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#REDIRECT [[IR 05000324/2007005]]
 
{{IR-Nav| site = 05000325 | year = 2007 | report number = 005 }}
 
=Text=
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[[Issue date::January 29, 2008]]
 
Carolina Power and Light CompanyATTN:Mr. Benjamin WaldrepVice PresidentBrunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461
 
SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTIONREPORT NOS. 05000324/2007005 AND 05000325/2007005
 
==Dear Mr. Waldrep:==
On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Brunswick Units 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 22, 2008, with you andother members of your staff. The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.
 
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.On the basis of the results of this inspection, no findings of significance were identified.
 
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letterand its enclosure will be available electronically for public inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC's 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).
 
Sincerely,/RA/Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor ProjectsDocket Nos.: 50-325, 50-324License Nos:DPR-71, DPR-62
 
===Enclosure:===
Inspection Report 05000325, 324/2007005
 
===w/Attachment:===
Supplemental Informationcc w/encl: (See page 2)
January 29, 2008Carolina Power and Light CompanyATTN:Mr. Benjamin WaldrepVice PresidentBrunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461SUBJECT:BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTIONREPORT NOS. 05000324/2007005 AND 05000325/2007005Dear M
 
=SUMMARY OF FINDINGS=
IR 05000325/2007005, 05000324/2007005; 10/01/07- 12/31/07;  Brunswick SteamElectric Plant, Units 1 and 2.The report covered a 3-month period of inspection by resident inspectors and one seniorreactor inspector. One Green non-cited violation (NCV) was identified. The significanceof 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.A.NRC-Identified and Self-Revealing FindingsNONEB.Licensee-Identified FindingsNONE Enclosure
 
=REPORT DETAILS=
Summary of Plant StatusUnit 1Unit 1 began the inspection period operating at full power. On October 6, power wasreduced 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 2Unit 2 began the inspection period operating at full power. On October 1, a powerascension 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.
 
3Enclosure1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection
 
====a. Inspection Scope====
The inspectors assessed the effectiveness of the licensee's cold weather protectionprogram as it related to ensuring that the facility's 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 licensee's 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 246713, Unit 2 condensate storage tank heat trace inoperable*AR 253047, Emergency diesel generator #1 jacket water heater temperatureswitch
 
====b. Findings====
No findings of significance were identified.
{{a|1R04}}
==1R04 Equipment Alignment==
 
===.1 Partial System Walkdowns===
 
====a. Inspection Scope====
The inspectors performed three partial walkdowns of the below-listed systems to verifythat 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 wasOOS for scheduled maintenance on October 3, 2007 4Enclosure*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 onNovember 19, 2007To assess the licensee's ability to identify and correct problems, the inspectors reviewedthe following Action Requests (ARs):*AR 251684, RCIC extent of condition evaluation using Panametrics*AR 252203, U2 RCIC seal purge line orifice missing
*AR 259682, U1 RCIC steam supply drain pot steam leak
*AR 254033, EDG starting air pilot air lines support discrepancies
*AR 254280, EDG #3 brush inspection meg readings
*AR 259504, 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 2high 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 licensee's identification and resolutions of problems, the inspectorsreviewed the following:*AR 250203, HPCI inoperable due to pump seal leakage*AR 225856, HPCI lube oil coolers debris
*AR 229349, HPCI condensate pump trip
*AR 251647, U2 HPCI vacuum tank level issues
*AR 251490, Water in U2 HPCI lube oil
 
====b. Findings====
No findings of significance were identified.
 
5Enclosure1R05Fire Protection
 
===.1 Fire Area Walkdowns===
 
====a. Inspection Scope====
The inspectors reviewed ARs and work orders (WOs) associated with the firesuppression 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 unitlocated outside near the Emergency Diesel Generator Building, to assess the firebrigade performance and to verify that proper firefighting techniques for the type of fireencountered were utilized. The inspectors monitored the fire brigade's use of protectiveequipment and firefighting equipment to verify that preplanned firefighting proceduresand appropriate firefighting techniques were used, and to verify that the directions of thefire brigade leader were thorough, clear, and effective. The inspectors attended thecritique to confirm that appropriate feedback on performance was provided to brigademembers and to ensure that areas for improvement were properly identified for licenseefollow-up. In preparing for the drill,  the inspectors reviewed the preplanned drillscenario,  Brunswick Nuclear Plant Drill Scenario Guide, 99-F-0S, Revision 1.
 
====b. Findings====
No findings of significance were identified.
 
6Enclosure1R06Flood Protection Measures
 
===.1 Internal Flooding===
 
====a. Inspection Scope====
The inspectors reviewed the licensee's internal flooding analysis as described inUpdated Final Safety Analysis Report (UFSAR) Section 3.4.2, Protection From InternalFlooding. 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 licensee's external flooding analysis as described inUFSAR 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.
 
7Enclosure1R11Licensed Operator Requalification
 
===.1 Quarterly Review===
 
====a. Inspection Scope====
The inspectors observed licensed operator performance and reviewed the associatedtraining documents during annual dynamic simulator examination sessions for trainingcycle 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.
{{a|1R12}}
==1R12 Maintenance Effectiveness==
 
====a. Inspection Scope====
For the two equipment issues described in the ARs listed below, the inspectors reviewedthe licensee's implementation of the Maintenance Rule (10 CFR 50.65) with respect tothe characterization of failures, the appropriateness of the associated Maintenance Rulea(1) or a(2) classification, and the appropriateness of the associated a(1) goals andcorrective actions. The inspectors reviewed the work controls and work practicesassociated with the degraded performance or condition to verify that they wereappropriate and did not contribute to the issue. The inspectors also reviewed operationslogs and licensee event reports to verify unavailability times of components andsystems, if applicable. Licensee performance was evaluated against the requirementsof Procedure ADM-NGGC-0101, Maintenance Rule Program.
 
*AR 242066, BNP response to operating experience 2007-08 degradation ofburied piping*AR 256103, Loss of full out indications on the full core display
 
====b. Findings====
No findings of significance were identified.
{{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Evaluation==
 
====a. Inspection Scope====
The inspectors reviewed the licensee's 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 250203, HPCI inoperable due to pump seal leakage*AR 255545, Unexpected annunciators during performance test (PT-12.2a) forEDG #1*AR 257721, Unit 1 condensate storage tank instrumental vent line excessivesloping*AR 257744, EDG #3 jacket water leakage from flexmaster jumpers
*AR 256079, 1-E11-F017B inoperable due to high energy line break issues at themotor control cubicle compartment
 
====b. Findings====
No findings of significance were identified.
{{a|1R15}}
==1R15 Operability Evaluations==
 
====a. Inspection Scope====
The inspectors reviewed the operability evaluations associated with the six issuesdocumented 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.
 
9Enclosure*AR 249130, 1A Residual heat removal heat exchanger degradation duringtesting (OPF08.1.4A) *AR 245864, E-4 Loss of coolant accident logic relay 27E2 de-energized*AR 250793, Unit 2 RCIC operability concern
*AR 252203, Unit 2 RCIC seal purge line orifice missing
*AR 251885, Unit 2 HPCI main pump seal leak exceeds posting
*AR 251490, Water in Unit 2 HPCI lube oil
 
====b. Findings====
No findings of significance were identified.
{{a|1R19}}
==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 licensee's 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 250499, Basis for changing piping test plan not understood
*AR 247456, Balance of plant under-voltage relays not tested as required
 
====b. Findings====
No findings of significance were identified.
{{a|1R22}}
==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.
 
10Enclosure*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 leakagerate determination), performed the week of November 12, 2007.0PT-9.3a, High Pressure Coolant Injection System Component Test, performedon 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 PressureCoolant Injection System Valve Operability Test, performed on Unit 1 on December 7,2007. The inspectors evaluated the effectiveness of the licensee's American Society ofMechanical Engineers (ASME) Section XI testing program to determine equipmentavailability and reliability. The inspectors evaluated selected portions of the followingareas: 1) testing procedures; 2) acceptance criteria; 3) testing methods; 4) compliancewith the licensee's IST program, TS, selected licensee commitments, and coderequirements; 5) range and accuracy of test instruments; and 6) required correctiveactions. The inspectors also assessed any applicable corrective actions taken.To assess the licensee's ability to identify and correct problems, the inspector reviewedAR 214876 which documented that the Unit 1 A conventional service water pump wasdiscovered to be in the Alert range following testing on November 30, 2006.
 
====b. Findings====
No findings of significance were identified.1EP6Drill Evaluation
 
====a. Inspection Scope====
The inspectors observed site emergency preparedness training drill/simulator scenariosconducted 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 licensee's post-drill critiques at the technical support center and emergency operating facility.
 
11EnclosureThe inspectors verified that the licensee properly evaluated the drill's performance withrespect 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 252936, knowledge gap in the required actions associated with the ReactorBuilding positive pressure as defined in AST documentation*AR 252937, rewording of SPDS indication to prevent human error
*AR 254108, JIC positions not filled during ERO drill
 
====b. Findings====
No findings of significance were identified.
{{a|1R23}}
==1R23 Temporary Plant Modifications==
 
====a. Inspection Scope====
The inspectors reviewed Operating Manual 0PLP-22, Temporary Changes, to assessthe implementation of Engineering Change (EC) 67830, Reactor Core Isolation CoolingSystem 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 thefunctional capability of the EDG, that the modification was properly installed, andappropriate post-installation testing was performed.
 
====b. Findings====
No findings of significance were identified.4.OTHER ACTIVITIES 4OA1Performance 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 CornerstoneThe inspectors sampled licensee submittals for the Units 1 and 2 PIs listed below for theperiod January 2007 through November 2007.
 
12Enclosure*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 toverify the accuracy of the PIs. The licensee's 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.4OA2Identification and Resolution of Problems
 
===.1 Routine Review of ARsTo aid in the identification of repetitive equipment failures or specific humanperformance issues for followup, the inspectors performed frequent screenings of items===
 
entered into the licensee's 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 operatorworkarounds as documented in licensee's 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 causeimplications*Prioritization and resolution of the issue commensurate with the safetysignificance*Identification of the root cause and contributing causes of the problem
*Identification and implementation of corrective actions commensurate with thesafety significance of the issue The inspectors reviewed the associated corrective action for AR 250203, Unit 2 highpressure 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 licensee's CAP and associated documents toidentify trends that could indicate the existence of a more significant safety issue. Thereview was focused on repetitive equipment issues but also considered the results offrequent inspector CAP item screening (discussed above), licensee trending efforts, andlicensee human performance results. The review considered the period of July throughDecember 2007. The review further included issues documented outside the normalCAP in major equipment lists, repetitive and/or rework maintenance lists, operationalfocus list, control room deficiency list, outstanding work order list, quality assuranceaudit/surveillance reports, key performance indicators, and self-assessment reports. The inspectors compared and contrasted their results with the results contained inmultiple root cause evaluations the licensee has performed over the last 2 quarters. Corrective actions associated with a sample of the issues identified in the licensee'strend reports were reviewed for adequacy. The inspectors also evaluated the reportsagainst the requirements of the licensee's CAP as specified in Nuclear GenerationGroup Standard Procedure CAP-NGGC-0200, Corrective Action Program, and 10 CFR50, Appendix B.
 
b.Assessment and ObservationsNo findings of significance were identified. The inspectors noted a trend in the controland retrieval of foreign material in systems and the adverse effects this has had onsystem performance; this was exemplified by the following identified issues:1) Foreign material found in the 1B Residual Heat Removal (RHR) Room cooler(AR243465); 2) Metallic foreign material found in the 1B RHR Heat Exchanger(AR246790); 3) 1D RHRSW Booster pump failed to start was bound by valve pin (AR243867); 4) Unit 2 HPCI main pump inboard seal failure due to blockage of seal coolingline (AR250203). The inspectors have determined that the licensee has addressed allimmediate operability concerns, and is currently developing long-term improvements.4OA6Meetings, Including ExitExit Meeting SummaryOn January 24, 2008, the resident inspectors presented the inspection results toMr. Waldrep and other members of his staff. The inspectors confirmed that proprietaryinformation was not provided or examined during the inspection.ATTACHMENT: 
 
=SUPPLEMENTAL INFORMATION=
 
==KEY POINTS OF CONTACT==
 
===Licensee Personnel===
: [[contact::G. Atkinson]], Supervisor - Emergency Preparedness
: [[contact::L. Beller]], Superintendent Operations Training
: [[contact::A. Brittain]], Manager - Security
: [[contact::D. Griffith]], Manager -  Training Manager
: [[contact::L. Grzeck]], Lead Engineer - Technical Support
: [[contact::S. Howard]], Manager - Operations
: [[contact::R. Ivey]], Manager - Site Support Services
: [[contact::T. Pearson]], Supervisor - Operations Training
: [[contact::A. Pope]], Supervisor - Licensing/Regulatory Programs
: [[contact::S. Rogers]], Manager - Maintenance
: [[contact::B. Waldrep]], Site Vice President
: [[contact::T. Sherrill]], Engineer - Technical Support
: [[contact::T. Trask]], Manager - Engineering
: [[contact::J. Titrington]], Manger - Nuclear Assessment Services
: [[contact::M. Turkal]], Lead Engineer - Technical Support
: [[contact::M. Williams]], Manager - Operations Support
: [[contact::E. Wills]], Plant General Manager
===NRC Personnel===
Randall Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II
Attachment
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
Opened and ClosedNone DiscussedNone
==LIST OF DOCUMENTS REVIEWED==
==Section 1R01: Adverse Weather ProtectionPlant Operating Manual (POM), Volume==
: VII, Operating Instruction 0OI-01.03, Non-RoutineActivities
: POM, Volume XII, Preventive Maintenance 0PM-HT001, Preventive Maintenance on PlantFreeze Protection and Heat Tracing System
 
==Section 1R04: Equipment AlignmentPOM, Volume==
: III, Operating Procedure 2OP-39, High Pressure Coolant Injection SystemOperating Procedure
: POM, Volume III, 0OP-39, Diesel Generator Operating ProcedureSystem Description
: SD-39, Emergency Diesel Generators
 
==Section 1R05: Fire ProtectionPOM, Volume==
: XIX, Prefire Plan 0PFP-DG, Diesel Generator Building Prefire PlansPOM, Volume XIX, Prefire Plan 0PFP-PBAA, Power Block Auxiliary Areas Prefire Plans
: POM, Volume XIX, Prefire Plan 1PFP-RB, Unit 1 Reactor Building Prefire Plans
 
==Section 1R06: Flood Protection MeasuresPOM, Volume==
: XXI, Abnormal Operating Procedure (AOP) 0AOP-13.0, Operation During
: Hurricane, Flood Conditions, Tornado, or Earthquake
: POM, Volume X, Periodic Test (PT) 0PT-34.2.2.1, Fire Door, ASSD Access/Egress Door, Severe Weather Door Inspections Updated Final Safety Analysis Report Chapters 2 and 3
}}

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