september 29, 2010consist of changes to the pvngs technical specifications, in response to your...

UNITED STATES NUCLEAR REGULATORY COMMISSION

WASHINGTON, D.C. 20555-0001

September 29, 2010

Mr. Randall K. Edington Executive Vice President Nuclear/

Chief Nuclear Officer Mail Station 7602 Arizona Public Service Company P.O. Box 52034 Phoenix, AZ 85072-2034

SUB~IECT: PALO VERDE NUCLEAR GENERATING STATION, UNITS 1, 2, AND 3ISSUANCE OF AMENDMENTS RE: CHANGES TO TECHNICAL SPECIFICATION 3.8.7, "INVERTERS - OPERATING" (TAC NOS. ME2337, ME2338, AND ME2339)

Dear Mr. Edington:

The U.S. Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment No. 180 to Facility Operating License No. NPF-41, Amendment No. 180 to Facility Operating License No. NPF-51, and Amendment No. 180 to Facility Operating License No. NPF-74 for the Palo Verde Nuclear Generating Station (PVNGS), Units 1,2, and 3, respectively. The amendments consist of changes to the PVNGS Technical Specifications, in response to your application dated September 28, 2009, as supplemented by letters dated June 24 and September 3 and 24, 2010.

The amendments revise Required Action A.1 ofTS 3.8.7, "Inverters - Operating," for PVNGS, Units 1, 2, and 3, by extending the Completion Time for restoration of an inoperable vital alternating current inverter from 24 hours to 7 days.

R. Edington - 2

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

Sincerely,

~y~/(71JJJaS R. Hall, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Docket Nos. STN 50-528, STN 50-529, and STN 50-530

Enclosures: 1. Amendment No. 180 to NPF-41 2. Amendment No. 180 to NPF-51 3. Amendment No. 180 to NPF-74 4. Safety Evaluation

cc w/encls: Distribution via Listserv



ARIZONA PUBLIC SERVICE COMPANY, ET AL.

DOCKET NO. STN 50-528

PALO VERDE NUCLEAR GENERATING STATION, UNIT 1

AMENDMENT TO FACILITY OPERATING LICENSE

Amendment No. 180 License No. NPF-41

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

A. The application for amendment by the Arizona Public Service Company (APS or the licensee) on behalf of itself and the Salt River Project Agricultural Improvement and Power District, EI Paso Electric Company, Southern California Edison Company, Public Service Company of New Mexico, Los Angeles Department of Water and Power, and Southern California Public Power Authority dated September 28,2009, as supplemented by letters dated June 24 and September 3 and 24, 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I;

B. The facility will operate in conformity with the application, 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 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.

Enclosure 1

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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-41 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. 180, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated into this license. APS shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan, except where otherwise stated in specific license conditions.

3. This license amendment is effective as of the date of issuance and shall be implemented within 60 days of 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-41 and Technical Specifications

Date of Issuance: September 29, 2010









A. The application for amendment by the Arizona Public Service Company (APS or the licensee) on behalf of itself and the Salt River Project Agricultural Improvement and Power District, EI Paso Electric Company, Southern California Edison Company, Public Service Company of New Mexico, Los Angeles Department of Water and Power, and Southern California Public Power Authority dated September 28, 2009, as supplemented by letters dated June 24 and September 3 and 24, 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I;

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



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.

Enclosure 2

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FORTHE NUCLEAR REGULATORY COMMISSION













A. The application for amendment by the Arizona Public Service Company (APS or the licensee) on behalf of itself and the Salt River Project Agricultural Improvement and Power District, EI Paso Electric Company, Southern California Edison Company, Public Service Company of New Mexico, Los Angeles Department of Water and Power, and Southern California Public Power Authority dated September 28,2009, as supplemented by letters dated June 24 and September 3 and 24, 2010, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I;

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



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.

Enclosure 3

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FOR THE NUCLEAR REGULATORY COMMISSION





ATTACHMENT TO LICENSE AMENDMENT NOS. 180, 180, AND 180

FACILITY OPERATING LICENSE NOS. NPF-41, NPF-51, AND NPF-74

DOCKET NOS. STN 50-528, STN 50-529, AND STN 50-530

Replace the following pages of the Facility Operating Licenses Nos. NPF-41, NPF-51, and NPF-74, 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-41

REMOVE INSERT

-5- -5


REMOVE INSERT

-6- -6


REMOVE INSERT

-4- -4

Technical Specifications

REMOVE INSERT

3.8.7-1 3.8.7-1

-5


The Technical Specifications contained in Appendix A, as revised through Amendment No. 180, and the Environmental Protection Plan contained in Appendix S, are hereby incorporated into this license. APS shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan, except where otherwise stated in specific license conditions.

(3) Antitrust Conditions

This license is sUbject to the antitrust conditions delineated in Appendix C to this license.

(4) Operating Staff Experience Requirements

Deleted

(5) Post-Fuel-Loading Initial Test Program (Section 14, SER and SSER 2)*

Deleted

(6) Environmental Qualification

Deleted

(7) Fire Protection Program

APS shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility, as supplemented and amended, and as approved in the SER through Supplement 11, SUbject to the following provision:

APS may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

(8) Emergency Preparedness

Deleted

'The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

Amendment No. 180

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The Technical Specifications contained in Appendix A, as revised through Amendment No. 180, and the Environmental Protection Plan contained in Appendix 8, are hereby incorporated into this license. APS shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan, except where otherwise stated in specific license conditions.


This license is subject to the antitrust conditions delineated in Appendix C to this license.

(4) Operating Staff Experience Reguirements (Section 13.1.2. SSER 9)*

Deleted

(5) Initial Test Program (Section 14. SER and SSER 2)

Deleted

(6) Fire Protection Program

APS shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility, as supplemented and amended, and as approved in the SER through Supplement 11, subject to the following provision:

APS may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

(7) Inservice Inspection Program (Sections 5.2.4 and 6.6, SER and SSER 9)

Deleted

(8) Supplement NO.1 to NUREG-0737 Requirements

Deleted

*The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

Amendment No. 180

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(1) Maximum Power Level

Arizona Public Service Company (APS) is authorized to operate the facility at reactor core power levels not in excess of 3990 megawatts thermal (100% power),in accordance with the conditions specified herein.




This license is sUbject to the antitrust conditions delineated in Appendix C to this license.

(4) Initial Test Program (Section 14, SER and SSER 2)

Deleted

(5) Additional Conditions

The Additional Conditions contained in Appendix D, as revised through Amendment No. 171, are hereby incorporated into this license. The licensee shall operate the facility in accordance with the Additional Conditions.

(6) Mitigation Strategy License Condition

APS shall develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

(a) Fire fighting response strategy with the following elements:

1. Pre-defined coordinated fire response strategy and guidance.

2. Assessment of mutual aid fire fighting assets. 3. Designated staging areas for equipment and materials. 4. Command and control. 5. Training of response personnel.

Amendment No. 180

Inverters - Operating3.8.7

3.8 ELECTRICAL POWER SYSTEMS

3.8.7 Inverters - Operating

LCO 3.8.7 The required Train A and Train B inverters shall be OPERABLE.

----------------------------NITfE---------------------------One inverter may be disconnected from its associated DC bus for ~ 24' hours to perform an equalizing charge on its associated battery, provided:

a. The associated AC vital instrument bus is energized from its Class IE constant voltage source regulator; and

b. All other AC vital instrument buses are energized from their associated OPERABLE inverters.

APPLICABILITY: MODES 1. 2, 3. and 4.

ACTIONS

CONDITION REQU IRED ACTI ON COMPLETION TIME

A. One required inverter inoperable.

A.l ---------NOTE--------Enter applicableConditions and Required Actions of LCO 3.8.9. "Distribution Systems - Operat'ing"with any vital instrument bus de-energized.

Restore inverter to OPERABLE status.

7 days

(continued)

PALO VERDE UNITS 1,2.3 3.8.7-1 AMENDMENT NO. W 180



SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION

RELATED TO AMENDMENT NO. 180 TO FACILITY OPERATING LICENSE NO. NPF-41,

AMENDMENT NO. 180 TO FACILITY OPERATING LICENSE NO. NPF-51, AND

AMENDMENT NO. 180 TO FACILITY OPERATING LICENSE NO. NPF-74


PALO VERDE NUCLEAR GENERATING STATION, UNITS 1,2, AND 3

DOCKET NOS. STN 50-528, STN 50-529, AND STN 50-530

1.0 INTRODUCTION

By application dated September 28, 2009 (Reference 1), as supplemented by letters dated June 24 and September 3 and 24, 2010 (References 2, 3, and 4, respectively), Arizona Public Service Company (APS, the licensee) requested changes to the Technical Specifications (TSs) for the Palo Verde Nuclear Generating Station (PVNGS), Units 1, 2, and 3. The proposed amendments would revise Required Action A.1 of TS 3.8.7, "Inverters - Operating," for PVNGS, Units 1, 2, and 3, by extending the Completion Time (CT) for restoration of an inoperable vital alternating current (AC) inverter from 24 hours to 7 days, to support the ability to complete online corrective maintenance of these components.

The licensee's supplemental letters dated June 24 and September 3 and 24, 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) staff's original proposed no significant hazards consideration determination as published in the Federal Register on December 1, 2009 (74 FR 62833).

2.0 REGULATORY EVALUATION

APS identified the regulatory requirements applicable to the license amendment request (LAR) in its application dated September 28, 2009. The licensee's application and its supplemental letters provided risk-informed and deterministic evaluations in support of the proposed changes. The regulatory requirements and guidance that the NRC staff considered in its review of the application are discussed below.

Enclosure 4

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2.1 Applicable Regulations

Section 182.a. of the Atomic Energy Act of 1954, as amended requires applicants for licenses to operate nuclear power plants to include technical specifications as part of the license application. These TSs become part of any license issued and are derived from the plant safety analyses. The regulations in Title 10 of the Code of Federal Regulations (10 CFR), Section 50.36, 'Technical specifications;' contain the requirements for the content of TSs. Pursuant to 10 CFR 50.36, TSs are required to include, in part, limiting conditions for operation (LCOs), which include CTs for equipment that is required for safe operation of the facility.

The regulations in 10 CFR 50, Appendix A, General Design Criterion (GDC) 17, "Electric power systems," require, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of structures, systems, and components (SSCs) that are important to safety. The onsite electric power supplies, including the batteries, and onsite electrical distribution system, 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 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, a loss of power from the unit, the offsite transmission network, or the onsite power supplies.

Section 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," of 10 CFR requires that preventive maintenance activities must be sufficient to provide reasonable assurance that SSCs are capable of fulfilling their intended functions and that such activities be balanced against the objective of minimizing the unavailability of SSCs. Paragraph 50.65(a)(4) requires licensees to assess and manage the increase in risk that may result from proposed maintenance activities.

2.2 Applicable Regulatory Criteria/Guidance

The regulatory guidance (RG) that the NRC staff used in its review of the risk information submitted in support of the LAR consisted of the following:

• RG 1.174, ''An Approach for Using Probabilistic Risk Assessment [PRA] in RiskInformed Decisions on Plant-Specific Changes to the Licensing Basis;' (Reference 5), describes an acceptable method for licensees and the NRC to use for assessing the nature and impact of proposed changes to the licensing basis by considering engineering issues and applying risk insights. This regulatory guide also provides risk-acceptance guidelines for evaluating the results of such evaluations.

• RG 1.177, ''An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications;' (Reference 6), describes methods acceptable to the NRC for assessing the nature and impact of proposed permanent TS changes, including allowed outage times, by considering engineering issues and applying risk insights. This regulatory guide also provides risk-acceptance guidelines for evaluating the results of such assessments. RG 1.177 identifies a three-tiered

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approach for licensees' evaluation of the risk associated with a proposed TS CT 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 (LiCDF) and change in large early release frequency (LiLERF). 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 present TS change in light of past related applications or additional applications 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 equipment associated with the proposed CT 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-ofservice 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 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.

• RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," (Reference 7), 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

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confidence in the results, such that the PRA can be used in regulatory decision making for light-water reactors.

General guidance for evaluating the technical basis for proposed risk-informed changes is provided in Section 19.2, "Review of Risk Information Used to Support Permanent PlantSpecific Changes to the Licensing Basis: General Guidance," of the NRC Standard Review Plan (SRP), NUREG-0800 (Reference 8). Guidance on evaluating PRA technical adequacy is provided in Section 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 9). More specific guidance related to risk-informed TS changes is provided in SRP Section 16.1, "Risk-Informed Decision Making: Technical Specifications" (Reference 10), which includes CT changes as part of risk-informed decision making. Section 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:

• The proposed change meets the current regulations, unless it explicitly relates to a requested exemption or rule change (Key Principle 1).

• The proposed change is consistent with the defense-in-depth philosophy (Key Principle 2).

• The proposed change maintains sufficient safety margins (Key Principle 3).

• When proposed changes increase core damage frequency (CDF) or risk, the increase(s) should be small and consistent with the intent of the Commission's Safety Goal Policy Statement (Key Principle 4).

• The impact of the proposed change should be monitored using performance measurement strategies (Key Principle 5).

3.0 TECHNICAL EVALUATION

The NRC staff has reviewed the licensee's analysis provided in the license amendment application dated September 28, 2009 (Reference 1), as supplemented by letters dated June 24 and September 3 and 24, 2010 (References 2, 3 and 4, respectively). The staff performed both a deterministic evaluation and a risk-informed evaluation of the application, as discussed below.

3.1 Deterministic Evaluation

The deterministic engineering evaluation addresses Key Principles 1, 2, 3, and 5 of the NRC staff's philosophy of risk-informed decision making, which concerns compliance with current regulations, evaluation of defense-in-depth, evaluation of safety margins, and performance monitoring strategies.

3.1.1 System Design

Vital (Class 'I E) AC inverters provide AC electrical power to the four vital AC instrumentation and control buses. The vital AC inverters are the preferred source of power for the four 120-volt vital AC instrumentation buses because they provide an uninterruptible power supply since they are powered from the Class 1E 125-volt direct current (DC) battery source. This configuration provides an uninterruptible power source for the instrumentation and controls for the four

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channels of Reactor Protective System (RPS) and the Engineered Safety Features Actuation System (ESFAS). There are two vital AC inverters per independent train (A and B), for a total of four vital AC inverters, powering four vital AC instrumentation and control buses per PVNGS unit. Alternatively, the vital AC instrumentation buses can be powered from an AC source via a Class 1E constant voltage regulator (which is Emergency Diesel Generator (EDG) backed) through a transfer switch.

The vital AC inverters are designed to provide the required capacity, capability, redundancy, and reliability to ensure the availability of power to the RPS and ESFAS instrumentation and controls so that the fuel, Reactor Coolant System, and containment design limits are not exceeded.

The vital AC inverters ensure the availability of AC electrical power for the instrumentation and controls of systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence or a postulated design basis accident. Maintaining the required vital AC inverters operable ensures that the redundancy incorporated into the design of the RPS and ESFAS instrumentation and controls is maintained. The four inverters (two per train) ensure an uninterruptible supply of AC electrical power to the vital AC instrument buses, even if the 4160-volt safety buses (the AC power source for major plant safety systems) are deenergized.

During normal operation, a 125-volt DC station battery provides power to each vital AC inverter, which, in turn, powers the corresponding vital AC instrumentation bus. In this configuration, the inverter is operable when its output voltage and frequency are within tolerances. With a vital AC inverter inoperable, its associated vital AC instrument bus becomes inoperable until that bus is reenergized from its Class 1E constant voltage source regulator. With a vital AC inverter inoperable and the associated vital AC instrumentation bus supplied from the alternate regulated AC electrical power source (the Class 1E constant voltage regulator), a failure of that AC source (for example, due to a loss of offsite power), will result in a momentary loss of power to the associated vital AC instrumentation bus. Power would be restored to the bus once the associated EDG starts and loads and re-energizes the bus.

3.1.2 NRC Staff Evaluation

In a request for additional information, dated April 13, 2010 (Reference 11), the NRC staff requested a detailed description of loss-of-power effects for the vital AC buses and Abnormal Operating Procedures (AOPs) developed to respond to such loss-of-power events. In Reference 2, the licensee provided detailed descriptions of the loss-of-power effects and identified the AOPs developed to respond to loss-of-power events. Should power be lost to a vital AC bus while powered from its backup source (i.e., Class 1E constant voltage regulator), AOPs provide detailed directions for operators to properly respond to the effects of losing power to the vital AC bus. Following restoration of vital AC instrumentation bus power, bus loads would be restored with no adverse impact to PVNGS, since the unaffected instrument channels would be expected to be operable and powered from their respective inverters. Based on the above, the NRC staff concludes the licensee's response is acceptable.

The licensee has requested an increased CT of 7 days, versus the current 24 hours, for Required Action A.1 of TS 3.8.7, for one required inverter inoperable, to support online emergent corrective maintenance of the vital AC inverters. In Reference 11, the NRC staff requested a detailed discussion concerning the maintenance plan/schedule supporting the need

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for a CT of 7 days versus the existing 24-hour CT. In Reference 2, the licensee stated that a comprehensive maintenance plan has been developed to ensure that maintenance is conducted consistently with proper failure evaluation, scope of work definition, maintenance planning with appropriate schedule margins promoting quality maintenance, maintenance process and post maintenance testing. In a telephone conference on September 22, 2010, the NRC staff requested further clarification concerning the limiting duration for an inverter maintenance evolution supporting the proposed 7-day CT. By letter dated September 24,2010 (Reference 4), the licensee provided a detailed timeline that addressed restoration of an inverter after a severe failure. Based on its review of the licensee's response, the NRC staff determined that given a severe inverter failure involving more complex maintenance actions, maintenance evolutions beyond 24 hours and up to 7 days could be necessary. Therefore, extending the CT to 7 days would provide a reasonable amount of time to allow the licensee to perform adequate analyses, develop detailed corrective action plans, and perform quality corrective maintenance on a vital inverter. Based on this information, the NRC staff concludes that the requested 7-day CT duration is acceptable.

The NRC staff also requested the licensee to provide a detailed discussion concerning corrective actions as result of the multiple, recent inverter failures at PVNGS, to provide assurance that the licensee has taken adequate measures to address performance issues with these vital inverters. Proper operational performance of the inverters is important, particularly when operating with less than the four channels required by TSs. In Reference 2, the licensee discussed the various failures that have occurred and the corrective maintenance that has been completed. The licensee has developed a comprehensive maintenance plan with increased emphasis on predictive maintenance for the vital inverters. According to the licensee, this program incorporates improved preventative maintenance practices, including proactive component replacement and improved monitoring of important parameters of inverter operation. The licensee reported that since it had developed and implemented a focused recovery plan, the inverter system performance has shown improvement (the indicator color has improved from yellow to white in March 2010) and has been good through 2009 and 2010, even though an additional inverter failure occurred in the spring of 2010. This most recent failure is not directly correlated to inverter performance and was unlike the past failures in that it was a result of postmaintenance testing. The NRC staff concludes that actions taken by the licensee appear to be effective, and that the enhanced predictive maintenance program provides confidence in the availability, capability, and reliability of the PVNGS vital inverters.

The NRC staff requested the licensee to provide a detailed discussion concerning compensatory measures to be implemented when an inverter is removed from service for the extended CT. In Reference 2, the licensee identified the following compensatory measures:

a. Inverter maintenance will not be undertaken during periods when the associated EDG is scheduled for maintenance.

b. Inverter maintenance will not be undertaken during periods when planned maintenance on RPS or ESFAS from another channel would place that channel in a tripped condition.

The NRC staff reviewed the LAR, the responses to the requests for additional information, and the design bases in the PVNGS Updated Final Safety Analysis Report (UFSAR) and determined that the aforementioned compensatory measures provided additional assurance that plant safety will be maintained during the extended CT. Additionally, the NRC staff concludes that the

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licensee's actions to assess and manage increased risk in accordance with 10 CFR 50.65 provide sufficient assurance that plant safety will be maintained during the extended CT.

3.1.3 Summary of Deterministic Evaluation

Based on the above, the NRC staff concludes that the proposed change to the PVNGS TSs provides reasonable assurance of the continued availability of the required power to shut down the reactor and to maintain the reactor in a safe condition after an anticipated operational occurrence or a postulated design-basis accident. The NRC staff also concludes that the proposed change is in accordance with 10 CFR 50.36 and 10 CFR 50.65, meets the intent of GDC 17, and is consistent with the key principles for risk-informed evaluations. Therefore, the NRC staff concludes that the proposed change to revise PVNGS TS 3.8.7, "Inverters Operating," Required Action A.1 , to allow one required inverter to be inoperable for up to 7 days to support online maintenance of the vital AC inverters, is acceptable.

3.2 Risk-Informed Evaluation

3.2.1 Review Methodology

The NRC staff reviewed the license amendment application using the three-tiered approach and the five key principles of risk-informed decision making presented in RG 1.174 and RG 1.177, in accordance with SRP Section 19.2 and Section 16.1. The key information used in the staff's review is contained in the licensee's application dated September 28, 2009 (Reference 1), Enclosure 1, Section 3.4, and Enclosures 2 through 6, and in the licensee's supplemental letter dated June 24, 2010 (Reference 2).

3.2.2 NRC Staff Technical Evaluation (PRA)

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

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 staff review involves two aspects: (1) evaluation of the validity of the PVNGS 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 PVNGS PRA used in evaluating the proposed changes to TS 3.8.7 CTs is of sufficient scope, level of detail, and technical adequacy for this application. The NRC staff evaluated the PRA quality information provided by the licensee in the LAR and its supplements, including industry peer review results and self-assessments performed by the licensee.

The PVNGS PRA model, identified as documented in Engineering Study 13-NS-C029, Revision 15, addresses both CDF and large early release frequency (LERF). The model

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includes the inverters and backup power supplies. A truncation level of 1E-12/year for CDF, and 1E-13/year for LERF, has been applied to generate results for this application. Channel 'A' of the four inverter channels was determined to have the greatest risk impact, and so the results for this application are conservatively based on this channel being inoperable. The licensee qualitatively identified the asymmetries in plant design which result in channel 'A' being highest risk as related to auxiliary feedwater system impacts between channels 'A' and 'B', and the significance and lower number of safety-related loads for channels 'C' and 'D'.

The licensee has administrative procedures and processes for configuration control of the PRA model, which includes review of relevant changes to the plant equipment and procedures, and capture of plant-specific data related to equipment performance and initiating events. The licensee stated that no outstanding plant changes, implemented but not yet incorporated into the PRA models, were identified that would affect the analysis performed in support of this amendment request.

In November 1999, the Combustion Engineering Owners Group performed a peer review of the PVNGS PRA model. Since the completion of the peer review, all significant findings and observations have been addressed, with the sole exception of one item which is the lack of an internal flooding risk analysis. The licensee stated that the Individual Plant Examination conducted for the PVNGS evaluated internal flooding, and there were no vulnerabilities identified and all compartments were screened. This result is attributed to the compartmentalized design of the facility. The licensee stated that the conclusion of this evaluation remain valid. This item is further discussed below.

The licensee also conducted a self-assessment of the PVNGS PRA against Addendum B of the American Society of Mechanical Engineers (ASME) PRA Standard using the guidance of RG 1.200 Revision 1. Capability category II of the standard was evaluated. The results of this self-assessment identified several failures to meet a supporting requirement (SR) at capability category II of the ASME standard, and the licensee identified and dispositioned those elements relevant to this application. The licensee addressed the findings for these SRs relative to this application, and the NRC evaluated the licensee's dispositions, as discussed below. The finding is stated first, followed by the licensee's disposition and the NRC staff's conclusion for each item.

• SR IE-A2: The PRA does not include an internal flood model. The licensee stated that the Individual Plant Examination conducted for the PVNGS evaluated internal flooding, and there were no vulnerabilities identified and all compartments were screened. This result is attributed to the compartmentalized design of the facility, and this conclusion is still valid. Further, the equipment of importance for the vital AC application is not located in areas of the plant where a significant flood initiator could occur. Specifically, the inverters and DC buses and battery chargers that supply the inverters have no direct flooding sources in their location (DC Equipment Rooms), and the spray-tight motor control centers and load centers that supply power to the inverters and battery chargers in the ESF switchgear rooms and the electrical penetration rooms are exposed only to dry fire suppression piping and a limited capacity 2-inch chilled water piping. There are no large flooding sources that could challenge the remaining operable inverters in the event of a piping failure. The NRC staff concludes that because there are no significant flooding sources in proximity to the equipment important to this proposed TS change, there is no impact on this application.

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• SRs IE-A5, IE-A6: The development of initiating events may be incomplete since the analysis did not consider events at low power or shutdown conditions, and did not include interviews of plant personnel. The licensee identified that crosscomparisons of other PRA models for similar plant designs did not identify missing initiating events, and any such missing initiating events would be extremely unlikely to be significant. In addition, the licensee stated that the initial development of the initiating events for the PVNGS PRA included extensive input from system engineers and operators, and that only the documentation of this input may be insufficient. The NRC staff concludes that because the scope of initiators was found to be complete by alternative means (comparison of models for similar plants), there is no impact on this application.

• SR IE-C4: The PRA model does not include a vessel rupture as an initiator, and the screening criterion for interfacing systems loss-of-coolant accidents (LOCAs) is not appropriate (although the events would still screen out if proper criteria were used). The licensee identified vessel rupture as contributing 1E-7/year to the COF, and less than 1E-8/year to LERF. The unavailability of a vital inverter would not be relevant for this accident scenario, since a vessel rupture is assumed to proceed directly to core damage, and the event cannot be mitigated. Therefore, the staff concludes that this LAR is not affected by this initiating event.

• SR SY-A4: The licensee's self-assessment identified the failure to conduct walkdowns using system engineers and operators to validate that the PRA model reflects the as-built and operated plant. In its application, the licensee stated that system engineers were involved in the PRA validation effort, by reviewing the fault tree models. The licensee also indicated that the PRA analysts working on the validation effort were knowledgeable about the plant layout, and normal and emergency operations. In its response to the staff's RAI (Reference 2) the licensee further stated that the original plant walkdowns were conducted by the PRA group, and included two engineers who held Senior Reactor Operator licenses for PVNGS and, therefore, had the requisite Operations experience to address this element. Although system engineers did not specifically perform the walkdowns, the personnel that did perform the walkdowns had appropriate and similar expertise, and the NRC staff does not expect the licensee's nonconformance with the specific requirements of this element of the standard to have any adverse impact on the fidelity of the PRA model. Therefore, the staff finds that the disposition of this element has no impact on this application.

• SRs QU-A2b, QU-E3: The state-of-knowledge correlation is not discussed or accounted for in the PRA model. The licensee performed additional analyses accounting for the correlation in the COF results for this application and stated that the estimated mean COF value is only about 1 percent above the point estimate COF. Therefore, the staff concludes that the licensee has demonstrated that these items have very minimal impact on this application.

• SR QU-03: The licensee's self-assessment identified that there is no recent comparison to the PRA results for similar plant designs. In its application and RAI responses, the licensee identified 2 previous comparisons that had been completed by the Combustion Engineering Owners Group several years ago,

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made to address common industry initiatives (such as guidance on LERF developed by Westinghouse) and initiatives of the Electric Power Research Institute and the NRC. The licensee also provided a detailed discussion of the results of these prior comparisons, and further addressed those items unique to PVNGS when compared to other similar plant designs. The information developed from the comparisons and the recent PRA updates demonstrate that the PVNGS PRA model is generally consistent with other PRA models for similar plant designs, and accurately accounts for differences in plant design. Therefore, the staff concludes that the disposition of this element has no impact on this application.

• SRs QU-E 1, QU-E2, QU-E4, LE-F2, LE-F3: The sources of model uncertainty are not identified; a systematic approach to identify key assumptions is not used; and the sensitivity of the results of the PRA quantification to these assumptions and uncertainties is not performed. The licensee identified the major sources of uncertainty relevant to this application (loss of off-site power frequency, inverter failure rate, voltage regulator failure rate, and EDG unavailability), and provided supporting sensitivity analyses in Reference 1. The licensee also indicated that the vital AC system is thoroughly modeled in the PRA, ensuring completeness and minimizing additional uncertainties for this application. The NRC staff reviewed the licensee's analyses, and concludes that the licensee has adequately addressed these supporting requirements for this application.

• SRs LE-C2a, LE-C2b, LE-C8b, LE-C9b, LE-D4, LE-D5: These SRs relate to realistic analyses supporting the containment performance following postulated core damage. The PVNGS PRA model uses conservative assumptions and therefore does not meet capability category II for more realistic analyses. The licensee stated that the small value of LERF does not warrant additional evaluation, and that any reduction in LERF is not expected to be significant. Therefore, the staff concludes that the disposition of this element has no impact on this application.

• SR LE-C10: The engineering basis for any decontamination factors (DFs) applied when crediting scrubbing of a release has not been provided. In Reference 2, the licensee identified that the DFs used are consistent with the plant safety analysis, and are only credited when secondary cooling is not failed. Therefore, the staff concludes that an engineering basis has been identified for crediting scrubbing, which satisfies this requirement for this application.

• SR LE-G5: Limitations of the LERF model are not identified. The licensee stated that the inverters have no direct impact on containment performance or containment bypass, and that the impact of inverter failure on LERF for this application is two orders of magnitude below the acceptance guidance in RG 1.174. Based on these considerations, the staff concludes that the LERF model is adequate for this application, and this SR deficiency would have minimal impact on the application.

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• SRs IE-D2. IE-D3, AS-C1, AS-C2. AS-C3. SC-C2. SC-C3, SY-C1, SY-C2. SY-C3. QU-F1. QU-F2. QU-F4, QU-F5. QU-F6: These SRs relate to deficiencies with respect to documentation of specific areas of the PRA model. The licensee provided an updated status identifying substantial progress in improving its model documentation. The licensee stated that with the March 2010 PRA model update, all items listed above now meet the documentation requirements, except for some remaining minor deficiencies in SY-C1, SY-C2, and SY-C3, which deal with system modeling and uncertainties. Reference 2 provided a detailed discussion addressing these 3 SRs. The licensee maintains that all important PRA information is adequately documented (for example, in the Risk Spectrum PRA file), but not necessarily in a form that facilitates peer review. Based on these updates, the staff concludes that the remaining identified deficiencies in documentation have no impact on this application.

Based the above, the NRC staff agrees that the outstanding gaps in the PVNGS PRA would not have a significant impact on the internal events risk assessment results supporting this request. Therefore, the staff concludes that the licensee 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), RG 1.200, and SRP Chapter 19.1, and that the quality of the PVNGS internal events PRA is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

PRA Quality - Internal Fires Model

The licensee identified that it quantitatively evaluated internal fires along with internal events in its risk analysis. There are no outstanding plant changes not incorporated into the fire PRA models.

The technical elements of RG 1.200, Revision 1, Section 1.2.4, applicable to fire PRA models, are addressed as follows:

• Screening Analysis - Only areas and compartments separate from the nuclear support and power generation areas were screened out. The compartments in the Auxiliary, Main Steam Support Structure, Control, Turbine, and Corridor Buildings were modeled, even if there were no trip initiators or mitigating equipment or cables present. This is conservative, since the potential exists for a manual trip due to fire in any of these areas (which would not be included if they were screened).

• Fire Initiation Analysis-Electric Power and Research Institute (EPRI) TR-1000894, EPRI Fire Events Database, was used as the source for frequencies with apportionment among compartments and equipment per the EPRI TR-105928, EPRI Fire PRA Implementation Guide.

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• Fire Damage Analysis - Fire event trees were constructed that split the total frequency for a compartment into fractional contributions from each fire source in the compartment and from transient materials. Fire propagation potential is modeled. Fire suppression is only credited where it can reasonably be expected to arrest propagation to needed mitigating equipment or cables within the same compartment, and would not render equipment unavailable from the spray. The fire propagation code COMPBRN was used only to generate a few bounding cases for fires. Over 100 specific plant damage states were defined, and were linked to mitigation event trees.

• Plant Response Analysis and Quantification - Each plant damage state from the previous step is then an input to a mitigation event tree. Several types of transient event trees were used from the internal events analysis, including uncomplicated reactor trip, turbine trip, loss of offsite power, and loss of heating, ventilation, and air conditioning (HVAC). Most transient event trees include induced LOCA through stuck-open pressurizer safety valves.

Components were analyzed regarding their potential spurious operation and how a fire-induced transient might be impacted. In its response to a request for additional information (Reference 3), the licensee provided additional assessments of potential spurious operations. The guidance of NUREG/CR-6850, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities;' September 2005, was used to determine the types of circuit failures to consider. The PRA model was quantified applying the specific configuration of the inverter power supplies to identify relevant fire areas, and then an assessment was made of spurious actuations on the opposite train and those on the same train where the fire effects could also interrupt power to the inverter backup voltage regulator. The licensee concluded that the impact of multiple spurious operations for this configuration is minimal.

Only plant equipment known not to be damaged due to fire effects was credited for mitigation of a fire. Specifically, if cable routing associated with a component is not known, then the component was not credited.

EPRI TR-105928, EPRI Fire PRA Implementation Guide, applies penalty factors of two or three depending upon time constraints and whether the action is inside or outside of the control room. Human actions were not credited if the operator would have to go into a compartment affected by the fire. The only human reliability analysis specific to fire is establishing plant control from the remote shutdown panel in the event of a control room fire.

An independent assessment of the fire PRA was conducted by a consultant in 2003. Only five issues from this review remain unresolved. These are either category C (considered desirable to maintain maximum flexibility in PRA applications and consistency in the industry, but not likely to significantly affect results or conclusions) or D (editorial or minor technical item, left to the discretion of the host utility).

Based on the above discussion of the fire PRA development and review, and considering the relatively minor impact calculated from risk associated with fire events for this application, the NRC staff concludes that the licensee 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), RG 1.200, and SRP Chapter 19.1, and that the quality of the fire PRA and methods applied is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

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PRA Risk Results and Insights

The inverter unavailability is directly modeled in the PRA by assuming that the inverter is out of service and the associated instrument bus is aligned to its backup voltage regulator. No credit is taken for aligning any other instrument buses to their backup regulators in the event that a second random inverter failure occurs, which is conservative for a risk calculation. Random unavailability of other components is retained in the risk analyses, which is also conservative. The ICCDP and ICLERP are based on the entire 7-day duration of the proposed 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.

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

Risk Measure Internal Evehts Internal Fires Total

ICCDP 4.8E-8 9.6E-11 4.8E-8

ICLERP 2.0E-9 3.8E-12 2.0E-9

~CDF (Assume 2 weeks/year unavailability) 7E-9/year

~LERF (Assume 2 weeks/year unavailability) 5E-10/year

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. The licensee's estimates of internal events and fire risk are consistent with these guidelines. Therefore, the NRC staff concludes that the risk is acceptable to permit the proposed change.

Evaluation of Seismic Risk

The licensee estimated the seismic contribution to risk based on the assumption that all equipment is unaffected by an operating basis earthquake (GBE), and evaluating the increase in risk for earthquakes greater than the GBE by assuming all non-seismically qualified equipment fails with certainty and assuming a non-recoverable loss of offsite power. The resulting change in risk was determined to be negligible. This is a reasonable result for the configuration with a single inverter out of service, since the affected instrument bus is seismically qualified and remains powered from the seismically qualified diesel generator and safety-related AC power system. Therefore, the NRC staff concludes that seismic risk is not a significant contributor to the risk during an inverter outage.

Qualitative Evaluation of External Hazards

PVNGS conforms to the SRP requirements with regard to external hazards, as discussed in the individual plant examination of external events submittal. Therefore, no vulnerabilities to other external events exist at PVNGS. Based on the conformance of the plant to the SRP, the NRC staff concludes that the risk contribution from other external hazards is not significant for this application.

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Shutdown Risk

The licensee's submittal did not specifically address shutdown risk in the tier one risk evaluation, and the proposed change to TS is not applicable to shutdown conditions.

Uncertainty Analysis

The licensee identified important initiators and basic event parameters which would have the most impact on the risk results. Sensitivity studies were then conducted to determine the potential bounding impact. The licensee evaluated:

• Loss of offsite power frequency • Inverter failure rate • Common cause factor for inverters • Voltage regulator failure rate • Diesel generator unavailability

The licensee re-evaluated the ICCDP and ICLERP using the 95th percentile value of each of the above parameters, except for the common cause factor, which instead was increased from 0.1 to 0.5. For each case, the resulting ICCDP and ICLERP remained well below the acceptance guidelines of RG 1.177. This effectively demonstrates that the conclusions of the risk analysis are insensitive to these sources of uncertainty.

3.2.2.2 Tier 2: Avoidance of Risk-Significant Plant Configuration

The licensee identified that concurrent maintenance of the associated train diesel generator, or of an RPS or ESFAS channel that results in the channel being in a tripped condition, should not be in progress when the TS action for an inoperable inverter is entered for planned corrective maintenance activities. Although identified as a tier 2 restriction, the licensee identified (Reference 3) that the risk significance of these configurations is not high, but that restriction for planned activities is an appropriately conservative administrative control based on qualitative considerations of the impacts of a loss of offsite power during inverter outages. Therefore, the associated TS Bases for TS 3.8.7 has been revised to identify these restrictions, rather than placing them in the TS action requirement. Since the configurations are not risk-significant, the NRC staff concludes this is acceptable.

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, and requires assessment for both planned and unplanned activities. Administrative controls are implemented based on the level of risk.

3.2.3 Summary of Risk-Informed Evaluation

The risk impact of the proposed 7-day CT for inverters, TS 3.8.7, Required Action A.1, 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 Chapter 16.1, "RiskInformed Decisionmaking: Technical Specifications;' of NUREG-0800. The Tier 2 evaluation

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identified the applicable risk-significant plant equipment outage configurations to be avoided, and appropriate TS controls are in place to assure these restrictions are in place. The licensee's CRMP satisfies the 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 are reasonable and of sufficient quality.

Based on the above, the NRC staff concludes that the proposed change to revise the CT of Required Action A.1 of TS 3.8.7, "Inverters-Operating:' from 24 hours to 7 days, is acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Arizona State official was notified of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on December 1,2009 (74 FR 62833). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

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

7.0 REFERENCES

1. Mims, D. C, Arizona Public Service Company, letter to U.S. Nuclear Regulatory Commission, "Request to Amend Technical Specification (TS) 3.8.7, "Inverters-Operating:' to Extend Completion Time for Restoration of an Inoperable Inverter:' dated September 28, 2009 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML09281 0227),

2. Hesser, J. H., Arizona Public Service Company, letter to U.S. Nuclear Regulatory Commission, "Request to Amend Technical Specification (TS) 3.8.7, "Inverters-Operating:' to Extend Completion Time for Restoration of an Inoperable Inverter-Request for Additional Information Response:' dated June 24,2010 (ADAMS Accession No. ML101880263).

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3. Hesser, J. H., Arizona Public Service Company, letter to U.S. Nuclear Regulatory Commission, "Response to Second Request for Additional Information (RAI)-Request to Amend Technical Specification (TS) 3.8.7, "Inverters-Operating;'to Extend Completion Time for Restoration of an Inoperable Inverter;' dated September 3, 2010 (ADAMS Accession No. ML102571398).

4. Hesser, J. H., Arizona Public Service Company, letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information (RAI)-Request to Amend Technical Specification (TS) 3.8.7, "Inverters-Operating;'to Extend Completion Time for Restoration of an Inoperable Inverter;' dated September 24, 2010 (ADAMS Accession No. ML102720481).

5. U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis;' Regulatory Guide 1.174, Revision 1, November 2002 (ADAMS Accession No. ML023240437).

6. U.S. Nuclear Regulatory Commission, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications;' Regulatory Guide 1.177, August 1998 (ADAMS Accession No. ML003740176).

7. U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities;' Regulatory Guide 1.200, Revision 2, March 2009 (ADAMS Accession No. ML090410014).

8. NUREG-0800, Standard Review Plan 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis;' Revision 0, June 2007.

9. NUREG-0800, Standard Review Plan 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities;' Revision 1, September 2006.

10. NUREG-0800, Standard Review Plan 16.1, "Risk-Informed Decision Making: Technical Specifications;' Revision 0, August 1998.

11. Hall, J. R, U.S. Nuclear Regulatory Commission, electronic mail to R Stroud, Arizona Public Service Company, "Request for Additional Information;' dated April 13, 2010 (ADAMS Accession No. ML101030884).

Principal Contributors: A. Howe K. Miller

Date: September 29, 2010

R. Edington - 2

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

Sincerely,

IRAJ

James R. Hall, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Docket Nos. STN 50-528, STN 50-529, and STN 50-530

Enclosures: 1. Amendment No. 180 to NPF-41 2. Amendment No. 180 to NPF-51 3. Amendment No. 180 to NPF-74 4. Safety Evaluation

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