Text

Issuance of Amendment Nos. 152 and 152, Revise Technical Specification 3.8.1, AC Sources - Operating, to Extend Completion Time on a One-time Basis
	ML102810130
Person / Time
Site:	Comanche Peak
Issue date:	10/29/2010
From:	Balwant Singal; Plant Licensing Branch IV
To:	Flores R; Luminant Generation Co
	Singal, B K, NRR/DORL/LPL4, 301-415-3016
References
	TAC ME2546, TAC ME2547
	Download: ML102810130 (31)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 October 29, 2010 Mr. Rafael Flores Senior Vice President and Chief Nuclear Officer Attention: Regulatory Affairs Luminant Generation Company LLC P.O. Box 1002 Glen Rose, TX 76043

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS RE: REVISION TO TECHNICAL SPECIFICATION 3.8.1, "AC SOURCES - OPERATING," FOR EXTENSION OF THE COMPLETION TIME FOR THE OFFSITE CIRCUITS ON A ONE-TIME BASIS FROM 72 HOURS TO 14 DAYS (TAC NOS. ME2546 AND ME2547)

Dear Mr. Flores:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 152 to Facility Operating License No. NPF-87 and Amendment No. 152 to Facility Operating License No. NPF-89 for Comanche Peak Nuclear Power Plant, Units 1 and 2, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated October 26, 2009, as supplemented by letter dated May 4, 2010.

The amendments revise TS 3.8.1, "AC [Alternating Current] Sources - Operating," to extend, on a one-time basis, the allowable Completion Time of Required Action A.3 for the offsite circuit inoperable, from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. This change is only applicable to startup transformer (ST)

XST2 and will expire on March 1, 2011. This change is needed to allow sufficient time to make final terminations as part of a plant modification to facilitate connection of either ST XST2 or the spare ST to the Class 1E buses.

R. Flores

- 2 A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

~'~~)l.-~

Balwant K. Singal, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-445 and 50-446

Enclosures:

1. Amendment No. 152 to NPF-87

2. Amendment No. 152 to NPF-89

3. Safety Evaluation cc w/encls: Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 LUMINANT GENERATION COMPANY LLC COMANCHE PEAK NUCLEAR POWER PLANT, UNIT NO.1 DOCKET NO. 50-445 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 152 License No. NPF-87

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Luminant Generation Company LLC dated October 26, 2009, as supplemented by letter dated May 4, 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

- 2

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Facility Operating License No. NPF-87 is hereby amended to read as follows:

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A as revised through Amendment No. 152 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated into this license. Luminant Generation Company LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan as indicated in the attachment to this license amendment.

3.

The license amendment is effective as of its date of issuance and shall be implemented within 120 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Facility Operating License No. NPF-87 and Technical Specifications Date of Issuance: October 29, 2010

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 LUMINANT GENERATION COMPANY LLC COMANCHE PEAK NUCLEAR POWER PLANT, UNIT NO.2 DOCKET NO. 50-446 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 152 License No. NPF-89

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Luminant Generation Company LLC dated October 26, 2009, as supplemented by letter dated May 4, 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

- 2

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Facility Operating License No. NPF-89 is hereby amended to read as follows:

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A as revised through Amendment No. 152 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated into this license. Luminant Generation Company LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 120 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Attachment Changes to the Facility Operating License No. NPF-89 and Technical Specifications Date of Issuance: October 29, 2010

ATTACHMENT TO LICENSE AMENDMENT NO. 152 TO FACILITY OPERATING LICENSE NO. NPF-87 AND AMENDMENT NO. 152 TO FACILITY OPERATING LICENSE NO. NPF-89 DOCKET NOS. 50-445 AND 50-446 Replace the following pages of the Facility Operating License Nos. NPF-87 and NPF-89, and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Facility Operating License No. NPF-87 REMOVE INSERT 3

3 Facility Operating License No. NPF-89 REMOVE INSERT 3

3 Technical Specifications REMOVE INSERT 3.8-2 3.8-2

- 3 (3)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Part 70, to receive, possess, and use at any time, special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, and described in the Final Safety Analysis Report, as supplemented and amended; (4)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use, at any time, any byproduct, source, and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required, any byproduct, source, and special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C.

This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

Maximum Power Level Luminant Generation Company LLC is authorized to operate the facility at reactor core power levels not in excess of 3458 megawatts thermal through Cycle 13 and 3612 megawatts thermal starting with Cycle 14 in accordance with the conditions specified herein.

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A as revised through Amendment No. 152 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated into this license. Luminant Generation Company LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Unit 1 Amendment No. 152

- 3 (3)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Part 70, to receive, possess, and use at any time, special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, and described in the Final Safety Analysis Report, as supplemented and amended; (4)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use, at any time, any byproduct, source, and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required, any byproduct, source, and special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)

Luminant Generation Company LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C.

This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1 )

Maximum Power Level Luminant Generation Company LLC is authorized to operate the facility at reactor core power levels not in excess of 3458 megawatts thermal through Cycle 11 and 3612 megawatts thermal starting with Cycle 12 in accordance with the conditions specified herein.

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A as revised through Amendment No. 152 and the Environmental Protection Plan contained in Appendix 8, are hereby incorporated into this license. Luminant Generation Company LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3)

Antitrust Conditions DELETED Unit 2 Amendment No. 152

3.8.1 AC Sources -- Operating ACTIONS

NOTE:--------------------------------------------------------------

LCO 3.0A.b is not applicable to DGs.

CONDITION RE:QUIRE:D ACTION COMPLE:TION TIME:

A. One required offsite circuit inoperable.

A.1 Perform SR 3.8.1.1 for required OPE:RABLE: offsite circuit.

AND A.2 --------------------NOTE:-------------------

In MODE:S 1,2 and 3, the TDAFW pump is considered a required redundant feature.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter Declare required feature(s) with no offsite power available inoperable when its redundant required feature(s) is inoperable.

AND A.3 Restore required offsite circuit to OPE:RABLE: status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of no offsite power to one train concurrent with inoperability of redundant required feature(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR 14 days for a one-time outage on XST2 to complete a plant modification to be completed by March 1, 2011.

COMANCHE: PE:AK - UNITS 1 AND 2 3.8-2 Amendment No. 4W; 152

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 152 TO FACILITY OPERATING LICENSE NO. NPF-87 AND AMENDMENT NO. 152 TO FACILITY OPERATING LICENSE NO. NPF-89 LUMINANT GENERATION COMPANY LLC COMANCHE PEAK NUCLEAR POWER PLANT. UNITS 1 AND 2 DOCKET NOS. 50-445 AND 50-446

1.0 INTRODUCTION

By "CP-200900520, License Amendment Request (LAR 09-003), Revision to Technical Specification 3.8.1, AC Sources - Operating, for One-Time, 14-Day Completion Time for [[Topic" contains a listed "[" character as part of the property label and has therefore been classified as invalid.s|letter dated October 26, 2009]] (Reference 1), as supplemented by letter dated May 4, 2010 (Reference 2), Luminant Generation Company, LLC (Luminant, the licensee) requested changes to the technical specifications (TSs) for the Comanche Peak Nuclear Power Plant (CPNPP), Units 1 and 2. The proposed amendment would revise TS 3.8.1, "AC [Alternating Current] Sources - Operating," to extend the allowable Completion Time (CT) for Required Action A.3, from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days, on a one-time basis. The proposed amendment would only apply for an outage of startup transformer (ST) (designated XST2) to complete a plant modification, which could begin anytime after the amendment is approved and would expire on March 1,2011.

The change is requested in order to make final electrical terminations as part of a plant modification which would facilitate connection of either ST XST2 or the spare ST to the Class 1E buses. After completion of this modification, the spare ST will be capable of being connected to the buses within the existing 72-hour CT of TS 3.8.1 Required Action A.3.

Because the two permanent transformers are shared between CPNPP, Units 1 and 2, both the units would have to be in cold shutdown to permit installation of the modification under the current TS requirements.

The supplemental letter dated May 4, 2010, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staffs original proposed no significant hazards consideration determination as published in the Federal Register on January 26, 2010 (75 FR 4117).

- 2

2.0 REGULATORY EVALUATION

The regulatory requirements and guidance which the NRC staff considered in its review of the application are discussed below.

2.1 Applicable Regulations Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix A, "General Design Criteria [GDG] for Nuclear Power Plants," GDC 17, "Electric power systems," requires, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of structures, systems, and components that are important to safety. The onsite electric power supplies shall have sufficient independence, redundancy, and testability to perform their safety functions, assuming a single failure. The offsite power system shall be supplied by two physically independent circuits that are designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. In addition, this criterion requires provisions to minimize the probability of losing electric power from any of the remaining electric power supplies as a result of, or coincident with, the loss of power from the transmission network, or the onsite electric power supplies.

GDC 18, "Inspection and testing of electric power systems," requires, in part, that electric power systems that are important to safety shall be designed to permit appropriate periodic inspection and testing.

The regulations in 10 CFR 50.36, "Technical specifications," require, in part, that the licensee will establish limiting conditions for operation, which include CTs for equipment that is required for safe operation of the facility.

The regulations in 10 CFR 50.63, "Loss of all alternating current power," require, in part, that each light-water cooled nuclear power plant licensed to operate must be able to withstand for a specified duration and recover from a station blackout.

The regulations in 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," require, in part, that preventative maintenance activities must not reduce the overall availability of the systems, structures, or components.

2.2 Applicable Regulatory Criteria/Guidance 2.2.1 Regulatory Guidance The regulatory guidance on which the NRC staff based its acceptance follows.

NRC Regulatory Guide (RG) 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (Reference 3),

describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed permanent licensing basis changes by considering engineering issues and

- 3 applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.

NRC RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications" (Reference 4), describes an acceptable risk-informed approach specifically for assessing proposed permanent TS changes in allowed outage times. RG 1.177 also provides risk acceptance guidelines for evaluating the results of such assessments and identifies a three tiered approach for the licensee's evaluation of the risk associated with a proposed CT TS change, as discussed below.

Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commission's Safety Goal Policy Statement, as documented in RG 1.174 and RG 1.177. The first tier assesses the impact on operational plant risk based on the change in core damage frequency (b.CDF) and change in large early release frequency (b.LERF). It also evaluates plant risk while equipment covered by the proposed CT is out-of service, as represented by incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP).

Tier 1 also addresses probabilistic risk assessment (PRA) quality, including the technical adequacy of the licensee's plant-specific PRA for the subject application. Cumulative risk of the proposed TS change in light of the previous or any additional proposed TS changes under review are also considered along with uncertainty/sensitivity analysis with respect to the assumptions related to the proposed TS change.

Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed license amendment, is taken out of service simultaneously, or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The purpose of this evaluation is to ensure that there are appropriate restrictions in place such that risk-significant plant equipment outage configurations will not occur when the proposed modification is implemented.

Tier 3 addresses the licensee's overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and appropriate compensatory measures are taken to avoid risk-significant configurations that may not have been considered when the Tier 2 evaluation was performed. Compared with Tier 2, Tier 3 provides additional coverage to ensure risk-significant plant equipment outage configurations are identified in a timely manner and that the risk impact of out-of service equipment is appropriately evaluated prior to performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule (10 CFR 50.65(a)(4)), which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance testing and corrective and preventive maintenance, subject to the guidance provided in RG 1.177, Section 2.3.7.1, and the adequacy of the

- 4 licensee's program and PRA model for this application. The CRMP is to ensure that equipment removed from service prior to or during the proposed extended CT will be appropriately assessed from a risk perspective.

For TS changes which implement one-time requirements, examination of the risk metrics identified in RG 1.174 and RG 1.177 provides insight about the potential risk impacts, even though neither of these RGs provides numerical risk acceptance guidelines for evaluating such TS changes against the fourth key principle. It can be demonstrated with reasonable assurance that a TS change implementing temporary requirements meets the fourth key principle of the associated risk metrics:

Satisfy the risk acceptance guidelines in RG 1.174 and RG 1.177, or Are not substantially above the risk acceptance guidelines in RG 1.174 and RG 1.177 and effective compensatory measures to maintain lower risk are implemented while the temporary TS change is in effect.

NRC RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 5), describes an acceptable approach for determining whether the quality of the PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decision making for light-water reactors.

2.2.2 Review Guidance General guidance for evaluating the technical basis for proposed risk-informed changes is provided in Chapter 19.2, "Review of Risk Information Used to Support Permanent Plant Specific Changes to the Licensing Basis: General Guidance," of the NRC Standard Review Plan (SRP), NUREG-0800 (Reference 6). Guidance on evaluating PRA technical adequacy is provided in Chapter 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 7). More specific guidance related to risk-informed TS changes is provided in SRP Section 16.1, "Risk-Informed Decisionmaking:

Technical Specifications," (Reference 8), which includes CT changes as part of risk-informed decision making. Chapter 19.2 of the SRP states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:

1.

The proposed change meets the current regulations, unless it is explicitly related to a requested exemption.

2.

The proposed change is consistent with the defense-in-depth philosophy.

3.

The proposed change maintains sufficient safety margins.

4.

When proposed changes result in an increase in core damage frequency or risk, the increases should be small and consistent with the intent of the Commission's Safety Goal Policy Statement (60 FR 42622; August 16,1995).

- 5

5.

The impact of the proposed change should be monitored using performance measurement strategies.

For one-time changes, SRP Chapters 19.2 and 16.1 are used to provide general guidance regarding evaluation of the potential risk impacts.

3.0 TECHNICAL EVALUATION

3.1 Background

In its letter dated October 29, 2009, the licensee stated that the CPNPP, Units 1 and 2 offsite power system is comprised of 138 kiloVolt (kV) and 345 kV systems. Separate connections to the 138 kV and 345 kV switchyards provide independent and reliable offsite power sources to the CPNPP Class 1E systems. The highly reliable network interconnections are made through five 345 kV and two 138 kV transmission lines.

Two physically independent and redundant sources of offsite power are available on an immediate basis for the safe shutdown of either unit. The preferred source for CPNPP, Unit 1 is the 345 kV offsite supply from the 345 kV switchyard via ST XST2. The preferred source for CPNPP, Unit 2 is the 138 kV offsite supply from the 138 kV switchyard via ST XST1. Each of the STs (XST1 and XST2) normally energizes its related 6.9 kV alternating current (AC)

Class 1E buses as a preferred source (i.e., XST1 normally energizes the CPNPP, Unit 2 Class 1E buses and XST2 normally energizes the CPNPP, Unit 1 Class 'I E buses).

The preferred power sources supply power to the Class 1E buses during plant startup, normal operation, emergency shutdown, and upon a unit trip. This eliminates the need for automatic transfer of safety-related loads in the event of a unit trip.

Each ST has the capacity to supply the required Class 'I E loads of both units during all modes of plant operation. In the event that one ST (e.g., XST1, a preferred source) becomes unavailable to its Class 1E buses, power is made available from the other ST (e.g., XST2, an alternate source) by an automatic transfer scheme. For the loss of an ST, the load transfer only takes place in the unit for which the transformer was the preferred source. If it becomes necessary to safely shut down both units simultaneously, sharing of these offsite power sources between the two units has no effect on the station's electrical system reliability because each transformer is capable of supplying the required safety-related loads of both units although the design criteria requires consideration of a design-basis accident on one unit only.

The CPNPP onsite AC power system is an independent, automatically starting system designed to furnish reliable and adequate power for Class 1E loads to ensure safe plant shutdown and onsite power when the preferred and alternate offsite power sources are not available. Four independent emergency diesel generator (EDG) sets, two per unit, are provided.

Loads important to plant safety are divided into redundant divisions. Each division is provided with onsite power from a dedicated EDG. Each EDG is directly connected to its dedicated bus.

The EDGs are physically and electrically independent. With this arrangement, redundant components of all engineered safety feature (ESF) systems are supplied from a separate ESF bus so that no single failure can jeopardize the proper functioning of redundant ESF loads. Due

- 6 to the redundancy of each CPNPP unit's ESF divisions and EDGs, the loss of anyone of the EDGs will not prevent the safe shutdown of any of the CPNPP units. The total onsite power system, including EDGs and electrical power distribution equipment, satisfies the single failure criterion.

An EDG is automatically started by a safety injection signal or an undervoltage condition on the 6.9 kV ESF bus served by the EDG. Upon loss of voltage on a 6.9 kV ESF bus due to a loss of offsite power (LOOP) with no safety injection signal present, under-voltage relays automatically start the EDGs and close its output breaker. Sequential loading of the EDG is automatically performed as a result of sequential loading of its dedicated bus.

The EDG output breaker will close to its dedicated 6.9 kV Class 1E bus automatically only if the other source feeder breakers to the bus are open. When the EDG output breaker is closed, no other source feeder breaker will close automatically. The licensee's design and procedural controls ensure that no means exist for connecting redundant buses with each other.

The requested extended CT would be used to allow sufficient time to make cable terminations as part of a plant modification to allow future operational connection of ST XST2 or the spare ST (to be renamed XST2A) to the safety-related buses within the current TS CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In other words, a third offsite circuit would be available (using the spare ST XST2A), within the existing TS CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , should the normal offsite circuit (XST2) require maintenance. More specifically, cabling will be installed between ST XST2, the spare ST (XST2A) and the 6.9 kV transfer panels that will allow XST2A to be used as an additional offsite circuit to the Class 1E buses in place of the normal XST2 circuit within the existing CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The NRC staff reviewed the licensee's analyses in support of its proposed license amendment request (LAR), which are described in licensee's submittal dated October 26, 2009 (Reference 1).

3.2 Review Methodology The NRC staff reviewed the proposed LAR from a deterministic as well as a PRA perspective.

Section 3.2.1 of this safety evaluation (SE) addresses the deterministic aspects of the proposed changes and the probabilistic aspects of the request are addressed in Section 3.2.2.

3.2.1 Deterministic Evaluation Deterministic evaluation was performed in accordance with the key principles described in SRP Chapter 19.2 and listed in Section 2.2.2 of this SE.

As described in Section 3.1 above and, as stated by the licensee in Attachment 2, Section 3.2 of its "CP-200900520, License Amendment Request (LAR 09-003), Revision to Technical Specification 3.8.1, AC Sources - Operating, for One-Time, 14-Day Completion Time for [[Topic" contains a listed "[" character as part of the property label and has therefore been classified as invalid.s|letter dated October 26, 2009]]:

The requested extended CT is needed to allow sufficient time to make final terminations as part of a plant modification to facilitate connection of ST XST2 or the spare startup transformer (renamed XST2A) to the [Class] 1E buses within the current TS CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Installation of this modification will enhance the plant design by providing the capability to preclude an extended interruption of

- 7 offsite power in case of failure of, or maintenance on, XST2 that would exceed the CT.

Installation of the cabling from XST2 and spare ST to the new 6.9kV transfer panels will allow the spare ST to be a fully installed spare capable of being aligned to provide power to the [Class] 1E buses in place of XST2 from its current location within the existing CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The modification will be completed in two phases. The transfer panels and additional cables and raceway connections to the spare startup transformer will be installed with both XST1 and XST2 available and while both CPNPP Units continue power operations in Mode 1. However for the second phase, making the final cable terminations on XST2 and the transfer panels, XST2 will be out-of service for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months but less or equal to 14 days.

In general, completing the modification will require that XST2 be removed from service in order to route the existing cabling from the transformer to the [Class]

1E buses thru the transfer panels installed for this modification. The entire sequence of activities is projected to require approximately 11 days and 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months , to complete. Table 'I [of "CP-200900520, License Amendment Request (LAR 09-003), Revision to Technical Specification 3.8.1, AC Sources - Operating, for One-Time, 14-Day Completion Time for [[Topic" contains a listed "[" character as part of the property label and has therefore been classified as invalid.s|letter dated October 26, 2009]]], provides a more detailed list of planned maintenance activities and their durations.

Once the modification to the plant is complete and XST2 needs maintenance or if XST2 fails, the spare ST can be connected to the safety buses to restore the 345kV offsite source within the current TS CT. After maintenance or repair on XST2 is completed, XST2 may be put back in-service.

As further stated by the licensee in its application dated October 26, 2009:

During the one-time, 14-day CT for XST2, only one offsite AC source (XST1) and both the EDGs of the Units will remain available. If during the XST2 extended CT, power from the remaining offsite source via XST1 is lost, the redundant EDG of each Unit will provide emergency power for the safety buses. Emergency power to at least one safety bus for each Unit will still be available through an EDG even if the other EDG becomes inoperable due to an assumed single failure.

Per the pre-application meeting between the NRC and Luminant Power

[Luminant Generation Company LLC] on August 25, 2009, as a defense-in-depth feature, a set of temporary power diesel generators (TPDGs) will be installed for each Unit to maintain the capability to provide power for one train of ESF equipment needed for safe shutdown and long term cooling of each Unit during the XST2 extended CT to respond to a beyond design basis event if loss of XST1 occurs and both EDGs of a Unit fail to start and load as designed. If required, due to a loss of offsite power from XST1 coincident with the failure of both Class 1E EDGs of a Unit, the TPDGs will be manually connected to the affected Unit's 6.9kV safety bus in Modes 3, 4, and 5. Thus, the minimum set of components for one train required to maintain the affected Unit in a safe shutdown condition can

- 8 be loaded onto the TPDG and operating within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months which meets CPNPP's Station Black Out analysis.

In response to an NRC staff request for additional information dated April 12, 2010 (Reference 9), the licensee provided additional information on sizing, connecting, testing and operating criteria for TPDGs in its supplemental letter dated May 4, 2010 (Reference 2).

Specifically, the TPDG sets are each capable of supplying 3,045 kilowatts (kW) of load with the total loading required for safe shutdown of a unit being 3,01 'I kW. In addition, testing by the TPDG vendor confirms the ability of the TPDG set to supply 3,000 kW of load and also the ability to start the largest load (1000 HP motor) while also maintaining 3,000 kW after the motor start. Phase rotation testing after installation at the plant will be completed by plant staff and operations staff will verify (on a per-shift basis) TPDG set parameters to ensure its readiness to start and power the necessary plant safe shutdown loads. The TPDG sets will be connected to the plant's 6.9 kilovolt (kV) system with cabling and a transformer rated to handle the required safe shutdown loading and operating procedures will be modified to direct operations personnel in starting the TPDG sets and loading of necessary safe shutdown loads within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The NRC staff review concluded that the design of the proposed TPDGs and their connections were acceptable and, if required, would provide the necessary timely altemate supply for safe shutdown of both units.

In its letter dated October 29, 2009, the licensee stated that the following compensatory measures will be implemented by the licensee for completion of the proposed modification during the extended CT:

1.

Restricted access to and suspension of maintenance in the switchyard.

2.

Suspension of routine or elective maintenance on EDGs, turbine-driven auxiliary feedwater (TDAFW) pumps, the other ST (XST1), and the station service water (SSW) pumps.

3.

The EDGs and the TDAFW pumps will be tested for operability within 2 weeks prior to the extended CT period.

4.

TPDGs (one set per unit) will be available, tested, and verified available throughout the extended CT period for added defense-in-depth as a replacement source. These TPDGs will be sized to be capable of supplying safe-shutdown loads on each unit. They will be tested to ensure their capability to supply the necessary safety equipment in addition to being able to start the largest load.

Temporary cables and connections between the TPDGs and the 1E distribution system, along with procedures, training and other administrative controls, to connect and load the TPDGs, will be implemented.

5.

Suspension of work activities near the other ST's (XST1) power and control cabling.

6.

Hourly fire watches along the paths of ST XST1's control and power cables.

- 9

7.

Scheduling of this work during the extended CT will consider potential for adverse weather such as high winds/tornados and other severe weather. In addition, weather conditions will be assessed by operations twice per shift during the extended CT period.

8.

Seismic walkdown of the EOGs and the TOAFW pumps will be completed prior to the extended CT period.

9.

Scheduling of work activities during the extended CT will consider the potential for grid stress. In addition, operations will contact the grid operator once per day during the extended CT period to ensure no transmission system problems exist which could affect opposite power to the plant (Commitment No. 3792178).

As noted above, TPOGs (one for each unit) will be made available to provide power to equipment for long-term cooling throughout the extended CT period for added defense-in-depth.

The affected work groups will be trained prior to start of the implementation of the proposed change. The licensee will ensure that operating and maintenance procedures are made available to its staff for using XST2A as an alternate ST for XST2. To ensure grid reliability during the implementation of the modification, the licensee will communicate with Oncor, the transmission service provider, once per day, to ensure that transmission work activities that could affect CPNPP switchyards are limited. Also, the licensee will monitor local weather conditions and forecasts twice per shift to assess potential impacts on plant conditions and take compensatory measures or risk-reduction measures to reduce challenges to plant safety or the electrical distribution system. The proposed change is only one-time change and expires on March 1, 2011. After completion of this modification, if XST2 should require maintenance or repair or failure occurs, the spare transformer can be connected to the Class 'I E buses within the current CT ensuring no reduction in safety margins.

Based on the NRC staff's review of the LAR, the responses to the request for additional information, the updated final safety analysis report, and the aforementioned compensatory measures, there is reasonable assurance that the limiting conditions for operation of the facility are satisfied in accordance with 10 CFR 50.36. Also, the completion of this modification, in accordance with actions specified in this LAR, will provide for adequate management of risk pursuant to 10 CFR 50.65. The compensatory measures, including the aforementioned TPDGs sized and tested for safe-shutdown loads on each unit, will minimize the risk of a station blackout and support compliance with regulations promulgated under 10 CFR 50.63 and GOCs 17 and 18. The proposed change to the CT is only a one-time change for completing the modification and the existing CT will be restored after the modification is complete.

Based on the above, the NRC staff concludes that the proposed change follows the key principles and guidance provided by SRP 19.2 concerning compliance with current regulations, evaluation of defense-in-depth, evaluation of safety margins, small change in core damage frequency or risk consistent with the intent of Commission's Safety Goal Policy Statement, and performance monitoring strategies. The proposed change, once implemented, will improve the availability of the offsite AC sources and is a safety enhancement. Hence, the proposed one time change to TS 3.8.1 Required Action A.3 CT from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days (expiring March 1, 2011) for transformer XST2 to complete a plant modification, is acceptable.

- 10 3.2.2

Probabilistic Risk Assessment Evaluation

The evaluation presented below addresses the NRC staff's philosophy of risk-informed decision making, that when the proposed changes result in a ~CDF or risk, the increase should be small and consistent with the intent of the Commission's Safety Goal Policy Statement (Key Principle 4, Reference 6).

3.2.2.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk. The Tier 1 NRC staff review involves two aspects: (1) evaluation of the validity of the CPNPP PRA models and their application to the proposed changes, and (2) evaluation of the PRA results and insights based on the licensee's proposed application.

PRA Quality - Internal Events Model The objective of the PRA quality review is to determine whether the CPNPP PRA used in evaluating the proposed changes to the TS 3.8.1 CT is of sufficient scope, level of detail, and technical adequacy for this application. The NRC staff review evaluated the PRA quality information provided by the licensee in its submittal, including industry peer review results and self-assessments performed by the licensee.

The CPNPP PRA model, identified as revision 3D, addresses both core damage frequency (CDF) and large early release frequency (LERF), and includes the STs, offsite power circuits, and diesel generators. The model includes a LOOP initiator which can assess the impact of unavailability of the ST for this LAR.

The licensee has processes for configuration control of the PRA model to reflect plant modifications and procedure changes, and no plant changes were identified as not yet incorporated into the CPNPP PRA model. The models address steam generator replacement in CPNPP, Unit 1, and recent power uprates performed for both units.

Appropriately low-truncation levels were applied to generate the cutsets for this application.

In 2002, the Westinghouse Owners Group (WOG) performed a peer review of the CPNPP PRA model. Since the completion of the peer review, all significant findings and observations have been resolved. In 2004, a focused scope review of the Systems Analysis element was performed to support a major model update, with no technical adequacy findings. The licensee also conducted a self-assessment, with some external peer support, of the CPNPP PRA in 2004, to confirm consistency with industry modeling approaches and standards. In addition, in 2005, two reviews were conducted by external consultants against the Quantification element of the American Society of Mechanical Engineers (ASME) PRA Standard. No significant findings were identified.

A self-assessment using the ASME PRA Standard and RG 1.200, Revision 1 was conducted in 2007-2008. The assessment compared the CPNPP PRA model with capability category II requirements. The results of this self-assessment were identified as "gaps," and were evaluated as to their impact on this application by the licensee. The majority of gaps were identified as

- 11 documentation deficiencies which would not impact the risk results of this request. Gaps associated with technical requirements were evaluated by the licensee, and the evaluation, documented in the submittal, concluded that none of the technical gaps are significant to the evaluation of risk associated with this application.

The NRC staff review of the licensee's basis for technical adequacy of the internal events PRA model determined that it is acceptable commensurate with the application. Specifically:

The licensee has developed, and continues to maintain, its PRA model consistent with plant configuration changes and with industry standards and consensus modeling approaches.

The licensee has performed technical reviews of its PRA model and has made appropriate changes based on those reviews.

The licensee has followed the process identified in NRC staff-endorsed PRA standards to assess the technical adequacy of its model.

The risk impact of one ST outage is minimal given that the redundant transformer is physically able to provide all required AC electrical power for normal and accident conditions for both units, and given that the onsite diesel generators are available during the outage. In addition, the licensee is providing TPDGs for additional AC capability.

The requested change is for a one-time application only to install a plant modification which will improve the availability of the offsite AC sources and is a safety enhancement, and the duration of 14 days is consistent with previously granted amendments for AC electrical equipment.

The NRC staff notes that the self-assessment performed by the licensee identified several significant deficiencies in the internal events PRA model in the treatment of human error dependencies, credit for equipment repairs, and component failure data development. The staff does not agree with the licensee's disposition of these deficiencies as unimportant to the risk calculations. In fact, the treatment of repairs to equipment was identified by the staff's evaluation of the Individual Plant Examination (IPE) as a weakness, and apparently the licensee has yet to correct these deficiencies. However, the specific change requested is for a one-time increased CT for one of two redundant offsite power transformers to implement a safety enhancement modification and, given the availability of the safety-related diesel generators and TPDGs, represents a very small temporary increase in risk. Even if the significant deficiencies were required to be corrected, the resulting calculated change in risk would be unlikely to challenge the acceptance guidelines. Since the licensee's request is limited to only a one-time CT extension to implement a safety enhancement modification, and because the staff wants to encourage licensees to make safety improvements, a revised, more rigorous calculation of the change in risk using a corrected model is not warranted for this particular application.

Based on the above, the NRC staff concludes that the quality of the CPNPP internal events PRA is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

- 12 PRA Quality - Internal Fires Model The licensee provided a separate quantitative estimate of the impact of the ST outage on fire risk applying the methodology and data used in the Individual Plant Examination of External Events (IPEEE) for evaluation of internal fires. Routing information for power and control cabling associated with each ST was obtained by physical walkdowns, and potential fire impacts were identified. The impact of a postulated fire in the operable ST was also considered in this evaluation. Fire zones containing cabling for both redundant transformers where a single fire scenario could affect both transformers, or for which the development of a hot gas layer would occur, were not further evaluated since a postulated fire in these zones would disable both transformers, and so the risk would not be changed by the unavailability status of one transformer. The licensee's evaluation considered unit-specific design features. The analysis conservatively did not evaluate the effect of open space between the target cables in shielded conduits and the intervening cable trays. The change in risk was assessed using the current internal events PRA model for the conditional core damage probabilities. No credit was taken for compensatory measures being implemented to reduce the likelihood of fires in affected zones. For each fire scenario identified, the change in risk was calculated as the difference in CDF for the fire impacts with one transformer available compared to the impact with both transformers available.

Because there is no unique plant impact from fires unless the remaining transformer is affected, and based on the conservative assumptions applied to the analysis, the NRC staff concludes that the licensee's scope of analysis and methodology applied is acceptable for this application, and has satisfied the intent of RG 1.177 (Sections 2.3.1, 2.3.2, and 2.3.3), RG 1.174 (Sections 2.2.3 and 2.5), and SRP Chapter 19.1, and that the quality of the fire risk analyses and methods applied is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

PRA Risk Results and Insights The ST is modeled in the PRA as impacting both mitigation and the LOOP-initiating event and, therefore, transformer outage can be directly modeled in the PRA by assuming it is unavailable and unrecoverable. Unavailability of other plant eqUipment at their nominal average values is assumed, except for the specific equipment identified as assumed to be available by regulatory commitment.

The ICCDP and ICLERP are based on the entire 14-day duration of the proposed extended CT.

The licensee's methodology is consistent with the guidance of RG 1.177, Section 2.3.4 and Section 2.4 and is, therefore, acceptable to the NRC staff.

- 13 The licensee presented risk results for internal events and for internal fire events. The results are as follows:

Risk Measure Internal Events Internal Fires TOTAL ICCDP 2.75E-7 (Unit 1) 2.17E-7 (Unit 1) 4.9E-7 (Unit 1) 2.54E-7 (Unit 2) 7.88E-7 (Unit 2) 1.0E-6 (Unit 2)

ICLERP 6.25E-9 (Unit 1)

Not evaluated, Not available 5.10E-9 (Unit 2) assumed not siQnificant The difference in fire ICCDP for CPNPP, Unit 2 was identified by the licensee as due to differences in ST cable routing for CPNPP, Units 1 and 2.

The licensee did not explicitly provide an estimate of the ~CDF and ~LERF associated with this one-time proposed change. The ~CDF and ~LERF are determined by assuming a frequency for entry into an extended CT of this nature. Because the proposed TS change is a one-time change, it can be conservatively assumed that the frequency of the extended CT is 1/year, and so the ~CDF and ~LERF are numerically identical with the ICCDP and ICLERP.

Per RG 1.177, the acceptance guidelines for ICCDP and ICLERP are 5E-7 and 5E-8, respectively, applicable to permanent changes to the TS. Per RG 1.174, the acceptance guidelines for ~CDF and ~LERF are 1E-6/year and 1E-7/year, respectively, for very small changes in risk, also applicable to permanent changes. Considering that the associated increase in risk will occur only once, slightly exceeding the ICCDP guidelines was found to be acceptable to the NRC staff. The licensee's cumulative estimate of internal event and internal fire risk of approximately 1E-6 ICCDP (limiting for CPNPP, Unit 2), and the staff's calculation based on 1/year frequency of 1E-6/year ~CDF are reasonably consistent with the guidelines applicable to permanent changes. The internal events ICLERP of 5.1 E-9, resulting in 5.1 E-9/year ~LERF, assuming 1Iyear frequency, is a more than factor of 10 below the acceptance guidelines. No unique fire impacts were identified which would impact the containment function, and so LERF due to fire is not expected to be significant. Therefore, the staff concludes that the risk is acceptable to permit a one-time change.

Qualitative Evaluation of Seismic Risk The licensee did not quantitatively assess the impact of seismic events on CDF or LERF, but instead provided a qualitative assessment of the impact of seismic events during the transformer outage. The risk impact is expected to be insignificant based on the following:

1)

The plant is located in a low seismicity region as per NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - Final Report," June 1991 (Reference 10).

2)

Neither the switchyard nor the STs are category I seismic structures and are, therefore, not assumed to survive a seismic event. Power is provided by the onsite diesel generators.

- 14

3)

The frequency of a seismic event is small compared to LOOP from other causes, and so the seismic risk would also be small.

The licensee has committed to compensatory measures to assure the availability of the diesel generators and TDAFW pumps by performing walkdowns for any obvious mounting or seismic interaction issues (loose parts, missing hardware) prior to entering the extended CT. This will further reduce seismic risk.

Based on the above, the NRC staff concludes that seismic risk is not a significant contributor to the risk during the ST outage.

Qualitative Evaluation of High WindlTornado Events The impact on the plant due to high winds or tornado events is an unrecoverable LOOP, due to either the damage of the plant switchyard or transformers, or damage to offsite power lines and equipment. In either case, the unavailability of one transformer has no relevance, since offsite sources are impacted.

The licensee identified the design features of the plant which limit the potential impact of these events, including robustness of seismic category I structures, turbine building, and switchyard for withstanding high winds.

Based on the expected impact to offsite power supplies from these events, the NRC staff concludes that the risk contribution from high winds and tornadoes is insignificant for the proposed amendment request.

Qualitative Evaluation of Internal Flooding The licensee conducted walkdowns of the power and control cables associated with the STs and determined that the cables are mostly routed in trays and junction boxes well above floor level such that they are not affected by floods. Where the cables are routed in the floor, there are no junction boxes and so the cables would not be affected by flooding. The licensee re evaluated the internal flooding analysis using the latest internal event PRA model and found no change in risk based on the unavailability status of the STs.

Based on the qualitative assessment of the physical layout of the cables, the NRC staff concludes that the risk contribution from internal flooding is insignificant for the proposed amendment request.

Qualitative Evaluation of External Flooding The licensee identified that the IPEEE did not identify any external flooding scenarios where the flood level reached elevation 810 feet, which is the elevation where the STs are located. Based on the above, NRC staff concludes extending the CT to 14 days does not affect the plant risk due the external flooding events.

- 15 Qualitative Evaluation of External Fires During the ST outage, brush or forest fires could result in interruption of power to the switchyard and associated operable ST. Minimal combustibles exist in the relevant plant protected area (switchyard, transformer, and into the plant), and offsite rights of way are routinely cleared of trees and significant vegetation, limiting the potential for significant fires which could have the potential to interrupt offsite power. Therefore, the NRC staff concludes the risk associated with external fires during the transformer outage is minimal.

Qualitative Evaluation of Transportation and Nearby Facility Accidents The licensee confirmed that the insights from the IPEEE regarding the very low risk from these types of events remains valid, and so the contribution from transportation and facility accidents is very low during the transformer outage.

Shutdown Risk The licensee's submittal did not specifically address shutdown risk in the tier one risk evaluation, since the proposed change to TS is implemented with both units operating at power.

Avoided shutdown risk was conservatively not considered in the evaluation.

Uncertainty Analysis The licensee evaluated PRA model assumptions to identify those which are key for this application, specifically related to dependency and reliability of important components, offsite power loss frequency and recovery, component recovery, and deferred maintenance. The quantitative evaluation of these model elements demonstrated that the risk insights are robust and not affected by assumption's or data employed in the PRA model.

3.2.2.2 Tier 2: Avoidance of Risk-Significant Plant Configuration The licensee identified compensatory measures to be implemented during the one-time transformer outage. Regulatory commitments for these measures are identified in Section 4.0 of this SE. Some of the key compensatory measures applicable to this evaluation are summarized below:

Suspension of maintenance and restriction of access to both switchyards and relay houses Suspension of routine or elective maintenance on important components Testing of important components within two weeks of the start of transformer outage TPDG sets on site for each unit Suspension of work near remaining operable transformer and cabling Hourly fire watches near remaining operable transformer and cabling Weather consideration for timing of outage Seismic walkdown of important components

- 16 3.2.2.3 Tier 3: Risk-Informed Configuration Risk Management The licensee stated that its CRMP ensures that the risk impact of equipment out of service is appropriately evaluated prior to performing any maintenance activity. The program provides for proceduralized risk-informed assessment of equipment unavailability, including CDF and LERF aspects, and requires assessment for both planned and unplanned activities. The CRMP is required by CPNPP TS 5.5.18, "Configuration Risk Management Program (CRMP)," and conforms to the endorsed industry guidelines.

The risk impact of the proposed one-time 14-day CT for the installation of a plant modification for the spare ST, as reflected in llCDF, llLERF, ICCDP, and ICLERP, is consistent with the acceptance guidelines specified in RG 1.174, RG 1.177, and NRC staff guidance outlined in SRP Chapter 16.1. The Tier 2 evaluation identified the applicable risk-significant plant equipment outage configurations needing compensatory measures that will be implemented by the licensee prior to and during the service water outage. The licensee's CRMP satisfies the CRMP requirements of RG 1.177. Therefore, the NRC staff concludes that the risk analysis methodology and approach used by the licensee to estimate the risk impacts and manage configuration risk during the extended transformer outage are reasonable and of sufficient quality.

Based on the above, the NRC staff concludes that the proposed one-time change to revise the CT of Required Action A.3 of TS 3.8.1, "AC Sources - Operating," is acceptable.

3.2.3 Results of NRC Staff Evaluation Based on the results of the deterministic evaluation described above in Section 3.2.1 and the PRA evaluation described above in Section 3.2.2, the NRC staff concludes that the proposed one-time change to TS 3.8.1, "AC Sources - Operating," to extend the allowable CT for Required Action A.3 from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days to complete the proposed plant modification meets the requirements of 10 CFR 50.36 and is acceptable. The existing CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months will be restored after the modification is complete and the one-time amendment will expire on March 1, 2011.

4.0 REGULATORY COMMITMENTS The licensee has provided several compensatory measures to assure safe shutdown and offsite and on site power capability and availability during the implementation of the proposed modification. To provide extra assurance, the licensee submitted these compensatory measures as the following Regulatory Commitments in its letters dated October 26, 2009, and May 4,2010:

Commitment No.

Commitment Due Date/Event 3792121 The temporary power diesel generators provided for each Unit will be verified available to provide power to equipment for long term cooling once per shift.