IR 05000324/2007005

IR 05000325-07-005, 05000324-07-005; on 10/01/07 - 12/31/07; Brunswick Steam Electric Plant, Units 1 and 2

ML080800012
Person / Time
Site:	Brunswick
Issue date:	03/19/2008
From:	Randy Musser NRC/RGN-II/DRP/RPB4
To:	Waldrep B Carolina Power & Light Co
References
IR-07-005
Download: ML080800012 (21)

Text

rch 19, 2008

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS. 05000325/2007005 AND 05000324/2007005 ERRATA

Dear Mr. Waldrep:

On January 29, 2008, the U. S. Nuclear Regulatory Commission (NRC) issued the subject inspection report for the Brunswick Steam Electric Plant. In reviewing this report, it was noted that the Summary Of Findings page contained an incorrect statement regarding the identification of a Green non-cited violation (NCV). Also, we inadvertently omitted the operator licensing annual requalification inspection under section 1R11. Accordingly, we are providing a revised version of Inspection Report 05000325/2007005 and 05000324/2007005 that documents the above changes.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) components of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

I apologize for any inconvenience these errors may have caused. If you have any questions, please contact me at (404) 562-4603.

Sincerely,

/RA/

Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos: 50-325, 50-324 License Nos. DPR-71, DPR-62

Enclosure:

As stated

OFFICE RII:DRP RII:DRP RII:DRP RII:DRS RII:DRS RII:DRS SIGNATURE RAM RAM for RAM for GJW NAME R Musser J Austin S Rutledge G Wilson DATE 03/19 /2008 03/19 /2008 03/19 /2008 03/19 /2008 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO

CP&L 2

REGION II==

Docket Nos: 50-325, 50-324 License Nos: DPR-71, DPR-62 Report Nos: 05000325/2007005 and 05000324/2007005 Licensee: Carolina Power and Light (CP&L)

Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road SE Southport, NC 28461 Dates: October 1, 2007 through December 31, 2007 Inspectors: J. Austin, Senior Resident Inspector S. Rutledge, Resident Inspector Approved by: Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000325/2007005, 05000324/2007005; 10/01/07- 12/31/07; Brunswick Steam

Electric Plant, Units 1 and 2.

The report covered a 3-month period of inspection by resident inspectors and one senior reactor inspector. The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter (IAC) 0609, Significance Determination Process (SDP). The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified and Self-Revealing Findings

NONE B. Licensee-Identified Findings NONE

REPORT DETAILS

Summary of Plant Status

Unit 1 Unit 1 began the inspection period operating at full power. On October 6, power was reduced to 93 percent to perform a control rod improvement. The unit was restored to full power the same day. On October 13, power was reduced to 93 percent to perform a control rod improvement. The unit was returned to full power the same day. On October 20, power was reduced to 93 percent to perform a control rod improvement.

Full power was restored the same day. On October 27, power was reduced to 93 percent to perform a control rod improvement. Full power was achieved later that day.

On November 3, power was reduced to 67 percent to facilitate valve testing. The unit was returned to full power later that day. On November 4, power was reduced to 95 percent to perform a control rod improvement. Full power was restored on November 5.

On November 11, power was reduced to 90 percent to perform a control rod improvement. Full power was achieved later that day. On November 16, power was reduced to 91 percent to perform a control rod improvement. The unit was returned to full power November 17. On November 24, power was reduced to 90 percent for control rod testing. Full power was restored later that day. The unit remained at full power for the remainder of the inspection period.

Unit 2 Unit 2 began the inspection period operating at full power. On October 1, a power ascension occurred from main turbine valve testing. Full power was restored later that day. On October 1, power was reduced to 95 percent to perform a control rod improvement. Full power was restored later that day. On October 1, power was reduced to 96 percent to perform a control rod improvement. The unit was returned to full power later that day. On October 2, power was reduced to 98 percent to perform a control rod improvement. Full power was restored later that day. On November 8, power was reduced to 71 percent for a Whiteville line outage. Power was returned to full later that day. On November 9, power was reduced to 98 percent for a control rod improvement. Full power was restored later that day. On November 17, power was reduced to 68 percent for main turbine valve, reactor feed pump and scram time testing.

The unit was returned to full power on November 18. On November 18, power was reduced to 94 percent for xenon build-up following main turbine valve testing and control rod sequence exchange. Full power was returned on November 19. On November 19, power was reduced to 85 percent to perform a control rod improvement. Full power was restored November 20. On November 20, power was reduced to 95 percent to perform a control rod improvement. Full power was achieved November 21, 2007. The unit remained at full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors assessed the effectiveness of the licensees cold weather protection program as it related to ensuring that the facilitys service water pumps, emergency diesel generators, and condensate storage tank low level switches would remain functional and available in cold weather conditions. In addition to reviewing the licensees program-related documents and procedures, walkdowns were conducted of the freeze protection equipment (e.g., heat tracing, area space heaters, etc.) associated with the above systems/components. Licensee problem identification and resolution associated with cold weather protections was also assessed.

• AR 246713246713 Unit 2 condensate storage tank heat trace inoperable

• AR 253047253047 Emergency diesel generator #1 jacket water heater temperature switch

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed three partial walkdowns of the below-listed systems to verify that the systems were correctly aligned while the redundant train or system was inoperable or out-of-service (OOS) or, for single train risk significant systems, while the system was available in a standby condition. The inspectors assessed conditions such as equipment alignment (i.e., valve positions, damper positions, and breaker alignment)and system operational readiness (i.e., control power and permissive status) that could affect operability. The inspectors verified that the licensee identified and resolved equipment alignment problems that could cause initiating events or impact mitigating system availability. The inspectors reviewed Administrative Procedure ADM-NGGC-0106, Configuration Management Program Implementation, to verify that available structures, systems or components (SSCs) met the requirements of the configuration control program. Documents reviewed are listed in the Attachment.

• 2A Nuclear service water pump when the 2B nuclear service water pump was OOS for scheduled maintenance on October 3, 2007

• Unit 2 RCIC when the Unit 2 HPCI was OOS for seal repair on October 15, 2007

• EDG #2, #3, and #4 while EDG #1 was OOS for scheduled maintenance on November 19, 2007 To assess the licensees ability to identify and correct problems, the inspectors reviewed the following Action Requests (ARs):

• AR 251684251684 RCIC extent of condition evaluation using Panametrics

• AR 252203252203 U2 RCIC seal purge line orifice missing

• AR 259682259682 U1 RCIC steam supply drain pot steam leak

• AR 254033254033 EDG starting air pilot air lines support discrepancies

• AR 254280254280 EDG #3 brush inspection meg readings

• AR 259504259504 EDG #1 generator vibration alarm

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted a detailed review of the alignment and condition of the Unit 2 high pressure coolant injection system. The inspector reviewed the Updated Final Safety Analysis Report, associated attachments of Operating Procedure 2OP-19, High Pressure Coolant Injection System Operating Procedure, 0PT-09.2, HPCI System Operability Test and the systems diagrams (drawing numbers D-02523 and LL-09272)in determining correct system lineup. The inspectors also reviewed maintenance history of the system.

To assess the licensees identification and resolutions of problems, the inspectors reviewed the following:

• AR 250203250203 HPCI inoperable due to pump seal leakage

• AR 225856225856 HPCI lube oil coolers debris

• AR 229349229349 HPCI condensate pump trip

• AR 251647251647 U2 HPCI vacuum tank level issues

• AR 251490251490 Water in U2 HPCI lube oil

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Fire Area Walkdowns

a. Inspection Scope

The inspectors reviewed ARs and work orders (WOs) associated with the fire suppression system to confirm that their disposition was in accordance with Procedure 0AP-033, Fire Protection Program Manual. The inspectors reviewed the status of ongoing surveillance activities to verify that they were current to support the operability of the fire protection system. In addition, the inspectors observed the fire suppression and detection equipment to determine whether any conditions or deficiencies existed which would impair the operability of that equipment. The inspectors toured the following six areas important to reactor safety and reviewed the associated prefire plans to verify that the requirements for fire protection design features, fire area boundaries, and combustible loading were met. Documents reviewed are listed in the Attachment.

• Units 1 and 2 Control Building, - 49' elevation (2 areas)

• Units 1 and 2 Control Building, - 23' elevation (2 areas)

• Units 1 and 2 Reactor Building - 17' elevation (2 areas)

b. Findings

No findings of significance were identified.

.2 Fire Drill

a. Inspection Scope

On October 6, 2007, the inspectors observed a plant fire drill at the auxiliary boiler unit located outside near the Emergency Diesel Generator Building, to assess the fire brigade performance and to verify that proper firefighting techniques for the type of fire encountered were utilized. The inspectors monitored the fire brigades use of protective equipment and firefighting equipment to verify that preplanned firefighting procedures and appropriate firefighting techniques were used, and to verify that the directions of the fire brigade leader were thorough, clear, and effective. The inspectors attended the critique to confirm that appropriate feedback on performance was provided to brigade members and to ensure that areas for improvement were properly identified for licensee follow-up. In preparing for the drill, the inspectors reviewed the preplanned drill scenario, Brunswick Nuclear Plant Drill Scenario Guide, 99-F-0S, Revision 1.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed the licensees internal flooding analysis as described in Updated Final Safety Analysis Report (UFSAR) Section 3.4.2, Protection From Internal Flooding. Due to the risk significance of equipment in the Service Water and Emergency Diesel Generator Buildings, the inspectors reviewed UFSAR Section 3.4.2 analysis of the effects of postulated piping failures for these two areas to determine if the analysis assumptions and conclusions were based on the current plant configuration. The internal flooding design features and equipment for coping with internal flooding was inspected for the equipment located in these buildings. The walkdown included sources of flooding and drainage, sump pumps, level switches, watertight doors, curbs, pedestals and equipment mounting. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 External Flooding

a. Inspection Scope

The inspectors reviewed the licensees external flooding analysis as described in UFSAR Section 3.4.1, Protection from External Flooding, to determine the external flood control design features. Walkdowns were conducted to inspect the external flood protection barriers including watertight doors, curbs, sealing of external building penetrations below flood line, and the sump pumps and level alarm circuits. Areas reviewed included the Emergency Diesel Generator Building, and the Service Water Building. The inspector reviewed the procedures for coping with external flooding contained in Abnormal Operating Procedure (AOP) 0AOP-13.0, Operation During Hurricane, Flood Conditions, Tornado, or Earthquake. Other documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

.1 Quarterly Review

a. Inspection Scope

The inspectors observed licensed operator performance and reviewed the associated training documents during annual dynamic simulator examination sessions for training cycle 2007-05. The simulator observations and review included evaluations of emergency operating procedure and abnormal operating procedure utilization. The inspectors reviewed Procedure 0TPP-200, Licensed Operator Continuing Training Program, to verify that the program ensures safe power plant operation. Simulator sessions were observed on November 20, 2007. The scenarios tested the operators ability to respond to secondary plant failures, loss of emergency power, and an automatic trip without a scram followed by a rupture of the scram discharge volume.

The inspectors reviewed operator activities to verify consistent clarity and formality of communication, conservative decision-making by the crew, appropriate use of procedures, and proper alarm response. Group dynamics and supervisory oversight, including the ability to properly identify and implement appropriate Technical Specification (TS) actions, regulatory reports, and notifications, were observed. The inspectors observed instructor critiques and preliminary grading of the operating crews and assessed whether appropriate feedback was planned to be provided to the licensed operators.

b. Findings

No findings of significance were identified.

.2 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On December 13, 2007, the licensee completed the requalification biennial written exam and annual operating tests, required to be given to all licensed operators by 10 CFR 55.59(a)(2). The inspectors performed an in-office review of the overall pass/fail results of the individual written examination and operating tests and the crew simulator operating tests. These results were compared to the thresholds established in Manual Chapter 609 Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the two equipment issues described in the ARs listed below, the inspectors reviewed the licensees implementation of the Maintenance Rule (10 CFR 50.65) with respect to the characterization of failures, the appropriateness of the associated Maintenance Rule a(1) or a(2) classification, and the appropriateness of the associated a(1) goals and corrective actions. The inspectors reviewed the work controls and work practices associated with the degraded performance or condition to verify that they were appropriate and did not contribute to the issue. The inspectors also reviewed operations logs and licensee event reports to verify unavailability times of components and systems, if applicable. Licensee performance was evaluated against the requirements of Procedure ADM-NGGC-0101, Maintenance Rule Program.

• AR 242066242066 BNP response to operating experience 2007-08 degradation of buried piping

• AR 256103256103 Loss of full out indications on the full core display

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed the licensees implementation of 10 CFR 50.65 (a)(4)requirements during scheduled and emergent maintenance activities, using Procedure 0AP-025, BNP Integrated Scheduling and Technical Requirements Manual 5.5.13, Configuration Risk Management Program. The inspectors reviewed the effectiveness of risk assessments performed due to changes in plant configuration for maintenance activities (planned and emergent). The review was conducted to verify that, upon unforseen situations, the licensee had taken the necessary steps to plan and control the resultant emergent work activities. The inspectors reviewed the applicable plant risk profiles, work week schedules, and maintenance WOs for the following five conditions:

• AR 250203250203 HPCI inoperable due to pump seal leakage

• AR 255545255545 Unexpected annunciators during performance test (PT-12.2a) for EDG #1

• AR 257721257721 Unit 1 condensate storage tank instrumental vent line excessive sloping

• AR 257744257744 EDG #3 jacket water leakage from flexmaster jumpers

• AR 256079256079 1-E11-F017B inoperable due to high energy line break issues at the motor control cubicle compartment

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the operability evaluations associated with the six issues documented in the ARs listed below, which affected risk significant systems or components, to assess, as appropriate: 1) the technical adequacy of the evaluations; 2)the justification of continued system operability; 3) any existing degraded conditions used as compensatory measures; 4) the adequacy of any compensatory measures in place, including their intended use and control; and 5) where continued operability was considered unjustified, the impact on any TS limiting condition for operation and the risk significance. In addition to the reviews, discussions were conducted with the applicable system engineer regarding the ability of the system to perform its intended safety function.

• AR 249130249130 1A Residual heat removal heat exchanger degradation during testing (OPF08.1.4A)

• AR 245864245864 E-4 Loss of coolant accident logic relay 27E2 de-energized

• AR 250793250793 Unit 2 RCIC operability concern

• AR 252203252203 Unit 2 RCIC seal purge line orifice missing

• AR 251885251885 Unit 2 HPCI main pump seal leak exceeds posting

• AR 251490251490 Water in Unit 2 HPCI lube oil

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

For the five maintenance activities listed below, the inspectors reviewed the post-maintenance test procedure and witnessed the testing and/or reviewed test records to confirm that the scope of testing adequately verified that the work performed was correctly completed. The inspectors verified that the test demonstrated that the affected equipment was capable of performing its intended function and was operable in accordance with TS requirements. The inspectors reviewed the licensees actions against the requirements in Procedure 0PLP-20, Post Maintenance Testing Program.

• PT 9.2 HPCI Operability Test following inboard seal failure

• WO 114145 RCIC system fill and vent after pump maintenance

• WO 1137349 Inspection of HPCI sump after drain down

• AR 250499250499 Basis for changing piping test plan not understood

• AR 247456247456 Balance of plant under-voltage relays not tested as required

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed test data for the three risk significant SSC surveillances, listed below, to verify the tests met TS surveillance requirements, UFSAR commitments, in-service testing (IST) requirements, and licensee procedural requirements. The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions.

• 0PT-09.2mst-HPCI 23Q, High Pressure Coolant Injection System operability test, performed on Unit 2 on October 22, 2007

• 2O1-03.2, Control Operator Daily Surveillance Report (including drywell leakage rate determination), performed the week of November 12, 2007.

C 0PT-9.3a, High Pressure Coolant Injection System Component Test, performed on Unit 1 on December 7, 2007.

b. Findings

No findings of significance were identified.

.2 In-service Surveillance Testing

a. Inspection Scope

The inspectors reviewed the performance of Periodic Test 0PT-9.7, High Pressure Coolant Injection System Valve Operability Test, performed on Unit 1 on December 7, 2007. The inspectors evaluated the effectiveness of the licensees American Society of Mechanical Engineers (ASME)Section XI testing program to determine equipment availability and reliability. The inspectors evaluated selected portions of the following areas: 1) testing procedures; 2) acceptance criteria; 3) testing methods; 4) compliance with the licensees IST program, TS, selected licensee commitments, and code requirements; 5) range and accuracy of test instruments; and 6) required corrective actions. The inspectors also assessed any applicable corrective actions taken.

To assess the licensees ability to identify and correct problems, the inspector reviewed AR 214876214876which documented that the Unit 1 A conventional service water pump was discovered to be in the Alert range following testing on November 30, 2006.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed site emergency preparedness training drill/simulator scenarios conducted on October 30, 2007 and November 8, 2007. The inspectors reviewed the drill scenario narrative to identify the timing and location of classifications, notifications, and protective action recommendations development activities. The inspectors evaluated the drill conduct from the control room simulator, technical support center, and the emergency operations facility. During the drill, the inspectors assessed the adequacy of event classification and notification activities. The inspectors observed portions of the licensees post-drill critiques at the technical support center and emergency operating facility.

The inspectors verified that the licensee properly evaluated the drills performance with respect to performance indicators and assessed drill performance with respect to drill objectives. To assess the ability of the licensee to identify and correct problems, the inspectors reviewed the following corrective action documents that were generated as a result of the drill:

• AR 252936252936 knowledge gap in the required actions associated with the Reactor Building positive pressure as defined in AST documentation

• AR 252937252937 rewording of SPDS indication to prevent human error

• AR 254108254108 JIC positions not filled during ERO drill

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed Operating Manual 0PLP-22, Temporary Changes, to assess the implementation of Engineering Change (EC) 67830, Reactor Core Isolation Cooling System Low Suction Pressure Trip Delay which was implemented on October 21, 2007.

The inspectors reviewed the EC to verify that the modification did not affect the functional capability of the EDG, that the modification was properly installed, and appropriate post-installation testing was performed.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee data for the performance indicators (PIs) listed below.

To verify the accuracy of the PI data reported during the period reviewed, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev.

5 were used to verify the basis for each data element.

Reactor Safety Cornerstone The inspectors sampled licensee submittals for the Units 1 and 2 PIs listed below for the period January 2007 through November 2007.

• High Pressure Coolant Injection System

• Reactor Core Isolation Cooling System A sample of plant records and data was reviewed and compared to the reported data to verify the accuracy of the PIs. The licensees corrective action program records were also reviewed to determine if any problems with the collection of PI data had occurred.

Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of ARs

To aid in the identification of repetitive equipment failures or specific human performance issues for followup, the inspectors performed frequent screenings of items entered into the licensees CAP. The review was accomplished by reviewing daily ARs.

.2 Annual Sample Review

a. Inspection Scope

The inspectors performed an in-depth annual sample review of plant operator workarounds as documented in licensees operator workaround program and corrective action documents. This review was performed to verify that the licensee identified operator workarounds at an appropriate threshold, entered the issues into the CAP, and planned or implemented appropriate corrective actions. The inspectors reviewed the actions taken to verify that the licensee had adequately addressed the following attributes:

• Complete, accurate, and timely identification of the problem

• Evaluation and disposition of operability and reportability issues

• Consideration of previous failures, extent of condition, generic or common cause implications

• Prioritization and resolution of the issue commensurate with the safety significance

• Identification of the root cause and contributing causes of the problem

• Identification and implementation of corrective actions commensurate with the safety significance of the issue The inspectors reviewed the associated corrective action for AR 250203250203 Unit 2 high pressure coolant injection pump seal failure that occurred on October 10, 2007.

b. Findings and Observations

No findings of significance were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The review was focused on repetitive equipment issues but also considered the results of frequent inspector CAP item screening (discussed above), licensee trending efforts, and licensee human performance results. The review considered the period of July through December 2007. The review further included issues documented outside the normal CAP in major equipment lists, repetitive and/or rework maintenance lists, operational focus list, control room deficiency list, outstanding work order list, quality assurance audit/surveillance reports, key performance indicators, and self-assessment reports.

The inspectors compared and contrasted their results with the results contained in multiple root cause evaluations the licensee has performed over the last 2 quarters.

Corrective actions associated with a sample of the issues identified in the licensees trend reports were reviewed for adequacy. The inspectors also evaluated the reports against the requirements of the licensees CAP as specified in Nuclear Generation Group Standard Procedure CAP-NGGC-0200, Corrective Action Program, and 10 CFR 50, Appendix B.

b. Assessment and Observations No findings of significance were identified. The inspectors noted a trend in the control and retrieval of foreign material in systems and the adverse effects this has had on system performance; this was exemplified by the following identified issues:

1) Foreign material found in the 1B Residual Heat Removal (RHR) Room cooler (AR243465243465; 2) Metallic foreign material found in the 1B RHR Heat Exchanger (AR246790246790; 3) 1D RHRSW Booster pump failed to start was bound by valve pin (AR 243867243867; 4) Unit 2 HPCI main pump inboard seal failure due to blockage of seal cooling line (AR250203250203. The inspectors have determined that the licensee has addressed all immediate operability concerns, and is currently developing long-term improvements.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 24, 2008, the resident inspectors presented the inspection results to Mr. Waldrep and other members of his staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Atkinson, Supervisor - Emergency Preparedness

L. Beller, Superintendent Operations Training

A. Brittain, Manager - Security

D. Griffith, Manager - Training Manager

L. Grzeck, Lead Engineer - Technical Support

S. Howard, Manager - Operations

R. Ivey, Manager - Site Support Services

T. Pearson, Supervisor - Operations Training

A. Pope, Supervisor - Licensing/Regulatory Programs

S. Rogers, Manager - Maintenance

B. Waldrep, Site Vice President

T. Sherrill, Engineer - Technical Support

T. Trask, Manager - Engineering

J. Titrington, Manger - Nuclear Assessment Services

M. Turkal, Lead Engineer - Technical Support

M. Williams, Manager - Operations Support

E. Wills, Plant General Manager

NRC Personnel

R. Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

None

Discussed

None