ML062430684

V. C. Summer, License Amendment, WCAP-14333, Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times.

ML062430684
Person / Time
Site:	Summer
Issue date:	10/24/2006
From:	Martin R NRC/NRR/ADRO/DORL/LPLII-1
To:	Archie J South Carolina Electric & Gas Co
Martin R, NRR/DORL, 415-1493
Shared Package
ML062430685	List: ML062430684
References
TAC MC8898, WCAP-14333
Download: ML062430684 (32)

Text

October 24, 2006 Mr. Jeffery B. Archie Vice President, Nuclear Operations

South Carolina Electric & Gas Company

Virgil C. Summer Nuclear Station

Post Office Box 88

Jenkinsville, SC 29065

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 - ISSUANCE OF AMENDMENT REGARDING WCAP-14333, "PROBABILISTIC RISK ANALYSIS

OF THE RPS AND ESFAS TEST TIMES AND COMPLETION TIMES" (TAC NO. MC8898)

Dear Mr. Archie:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 177 to Renewed Facility Operating License No. NPF-12 for the Virgil C. Summer Nuclear Station, Unit 1. The amendment changes the technical specifications (TSs) in response to your

application dated November 15, 2005, as supplemented on May 31, August 31, and

September 29, 2006.

This amendment revises TS 3/4.3.1, "Reactor Tr ip System Instrumentation," and TS 3/4.3.2,"Engineered Safety Feature Actuation System In strumentation," to implement the allowed outage time and bypass test time changes approved in WCAP-14333-P-A, revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," dated

October 1998 and makes additional changes to ACTION 8 of TS 3/4.3.1.

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

Sincerely,/RA/Robert E. Martin, Senior Project Manager Plant Licensing Branch II-1

Division of Operating Reactor Licensing

Office of Nuclear Reactor Regulation Docket No. 50-395

Enclosures:

1. Amendment No. 177 to NPF-12

2. Safety Evaluation cc w/enclosures: See next page October 24, 2006 Mr. Jeffery B. Archie

Vice President, Nuclear Operations

South Carolina Electric & Gas Company

Virgil C. Summer Nuclear Station

Post Office Box 88

Jenkinsville, SC 29065

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 - ISSUANCE OF AMENDMENT REGARDING WCAP-14333, "PROBABILISTIC RISK ANALYSIS

OF THE RPS AND ESFAS TEST TIMES AND COMPLETION TIMES" (TAC NO. MC8898)

Dear Mr. Archie:

The Nuclear Regulatory Commission has issued the enclosed Amendment No. 177 to Renewed Facility Operating License No. NPF-12 for the Virgil C. Summer Nuclear Station, Unit 1. The amendment changes the technical specifications (TSs) in response to your

application dated November 15, 2005, as supplemented on May 31, August 31, and

September 29, 2006.

This amendment revises TS 3/4.3.1, "Reactor Tr ip System Instrumentation," and TS 3/4.3.2,"Engineered Safety Feature Actuation System In strumentation," to implement the allowed outage time and bypass test time changes approved in WCAP-14333-P-A, revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," dated

October 1998 and makes additional changes to ACTION 8 of TS 3/4.3.1.

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

Sincerely,/RA/Robert E. Martin, Senior Project Manager Plant Licensing Branch II-1

Division of Operating Reactor Licensing

Office of Nuclear Reactor Regulation Docket No. 50-395

Enclosures:

1. Amendment No. 177 to NPF-12

2. Safety Evaluation cc w/enclosures: See next page DISTRIBUTION:PublicRidsOgcRpRidsRgn2MailCenterRidsNrrDorlLpl2-1(EMarinos)RidsAcrsAcnwMailCenterRidsNrrDorlDpr RidsNrrPMRMartin(hard copy)GHill(2 hard copies)CDoutt RidsNrrLACSola(hard copy)RidsNrrDirsItsbCschulton

RidsNrrDraAplaPackage No: MLML062430685Tech Spec.: ML063000026Amendment No: ML062430684*No Legal Objection NRR-058OFFICELPL2-1/PMLPL2-1/LADRA/APLAOGCLPL2-1/BC NAMERMartinCSolaMRubin (by memo dated)MZobler*EMarinosDATE 10/23/0610/23/0609/19/0610/18/0610/24/06 OFFICIAL RECORD COPY SOUTH CAROLINA ELECTRIC & GAS COMPANY SOUTH CAROLINA PUBLIC SERVICE AUTHORITY DOCKET NO. 50-395 VIRGIL C. SUMMER NUCLEAR STATION, UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 177 Renewed License No. NPF-12 1.The Nuclear Regulatory Commission (the Commission) has found that:A.The application for amendment by South Carolina Electric & Gas Company (the licensee), dated November 15, 2005, as supplemented on May 31, August 31, and September 29, 2006 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, 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; andE.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.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

Renewed Facility Operating License No. NPF-12 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. 177, and the Environmental Protection Plan contained in

Appendix B, are hereby incorporated in the license. South Carolina Electric &

Gas Company shall operate the facility in accordance with the Technical

Specifications and the Environmental Protection Plan.3.This amendment is effective as of its dat e of issuance and shall be implemented within 60 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/Evangelos C. Marinos, Chief Plant Licensing Branch II-1

Division of Operating Reactor Licensing

Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: October 24, 2006 ATTACHMENT TO LICENSE AMENDMENT NO. 177 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-12 DOCKET NO. 50-395 Replace page 3 of Renewed Facility Operating License No. NPF-12 with the attached revised page 3.Replace the following pages with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Page Insert Page Technical Specifications Technical Specifications3/4 3-63/4 3-63/4 3-73/4 3-7 3/4 3-83/4 3-8 3/4 3-233/4 3-23 3/4 3-243/4 3-24 Bases BasesB 3/4 3-1B 3/4 3-1B 3/4 3-1aB 3/4 3-1a B 3/4 3-1bB 3/4 3-1b B 3/4 3-1cB 3/4 3-1c B 3/4 3-1dB 3/4 3-1d SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 177 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-12 SOUTH CAROLINA ELECTRIC & GAS COMPANY SOUTH CAROLINA PUBLIC SERVICE AUTHORITY VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 DOCKET NO. 50-39

51.0 INTRODUCTION

By application dated November 15, 2005, as supplemented on May 31, August 31, and September 29, 2006, (References 1, 2, 3 and 4), South Carolina Electric & Gas Company (SCE&G, the licensee) requested changes to the technical specifications (TSs) for the Virgil C.

Summer Nuclear Station, Unit 1 (VCSNS). The May 31, August 31, and September 29, 2006, letters provided clarifying information that did not change the November 15, 2005 application

and the initial proposed no significant hazards consideration determination.1.1Proposed Changes

The proposed changes would revise TS 3/4.3.1, "Reactor Trip System Instrumentation" (RTS), and TS 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation" (ESFAS), to

implement the extensions of restoration times for inoperable instrument channels and the

extensions of channel bypass times that have been approved by the Nuclear Regulatory Commission (NRC) staff in WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the

RPS [reactor protection system] and ESFAS Test Times and Completion Times,"

(WCAP-14333, Reference 9). The proposed changes in the license amendment request are

similar to those in the NRC-approved Technical Specification Task Force (TSTF) change

traveler TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)" (TSTF-418, Reference 10). This license amendment is not related to, or in

response to, any ongoing NRC activities (e.g., generic letters).1.2Background

The proposed TS modifications affect the RPS (i.e., RTS and ESFAS). The RTS is designed to shutdown the reactor when a limit to permissible operation is reached. The ESFAS is designed

to actuate for transients that challenge the normal control and heat removal systems. The RPS comprises several major functions including instrumentation, logic, reactor trip, and ESFAS actuation. Instrumentation consists of sensors, power supplies, signal processing and

bistable outputs and typically consists of three or four channels. The logic (i.e., logic cabinets)

includes two parallel logic blocks consisting of two trains (A and B) of RPS logic where the input

coincidence for various trip functions is determined. The RPS logic provides two parallel

outputs for ESFAS actuation. Each output is actuated by its associated RPS logic train, which

initiates the ESFAS function through master and slave relays.

Additionally, two parallel actuation paths are pr ovided from the RPS logic to the reactor trip breakers (RTBs). Normally, a RTB receives it s signal from its associated RPS logic train.

Bypass breakers are provided for when a breaker is out of service. In this configuration, the bypass breaker is associated with the logic train of the operable RTB. The RPS utilizes two

normally closed RTBs and two normally open bypass breakers. RPS logic train A actuates

RTB A and train B logic actuates RTB B. Opening of either RTB will disconnect power from the

control rods, causing a reactor trip.

The Westinghouse Owners Group (WOG) Technical Specification Optimization Program evaluated changes to surveillance test intervals (STIs) and allowed outage times (AOTs) for the

analog channels, logic cabinets, master and slave relays, and reactor trip breakers and

requested relaxations in TS requirements as follows. In 1983, the WOG submitted

WCAP-10271-P, "Evaluation of Surveillance Frequencies and Out-of-Service Times for the

Reactor Protection Instrumentation System," wh ich provided a methodology to be used to justify revisions to a plant's RPS TS. The methodology evaluated increases in surveillance intervals, test and maintenance out-of-service times, and the bypassing of portions of the RPS during test

and maintenance. The NRC staff approved WCAP-10271 and its supplements in references 5, 6, 7 and 8. These actions were part of the implementation of the recommendations for review of

surveillance test requirements made in NUREG

-1024, "Technical Specifications - Enhancing the Safety Impact," wherein the NRC suggested that TS action statements be reviewed to

assure that they have an adequate technical basis and do indeed minimize plant risk. TSs

approved in WCAP-10271 were incorporated into NUREG-1431, Revision 0, "Standard

Technical Specifications, Westinghouse Plants" (STS). Further details on the development of

the STS and TSTF 418 may be found in Reference 10.

In WCAP-10271, the WOG performed fault tree analyses to calculate the reactor trip unavailability, with consideration for surveillance intervals and test and maintenance times. The

sensitivity to variations in surveillance intervals and test and maintenance times were also

evaluated with respect to maintaining or revising current surveillance intervals. The WOG

concluded that the results of the analyses for the RPS were adequate to justify a revision of the

STS. WCAP-10271 including Supplement 1, was accepted, with conditions, by NRC in 1985, in

which the NRC staff approved the following changes for plant-specific TS:* Increase the surveillance interval for RTS analog channel operational tests from once per month to once per quarter.*Increase the time in which an inoperable RTS analog channel may be maintained in an untripped condition from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />. *Increase the time an inoperable RTS analog channel may be bypassed to allow testing of another channel in the same function from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. Also, the channel test

may be done in the bypass mode, leaving the inoperable channel in a tripped condition.* Allow testing of the RTS analog channels in a bypass condition instead of a tripped condition.

On February 22, 1989, (Reference 7), the NRC staff issued a safety evaluation (SE) for WCAP-10271, Supplement 2, that approved similar relaxations for the ESFAS. An additional

supplemental SE was issued on April 30, 1990, (Reference 8), that provided consistency

between RTS and ESFAS STIs and AOTs.

Subsequent to the approval of WCAP-10271 and its supplements, the WOG submitted WCAP-14333-P, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and

Completion Times," dated May 1995. On July 15, 1998, in Reference 9, the NRC staff issued

an SE approving WCAP-14333 for reference in license applications based on stated

acceptance criteria. The NRC staff's SE included approval of draft TS for Specifications 3.3.1, and 3.3.2. The TS for WCAP-14333 were incorporated into NUREG-1431, Revision 2. The

purpose of this topical report was to provide justification for the following additional TS

relaxations beyond those approved in WCAP-10271.*Increase the bypass times and repair AOTs for both the solid-state and relay protection system RPS and ESFAS designs. TSs changes of this type increase the test bypass

times and the times to restore inoperable channels to operable status for both the solid

state protection system (SSPS) and relay protection system RTS and ESFAS designs.

For analog channels, this increases the action statement AOT from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, and the test bypass time from 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• Increase the AOT repair times for the logic cabinets, master relays, and slave relays. TS changes of this type increase the action statement AOTs from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> for

maintenance plus 6 additional hours for a plant mode change. *Revise the reactor trip breaker and logic cabinet bypass repair AOTs. TS changes of this type specify that reactor trip breakers can be bypassed during test or maintenance

for a period of time equivalent to the bypass time for the logic cabinets provided both are

tested at the same time and provided the plant design is such that both the reactor trip

breaker and the logic cabinet cause their associated electrical trains (buses) to be

inoperable during test or maintenance.

In the case of VCSNS, only WCAP-10271 has been incorporated into the VCSNS TS by previous NRC-approved license amendment reques ts. The VCSNS RPS utilizes the SSPS for the logic portion of the RPS.

Proposed changes were not evaluated generically in WCAP-14333 for several instrument functions that included; (1) Reactor Coolant Pump Breaker Position, (2) Automatic Swithchover

to Containment Sump (RWST Level-Low Low Coincident with Safety Injection and Coincident

with Containment Sump Level-High, and (3) Loss of Power Emergency Diesel Start. The

VCSNS TSs do not include item (1) and there were no changes proposed for item (3). The

analogous change to item (2) for VCSNS is discussed in section 3.2.2.

2.0REGULATORY ANALYSIS

2.1Applicable Regulations Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include TSs as part of the license. In Section 50.36 of Title 10 of the Code of Federal Regulations (10 CFR 50.36), the Commission establishes the regulatory requirements related to the content of TSs. 10 CFR 50.36 does not specify particular requirements to be

included in TSs, but does, in part, require that TSs include items in the following five specific

categories:

(1) safety limits, limiting safety syst em settings and limiting control settings (2) limiting conditions for operation (LCOs)

(3) surveillance requirements

(4) design features

(5) administrative controls The Maintenance Rule,10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," requires licensees to monitor the performance or

condition of structures systems and component s (SSCs) against licensee-established goals, in a manner sufficient to provide reasonable assurance that SSCs are capable of fulfilling their

intended functions as applicable to the implementation and monitoring program guidance of

RG 1.174, Section 2.3, and RG 1.177, Section 3. In addition,10 CFR 50.65(a)(4), as it relates to

the proposed AOT extension, requires the asse ssment and management of the increase in risk that may result from the proposed maintenance activity.

General Design Criterion (GDC) 13, "Instrumentation and Control," requires that appropriate controls be provided to maintain the applicable variables and systems within prescribed

operating ranges.

GDC 21, "Protection System Reliability and Testability," requires the protection system to be designed for high functional reliability and inservice testability, commensurate with the safety

functions to be performed. The protection system shall be designed to permit periodic testing of

its functioning when the reactor is in operation, including a capability to test channels

independently to determine failures and losses of redundancy that may have occurred.2.2Applicable Regulatory Criteria and Guidance

The NRC staff review of the November 15, 2005 application and its supplements, made use of the following applicable regulatory guidance:*NUREG-1431, "Standard Technical Specifications, Westinghouse Plants," Revision 2, and*TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)." General guidance for evaluating the technical basis for proposed risk-informed changes is provided in Chapter 19.0, "Use of Probabilis tic Risk Assessment (PRA) in Plant-Specific, Risk-Informed Decisionmaking: General Guidance," of the NRC Standard Review Plan (SRP),

NUREG-0800. More specific guidance related to risk-informed TS changes is provided in SRP

Section 16.1, "Risk-Informed Decisionmaking: Technical Specifications," which includes AOT

changes as part of risk-informed decisionmaking. Chapter 19.0 of the SRP states that a

risk-informed application should be evaluated to ensure that the proposed changes meet the

following five key principles: 1.The proposed change meets the current regulations, unless it explicitly relates to a requested exemption or rule change. 2.The proposed change is consistent with the defense-in-depth philosophy.

3.The proposed change maintains sufficient safety margins.

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

Statement. 5.The impact of the proposed change should be monitored using performance measurement strategies.

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

November 2002, describes a risk-informed approach, acceptable to the NRC, for licensees to

assess the nature and impact of proposed permanent licensing basis changes by considering

engineering issues and applying risk insights.

RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998, identifies an acceptable risk-informed approach, including

additional guidance geared toward the assessment of proposed permanent TS AOT changes.

Specifically, RG 1.177 identifies a three-tiered approach for the licensee's evaluation of the risk

associated with a proposed AOT TS change, as shown 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 (CDF) and change in large early release frequency (LERF). It also evaluates plant risk while equipment covered by the proposed AOT 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 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, are 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 AOT is implemented.

• Tier 3 addresses the licensee's overall conf iguration 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 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 AOT will be appropriately assessed from a risk perspective.

More specific methods and guidelines acceptable to the staff are also outlined in RG 1.177 for assessing risk-informed TS changes. Specifica lly, RG 1.177 provides recommendations for utilizing risk information to evaluate changes to TS AOTs and surveillance test intervals, with respect to the impact of the proposed change on the risk associated with plant operation.

RG 1.174 and RG 1.177 also describe acceptable implementation strategies and performance monitoring plans to help ensure that the assumptions and analysis used to support the

proposed TS changes will remain valid. The monitoring program should include means to

adequately track the performance of equipment that, when degraded, can affect the conclusions

of the licensee's evaluation for the proposed licensing basis change. RG 1.174 states that

monitoring performed in accordance with the Maintenance Rule,10 CFR 50.65, can be used

when the monitoring performed under the Maintenance Rule is sufficient for the SSCs affected

by the risk-informed application.

3.0TECHNICAL EVALUATION

- TRADITIONAL ENGINEERING REVIEW3.1 Reactor Trip System Instrumentation Changes

All discussions in this section refer to VCSNS TS 3/4.3.1, "Reactor Trip System Instrumentation."3.1.1Increased Bypass Allowance and Repair AOTs for Instrumentation Channels

The VCSNS TS changes increase the AOTs for analog channels from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, and the test bypass time from 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> as listed below. ACTION 2 is revised to increase the AOT to restore an inoperable RTS analog channel to operable status before it must be placed in the tripped condition from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> and

the time allowed for an RTS analog channel to be bypassed for testing is increased from

4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. Action 2 applies to Function 2.A, Power Range Neutron Flux - High

Setpoint, Function 2.B, Power Range Neutron Flux - Low Setpoint, and Function 3, Power

Range Neutron Flux Rate - High Positive Rate.

ACTION 6 is revised to increase the AOT to restore an inoperable RTS analog channel to operable status before it must be placed in the tripped condition from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> and

the time allowed for an RTS analog channel to be bypassed for testing is increased from

4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. Action 6 applies to Function 7, Overtemperature T, Function 8, Overpower T, Function 9, Pressurizer Pressure - Low, Function 10, Pressurizer Pressure - High, Function 11, Pressurizer Water Level - High, Function 12A, Loss of

Flow - Single Loop, Function 12B, Loss of Flow - Two Loops, Function 13, Steam Generator

Water Level Low-Low, and Function 14, Steam /Feedwater Mismatch and Low Steam

Generator Water Level, Function 15, Undervoltage Reactor Coolant Pumps, Function 16, Underfrequency Reactor Coolant Pumps, and Function 17A, Turbine Trip - Low Fluid Oil

Pressure.3.1.2Revised Reactor Trip Breaker and Logic Cabinet Bypass Repair AOTs

The VCSNS TSs reactor trip breakers bypass time during test or maintenance can be changed to be equivalent to the bypass time for the logic cabinets provided both are tested at the same

time and provided the plant design is such that both the reactor trip breaker and the logic

cabinet cause their associated electrical trains (buses) to be inoperable during test or

maintenance. On this basis, the test bypass time may be changed from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

ACTION 8 is revised to increase the time allowed for an RTB to be bypassed from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for concurrent surveillance testing of the RTB and automatic trip logic.

ACTION 12 is revised to increase the AOT to restore an inoperable train of automatic trip logic to operable status before the unit must be shutdown from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> for Safety

Injection Input from ESF (RTS Functions 18) and Automatic Trip Logic (RTS Function 21). 3.1.3Conclusion - RTS Changes in Sections 3.1.1 and 3.1.2

The NRC staff concludes that: (1) increase the required action completion time to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> and the test bypass times to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />, (2) revise the reactor trip breaker and logic cabinet bypass

required action completion time to be equivalent to the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> bypass time for the logic cabinets (for the case where logic cabinets and trip breakers both cause their train to be inoperable when

in test or maintenance) provided both are tested at the same time, and (3) increase the logic

cabinets, master relays and slave relays required action completion time to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />, are

consistent with the approved allowances accepted by the NRC staff based on WCAP-14333

and are, therefore, acceptable.

In addition, proposed TSs Bases provide an adequate basis or reason for the approved TS changes. 3.1.4RTS Changes Unrelated to WCAP-14333 ACTION 8 for RTS Function 20, RTBs, is also revised to include a requirement to restore an inoperable breaker to operable status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Currently Action 8 does not include such

an Action, and a unit shutdown must be initiated immediately if an RTB is inoperable. A note is

also added that a RTB may be bypassed for up to 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> for maintenance on the undervoltage

or shunt trip mechanisms.

The NRC staff finds that the revision to add a one hour AOT to restore an inoperable RTB to operable status is equal to the time allowed by LCO 3.0.3 for shutdown actions in the event of a

complete loss of RTS function. Applying the one hour AOT allowance to the condition of one

RTB train inoperable is conservative and allows for an orderly transition to shutdown and is

acceptable. The revision to add a 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> bypass AOT for maintenance on the undervoltage or

shunt trip mechanisms provided the other train is operable was reviewed by the NRC staff in

WCAP-10271-P-A, Supplement 1, May 1986. By letter dated June 18, 1991, the NRC staff

issued Amendment No. 101 to Renewed License No. NPF-12, revising the VCSNS TS to

include WCAP-10271-P-A, Supplement 1. The addition of the 2-hour bypass allowance is

therefore approved.3.2ESFAS Instrumentation Changes

All discussions in this section refer to the proposed changes to VCSNS TS 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation." 3.2.1Increased Repair Times for Logic Cabinets, Master Relays and Slave Relays

These TS changes increase the AOTs from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> for maintenance.

ACTION 14 is revised to increase the AOT for Function 1.b, Safety Injection Automatic Actuation Logic and Actuation Relays; Function 2.b, Reactor Building Spray Automatic

Actuation Logic and Actuation Relays; Function 3.a.3, Containment Isolation - Phase A Isolation

Automatic Actuation Logic and Actuation Relays, and Function 3.b.1, Containment Isolation -

Phase B Isolation Automatic Actuation Logic and Actuation Relays.

ACTION 21 is revised to increase the AOT for Function 4.b, Steam Line Isolation Automatic Actuation Logic and Actuation Relays; Function 6.b, Emergency Feedwater Automatic Actuation

Logic and Actuation Relays; and Function 8.b, Automatic Switchover to Containment Sump

Automatic Actuation Logic and Actuation Relays.

ACTION 25 is revised to increase the AOT for Function 5.B, Turbine Trip and Feedwater Isolation Automatic Actuation Logic and Actuation Relays. 3.2.2Increased Bypass Allowance and Repair AOTs for Instrumentation Channels

The VCSNS TS changes increase the AOTs for analog channels from 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, and the test bypass time from 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> as listed below.

ACTION 24 is revised for Function 1.c, Safety Injection on Reactor Building Pressure - High; Function 1.d, Safety Injection on Pressurizer Pressure Low; Function 1.e, Safety Injection on Differential Pressure Between Steam Lines - High; Function 1.f, Safety Injection on Steam Line Pressure - Low; Function 4.c, Steam Line Isolation on Reactor Building Pressure - High 2;

Function 4.d, Steam Line Isolation on Steam Flow in Two Steam Lines - High and Coincident

with Tavg - Low - Low; Function 4.e, Steam Line Isolation on Steam Line Pressure Low;

Function 5.a, Turbine Trip and Feedwater Isolation on Steam Generator Water Level

High - High; Function 6.c.i, Emergency Feedwater on Steam Generator Level Low - Low, Start

Motor Driven Pumps; and Function 6.c.ii, Emergency Feedwater on Steam Generator Level Low

- Low, Start Turbine Driven Pump. 3.2.3Conclusion - ESFAS Changes in Sections 3.2.1 and 3.2.2

The NRC staff concludes that the proposed changes to TS 3/4.3.2 that (1) increase the required action completion time to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> and the test bypass time to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> and, (2) that increase

the logic cabinets, master relays and slave relays required action completion time to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />

are consistent with the approved allowances accepted by the NRC staff based on

WCAP-14333, and are, therefore, acceptable.

In addition, proposed TSs Bases provide an adequate basis or reason for the approved TS changes. 3.3Administrative TS Changes

The Summer TSs changes related to administrative non-technical changes are listed below.

These changes are acceptable on the bases stated in the following discussions.

Action 21 is also revised from "restore the inoperable channels," to "restore the inoperable

channel" since there are only two trains of automatic actuation logic, and this Action only

addresses one inoperable train of actuation logic.

Action 25 is also revised from "restore the inoperable channels," to "restore the inoperable channel" since there are only two trains of automatic actuation logic, and this Action only

addresses one inoperable train of actuation logic.

4.0TECHNICAL EVALUATION

- PROBABILISTIC RISK ASSESSMENT An AOT extension increases the unavailability of a component due to the increased time the component is down for maintenance. For AOTs, the designated AOTs may not provide

adequate time for repair, but longer AOTs may incur a relatively larger risk. There are two

components to the risk impact: (1) the single event risk when the AOT is invoked and the

component is down for maintenance, and (2) the yearly risk contribution based on the expected

number of times the AOT will be implemented. The yearly AOT risk contribution is reflected in the frequency per year based on adjusting the component unavailability due to estimated yearly mean outage time. The yearly AOT risk impact is represented by the CDF and LERF metrics referenced in RG 1.174. The single event risk is represented by the ICCDP and the ICLERP

metrics referenced in RG 1.177 and reflects the probability of core damage or large early release during the period a component is down for maintenance. 4.1Detailed Description of the Proposed Change The proposed AOT and bypass times are based on WCAP-14333, (Reference 9), and Nuclear Energy Institute TSTF-418, (Reference 10).

The specific changes to TS 3/4.3.1, 3/4.3.2 proposed by the licensee are provided in Sections 2.1 through 2.10 of the licensee's submittals (References 1, 2, 3, and 4). The licensee

also included in its submittal, for information, a revised Bases for TS 3/4.3.1 and 3/4.3.2. The

proposed WCAP-14333 changes, applicable to VCSNS, are summarized in the table below.

RPS/ESFAS ComponentsAOTBypass Test Time Current (Hour)Proposed (Hour)Current (Hour)Proposed (Hour)Analog Channels6+6 172+6412Logic Cabinets6+624+64No ChangeMaster Relays6+624+64No ChangeSlave Relays6+624+64No ChangeReactor Trip Breakers6No change2No Change 21.The +6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> is the time allowed for the specified mode change2.The RTB AOT and bypass times are not revised directly by WCAP-14333 and it is assumed that the bypass times for the RTBs and the logic cabinets are separate and independent.

However, WCAP-14333 assumed that with either a logic cabinet or RTB in test or

maintenance, their associated train is also unavailable. Based on this, the analysis

presented in WCAP-14333 included a provision to accept a bypass time of the RTBs

equivalent to the bypass time for the logic cabinets (4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />) provided that both are tested

concurrently. Therefore, the RTB bypass time for VCSNS is extended for this maintenance

configuration. If the RTB is tested independently of the logic cabinets, the bypass time

remains unchanged, at 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />.

The deterministic evaluation of the licensee's proposed 1-hour AOT to restore an inoperable RTB to operable status and the 2-hour bypass test time for maintenance of the undervoltage

or shunt trip mechanisms, is provided in section 3.1.4 of this SE.

ESFAS Changes Unrelated to WCAP-14333

In addition, the licensee proposed increasing the ACTION 16 AOT and bypass test times to 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> and 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />, respectively, for the following functional units not specifically evaluated

by WCAP-14333. Specifically, the functions evaluated were Functions 2.c and 3.b.2, Reactor

Building Pressure - High - 3; Function 6.h, Emergency Feedwater Suction Transfer on Low

Pressure; and Function 8.a, Automatic Switchover to containment Sump on RWST level low-

low. The licensee evaluated the above functional units using the guidance of RG 1.174 and RG 1.177 and the VCSNS PRA to evaluate the change in CDF, LERF, ICCDP and ICLERP.

The risk impacts for all three functional units were well within the RG 1.174 CDF and LERF acceptance guidelines for a very small change. The results for ICCDP and ICLERP were also

well within the RG 1.177 acceptance guidelines. Accordingly, the proposed changes to

ACTION 16 are acceptable. 4.2Review of Methodology

Per SRP Chapter 19 and Section 16.1, the NRC staff reviewed the VCSNS incorporation of WCAP-14333 using the three-tiered approach and the five key principles of risk-informed

decisionmaking presented in RG 1.174 and RG 1.177 and the SE conditions and limitations for

WCAP-14333.4.3Key Information Used in the Review

The key information used in the NRC staff's review is contained in Enclosure 1 of the license amendment request, as supplemented by the licensee's submittals dated May 31, August 31, and September 29, 2006, TSTF-418, and the conditions/limitations identified in WCAP-14333

and the associated NRC staff SE. The NRC staff also utilized previous staff SEs related to

WCAP-10271, the licensee's individual plant examination (IPE) and individual plant examination

of external events (IPEEE), and the associated staff SEs. 4.4Comparison Against Regulatory Criteria/Guidelines

The NRC staff's evaluation of the licensee's proposed amendment to extend AOTs and bypass times using the three-tier approach and the five principles outlined in RGs 1.174 and 1.177 are

presented in the following sections.4.4.1Traditional Engineering Evaluation

The traditional engineering evaluation addresses key principles 1, 2, 3, and 5 of the NRC staff's philosophy of risk-informed decisionmaking, which concerns: (1) compliance with current

regulations, (2) evaluation of defense-in-depth, (3) evaluation of safety margins, and

(5) performance measurement strategies.

With respect to key principles 1, 2 and 3, the NRC staff previously performed a generic evaluation of WCAP-14333 and documented its results as discussed in Section 3 of this report.

The NRC staff's review of WCAP-14333 found that it was consistent with the guidelines of the

draft predecessor to RG 1.177. From traditional engineering insights, the NRC staff finds that

the proposed changes in WCAP-14333 continue to meet the regulations, have no impact on the

defense-in-depth philosophy, and would not involve a significant reduction in the margin of

safety.With respect to the fourth key principle, risk evaluation, the changes proposed by the licensee employ a risk-informed PRA approach using risk in sights to justify changes to AOTs and bypass times. The risk metrics CDF, LERF, ICCDP, and ICLERP developed in the topical report and used by the licensee to evaluate the impact of the proposed changes are consistent with those

presented in RGs 1.174 and 1.177. The evaluation of the licensee's risk evaluation is provided

in section 4.4.2 of this SE. With respect to the fifth key principle, performance measurement strategies, implementation and monitoring programs, RG 1.174 and RG 1.177 al so establish the need for an implementation and monitoring program to ensure that extensions to TS AOTs do not degrade operational

safety over time and that no adverse degradation occurs due to unanticipated degradation or

common cause mechanisms. An implementati on and monitoring program is intended to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of

SSCs impacted by the change. The evaluation of the licensee's implementation and monitoring program is provided in Section 4.4.3 of this SE.4.4.2Staff Technical Evaluation (PRA)

4.4.2.1 Applicability of WCAP-14333 to VCSNS.

To determine that WCAP-14333 is applicable to VCSNS, the licensee addressed the conditions and limitations of the staff SE and the implementation guidance developed by the WOG that

compares plant specific data to the generic analysis assumptions. The evaluation compared the

general baseline assumptions including surveillance, maintenance, calibration, actuation

signals, procedures, and operator actions to confirm the WCAP generic evaluation assumptions

were also applicable to VCSNS.

The licensee's evaluation of each of the WCAP-14333 conditions and limitations is discussed below.1.Confirm the applicability of WCAP-14333 analyses for their plant.

To demonstrate the applicability of WCAP-14333 to VCSNS, the licensee performed a comparison of WCAP-14333 generic assumptions and data with VCSNS plant specific

parameters. This comparison included the base component bypass, test and

maintenance intervals to those assumed by WCAP-14333. The evaluation also included

confirmation that procedures are in place for operator actions assumed by the generic

analysis and are applicable to VCSNS. The contribution from anticipated transient

without scram (ATWS) events were also confirmed to be consistent with that assumed in

the generic analysis. The applicability of the reactor trip actuation signals in the topical

report were also confirmed for VCSNS. Component failure probabilities were compared

to the topical report assumptions and found to be applicable to VCSNS. The

applicability of WCAP-14333 is discussed further in Section 4.4.2.2 Tier 1: PRA

Capability and Insights.

Based on the evaluation presented under Sections 4.4.2.2, "Tier 1" of this SE the staff considers this condition satisfied for VCSNS.2.Address the Tier 2 and Tier 3 analyses including CRMP insights, by confirming that these insights are incorporated into the referencing licensee's decisionmaking process

before taking equipment out of service.

Based on the evaluation presented under Sections 4.4.2.3, "Tier 2" and Section 4.4.2.4,"Tier 3" of this SE the NRC staff considers this condition satisfied for VCSNS. 4.4.2.2 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk based on the VCSNS/WCAP-14333 PRA model. The Tier 1 staff review involves two aspects: (1)

evaluation of the validity of the PRA and its application to the proposed changes and (2)

evaluation of the PRA results and insights based on the licensee's proposed application.

PRA Technical Adequacy

The objective of the PRA technical adequacy review is to determine whether the VCSNS/WCAP-14333 PRA used in evaluating the proposed RTS and ESFAS AOT and bypass

time extensions are of sufficient scope and detail for this application. For this safety evaluation, WCAP-14333 provided a generic PRA model used fo r the evaluation. This generic model and the WCAP-14333 evaluation were found by the NRC staff to be acceptable on a generic basis in

the WCAP-14333 SE dated July 15, 1998. In the SE, the NRC staff stated that although the use

of a representative model is generally reasonabl e, a degree of uncertainty is introduced when the representative model and the associated results are applied to a specific plant due to

modeling, design, and operational differences. Therefore, each licensee adopting

WCAP-14333 needs to confirm that the WCAP-14333 analysis and results are applicable to

their plant.

The NRC staff reviewed the information provided in the proposed license amendment request, as well as the findings and conditions of the staff WCAP-14333 SER. The WCAP-14333

conditions and limitations identified by the staff were considered limiting by VCSNS in that

WCAP-14333 does not specify the use of the VCSNS PRA or plant-specific estimates of CDF,LERF, ICCDP, or ICLERP in the implementation of WCAP-14333. However, the NRC staff, in its SER for WCAP-14333, found the applicability of the generic PRA analysis for the proposed

AOT to other Westinghouse plants may not be representative based on design variations in

actuated systems and the contribution to plant risk from accident classes impacted by the proposed change. The NRC staff therefore concluded that each licensee would need to address

any differences between their plant and the representative plant that could increase the AOT

risk significance. To address this, VCSNS reviewed of the scope and detail of the VCSNS PRA

and performed a cross comparison on the repr esentative WCAP-14333 PRA model parameters (a modified version of the Vogtle Electric Generating Plant (VEGP) to demonstrate the plant

specific applicability of the proposed VCSNS RPS and ESFAS AOTs and test bypass times.

Cross comparisons were performed on actuation logic; component test, maintenance, and

calibration times/intervals; at-power maintenance; ATWS; total internal events CDF; transient

events; operator actions; RTS trip actuation signals; and ESFAS actuation signals. Based on

the cross comparison per the implementation guidelines for WCAP-14333, the licensee

concluded that WCAP-14333 is applicable to VCSNS.

The approach used in WCAP-14333 is similar to that used in the earlier WCAP-10271 TS optimization program. As stated in WCAP-14333, this includes the fault tree models, signals, component reliability, and most of the test and maintenance assumptions. WCAP-14333 is

differentiated from the earlier WCAP-10271 analysis by the use of different common cause

modeling for analog channels and the use of licensee surveys to estimate component

unavailability. Operator actions for either manual trips or to initiate safety injection were also

modeled in WCAP-14333 and ATWS mitigation system actuation circuitry (AMSAC) is credited for emergency feedwater pump start. In addition, unlike WCAP-10271, the generic model used for WCAP-14333 is based on the VEGP PRA.

The NRC staff also reviewed the VCSNS IPE and IPEEE. The VCSNS IPE and IPEEE were developed in response to Generic Letter (GL) 88-20, "Individual Plant Examination for Severe

Accident Vulnerabilities." The NRC staff concluded that the VCSNS IPE and IPEEE met the

intent of GL 88-20.

Peer Review

The VCSNS PRA underwent industry peer review August 5, 2002 by the Westinghouse Owners Group (WOG) with the Peer review final report issued in December of 2002. The licensee

stated that all level "A" facts and observations (F&Os) have been addressed and all but two

level B F&Os. The licensee provided a discussion of the remaining level B F&Os in the

amendment request. The first F&O addressed a concern that the full plant level perspective of

the symptom and plant conditions that may influence the time available to perform Type C

actions were adequately addressed. The licensee stated that due to the generic nature of the

WCAP-14333 analysis and the operator actions credited, this F&O has no impact on the

incorporation of WCAP-14333 at VCSNS. The licensee provided additional information in their

RAI response demonstrating that this F&O does not adversely impact the proposed AOT and bypass times and has been incorporated into the VCSNS PRA. For the licensee functional units

that were not originally within the scope of WCAP-14333, the licensee provided additional

information indicating that the PRA did not credit these actions, or in the case of ESFAS

functional unit 8.a, the operator action was not dependent on prior operator actions and the

concern of the F&O was not applicable to these functional units.

The second F&O concerned the internal flooding analysis and assumptions made in the internal flooding analysis notebooks. The licensee stated that due to the generic analysis of

WCAP-14333, the F&O had no impact on the proposed changes. The NRC staff noted that

internal flooding may have unique plant specific vulnerabilities and may not be bounded by the

generic analysis. Additional review indicated that internal floods were not part of the

implementation guidance for WCAP-14333. The NRC staff noted in the SE for WCAP-14333

that the proposed TS changes will have only a small impact on external event risk. The licensee's RAI response provided additional information confirming the applicability of the

WCAP-14333 analysis to VCSNS and that flooding events are not impacted by the proposed

ESFAS or RTS instrumentation AOTs or bypass times. For the functional units not originally

part of the WCAP-14333 analysis, the licensee provided an evaluation that showed the

identified flooding events will not impact the availability of these signals.

The licensee also indicated that a review of the VCSNS PRA was performed to the American Society of Mechanical Engineers standard for the mitigating systems performance index. The

F&Os from this review have been included in the VCSNS PRA.

In addition to the peer review, the NRC staff reviewed the results of the benchmarking of the VCSNS Significance Determination Process (SDP) notebook that was performed in May of

2003. During the benchmark visit, the NRC staff identified some modeling differences that

resulted in more overestimations than typically found following benchmarking of a SDP

notebook. The NRC staff recommended that the SDP notebook be benchmarked to the

licensee's revised PRA following the licensee's evaluation and resolution of the teams comments. The licensee incorporated the NRC staff's comments as needed and indicated that the latest staff benchmarking did not result in any unresolved issues with the VCSNS PRA

model. PRA Update/Procedures

The licensee stated that a recent effort to benchmark the VCSNS PRA demonstrated that the PRA reflected the as-built as-operated plant. The last major update to the VCSNS PRA

occurred on March 30, 2004, with additional updates identified through August 2005. The

licensee also provided, as part of their RAI response, the PRA updates since the completion of

the IPE and IPEEE. The licensee also provided an implementation record of changes to the

PRA based on the IPE findings. VCSNS design guide PSA-08 states that the PRA should be

periodically updated and updates should be implemented every other refueling outage. The

update review includes plant changes, procedures and plant operating and equipment history.

PRA Results and Insights

The WCAP-14333 PRA model used data reported in previous studies for WCAP-10271 and plant surveys. The STI times were not revised by WCAP-14333 and therefore are also

representative of WCAP-10271 and VCSNS. The model was based on a plant with an SSPS

instead of a relay protection system. WCAP-14333 concluded that the signal unavailability

values for a relay plant were consistently smaller than those for a plant equipped with an SSPS

such as VCSNS and therefore a SSPS analysis was considered bounding.

The WCAP-14333 risk impacts were found to be within the RG 1.174 acceptance guidelines of less than 1.0E-6 for CDF and less than 1E-7 for LERF for the proposed bypass times and AOTs. The ICCDP for the proposed changes were found to be within the RG 1.177 acceptance

guideline of less than 5E-7. The acceptance guideline of less than 5E-8 for ICLERP were also

met for the proposed changes in WCAP-14333.

The licensee also estimated the risk impacts for the TS functional units not generically evaluated by WCAP-14333. Considering these additional functional units, the risk impact is

also within the RG 1.174 and 1.177 acceptance guidelines for CDF, LERF, ICCDP and ICLERP.Cumulative Risk

The cumulative CDF risk was evaluated in WCAP-14333 from the pre-TOP to WCAP-14333 (i.e., includes WCAP-10271). In this case, the cumulative impact on CDF for 2 out of 4 and 2

out of 3 logic was found to be within the RG 1.174 acceptance guidelines for a very small

change.The licensee identified design or operational modifications that are not reflected in the WCAP-14333 PRA evaluation for VCSNS. A review of the licensee's RAI responses shows that

the these modifications and previous risk-informed applications do not impact the proposed

AOT and bypass times. The licensee did not identify any additional license amendment

requests (LARs) under review that would impact the proposed AOTs and bypass times. External Events The licensee evaluated the proposed RPS and ESFAS AOT and bypass times for their potential impact on external events including fire, seis mic events, high winds, floods and other (HFO) events. These events are discussed below. In the SE for WCAP-14333 the NRC staff

considered the impact of the proposed TS changes on the risk from external events, such as fire and earthquakes, qualitatively with insights from NUREG-1150 " Severe Accident Risks: An

Assessment of Five U.S. Power Plants." Based on its review, the NRC staff concluded that the

proposed AOT and bypass time TS changes would have only a very small impact on risk from external events.

Fires In lieu of a fire PRA, the VCSNS IPEEE fire analysis used Revision 1 of the NUMARC/EPRI Fire Induced Vulnerability Evaluation (FIVE) Methodology and performed plant walkdowns, fire area

screening, and quantification of fire sequences for fires in unscreened fire areas. The IPEEE

estimated the fire contribution to plant CDF to be about 8.5E-5/year. The licensee did not

identify any potential vulnerabilities associated with fire events in the IPEEE. The IPEEE

identified the 1DA and 1DB switchgear rooms, control room, relay room, and turbine building as

not meeting the screening value of 1E-6. The IPEEE also notes that VCSNS is a self induced

loss of offsite power plant. Based on the IPEEE, the VCSNS response to a fire is to trip offsite

power to avoid hot shorts or spurious actuation of equipment. The unscreened fire areas result

in a single train shutdown. A higher risk will result since unaffected equipment may not be

available per procedure.

To further estimate the impact of the LAR on fire risk and to assure that the change in risk is very small, the licensee evaluated a relay room fire scenario that included the proposed SSC

AOT and test bypass times. The licensee considered a large fire in the instrumentation and

process control racks to be a representative case for a relay room fire and this was modeled in

the PRA. The scenario was modeled by assuming the failure of one train of ESFAS equipment

with the associated fire suppression also failed. The impact of the proposed AOTs and test

bypass times was incorporated by assuming the failure of the automatic actuation of the

remaining ESFAS train. Manual action was credited for the remaining train. The base case

included one train of ESFAS OOS because of the fire with a reactor trip as the initiating event.

The ICCDP and ICLERP results were estimated to be about 1.7E-9 and 2.5E-10, respectively, for the proposed AOT and test bypass times. The estimates for ICCDP and ICLERP

demonstrate that the proposed AOT and test bypa ss times have a negligibly small impact on fire risk for VCSNS.

Further, the licensee stated that the IPEEE fire analysis significant sequences included controlled removal of offsite power and securing a single EDG. Additional failures of starting

signals associated with the proposed AOT and test bypass times would have a negligible

impact on the significant sequences since thes e sequences credited only manual actuation of the turbine-driven emergency feedwater (TDEFW) pump. Therefore, based on the above, the

proposed AOT and test bypass times are expected to have a negligible impact on the IPEEE

fire risk results. Seismic Events VCSNS did not develop a seismic PRA, but ra ther employed a seismic margins assessment (SMA) for the IPEEE submittal. Therefore, no quantitative estimate of the seismic contribution

to plant CDF was provided. Four plant walkdowns were performed on the safe shutdown

equipment list, using the review level earthquake of 0.3g peak ground acceleration (PGA). The

high confidence of a low probability of failure (HCLPF) was found to be greater than 0.3g PGA

for all equipment and structures, with the exception of the service water pond dams that have a

HCLPF of 0.22g PGA. The VCSNS IPEEE did not identify any significant seismic concerns. The

VCSNS IPEEE resulted in no outliers that involve operability issues at VCSNS. Issues identified

during the IPEEE included a missing pipe support, cabinet seismic interactions, and the seismic

qualification of a neutral grounding resistor. These items were corrected by the licensee

subsequent to the IPEEE. There were no replacements or corrective actions necessary for

relays. The IPEEE did not identify any seismic issues/vulnerabilities associated with the

electrical and instrumentation and control logic areas.

As a result of using the SMA approach, the licensee did not quantify a seismic CDF. To confirm that the total seismic risk at VCSNS is sufficiently small, the staff performed an independent

simplistic calculation to estimate the magnitude of the seismic risk. The NRC staff used the

approximation method provided in a paper by Robert P. Kennedy entitled, "Overview ofMethods for Seismic PRA and Margin Analysis Including Recent Innovations

." This approach uses the plant's HCLPF value that is determined by the licensee's SMA and the site's seismic

hazard curve that is based on NUREG-1488, "Revised Livermore Seismic Hazard Estimate for

Sixty-Nine Nuclear Power Plant Sites East of the Rocky Mountains," to derive an approximation

of the magnitude of the risk associated with seismic events. The staff's independent simplistic

calculation, using a plant HCLPF value of 0.22g PGA, estimated a seismic CDF of about

4E-5/year.

As a confirmatory measure, the licensee ev aluated the proposed extended AOT on seismic risk qualitatively using the assumption that a seismic event would result in a non-recoverable LOOP.

The evaluation assumed the loss of function of the one motor driven emergency feedwater

pump and the loss of the TDEFW pump. The licensee estimated the ICCDP using the seismic

event frequency of the safe-shutdown earthquake (SSE) and conditional core damage

probability (LOOP and loss of emergency feedwater) during the proposed extended AOT. The

licensee's results for ICCDP and ICLERP for the proposed AOT and test bypass times were

within the limits of the RG 1.177 acceptance guidelines. Based on the IPEEE seismic margin

evaluation, the low probability of an earthquake greater than the SSE occurring during the

proposed AOT and test bypass times, and the licensee's qualitative estimates for ICCDP and

ICLERP, the seismic contribution to core damage due to the increased AOT and test bypass

times is expected to be negligible.

To provide additional perspective on the licensee's assessment that the seismic contribution for this application is negligible, the staff performed an additional simplistic calculation assuming a

non-recoverable LOOP occurs at a HCLPF of 0.1g PGA, which is the traditional HCLPF value

used for the failure of the switchyard transformer ceramic insulators. At this magnitude of

earthquake, no other seismic-related failures are expected (i.e., to lead to core damage would

require additional non-seismic failures of other equipment, such as the emergency diesel

generators and emergency feedwater pumps). Using the methodology described above, and

the HCLPF value of 0.1g PGA, the frequency of a seismically-induced non-recoverable LOOP is estimated to be about 2E-4/year. Based on the information provided in the licensee's submittal, the staff estimated that the plant may be in the proposed AOT and test bypass configurations no

more than about 1 percent of the year (less than 80 hours3.333 days <br />0.476 weeks <br />0.11 months <br /> per year). Thus, the probability of a

seismically-induced LOOP while in the proposed AOT or test bypass configurations is about 2E-

6/year. When combined with the failure of the other train, the ICCDP is less than 1E-7/year.

This confirms the impact of the LAR on seismic risk is negligibly small.

HFO External Events

The IPEEE for HFO external events were screened according to the 1975 SRP (NUREG 75/087) screening criteria. The licensee did not identify any plant vulnerabilities and

did not identify improvements associated with HFO events. The IPEEE submittal states that the

plant's licensing basis for high winds, tornado loads, and tornado missiles, conforms to the 1975

SRP criteria. The IPEEE noted that per NUREG-1407, if a plant meets the 1975 SRP criteria, HFO external events can be screened out as a significant contributor to total core damage

frequency. The licensee also qualitatively evaluated high winds similar to the seismic evaluation

with the assumption that high winds would result in a LOOP. The ICCDP and ICLERP results

were less that the RG 1.177 acceptance guidelines for the proposed AOTs and bypass times.

Based on the IPEEE HFO evaluation results and the licensee's qualitative estimates for ICCDP

and ICLERP for HFO events, the contribution to core damage due to the increased AOT and

bypass times is also expected to be minimal.

Shutdown and Transition Risk

The staff SE for WCAP-14333 indicates that transition risk would be decreased with incorporation of a longer AOT since mode transitions (i.e. avoiding potential reactor trips) may

be decreased with a longer AOT. WCAP-14333 estimated that the risk avoided is comparable

to the risk increase of the proposed AOT and bypass times and concluded that the averted risk

associated with avoiding one reactor trip is comparable to the increased risk of the proposed

AOTs and bypass times.

Based on the above, the NRC staff finds that the evaluation provided by VCSNS has shown the reference plant to be applicable to the VCSNS plant specific case, supportive of the proposed

AOT and bypass times requested for VCSNS, that the PRA reflects the as-built and as-operated

plant, and the licensee's estimates for CDF, LERF, ICCDP and ICLERP are within the acceptance guidelines of RG 1.174 and RG 1.177 and are, therefore, acceptable.

Total Risk Contribution

The staff was concerned that the estimated fire and seismic risk, in conjunction with the VCSNS internal event risk, would exceed the RG 1.174 base CDF of 1E-4/year with the implementation of WCAP-14333. The combined total CDF is estimated to be about 1.7E-4/year (4.9E-5/year +

8.5E-5/year + 4E-5/year). However, RG 1.174 further states that while there is no requirement

to calculate the total CDF, if there is an indication that the CDF may be considerably higher that

1E-4/year, the focus should be on finding ways to decrease, rather than increase risk. Given

the typically conservative nature of the FIVE analysis methodology and the estimation of the

seismic risk, the staff finds that the total CDF is not expected to be considerably higher than

1E-4/year and is acceptable for this application. 4.4.2.3 Tier 2 - Avoidance of Risk-Significant Plant Configurations A licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific pant equipment is taken out of service in accordance

with the proposed TS change. WCAP-14333 evaluated system importance for plant

configurations with ongoing test and maintenance on the analog channels, logic cabinets, master relays, and slave relays. Based on the RAI responses to WCAP-14333 the risk

significance did not change significantly with an analog channel out of service. Similar results

were also found with master relays and slave relays. A more significant change in the order of

risk significant systems occurs when a logic cabi net is removed from service. With a logic cabinet out of service the automatic actuation signals from one complete train of actuation logic

are unavailable increasing the importance of RPS and ESFAS actuation signals and the

associated actuated systems. To address this, the WCAP-14333 staff SE stated that each

licensee referencing WCAP-14333 must, therefore, examine the need to place necessary

restrictions on concurrent equipment outages when entering proposed AOTs to avoid risk

significant configurations. Based on WCAP-14333 and licensee evaluations, including the

functional units not evaluated generically by WCAP-14333, the only Tier 2 conditions identified

by the licensee concern the situation when a logic cabinet out of service. The Tier 2 restrictions

are presented below and were identified by the licensee as a regulatory commitment.*To preserve ATWS mitigation capability, activities that degrade the availability of the emergency feedwater system, RCS pressure relief system (pressurizer power-operated relief valves (PORVs) and safety valves), AMSAC, or turbine trip, should not be scheduled

when a logic cabinet is unavailable.*To preserve large loss-of-coolant accident mitigation capability, one complete emergency core cooling system (ECCS) train that can be actuated automatically must be maintained.*To preserve reactor trip and safeguards actuation capability, activities that cause master relays or slave relays in the available train and activities that cause analog channels to be

unavailable should not be scheduled when a logic cabinet is unavailable.*Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., service water and component cooling water) that support systems of functions listed in the first three

bullets should not be scheduled when a logic cabinet is unavailable. That is, one complete

train of a function that supports a complete train of a function noted above must be

available.

The licensee evaluated concurrent component outage configurations and confirmed the applicability of the Tier 2 restrictions for VCSNS. Based on the above, the NRC staff finds the

licensee's Tier 2 analysis supports the implementation of WCAP-14333 at VCSNS and satisfies

condition 2 of the Staff SE for WCAP-14333 regarding Tier 2.

4.4.2.4 Tier 3 - Risk-Informed Configuration Risk Management

VCSNS utilizes the Equipment Out of Service (EOOS) risk monitor and utilizes the same fault tree and data base used for the PRA model. To provide an adequate Tier 3 evaluation for

SSCs incorporating the proposed WCAP-14333 AOT and bypass times, the licensee will include

representative RTS and ESFAS actuation signals in the VCSNS PRS and EOOS risk monitor sufficient to perform Tier 3 evaluations. Actuation signals not specifically included in the PRA will be added or surrogates will be used to ensure that Tier 3 evaluations will reflect the

implementation of WCAP-14333.

The risk impact of maintenance and testing activities conforms to the requirements of the Maintenance Rule, 10 CFR 50.65(a)(4) and the RG 1.177 key components for a CRMP. The

risk management process is controlled and implemented through procedures at VCSNS including the establishment of risk thresholds. The licensee utilizes a risk monitor that employs

the same fault tree and database as the plant PRA but in the form of a zero maintenance model

to assess configuration risk. Both planned and emergent conditions may be assessed under

the licensee's CRMP. Licensee procedures require reviews of the procedures and that plant

modifications be evaluated for PRA updates. Ex ternal events are considered in the CRMP and administrative procedures are used for components not modeled. The licensee stated that the

VCSNS CRMP assesses both CDF and LERF.

A review of recent inspection reports that evaluated the licensee's assessment of plant risk, scheduling, and configuration control for selected planned and emergent work activities found

them acceptable and monitored in accordance with the requirements of 10 CFR 50.65(a)(4) and

plant procedures.

The NRC staff finds that, based on the licensee's conformance to the requirements of the Maintenance Rule, 10 CFR 50.65, and the RG 1.177 key components of a CRMP and based on

the VCSNS PRA being modified per plant PRA update procedures such that proposed

WCAP-14333 AOT and bypass times are represented in the plant PRA and plant risk monitor (EOOS), the licensee's Tier 3 program is adequate to support the implementation of

WCAP-14333 and satisfies condition 2 of the staff SE to WCAP-14333 with regards to Tier 3. 4.4.3Implementation and Monitoring Program

RG 1.174 and RG 1.177 also establish the need for an implementation and monitoring program to ensure that extensions to TS AOT or bypass times do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common

cause mechanisms. An implementation and monitoring program is intended to ensure that the

impact of the proposed TS change continues to reflect the reliability and availability of SSCs

impacted by the change. In addition, the application of the three-tiered approach in evaluating

TS AOT changes provides additional assurance t hat the changes will not significantly impact the key principle of defense-in-depth.

WCAP-14333 assumed that maintenance on master and slave relays, logic cabinets, and analog channels while at power occurs only after component failure (i.e. corrective

maintenance). The licensee clarified this in their RAI response stating that the WCAP-14333

assumptions for testing and maintenance are consistent with current VCSNS practices and that

the proposed AOT includes contributions from testing, repair, and calibration.

The licensee will also develop a procedure to specifically monitor the SSCs that are affected by the proposed AOT and bypass times. The scope of the components monitored will include the

logic cabinets, master relays, slave relays, and analog channels. The procedure provides a

means to confirm that the component unavailability assumptions due to test and maintenance

used in the WCAP-14333 analysis will remain valid for VCSNS. Based on the above, VCSNS satisfies the RG 1.174 and 1.177 guidelines for an implementation and monitoring program for the proposed TS change.4.4Comparison With Regulatory Guidance

The proposed changes are based on TSTF 418 and WCAP-14333, as approved by the NRC staff, including limitations and conditions identified in the NRC staff SE. As such, the

implementation of the topical report at VCSNS reflects the RG 1.174 and 1.177 acceptance

guidance for CDF, LERF, ICCDP and ICLERP.

4.5 Regulatory Commitment

The licensee will implement administrative controls to include the following restrictions when a logic cabinet is unavailable.*Activities that degrade the availability of the emergency feedwater system, RCS pressure relief system (pressurizer PORVs and safety va lves), AMSAC, or turbine trip, should not be scheduled when a logic cabinet is inoperable for maintenance.*One complete ECCS train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.*Activities that cause master relays or slave relays in the available train and activities that cause analog channels to be unavailable should not be scheduled when a logic train is

inoperable for maintenance*Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., service water and component cooling water) that support systems of functions listed in the first three

bullets should not be scheduled when a logic cabinet is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above

must be available.

In addition:

• VCSNS will develop a procedure specifically to monitor the components affected by this LAR including logic cabinets, master relays, slave relays, and analog channels. The

assumptions regarding component unavailability due to test and maintenance activities in

the analysis supporting WCAP-14333 will be evaluated to ensure that the intent of these

assumptions are met at VCSNS.*The VCSNS PRA and EOOS will be updated to include representative signals to model the reactor trip and ESFAS to the appropriate depth to perform Tier 3 evaluations. Signals not

explicitly modeled will either be added to the model or addressed by surrogates.

The NRC staff finds that reasonable controls for the implementation and for subsequent evaluation of proposed changes pertaining to the above regulatory commitment(s) are best

provided by the licensee's administrative pr ocesses, including its commitment management program. The above regulatory commitments do not warrant the creation of regulatory

requirements (i.e., items requiring prior NRC approval of subsequent changes). 4.5NRC Staff Findings and Conditions The NRC staff finds that the licensee has demonstrated the applicability of WCAP-14333 to VCSNS and has met the limitations and conditions as outlined in the staff SE. The risk impacts

for CDF, LERF, ICCDP, and ICLERP, as estimated by WCAP-14333, were found to be within the acceptance guidelines for RG 1.174 and 1.177. The plant-specific functional units were

shown to be applicable to the topical report evaluations and results. Additional analysis was

provided by the licensee for those functi onal units not evaluated generically by WCAP-14333. The licensee's Tier 2 analysis evaluated concurrent outage configurations and

confirmed the applicability of the risk significant configurations identified by the staff SE

limitations and conditions and topical report analysis to ensure these configurations are

controlled. The licensee's Tier 3 CRMP was found to be consistent with the RG 1.177 CRMP

guidelines, and the Maintenance Rule, 10 CFR 50.65(a)(4), for the implementation of

WCAP-14333. The VCSNS PRA will be modified per plant PRA udate procedures such that

proposed WCAP-14333 AOT and bypass times are represented in the plant PRA and plant risk

monitor (EOOS). The licensee will develop proc edures specifically to monitor the SSCs affected by the proposed AOT and bypass times. Therefore, the NRC staff finds that the TS

revisions proposed by the licensee are consistent with the extended bypass times and AOTs

approved for WCAP-14333 and that they meet the staff SE conditions and limitations for WCAP-

14333.

5.0 STATE CONSULTATION

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

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and changes

surveillance requirements. The NRC staff has determined that the amendment involves no

significant increase in the amounts, and no significant change in the types, of any effluents that

may be released offsite, and that there is no significant increase in individual or cumulative

occupational radiation exposure. The Commission has previously issued a proposed finding

that the amendment involves no significant hazards consideration, and there has been no public

comment on such finding (70 FR 75496, December 20, 2005). Accordingly, the amendment

meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant

to 10 CFR 51.22(b), no environmental impact st atement or environmental assessment need be prepared in connection with the issuance of the amendment.

7.0 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 amendment will not be inimical to the

common defense and security or to the health and safety of the public.

8.0 REFERENCES

1.Letter, J. B. Archie, SCE & G, to NRC Document Control Desk, "Implementation of WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test

Times and Completion Times," November 15, 2005 (ML053220309 [Agencywide

Document Access and Management System Accession Number]).2.Letter, J. B. Archie, SCE&G, to NRC Document Control Desk, "Implementation of WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test

Times and Completion Times, Response to Request for Additional Information,"

May 31, 2006 (ML061570275). 3.Letter, J. B. Archie, SCE&G, to NRC Document Control Desk, "Implementation of WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test

Times and Completion Times, Response to Request for Additional Information,"

August 31, 2006 (ML062490524). 4.Letter, J. B. Archie, SCE&G, to NRC Document Control Desk, "Implementation of WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test

Times and Completion Times, Summarized List of Commitments," September 29, 2006 (ML062760318).5.Letter, C. O. Thomas, NRC, to J. J. Sheppard, WOG, "Acceptance for Referencing of Licensing Topical Report WCAP-10271, Evaluation of Surveillance Frequencies and Out

of Service Times for the Reactor Protection Instrumentation Systems," February 21, 1985.6.Letter, H. R. Denton, NRC to L. D. Butterfield, WOG, providing comments on WOG guidelines for preparing submittals requesting NRC approval of RTS TSs, July 24, 1985.7.Letter, C. E. Rossi, NRC, to R. A. Newton, WOG, "WCAP-10271, Supplement 2 and WCAP-10271, Supplement 2, Revisin 1, Evaluation of Surveillance Frequencies and Out

of Service Times for the Engineered Safety Features Actuation System,"

February 22, 1989.8.Letter, C. E. Rossi, NRC, to G. T. Goering, WOG, "Westinghouse Topical Report WCAP-10271, Supplement 2, Revision 1, Evaluation of Surveillance Frequencies and Out

of Service Times for the Engineered Safety Features Actuation System," April 30, 1990.9.WCAP [Westinghouse Commercial Atomic Power]-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998, as approved by NRC letter dated July 15, 1998.10.Letter, W. D. Beckner, NRC, to A. Pietrangelo, Nuclear Energy Institute, approving changes to TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)," April 2, 2003 (ML030920633).

Principal Contributor:C. Schulten C. Doutt Date: October 24, 2006 Mr. Jeffrey B. Archie VIRGIL C. SUMMER NUCLEAR STATION South Carolina Electric & Gas Company cc: Mr. R. J. White

Nuclear Coordinator

S.C. Public Service Authority

c/o Virgil C. Summer Nuclear Station

Post Office Box 88, Mail Code 802

Jenkinsville, South Carolina 29065 Resident Inspector/Summer NPS c/o U.S. Nuclear Regulatory Commission

576 Stairway Road

Jenkinsville, South Carolina 29065 Chairman, Fairfield County Council Drawer 60 Winnsboro, South Carolina 29180 Mr. Henry Porter, Assistant Director Division of Waste Management

Bureau of Land & Waste Management

Dept. of Health & Environmental Control

2600 Bull Street

Columbia, South Carolina 29201 Mr. Thomas D. Gatlin, General Manager Nuclear Plant Operations

South Carolina Electric & Gas Company

Virgil C. Summer Nuclear Station

Post Office Box 88, Mail Code 300

Jenkinsville, South Carolina 29065 Mr. Robert G. Sweet, Manager Nuclear Licensing

South Carolina Electric & Gas Company

Virgil C. Summer Nuclear Station

Post Office Box 88, Mail Code 830

Jenkinsville, South Carolina 29065 Ms. Kathryn M. Sutton Morgan, Lewis & Bockius LLP

111 Pennsylvania Avenue, NW.

Washington, DC 20004