testing does not create a new or different type of accident 
for St. Lucie because no physical plant changes are made and no 
compensatory measures are being imposed that could potentially lead 
to a failure. There are no operational changes that could introduce 
a new failure mode or create a new or different kind of accident. 
The proposed change only adds an extension to the current interval 
for Type A testing and does not change implementation aspects of the 
test.
    (3) Operation of the facility in accordance with the proposed 
amendment would not involve a significant reduction in a margin of 
safety.
    The proposed change would not result in operation of the 
facility involving a significant reduction in a margin of safety. 
The proposed license amendment adds a one-time extension to the 
current interval for Type A testing (ILRT). The current one-time 
test interval of 15 years from the last Type A test would be 
extended to end prior to startup from the SL2-17 refueling outage. 
This is anticipated to be an approximately six month addition to the 
15 year interval.

[[Page 33216]]

    The NUREG-1493 generic study of the effects of extending the 
Type A test interval out to 20 years concluded that there is an 
imperceptible increase in plant risk. A plant specific risk 
calculation obtained results consistent with the generic conclusions 
regarding risk which show a slight but negligible increase in risk. 
Inspections required by the ASME code and maintenance rule are 
performed to ensure that the containment will not degrade in a 
manner that is only detectable by Type A testing (ILRT).

    The NRC staff has reviewed the licensee's analysis and, based on 
this review, it appears that the three standards of 50.92(c) are 
satisfied. Therefore, the NRC staff proposes to determine that the 
amendment request involves no significant hazards consideration.
    Attorney for licensee: M.S. Ross, Attorney, Florida Power & Light, 
P.O. Box 14000, Juno Beach, Florida 33408-0420.
    NRC Section Chief: Michael L. Marshall, Jr.

Nebraska Public Power District, Docket No. 50-298, Cooper Nuclear 
Station, Nemaha County, Nebraska

    Date of amendment request: April 13, 2005.
    Description of amendment request: The proposed amendment would 
incorporate several Technical Specification Task Force (TSTF) changes 
to the licensee's Technical Specifications (TSs). The specific TSTF 
changes that would be incorporated are:
    1. TSTF-222-A, Revision 1, ``Control Rod Scram Time Testing''--This 
change modifies TS Section 3.1.4, ``Control Rod Scram Times,'' to 
clarify that control rod scram time testing is required only for core 
cells in which work on the control rod or drive has been performed or 
fuel has been moved or replaced.
    2. TSTF-275-A, Revision 0, ``Clarify Requirement for EDG [emergency 
diesel generator] start signal on RPV [reactor pressure vessel] Level--
Low, Low, Low during RPV cavity flood-up''--This change modifies the TS 
Section 3.3.5.1, ``ECCS [emergency core cooling system] 
Instrumentation,'' to clarify that the ECCS initiation instrumentation, 
identified as being required in modes 4 and 5, is required to be 
operable only when the associated ECCS subsystems are required to be 
operable as defined in limiting condition of operation (LCO) 3.5.2, 
``ECCS--Shutdown.''
    3. TSTF-300-A, Revision 0, ``Eliminate DG [diesel generator] LOCA 
[loss-of-coolant accident]--Start SRs [surveillance requirements] while 
in S/D [shutdown] when no ECCS is Required''--This change modifies the 
TS Section 3.8.2, ``AC [alternating current] Sources--Shutdown,'' to 
add an additional note to the surveillance that verifies automatic 
start of the emergency diesel generators and automatic load shedding 
from the emergency buses, is considered to be met without the ECCS 
initiation signals operable when ECCS initiation signals are not 
required to be operable per Table 3.3.5.1-1, ECCS Instrumentation.
    4. TSTF-225, Revision 2, ``Fuel movement with inoperable refueling 
equipment interlocks''--This change modifies TS Section 3.9.1, 
``Refueling Equipment Interlocks,'' to add required actions to allow 
insertion of a control rod withdrawal block and verification that all 
control rods are fully inserted as alternate actions to suspending in-
vessel fuel movement in the event that one or more required refueling 
equipment interlocks are inoperable.
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), the licensee has 
provided its analysis of the issue of no significant hazards 
consideration, which is presented below:

    1. Do the proposed changes involve a significant increase in the 
probability or consequences of an accident previously evaluated?
    Response: No.
    1. Revision of CNS [Cooper Nuclear Station] TS SR 3.1.4.1 and SR 
3.1.4.4. The frequency at which control rod scram time is verified 
is not a precursor of an accident. A scram time slower than required 
might result in an increase in the consequences of an accident. 
However, revising the frequency for verifying the scram time of the 
control rods does not impact the scram time. Verifying that the 
scram time is acceptable will continue to be required prior to plant 
startup following fuel movement or work on the control rods or 
control rod drive system. Therefore, revising the frequency for 
verifying insertion time to clarify when it is required does not 
involve a significant increase in the probability of an accident or 
an increase in the consequences of an accident.
    2. Revision of TS Table 3.3.5.1-1. Clarifying when certain ECCS 
instrumentation must be operable with the plant shut down will not 
increase either the probability of an accident or the consequences 
of the accident. The ECCS instrumentation is required to be operable 
only when the associated ECCS subsystems are required to be 
operable. This continues to ensure that the instrumentation will be 
operable when it is required.
    3. Revision of TS SR 3.8.2.1. The frequency of verifying certain 
actions by surveillances is not a precursor to accidents. Clarifying 
that the actions required in response to an ECCS initiation signal 
are not required when the ECCS initiation signals are not required 
to be operable does not result in increased probability of an 
accident or increased consequences of an accident. Not requiring 
that a DG automatically start in response to the ECCS initiation 
signal when the ECCS subsystems that are supported by the DG are not 
required to be operable does not reduce the required ECCS 
protection.
    4. Revision of TS 3.9.1., Condition A Required Action. The 
actions taken when a refueling equipment interlock is inoperable are 
not initiators of any accident previously evaluated. The level of 
protection against withdrawing a control rod during the insertion of 
a fuel assembly or loading a fuel assembly into the vessel with a 
control rod withdrawn, provided by the proposed alternate Required 
Actions, is equivalent to that provided by the current Required 
Action. The radiological consequences of an accident described in 
the Updated Safety Analysis Report (USAR) while taking the proposed 
alternate Required Actions are not different from the consequences 
of an accident under the current Required Actions.
    Based on the above NPPD [Nebraska Public Power District] 
concludes that the proposed changes do not involve a significant 
increase in the probability or consequences of an accident 
previously evaluated.
    2. Do the proposed changes create the possibility of a new or 
different kind of accident from any accident previously evaluated?
    Response: No.
    The proposed changes to the CNS operating license involve 
revisions to the requirements for when certain surveillances are to 
be performed (change no. 1 and no. 3), clarification of when ECCS 
instrumentation is required to be operable (change no. 2), and 
addition of alternative Required Actions if certain plant components 
are inoperable (change no. 4). These changes will not result in 
revision of plant design, physical alteration of a plant structure, 
system, or component (SSC), or installation of a new or different 
type of equipment. The changes do not involve any revision of how 
the plant, an SSC, or a refueling equipment interlock, are operated. 
Based on this, the proposed changes do not create the possibility of 
a new or different kind of accident.
    3. Do the proposed changes involve a significant reduction in a 
margin of safety?
    Response: No.
    1. Revision of CNS TS SR 3.1.4.1 and SR 3.1.4.4. Sufficiently 
rapid insertion of control rods following certain accidents (scram 
time) will prevent fuel damage, and thereby maintain a margin of 
safety to fuel damage. No change is being made to the required 
insertion rate specified in plant technical specifications. 
Clarifying when control rod insertion times must be verified 
following movement of fuel assemblies, without actually changing the 
requirement (verification of insertion times will continue to be 
required whenever work that might impact the rod insertion time is 
done), does not reduce the margin of safety related to fuel damage.
    2. Revision of TS Table 3.3.5.1-1. Clarifying when certain ECCS 
instrumentation is required to be operable when CNS is in a shutdown 
mode does not change the requirement. Not requiring ECCS signals 
that initiate a DG to be operable when the ECCS subsystems that are 
supported by

[[Page 33217]]

the DG are not required to be operable does not result in a 
reduction of a margin of safety for the safety related equipment 
that is required to be operable.
    3. Revision of TS SR 3.8.2.1. Clarifying that automatic start of 
the DGs in response to the ECCS initiation signal is not required 
when the ECCS subsystems that are supported by the DG are not 
required to be operable does not result in a reduction in a margin 
of safety.
    4. Revision of TS 3.9.1, Condition A Required Action. The 
proposed alternate Required Actions to be taken when a refueling 
interlock is inoperable provide a level of protection against 
inadvertent criticality while inserting or moving fuel in the 
reactor vessel that is equivalent to the level provided by the 
current Required Action. As a result, the proposed alternate 
Required Actions do not result in a significant reduction in a 
margin of safety related to protection against inadvertent 
criticality when inserting or moving fuel assemblies.
    Based on the above NPPD concludes that the proposed changes do 
not involve a significant reduction in a margin of safety.

    The NRC staff has reviewed the licensee's analysis and, based on 
this review, it appears that the three standards of 10 CFR 50.92(c) are 
satisfied. Therefore, the NRC staff proposes to determine that the 
amendment request involves no significant hazards consideration.
    Attorney for licensee: Mr. John C. McClure, Nebraska Public Power 
District, Post Office Box 499, Columbus, NE 68602-0499.
    NRC Section Chief: David Terao.

PSEG Nuclear, LLC, Docket No. 50-354, Hope Creek Generating Station, 
Salem County, New Jersey

    Date of amendment request: February 25, 2005.
    Description of amendment request: The proposed amendment would 
revise Technical Specification (TS) 3.1.3.1, ``Control Rod 
Operability,'' such that scram discharge volume (SDV) vent or drain 
lines with inoperable valves would be isolated instead of requiring 
that the valve be restored to Operable status or the unit be placed in 
Hot Shutdown within 12 hours.
    The NRC staff issued a Notice of Opportunity for Comment in the 
Federal Register on February 24, 2003 (68 FR 8637), on possible 
amendments to revise the action for one or more SDV vent or drain lines 
with an inoperable valve, including a model safety evaluation and model 
no significant hazards consideration (NSHC) determination, using the 
consolidated line-item improvement process. The NRC staff subsequently 
issued a Notice of Availability of the models for referencing license 
amendment applications in the Federal Register on April 15, 2003 (68 FR 
18294). The licensee affirmed the applicability of the model NSHC 
determination (modified slightly to address plant-specific TS format) 
in its application dated February 25, 2005.
    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.
    A change is proposed to allow the affected SDV vent and drain 
line to be isolated when there are one or more SDV vent or drain 
lines with inoperable valves instead or requiring the valves to be 
restored to operable status or the unit be in hot shutdown within 12 
hours. With SDV vent or drain valves inoperable in one or more 
lines, the isolation function would be maintained since the 
redundant valve in the affected line would perform its safety 
function of isolating the SDV. Following the completion of the 
required action, the isolation function is fulfilled since the 
associated line is isolated. The ability to vent and drain the SDV 
is maintained and controlled through administrative controls. This 
requirement assures the reactor protection system is not adversely 
affected by the inoperable valves. With the safety functions of the 
valves being maintained, the probability or consequences of an 
accident previously evaluated are not significantly increased.
    Criterion 2--The proposed change does not create the possibility 
of a new or different kind of accident from any accident previously 
evaluated.
    The proposed change does not involve a physical alteration of 
the plant (no new or different type of equipment will be installed) 
or a change in the methods governing normal plant operation. Thus, 
this change does not create the possibility of a new or different 
kind of accident from any previously evaluated.
    Criterion 3--The proposed change does not involve a significant 
reduction in [a] margin of safety.
    The proposed change ensures that the safety functions of the SDV 
vent and drain valves are fulfilled. The isolation function is 
maintained by redundant valves and by the required action to isolate 
the affected line. The ability to vent and drain the SDV is 
maintained through administrative controls. In addition, the reactor 
protection system will prevent filling of the SDV to the point that 
it has insufficient volume to accept a full scram. Maintaining the 
safety functions related to isolation of the SDV and insertion of 
control rods ensures that the proposed change does not involve a 
significant reduction in the margin of safety.

    Based on the reasoning presented above, the NRC staff proposes to 
determine that the amendment request involves no significant hazards 
consideration.
    Attorney for licensee: Jeffrie J. Keenan, Esquire, Nuclear Business 
Unit--N21, P.O. Box 236, Hancocks Bridge, NJ 08038.
    NRC Section Chief: Darrell J. Roberts.

R.E. Ginna Nuclear Power Plant, LLC, Docket No. 50-244, R.E. Ginna 
Nuclear Power Plant, Wayne County, New York

    Date of amendment request: March 10, 2005.
    Description of amendment request: The amendment would revise 
Technical Specification Section 5.5.15, ``Containment Leakage Rate 
Testing Program,'' to allow a one-time extension of the interval 
between the Type A, integrated leakage rate tests (ILRTs), from 10 
years to no more than 15 years.
    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 to Technical Specification 5.5.15, 
Containment Leakage Rate Testing Program, involves a one-time 
extension to the current interval for Type A containment testing. 
The current test interval of ten (10) years would be extended on a 
one-time basis to no longer than fifteen (15) years from the last 
Type A test.
    The proposed Technical Specification change does not involve a 
physical change to the plant or a change in the manner which the 
plant is operated or controlled. The reactor containment is designed 
to provide an essentially leak tight barrier against the 
uncontrolled release of radioactivity to the environment for 
postulated accidents. As such the reactor containment itself and the 
testing requirements invoked to periodically demonstrate the 
integrity of the reactor containment exist to ensure the plant's 
ability to mitigate the consequences of an accident, and do not 
involve the prevention or identification of any precursors of an 
accident.
    The proposed change involves only the extension of the interval 
between Type A containment leakage tests. Type B and C containment 
leakage tests will continue to be performed at the frequency 
currently required by plant Technical Specifications. Industry 
experience has shown, as documented in NUREG-1493, that Type B and C 
containment leakage tests have identified a very large percentage of 
containment leakage paths and that the percentage of containment 
leakage paths that are detected only by Type A testing is very 
small. The Ginna ILRT test history supports this conclusion. In 
NUREG-1493 Section 10, Summary of Technical Findings, it is 
concluded, in part, that reducing the frequency of Type A 
containment leak tests to once per twenty (20) years leads to an 
imperceptible increase in risk.

[[Page 33218]]

    The proposed change does not result in an increase in core 
damage frequency since the containment system is used for mitigation 
purposes only. Containment Leakage Rate Testing Program local leak 
rate test requirements and administrative controls such as design 
change control, ASME [American Society of Mechanical Engineers] 
Section XI Inservice Inspection (ISI) Program Containment Repair and 
Replacement Program and procedural requirements for system 
restoration ensure that containment integrity is not degraded by 
plant modifications or maintenance activities. The design and 
construction requirements of the reactor containment itself combined 
with the containment inspections performed in accordance with the 
ASME Section XI Inservice Inspection (ISI) Program Containment 
Program, Boric Acid Corrosion Program, inspections in accordance 
with Regulatory Guide 1.163 position C.3 and the Maintenance Rule 
serve to provide a high degree of assurance that the containment 
will not degrade in a manner that is detectable only by Type A 
testing.
    Therefore, the proposed Technical Specification change does not 
involve a significant increase in the 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 to Technical Specification 5.5.15 involves a 
one-time extension to the current interval for Type A containment 
testing. The reactor containment and the testing requirements 
invoked to periodically demonstrate the integrity of the reactor 
containment exist to ensure the plant's ability to mitigate the 
consequences of an accident and do not involve the prevention or 
identification of any precursors of an accident. The proposed 
Technical Specification change does not involve a physical change to 
the plant (i.e., no new or different type of equipment will be 
installed) or changes in the methods in which the plant is operated 
or controlled.
    Therefore, the proposed Technical Specification change does not 
create the possibility of a new or different kind of accident from 
any previously evaluated.
    Criterion 3--The Proposed Change Does Not Involve a Significant 
Reduction in a Margin of Safety.
    The proposed change to Technical Specifications involves a one-
time extension to the current interval for Type A containment 
testing. The proposed Technical Specification change does not alter 
the manner in which safety limits, limiting safety system set 
points, or limiting conditions for operation are determined. The 
specific requirements and conditions of the Primary Containment 
Leakage Rate Testing Program, as defined in Technical 
Specifications, exist to ensure that the degree of reactor 
containment structural integrity and leak-tightness that is 
considered in the plant safety analysis is maintained. The overall 
containment leakage rate limit specified by Technical Specifications 
is maintained. The proposed change involves only the extension of 
the interval between Type A containment leakage tests. Type B and C 
containment leakage tests will continue to be performed at the 
frequency currently required by p